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 each Registrant as specified in I.R.S. Employer
Commission its charter, state of incorporation, address of Identification
File No. principal executive offices and telephone number Number
1-8349 Florida Progress Corporation 59-2147112
410 South Wilmington Street
Raleigh, North Carolina 27601
Telephone (919) 546-6111
State of Incorporation: Florida
1-3274 Florida Power Corporation 59-0247770
d/b/a Progress Energy Florida, Inc.
100 Central Avenue
St. Petersburg, Florida 33701
Telephone (727) 820-5151
State of Incorporation: Florida
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT
Title of each class Name of each exchange on which registered
Florida Progress Corporation:
7.10% Cumulative Quarterly Income Preferred Securities, New York Stock Exchange
Series A, of FPC Capital I (and the Guarantee of Florida
Progress with respect thereto)
Progress Energy Florida, Inc.: None
1
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Florida Progress Corporation: None
Florida Power Corporation: None
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 the registrants are accelerated filers (as
defined in Rule 12b-2 of the Act). YES [ ] NO [X]
As of June 30, 2004, the aggregate market value of the voting and non-voting
common equity of each of the registrants held by non-affiliates was $0. All of
the common stock of Florida Progress Corporation is owned by Progress Energy,
Inc., its corporate parent. All of the common stock of Florida Power Corporation
is owned by Florida Progress Corporation.
As of February 2005, each registrant had the following shares of common stock
outstanding:
Registrant Description Shares
Florida Progress Corporation Common Stock (without par value) 98,616,658
Florida Power Corporation Common Stock (without par value) 100
Florida Progress Corporation and Florida Power Corporation meet the conditions
set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore
filing this Form 10-K with the reduced disclosure format permitted by General
Instruction I(2) to such Form 10-K.
This combined Form 10-K is filed separately by two registrants: Florida Progress
Corporation and Florida Power Corporation. Information contained herein relating
to either individual registrant is filed by such registrant solely on its own
behalf. Each registrant makes no representation as to information relating
exclusively to the other registrant.
2
TABLE OF CONTENTS
GLOSSARY
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
PART II
ITEM 5. MARKET FOR THE REGISTRANTS' COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
ITEM 6. SELECTED 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. 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
RISK FACTORS
3
GLOSSARY OF TERMS
The following abbreviations or acronyms used in the text of this combined FORM
10-K are defined below:
TERM DEFINITION
AFUDC Allowance for funds used during construction
the Agreement Stipulation and Settlement Agreement related to
retail rate matters
ARO Asset retirement obligation
AST Advanced Separation Technology
Bcf Billion cubic feet
Btu British thermal units
CAIR Clean Air Interstate Rule
Calgon Calgon Carbon Corporation
Caronet Caronet, Inc.
the Code Internal Revenue Code
Colona Colona Synfuel Limited Partnership, L.L.L.P.
the Company, Florida
Progress or FPC Florida Progress Corporation
CP&L Energy CP&L Energy, Inc.
CR3 PEF's nuclear generating plant, Crystal River
Unit No. 3
DD&A Depreciation, depletion and amortization
DOE United States Department of Energy
ECRC Environmental Cost Recovery Clause
Electric Fuels Electric Fuels Corporation
EPA United States Environmental Protection Agency
EPIK EPIK Communications, Inc.
ESOP Employee stock ownership plan
ETS Engineering & Track-work Services
FASB Financial Accounting Standards Board
FASB Staff Position 106-2 Accounting and Disclosure Requirements Related to
the Medicare
Prescription Drug Improvement and Modernization
Act of 2003
FDEP Florida Department of Environmental Protection
FERC Federal Energy Regulatory Commission
FIN No. 46R FASB Interpretation No. 46, "Consolidation of
Variable Interest Entities - an Interpretation of
ARB No. 51"
Financial Statements Florida Progress' Financial Statements and Progress
Energy Florida's Financial Statements contained
under ITEM 8 herein
Florida Power or
the Utility Florida Power Corporation d/b/a Progress Energy
Florida, Inc.
FPSC Florida Public Service Commission
Funding Corp. Florida Progress' Funding Corporation
GAAP Accounting principles generally accepted in the
United States of America
Georgia Power Georgia Power Company
Global U.S. Global LLC
HLW High Level Waste
IRS Internal Revenue Service
ISO Independent System Operator
kV Kilovolt
kVA Kilovolt-ampere
LRS Locomotive and Railcar Services
LTIP Long-Term Incentive Plan
MAC Material adverse change
MACT Maximum Achievable Control Technology
Mcfe Million cubic feet equivalents
Medicare Act Medicare Prescription Drug, Improvement and
Modernization Act of 2003
MGP Manufactured Gas Plant
MW Megawatts
NEIL Nuclear Electric Insurance Limited
NERC North American Electric Reliability Council
NOx Nitrogen Oxide
NRC United States Nuclear Regulatory Commission
4
NSP Northern States Power
OCI Other comprehensive income
Odyssey Odyssey Telecorp, Inc.
OPEB Other postretirement benefits
P11 PEF's Intercession City Unit P11
PEF or the Utility Progress Energy Florida, Inc., formerly referred
to as Florida Power Corporation
PESC Progress Energy Service Company, LLC
PFA IRS Prefiling Agreement
The Plan Revenue Sharing Incentive Plan
PLRs Private Letter Rulings
PRPs Potentially Responsible Parties
Preferred Securities FPC-obligated mandatorily redeemable preferred
securities of FPC Capital I
Preferred Stock Progress Energy Florida Preferred Stock, $100 par
value
Progress Capital Progress Capital Holdings, Inc.
Progress Energy or
the Parent Progress Energy, Inc.
Progress Fuels Progress Fuels Corporation, formerly Electric Fuels
Corporation
Progress Rail Progress Rail Services Corporation
PSSP Performance Share Sub-Plan
PTC Progress Telecommunications Corporation
PT LLC Progress Telecom LLC
PVI Progress Ventures, Inc., formerly referred to as
Energy Ventures, a business unit of
Progress Energy
PUHCA Public Utility Holding Company Act of 1935, as
amended
PURPA Public Utility Regulatory Policies Act of 1978
PWR Pressurized Water Reactors
QFs Qualifying facilities
RAFT Railcar Asset Financing Trust
RBCA or Global RBCA Risk-based corrective action
Rail Rail Services
RCA Revolving credit agreement
ROE Return on equity
RSA Restricted stock agreement
RTO Regional Transmission Organization
SEC United States Securities and Exchange Commission
Section 29 Section 29 of the Internal Revenue Service Code
Service Company Progress Energy Service Company, LLC
SFAS No. 71 Statement of Financial Accounting Standards No. 71,
"Accounting for the Effects of Certain Types of
Regulation"
SFAS No. 123 Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation"
SFAS No. 133 Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative and Hedging Activities"
SFAS No. 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"
SMD NOPR Notice of Proposed Rulemaking in Docket
No. RM01-12-000, Remedying Undue Discrimination
through Open Access Transmission and Standard Market
Design
SNF Spent Nuclear Fuel
SO2 Sulfur dioxide
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
wholly owned subsidiary of Progress Fuels
5
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 "Liquidity and Capital Resources" about operating cash flows,
estimated capital requirements through the year 2007 and future financing plans
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 Florida Progress nor Progress Energy Florida (PEF) 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 Parent to implement its cost management
initiatives as planned; the uncertainty regarding the timing, creation and
structure of GridFlorida or other 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 of 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 and the affect it 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
PEF'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 the Company and PEF. New factors emerge from time to
time, and it is not possible for management to predict all such factors, nor can
it assess the effect of each such factor on the Company and PEF.
6
PART I
ITEM 1. BUSINESS
GENERAL
COMPANY
Florida Progress Corporation (Florida Progress or the Company, which term
includes consolidated subsidiaries unless otherwise indicated) is a wholly owned
subsidiary of Progress Energy, Inc. (Progress Energy), a registered holding
company under the Public Utility Holding Company Act (PUHCA) of 1935. Progress
Energy and its subsidiaries, including Florida Progress, are subject to the
regulatory provisions of PUHCA. Florida Progress was incorporated in Florida on
January 21, 1982. Florida Progress is the parent company of Florida Power
Corporation (Florida Power or the Utility) and certain other subsidiaries.
Progress Energy controls Florida Power Corporation and the other Florida
Progress subsidiaries through its ownership of Florida Progress.
On November 30, 2000, the acquisition of Florida Progress by CP&L Energy, Inc.
(CP&L Energy) became effective. In December 2000, CP&L Energy was renamed
Progress Energy, Inc.
Effective January 1, 2003, Florida Power began doing business under the name
Progress Energy Florida, Inc. (PEF). The legal name of the entity has not been
changed and there is no restructuring of any kind related to the name change.
The current corporate and business unit structure remains unchanged.
Florida Progress' revenues for the year ended December 31, 2004, were $5.9
billion, and assets at year-end were $9.7 billion. PEF's revenues for the year
ended December 31, 2004, were $3.5 billion, and assets at year-end were $7.9
billion. Florida Progress' principal executive offices are located at 410 South
Wilmington Street, Raleigh, North Carolina 27601-1748, telephone number (919)
546-6111. Information about Florida Progress and its subsidiaries can be found
at Progress Energy's home page on the Internet at
http://www.progress-energy.com, the contents of which are not and shall not be
deemed to be a part of this document or any other Securities and Exchange
Commission (SEC) filing. The Company makes available free of charge on its Web
site its annual reports on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K and all amendments to these reports as soon as reasonably
practicable after such material is electronically filed or furnished to the SEC.
Florida Progress' principal business segment is PEF, which encompasses all
regulated public utility operations. Florida Progress' other business segments,
including Energy and Related Services, Rail Services, and Other, represent its
diversified operations (See ITEM 1 "Business - Diversified Operations").
Progress Capital Holdings, Inc. (Progress Capital) is the downstream holding
company for Florida Progress' diversified subsidiaries and provides a portion of
the financing for the nonutility operations. Diversified operations include
Progress Fuels Corporation (Progress Fuels), formerly Electric Fuels Corporation
(Electric Fuels), and Progress Telecommunications Corporation (PTC). In January
2002, Electric Fuels changed its name to Progress Fuels. Progress Fuels is a
diversified nonutility energy company, whose principal business segments are
Energy and Related Services and Rail Services. The Company's Other category
consists primarily of PTC, the Company's Investment in FPC Capital I, and the
holding company, Florida Progress. PTC is a provider of wholesale
telecommunications services.
After the acquisition of Florida Progress, Progress Energy hired a financial
adviser to assist Florida Progress in evaluating its strategic alternatives with
respect to Progress Fuels' Inland Marine Transportation and Rail Services
segments. In November 2001, the Inland Marine Transportation segment was sold to
AEP Resources, Inc.
During 2001, Progress Energy decided to retain the Rail Services segment in the
near term. In December 2002, the Progress Energy Board of Directors adopted a
resolution approving the sale of Railcar Ltd., a subsidiary included in the Rail
Services segment. In March 2003, Progress Energy 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 in
February 2004.
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 23).
7
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 wholly owned subsidiary of Progress Fuels Corporation (Progress
Fuels), which is included in the Energy and Related Services 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
PEF's service territory during the third quarter of 2004. As of December 31,
2004, restoration of PEF's systems from hurricane related damage was estimated
at $385 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).
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).
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).
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).
Westchester Acquisition
In April 2002, Progress Fuels acquired 100% of Westchester Gas Company. During
2004, the name of the company was changed to Winchester Energy Company, 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 5C).
8
UTILITY OPERATIONS - 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 nine 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, 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
General
PEF's consumption of various types of fuel depends on several factors, the most
important of which are the demand for electricity by PEF's customers, the
availability of various generating units, the availability and cost of fuel and
the requirements of federal and state regulatory agencies. PEF's total system
generation (including jointly owned capacity) by primary energy source along
with purchased power for the 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
complete certainty. See "Commodity Price Risk" under Item 7A, QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK. However, PEF believes that its fuel
supply contracts, as described below, will be adequate to meet its fuel supply
needs.
9
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
Natural gas and oil supply for PEF's generation fleet is purchased under term
and spot contracts from several suppliers. The majority of the cost of PEF's oil
and gas is determined by market prices as reported in certain industry
publications. PEF believes that it has access to an adequate supply of oil and
gas for the reasonably foreseeable future. PEF's natural gas transportation is
purchased under term firm transportation contracts with interstate pipelines.
PEF also purchases capacity on a seasonal basis from numerous shippers and
interstate pipelines to serve its peaking load requirements. PEF 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."
10
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
has actively participated in regulatory reform deliberations in Florida.
Movement toward deregulation in this state has been affected by developments
related to deregulation of the electric industry in other states.
In response to a legislative directive, the FPSC and the Florida Department of
Environment and Protection 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 (the Applicants) collectively 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 8C 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
effect of these franchises is to provide for the manner in which PEF occupies
rights-of-way in incorporated areas of municipalities for the purpose of
constructing, operating and maintaining an energy transmission and distribution
system.
Approximately 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 Note 21E).
11
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 the Public Utility Regulatory Policies Act of 1978
(PURPA).
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 8B.
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 (See "Risk
Factors").
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, 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 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.
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
12
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
PEF owns and operates one nuclear generating plant, Crystal River Unit No. 3
(CR3), which is subject to regulation by the Nuclear Regulatory Commission (NRC)
under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974.
In the event of noncompliance, the NRC has the authority to impose fines, set
license conditions, shut down a nuclear unit, or some combination of these,
depending upon its assessment of the severity of the situation, until compliance
is achieved. 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.
The NRC operating license held by PEF for CR3 currently expires in December
2016. An application to extend this license 20 years is expected to be submitted
in the first quarter 2009. PEF currently has a 91.8% ownership interest in CR3.
A condition of the operating license for the unit requires an approved plan for
decontamination and decommissioning.
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. Inspection of
the vessel head at CR3 was performed during a previous outage and no degradation
of the reactor vessel head was identified.
In 2002, the NRC issued an additional bulletin dealing with head leakage due to
cracks near the control rod nozzles, asking licensees to commit to high
inspection standards to ensure the more susceptible plants have no cracks. 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 CR3 during its 2003
outage and found no signs of corrosion or leakage at the unit. The Company plans
to do additional, more detailed inspections as part of the next scheduled
10-year in-service inspection.
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. CR3 will
be required to inspect its new head within 7 years or four refueling outages
after replacement. CR3 plans to inspect its new head prior to the end of 2009.
ENVIRONMENTAL MATTERS
There are two former MGP sites and other sites associated with PEF that have
required or are anticipated to require investigation and/or remediation costs.
In addition, there are distribution substations and transformers which are also
anticipated to incur investigation and remediation costs. Presently, PEF cannot
determine the total costs that may be included in connection with the
remediation of all sites. See Note 20 for further discussion of these
environmental matters.
13
DIVERSIFIED OPERATIONS
General
Florida Progress' diversified operations are owned directly or indirectly
through Progress Capital, a Florida corporation and wholly owned subsidiary of
Florida Progress. Progress Capital holds the capital stock of, and provides the
financing for, Florida Progress' nonutility subsidiaries. Its primary subsidiary
is Progress Fuels, formerly Electric Fuels. In January 2002, Electric Fuels
changed its name to Progress Fuels.
Formed in 1976, Progress Fuels is an energy and transportation company. When the
Inland Marine Transportation unit was sold in November 2001, Progress Fuels was
reorganized into two business units: Energy and Related Services and Rail
Services.
Energy and Related Services
Progress Fuels' Energy and Related Services business unit supplies coal to
Florida Power's Crystal River Energy Complex and other utility and industrial
customers. This business unit has subsidiaries that produce natural gas and oil
products, blend and transload coal, mine coal and produce a solid coal-based
synthetic fuel.
Synthetic Fuel 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 taking 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 21 and in the "Risk Factors" section.
Rail Services
The Rail Services business segment, led by Progress Rail Services Corporation
(Progress Rail), is one of the largest integrated and diversified suppliers of
railroad and transit system products and services in North America and is
headquartered in Albertville, Alabama. Rail Services' principal business
functions include two business units: the 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 which supports the operation of rolling stock, as
well as 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.
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 23 for more information.
In March 2003, the Company signed a letter of intent to sell Railcar Ltd., to
The Andersons, Inc. The asset purchase agreement was signed in November 2003,
and the transaction closed in February 2004.
14
With operations in 23 states, Canada and Mexico, Progress Rail offers a full
range of railcar parts, maintenance-of-way equipment, rail and other track
material, railcar repair facilities, railcar scrapping and metal recycling as
well as railcar sales and leasing.
PROGRESS TELECOM LLC
In December 2003, 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 PT LLC, a subsidiary of PTC.
Subsequently, the stock of Caronet, a Progress Energy Carolinas subsidiary, was
sold to an affiliate of Odyssey for $2 million in cash and Caronet became an
indirect wholly owned subsidiary of Odyssey. Following consummation of all the
transactions described above, PTC holds a 55% ownership interest in, and is the
parent of, PT LLC. The accounts of PT LLC have been included in the Company's
Financial Statements since the transaction date.
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 approximately 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 (i.e., as the revenue
is earned) 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 Note 10 to the
Financial Statements.
COMPETITION
Florida Progress' nonutility subsidiaries compete in their respective
marketplaces in terms of price, quality of service, location and other factors.
Progress Fuels competes in several distinct markets. Its coal and synthetic fuel
operations compete in the eastern United States industrial coal markets, and its
rail operations compete in the railcar repair, parts and associated services
markets primarily in the eastern United States, but also in the midwest, west,
Canada and Mexico. Factors contributing to Progress Fuels' 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.
Progress Fuels' gas production operations compete in the East Texas/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.
15
ITEM 2. PROPERTIES
GENERAL
Florida Progress believes that its physical properties and those of its
subsidiaries are adequate to carry their businesses as currently conducted.
Florida Progress and its subsidiaries maintain property insurance against loss
or damage by fire or other perils to the extent that such property is usually
insured.
UTILITY OPERATIONS
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.
16
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 1,500 miles of 230 kV lines. PEF
also had 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 about 18,000,000 kVA.
DIVERSIFIED OPERATIONS
Progress Fuels controls, either directly or through subsidiaries, coal reserves
located in eastern Kentucky and southeastern 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.
Progress Fuels has oil and gas leases in East Texas and Louisiana with total
proven oil and gas reserves of approximately 247 billion cubic feet equivalent.
Progress Fuels' oil and gas production in 2004 was 30.4 billion cubic feet
equivalent. The following provides further information on the oil and gas
operations (See Note 22).
Gross and net developed and undeveloped acreage at December 31, 2004 follow:
- --------------------------------------------------------------------------
Developed Undeveloped
--------------------------- -------------------------
Gross Net Gross Net
- --------------------------------------------------------------------------
United States 94,891 67,300 15,797 13,291
- --------------------------------------------------------------------------
The number of gross and net development wells completed during each of the years
ending December 31 follows:
- ---------------------------------------------------------------------------------------
2004 2003 2002
- ---------------------------------------------------------------------------------------
(in millions) Gross Net Gross Net Gross Net
- ---------------------------------------------------------------------------------------
Development Wells:
Productive 90 74 110 101 51 44
Dry 1 1 2 2 - -
- ---------------------------------------------------------------------------------------
Total Development 91 75 112 103 51 44
- ---------------------------------------------------------------------------------------
The number of productive oil and gas wells at December 31, 2004, follows:
- ------------------------------------------------------------
Oil Gas
--------------------- -------------------
(in millions) Gross Net Gross Net
- ------------------------------------------------------------
United States 55 51 363 336
- ------------------------------------------------------------
17
OTHER
Progress Rail, a Progress Fuels subsidiary, is one of the largest integrated
processors of railroad materials in the United States, and is a leading supplier
of new and reconditioned freight car parts; rail, rail welding and track work
components; railcar repair facilities; railcar and locomotive leasing;
maintenance-of-way equipment and scrap metal recycling. It has facilities and
offices 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.
PTC provides wholesale telecommunications services throughout the Eastern United
States. PT LLC incorporates more than 420,000 fiber miles in its network,
including over 189 Points-of-Presence, or physical locations where a presence
for network access exists.
18
ITEM 3. LEGAL PROCEEDINGS
1. Calgon Carbon Corporation v. Potomac Capital Investment Corporation,
Potomac Electric Power Company, Progress Capital Holdings, Inc., and
Florida Progress Corporation, United States District Court for the Western
District of Pennsylvania, Civil Action No. 98-0072.
In 1996, Florida Progress sold its 80% interest in Advanced Separation
Technologies (AST) to Calgon Carbon Corporation (Calgon) for net proceeds
of $56 million in cash. In 1998, Calgon filed a lawsuit against Florida
Progress and the other selling shareholder and amended it in April 1998,
alleging misstatement of AST's 1996 revenues, assets and liabilities,
seeking damages and granting Calgon the right to rescind the sale. The
lawsuit also accused the sellers of failing to disclose flaws in AST's
manufacturing process and a lack of quality control.
All parties filed motions for summary judgment in July 2001. The summary
judgment motions of Calgon and the other selling shareholder were denied in
April 2002. The summary judgment motion of Florida Progress was withdrawn
pending a legal challenge to portions of the report of Calgon's expert,
Arthur Andersen, which had been used to oppose summary judgment. In
September 2003, the United States District Court for the Western District
of Pennsylvania issued final orders excluding from evidence in the case
that portion of Arthur Andersen's damage analysis based on the discounted
cash flow methodology of valuation. The Court did not exclude Arthur
Andersen's use of the guideline publicly traded company methodology in its
damage analysis. Florida Progress filed a renewed motion for summary
judgment in October 2003, which is pending. Because the motion has now been
outstanding for over a year, a ruling on the motion is expected at any
time.
Florida Progress believes that the aggregate total of all legitimate
warranty claims by customers of AST for which it is probable that Florida
Progress will be responsible under the Stock Purchase Agreement with Calgon
is approximately $3 million, and accordingly, accrued $3 million in the
third quarter of 1999 as an estimate of probable loss. The Company cannot
predict the outcome of this matter, but will vigorously defend against the
allegations (See Note 21).
2. U.S. Global, LLC v. Progress Energy, Inc. et al., Case No. 03004028-03
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.
19
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.
For a discussion of certain other legal matters, see Note 21 to the Financial
Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The information called for by ITEM 4 is omitted pursuant to Instruction I (2)
(c) to Form 10-K (Omission of Information by Certain Wholly owned Subsidiaries).
PART II
ITEM 5. MARKET FOR THE REGISTRANTS' COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
FLORIDA PROGRESS
Since November 2000, all of Florida Progress' common stock is owned by Progress
Energy, and as a result there is no established public trading market for the
stock. Since the Progress Energy acquisition Florida Progress has not issued or
repurchased any equity securities. Florida Progress receives dividends from PEF.
PEF has provisions restricting dividends in certain limited circumstances (See
Note 12B). FPC did not issue or repurchase any equity securities during 2004.
FPC does not have any equity compensation plans under which its equity
securities are issued.
PEF
All of PEF's common stock is owned by Florida Progress, and as a result there is
no established public trading market for the stock. For the past three years,
PEF has paid quarterly dividends to Florida Progress totaling the amounts shown
in the Statements of Common Equity in the Financial Statements. PEF has
provisions restricting dividends in certain circumstances (See Note 12B). PEF
did not issue or repurchase any equity securities during 2004. PEF does not have
any equity compensation plans under which its equity securities are issued.
ITEM 6. SELECTED FINANCIAL DATA
The information called for by ITEM 6 is omitted pursuant to Instruction I (2)
(a) to Form 10-K (Omission of Information by Certain Wholly owned Subsidiaries).
20
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
"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.
Overview
Florida Progress' income from continuing operations for the years ended December
31, 2004 and 2003 were $474 million and $443 million, respectively. The increase
in income from continuing operations in 2004 is primarily due to:
o Reduction in revenue sharing provisions in Florida.
o Favorable customer growth at the utility.
o Increased margins as a result of the allowed return on the Hines 2 Plant at
the utility.
o Increased earnings for natural gas operations, which include the gain
recorded on the disposition of certain gas assets.
o Increased earnings for Rail operations.
Partially offsetting these items were the:
o Reduction in synthetic fuel earnings due to lower synthetic fuel sales due
to the impact of hurricanes during the year.
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.
These and other key operating results are discussed by segment below.
Progress Energy Florida
PEF's operating results are primarily influenced by customer demand for
electricity, its ability to control costs and its regulatory return on equity.
Annual demand for electricity is based on the number of customers, their annual
usage and the impact of weather. Since PEF serves a predominately retail
customer base, operating results are primarily influenced by the level of retail
sales and the costs associated with those sales. In addition, the current
economic conditions in the service territories may impact the annual demand for
electricity.
The FPSC oversees the retail sales of the state's investor-owned electric
utilities and authorizes retail base rates. Base rates and the resulting base
revenues are intended to cover certain reasonable and prudent expenses of
utility operations and provide investors with a fair rate of return.
Costs not covered by base rates include fuel, purchased power, energy
conservation expenses and certain environmental costs. The FPSC allows electric
utilities to recover these costs, referred to as "pass-through" costs, through
various cost recovery clauses to the extent those costs are prudent. Due to the
regulatory treatment of these expenses and the method allows for recovery,
changes from year to year have no material impact on operating results.
PEF contributed segment profits of $333 million and $295 million in 2004 and
2003, 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.
PEF's profits in 2004 and 2003 were affected by the outcome of the Florida Power
rate case stipulation, which included a one-time retroactive revenue refund in
2002, a decrease in retail rates of 9.25% (effective May 1, 2002), provisions
for revenue sharing with the retail customer base, lower depreciation and
amortization and increased service revenue rates (See Note 8B).
21
A comparison of the results of operations of PEF for the past two years follows:
REVENUES
PEF's electric revenues for the years ended December 31, 2004, 2003 and 2002 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
----------------------------------------------------------------------------------------------
PEF's electric energy sales for the years ended December 31, 2004, 2003 and 2002
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 of 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. 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 partially 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 of 2003 that required PEF to
refund an additional $18 million to customers related to 2002. The 9.25% rate
reduction from the settlement accounted for an additional $46 million decline in
revenues. The 2003 impact of the rate settlement was partially offset by the
absence of the prior year interim rate refund of $35 million. Lower wholesale
revenues (excluding fuel revenues) of $17 million and the $8 million impact of
milder weather also reduced base revenues during 2003.
22
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 is 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.
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.
23
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 2002. 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 Progress
Energy 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
pretax income.
Progress Fuels Corporation
Progress Fuels makes up the majority of Florida Progress' diversified
operations. The results of operations for Progress Fuels' Energy and Related
Services and Rail Services units are discussed below.
Energy and Related Services - Income from continuing operations for Energy and
Related Services were $137 million and $166 million for 2004 and 2003,
respectively. The following summarizes Energy and Related Services' segment
profits for the years ended 2004 and 2003:
--------------------------------------------------------------------
(in millions) 2004 2003
--------------------------------------------------------------------
Synthetic fuel operations $ 57 $ 139
Natural gas operations 85 34
Coal fuel and other operations (5) (7)
--------------------------------------------------------------------
Segment profits $ 137 $ 166
--------------------------------------------------------------------
SYNTHETIC FUEL OPERATIONS
Synthetic fuel operations generated profits of $57 million and $139 million for
the years ended December 31, 2004 and 2003, respectively. The production and
sale of the synthetic fuel generate operating losses, but qualify for tax
credits under Section 29 of the Internal Revenue Code, which more than offset
the effects of such losses. The operations resulted in the following losses
(prior to tax credits) and tax credits for 2004 and 2003.
-----------------------------------------------------------------------
(in millions) 2004 2003
-----------------------------------------------------------------------
Tons sold 4.9 7.5
After-tax losses (excluding tax credits) $ (70) $ (74)
Tax credits 127 213
-----------------------------------------------------------------------
Net Profit $ 57 $ 139
-----------------------------------------------------------------------
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 five million tons in 2004 is down compared to 2003 production
levels of approximately eight 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.
As of September 30, 2004, the Company anticipated an ability to record
approximately three million tons of production based on the Company's projected
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 $47 million in the third quarter for tax credits associated with
approximately 1.8 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 five million tons. Therefore, the Company recorded tax
credits of $55 million for the quarter ended December 31, 2004, for tax credits
associated with approximately 2 million tons sold during the year that the
Company now anticipates can be used. As of December 31, 2004, the Company
24
anticipates that approximately $5 million of tax credits associated with
approximately 0.2 million tons sold during the year could not be used (See Note
21E). 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.
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.
NATURAL GAS OPERATIONS
Natural gas operations generated profits of $85 million and $34 million for the
years ended December 31, 2004 and 2003, respectively. Natural gas profits
increased $51 million in 2004 compared to 2003 due 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 (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.
The following 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%
- --------------------------------------------------------------------------------
25
RESULTS FROM PRODUCING ACTIVITIES
The following summarizes the results of operations of natural gas production
operations:
- ------------------------------------------------------------------------------
Years ending December 31,
($ in millions except for averages) 2004 2003 2002
- ------------------------------------------------------------------------------
Gas production (Bcfe) 30.4 25.1 12.7
Average sales price:
Gas (per Mcf) $ 4.84 $ 4.24 $ 2.77
Oil (per Bbl) $ 41.06 $ 29.46 $ 26.33
Average sales price combined (per Mcfe) $ 4.95 $ 4.27 $ 2.84
Average production cost (per Mcfe) $ 0.92 $ 0.66 $ 0.54
Revenue (millions)
Gas $ 168 $ 116 $ 32
Oil $ 11 $ 7 $ 3
Hedging $ (28) $ (16) $ 1
- ------------------------------------------------------------------------------
Total revenue 151 107 36
- ------------------------------------------------------------------------------
Production costs $ 28 $ 16 $ 7
- ------------------------------------------------------------------------------
COAL FUEL AND OTHER OPERATIONS
Coal fuel and other operations generated losses of $5 million and $7 million for
the years ended December 31, 2004 and, 2003, respectively. The increase in
profits for 2004 is primarily due to higher volumes and margins for coal fuel
operations of $16 million after-tax. A reduction in impairment losses of $2
million after-tax also increased coal earnings. An impairment of goodwill
related to the Diamond May coal mine reduced earnings by $8 million before and
after-tax (See Note 9). Results in 2003 included the recording of an impairment
of certain assets at the Kentucky May coal mine of $10 million after-tax in 2003
(See Note 10). 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 8B). Profits were also negatively
impacted by higher corporate costs of $10 million in 2004. Corporate cost in the
prior year included $4 million of favorability related to the reduction of an
environmental reserve (See Note 20). The remaining unfavorability in corporate
costs is attributable to increased interest expense related to unresolved tax
matters and higher professional fees.
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 were $62
million. The Company cannot currently predict the outcome of this matter.
RAIL SERVICES
Rail's operations represent the activities of Progress Rail Services Corporation
(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.
Rail contributed segment profits of $16 million and losses of $1 million for the
years ended December 31, 2004 and 2003, 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 rail road 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 good 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.
26
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 22 for more information.
Other
The Other segment includes telecommunications, holding company and financing
expenses and had net losses from continuing operations of $12 million and $17
million in 2004 and 2003, respectively.
PTC had net losses of $5 million and $3 million for 2004 and 2003, respectively.
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. In December 2003, 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 PT LLC, a subsidiary of PTC.
Subsequently, the stock of Caronet, a subsidiary of Progress Energy Carolinas,
was sold to an affiliate of Odyssey for $2 million in cash and Caronet became an
indirect wholly owned subsidiary of Odyssey. Following consummation of all the
transactions described above, PTC holds a 55 percent ownership interest in, and
is the parent of PT LLC. Odyssey holds a combined 45 percent ownership interest
in PT LLC through EPIK and Caronet. The accounts of PT LLC are included in the
Company's Financial Statements since the transaction date.
APPLICATION OF CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Florida Progress and PEF prepared their 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 its financial results 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 Progress
Energy's Board of Directors.
Utility Regulation
PEF is subject to regulation that sets the prices (rates) it is permitted to
charge customers based on the costs that regulatory agencies determine PEF is
permitted to recover (See Note 8). At times, regulators permit the future
recovery through rates of costs that would be currently charged to expense by a
nonregulated company. This ratemaking process results in deferral of expense
recognition and the recording of regulatory assets based on anticipated future
cash inflows. As a result of the changing regulatory framework, a significant
amount of regulatory assets have been recorded. PEF 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 agency often provides flexibility in the manner and timing
of the depreciation of property, nuclear decommissioning costs and amortization
of the regulatory assets.
Asset Impairments
Florida Progress 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.
In connection with a review of strategic alternatives regarding the Fuels' coal
mining business, the Company performed an impairment test of the goodwill of the
coal mining business in the fourth quarter of 2004. As a result of the
impairment test, the Company recorded an impairment loss of $8 million to write
off all of the goodwill of the coal mining business. The Company used a
probability-weighted discounted cash flow analysis to perform the assessment.
27
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
$15 million on a pre-tax basis during the fourth quarter of 2003. See Note 10 to
the Financial Statements for further information on this impairment. Fair value
was determined based on discounted cash flows.
During 2002, Florida Progress recorded pre-tax long-lived asset impairments of
$215 million related to its telecommunications business. See Note 10 to the
Financial Statements for further information on this impairment and other
charges. The fair value of these assets was determined using an external
valuation study heavily weighted on a discounted cash flow methodology and using
market approaches as supporting information.
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.
Synthetic Fuels Tax Credits
As discussed in Note 21E, Florida Progress, through the Energy and Related
Services business unit, 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, 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 on the Consolidated Balance Sheets. All of
Florida Progress' 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 at Note 21E and in the "Risk Factors" section.
Pension Costs
As discussed in Note 15 to the Financial Statements, Florida Progress and PEF
maintain qualified non-contributory defined benefit retirement (pension) plans.
The reported costs of providing pension benefits are dependent on numerous
factors resulting from actual plan experience and assumptions of future
experience. For example, such costs are impacted by employee demographics,
changes made to plan provisions, actual plan asset returns and key actuarial
assumptions such as rates of return on plan assets and discount rates used in
determining benefit obligations and annual costs. In addition, reported costs
reflect certain delayed recognition features in the accounting model used to
determine each year's cost.
Due to a decline in market interest rates for high-quality (AAA/AA) debt
securities, which are used as the benchmark for setting the discount rate used
to present value future benefit payments, Florida Progress 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 cost in 2005, all other factors remaining constant.
Evaluations of the effects of these and other factors have not been completed,
but Florida Progress estimates that 2005 total cost recognized for pension will
be approximately plus or minus $2 million of the amount recorded in 2004.
Florida Progress has pension plan assets with a fair value of approximately $919
million at December 31, 2004. Florida Progress' expected rate of return on
pension plan assets is 9.25%. The Company reviews this rate on a regular basis.
Under SFAS No. 87, "Employers' Accounting for Pensions" the expected rate of
return used in pension cost recognition is a long-term rate of return;
therefore, Florida Progress would only adjust that return if its fundamental
assessment of the debt and equity markets changes or its investment policy
changes significantly. Florida Progress believes that its pension plans' asset
investment mix and historical performance support the long-term rate of 9.25%
being used. Florida Progress does not adjust the rate in response to short-term
market fluctuations such as the abnormally high market return levels of the
28
latter 1990's, 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 cost by approximately $2 million. Approximately 95% of Florida
Progress' pension assets and obligations are attributable to PEF.
Another factor affecting Florida Progress' and PEF's pension cost, and
sensitivity of the cost to plan asset performance, is its selection of a method
to determine the market-related value of assets, i.e., the asset value to which
the 9.25% long-term expected 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. Florida Progress uses
the fair value method of determining market-related value. Changes in plan asset
performance are reflected in pension cost sooner under the fair value method
than the five-year averaging method and, therefore, pension cost tends to be
more volatile using the fair value method.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Florida Progress' utility and diversified operations are capital-intensive
businesses. Florida Progress relies upon its operating cash flow, commercial
paper facilities and its ability to access long-term capital markets for its
liquidity needs. Since a substantial majority of Florida Progress' operating
costs are related to its regulated electric utility, a significant portion of
these costs are recovered from customers through fuel and energy cost recovery
clauses.
The Company and its subsidiaries participate in two internal money pools,
operated by Progress Energy, to more effectively utilize cash resources and to
reduce outside short-term borrowings. Short-term borrowing needs are met first
by available funds of the money pool participants. Borrowing companies pay
interest at a rate designed to approximate the cost of outside short-term
borrowings. Subsidiaries, which invest in the money pool, earn interest on a
basis proportionate to their average monthly investment. Funds may be withdrawn
from or repaid to the pool at any time without prior notice.
At PEF, cash from operations is the primary source of cash for the utility's
capital expenditures. PEF's estimated capital requirements for 2005, 2006 and
2007 are approximately $490 million, $450 million and $550 million,
respectively. See Note 8D for a discussion of expected impacts on future capital
expenditures due to changes in capitalization practice for PEF.
In addition to funding its construction and other commitments with cash from
operations, the companies can access the capital markets through the issuance of
commercial paper, committed lines of credit, secured and unsecured notes,
preferred securities and equity from Progress Energy, which can offer issuances
of common stock. Risk factors associated with commercial paper back up credit
facilities and credit ratings are discussed below and in the "Risk Factors"
section of this report.
PEF's interim financing needs are funded primarily through its commercial paper
program and borrowings under its 364-day and 3-year revolving credit agreements
(RCAs). PEF's commercial paper program is supported by its lines of credit and
to the extent amounts are reserved for commercial paper, they are not available
for additional borrowings. PEF plans to enter into a new five-year line of
credit in 2005 that will replace these two facilities. In addition, PEF has an
uncommitted bank bid facility that authorizes them to borrow and re-borrow. The
facility was established to temporarily supplement commercial paper borrowings,
as needed.
In addition to funding the working capital needs of its diversified businesses
primarily through its commercial paper program, Progress Energy can issue
long-term debt to fund the capital requirements of Progress Fuels.
Cash Flow From Operating Activities
Florida Progress' cash provided by operations in 2004 of $611 million decreased
$31 million compared with 2003 due primarily to storm costs at PEF and an
increase in inventory levels, partially offset by recovery of previously under
recovered fuel costs at PEF. PEF's operating cash flow increased by $85 million
to $533 million in 2004, due primarily to higher net income, an increase in
deferred taxes from the restoration costs and casualty losses from the
hurricanes for tax purposes and recovery of previously under recovered fuel
costs, largely offset by storm costs.
Florida Progress' cash provided by operations in 2003 of $642 million decreased
$24 million compared with 2002 due primarily to increased deferred fuel costs at
PEF. PEF's operating cash flow increased by $29 million to $448 million in 2003,
due primarily to changes in working capital, partially offset by increased
deferred fuel costs as a result of rising prices.
29
Cash Flow From Investing Activities
Cash requirements of Florida Progress used in investing activities during 2004
of $372 million decreased $544 million when compared with 2003. The decrease was
due primarily to diversified property asset sales, lower diversified property
additions and lower utility property additions in 2004.
Cash requirements of Florida Progress used in investing activities during 2003
of $916 million increased $274 million when compared with 2002. The increase was
due primarily to diversified property additions in 2003.
PEF's capital expenditures, including nuclear fuel additions, totaled $492
million and $577 million for 2004 and 2003, respectively. These expenditures are
primarily for transmission and distribution assets and generating facilities
necessary to meet the needs of the utility's growing customer base. See Note 8D
for a discussion of expected impacts on future capital expenditures due to
changes in PEF's capitalization policy.
In planning for its future generation needs, PEF develops a forecast of annual
demand for electricity, including a forecast of the level and duration of peak
demands during the year. These forecasts have historically been developed using
a 15% reserve margin. The reserve margin is the difference between a company's
net system generating capacity and the maximum demand on the system. In December
1999, the FPSC approved a joint proposal by PEF, Florida Power & Light and Tampa
Electric Company to increase the reserve margin to 20% by 2004.
In response, PEF constructed a second generating unit at the Hines site. Hines
Unit 2 was placed into service in December 2003. Hines Unit 2 is the same
combined-cycle technology as Hines Unit 1 and has a summer generating capacity
of approximately 516 MW. In addition, PEF has begun construction of a third unit
and has received approval to begin construction of a fourth unit at the Hines
Energy Complex.
Diversified business property additions for 2004 and 2003 were $203 million and
$424 million, respectively. These capital expenditures have been primarily for
the expansion of the Company's natural gas operations.
During 2004, sales of subsidiaries and other investments primarily included
proceeds from the sale of Railcar Ltd., assets of approximately $75 million and
approximately $251 million from the sale of natural gas assets in the Forth
Worth basin of Texas. The Company used the proceeds from these sales to reduce
indebtedness and pay dividends to Progress Energy.
The Company received net proceeds of approximately $97 million in October 2003
for the sale of its Mesa gas properties located in Colorado. Proceeds were
primarily used to reduce short-term debt.
See Note 20 for a discussion of the effects of compliance with environmental
laws and related estimated capital expenditures.
Cash Flow From Financing Activities
Net cash (used in) provided by financing activities for the three years ending
December 31, 2004, 2003 and 2002 for the Company were $(237) million, $267
million and $5 million, respectively. Net cash (used in) provided by financing
activities for the three years ending December 31, 2004, 2003 and 2002 for PEF
were $(35) million, $124 million and $114 million, respectively. See Note 12 for
details of debt and credit facilities.
In addition to the financing activities discussed under "Overview," the
financing activities of the Company and PEF included:
2005
o In February 2005, PEF used proceeds from money pool borrowings to pay off
$55 million of RCA loans and in January 2005, PEF used proceeds from the
issuance of commercial paper to pay off $170 million of RCA loans.
2004
o During the fourth quarter of 2004, PEF borrowed a net total of $55 million
under its long-term revolving credit facility. In addition, PEF borrowed
$170 million under its short-term credit facility. The borrowed funds were
used to pay off maturing commercial paper and for other cash needs.
30
o The following table summarizes the Company's credit facilities as of
December 31, 2004:
---------------------------------------------------------------------------
(in millions)
Description Total Outstanding Available
---------------------------------------------------------------------------
364-Day (expiring 3/29/05) $ 200 $ 170 $ 30
3-Year (expiring 4/01/06) 200 55 145
Less: amounts reserved(a) (123)
---------------------------------------------------------------------------
Total credit facilities $ 400 $ 225 $ 52
---------------------------------------------------------------------------
(a) To the extent amounts are reserved for commercial paper outstanding,
they are not available for additional borrowings.
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 March 30, 2004, PEF extended its $200 million 364-day line of credit.
The line of credit will expire on March 29, 2005.
o On February 9, 2004, Progress Capital Holdings, Inc. paid at maturity $25
million 6.48% medium term notes with available cash from operations.
2003
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.
2002
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.
Credit Facilities
At December 31, 2004, PEF had committed lines of credit and outstanding balances
as shown under "Financing Activities." The credit facilities supporting the
credit were arranged through a syndication of financial institutions. There are
no bilateral contracts associated with these facilities.
PEF's financial policy precludes issuing commercial paper in excess of its
supporting lines of credit. At December 31, 2004, PEF had $123 million of
commercial paper outstanding, and an additional $225 million drawn directly from
the credit facilities, leaving $52 million available for issuance or drawdown.
In addition, PEF has requirements to pay minimal annual commitment fees to
maintain its credit facilities. At December 31, 2003, PEF did not have any
commercial paper outstanding. PEF expects to continue to use commercial paper
issuances as a source of liquidity.
The credit facilities include a defined maximum total debt-to-total capital
ratio (leverage) and coverage ratios. PEF is in compliance with these covenants
at December 31, 2004. See Note 12 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 PEF, pursuant to the
terms of the agreements, are as disclosed in Note 12.
PEF has an uncommitted bank bid facility authorizing it to borrow and re-borrow,
and have loans outstanding at any time up to $100 million. At December 31, 2004,
there were no outstanding loans against these facilities. PEF currently has on
file registration statements under which it can issue an aggregate of $750
million of various long-term debt securities.
PEF can issue First Mortgage Bonds under its First Mortgage Bond indenture. At
December 31, 2004, PEF could issue up to $3.7 billion based on property
additions and $176 million based upon retirements.
31
Credit Rating Matters
The major credit rating agencies have currently rated the Company's securities
as follows:
- --------------------------------------------------------------------------------
Moody's
Investors Service Standard & Poor's
- --------------------------------------------------------------------------------
Progress Energy Florida, Inc.
Corporate credit/issuer rating Not Applicable BBB
Commercial paper P-2 A-3
Senior secured debt A2 BBB
Senior unsecured debt A3 BBB
FPC Capital I
Preferred stock* Baa2 BB+
Progress Capital Holdings, Inc.
Senior unsecured debt* Baa1 BBB-
- --------------------------------------------------------------------------------
*Guaranteed by Florida Progress Corporation
These ratings reflect the current views of these rating agencies, and no
assurances can be given that these ratings will continue for any given period of
time. However, the Company monitors its financial condition as well as market
conditions that could ultimately affect its credit ratings.
The Company and its subsidiaries' debt indentures and credit agreements do not
contain any "ratings trigger" which would cause the acceleration of interest and
principal payments in the event of a ratings downgrade. However, a ratings
downgrade could increase our borrowing costs. See the "Risk Factors" section of
this Form 10-K.
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 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.
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, including pension, benefit and insurance costs; and delays in executing its
deleveraging plan. With respect to PEF, Moody's cited declining cash flow
coverage 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.
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 stated that it took this
action primarily due to declining cash flow coverage 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.
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
PEF. To date, 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%.
Due to the lower short-term rating issued by Moody's and S&P, PEF borrows under
its revolving credit facilities instead of issuing commercial paper due to the
difference in investor demand for lower-rated commercial paper. While the cost
of borrowing under its revolving credit facilities is higher than commercial
paper, it provides the same amount of liquidity.
32
OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS
The Company and PEF's off-balance sheet arrangements and contractual obligations
are described below. See Note 21 for information on the Company's and PEF's
contractual obligations at December 31, 2004.
Guarantees
At December 31, 2004, Progress Fuels had issued guarantees on behalf of third
parties with a maximum exposure of approximately $10 million. These guarantees
support synthetic fuel operations.
Market Risk and Derivatives
The Company and PEF, are exposed to various risks related to changes in market
conditions. The Company has a risk management committee that is chaired by the
Chief Financial Officer and includes senior executives from various business
groups. The risk management committee is responsible for administering risk
management policies and monitoring compliance with those policies by all
subsidiaries.
The Company manages its market risk in accordance with its established risk
management policies, which may include entering into various derivative
transactions.
The Company and PEF 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 16 and Item 7A, "Quantitative and Qualitative
Disclosures About Market Risk," for a discussion of market risk and derivatives.
New Accounting Standards
See Note 2 to the Financial Statements for a discussion of the anticipated
impact of new accounting standards.
33
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Florida Progress
Market risk represents the potential loss arising from adverse changes in market
rates and prices. Florida Progress is exposed to certain market risks, including
interest rate risk, marketable securities price risk and commodity price risk.
The Company manages its market risk in accordance with its established risk
management policies, which may include entering into various derivative
transactions.
These financial instruments are held for purposes other than trading. The risks
discussed below do not include the price risks associated with non-financial
instrument transactions and positions associated with Florida Progress'
operations, such as sales commitments and inventory.
Interest Rate Risk
Florida Progress is exposed to risk associated with changes in interest rates
with respect to its long-term debt. 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 long-term debt and the 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.
- -------------------------------------------------------------------------------------------------------------------
Fair Value
December 31,
December 31, 2004 2005 2006 2007 2008 2009 Thereafter Total 2004
- -------------------------------------------------------------------------------------------------------------------
(Dollars in millions)
Fixed rate long-term debt $ 49 $ 108 $ 124 $ 127 - $ 1,400 $ 1,808 $ 1,938
Average interest rate 6.63% 6.97% 6.79% 6.72% - 5.65% 5.91%
Variable rate long-
term debt - $ 55 - - - $ 241 $ 296 $ 296
Average interest rate - 2.95% - - - 1.67% 1.91%
FPC mandatorily redeemable
securities - - - - -
of Trust $ 309 $ 309 $ 312
Fixed rate - - - - - 7.10% 7.10%
Unsecured note with parent - - - - - $ 500 $ 500 $ 575
Average interest rate - - - - - 6.45% 6.45%
- -------------------------------------------------------------------------------------------------------------------
34
- -------------------------------------------------------------------------------------------------------------------
Fair Value
December 31,
December 31, 2003 2004 2005 2006 2007 2008 Thereafter Total 2003
- -------------------------------------------------------------------------------------------------------------------
(Dollars in millions)
Fixed rate long-term debt $ 68 $ 49 $ 109 $ 124 $ 127 $ 1,398 $ 1,875 $ 2,007
Average interest rate 6.61% 6.66% 6.96% 6.78% 6.72% 5.65% 5.93%
Variable rate long-
term debt - - - - - $ 241 $ 241 $ 241
Average interest rate - - - - - 1.04% 1.04%
FPC mandatorily redeemable
securities - - - - - $ 309 $ 309 $ 313
of Trust
Fixed rate - - - - - 7.10% 7.10%
Unsecured note with parent - - - - - $ 500 $ 500 $ 544
Average interest rate - - - - - 6.43% 6.43%
- -------------------------------------------------------------------------------------------------------------------
Marketable Securities Price Risk
Florida Progress, through PEF, is exposed to fluctuations in the return on
marketable securities with respect to its nuclear decommissioning trust funds.
PEF maintains trust funds, as required by the Nuclear Regulatory Commission, to
fund certain costs of decommissioning its nuclear plants. These funds are
primarily invested in stocks, bonds and cash equivalents, which are exposed to
price fluctuations in equity markets and to changes in interest rates. At
December 31, 2004 and 2003, the fair values of these funds were approximately
$463 million and $433 million, 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.
Commodity Price Risk
The Company and PEF 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. The Company's and PEF's exposure to these fluctuations is significantly
limited by the cost-based regulation of PEF. The FPSC allows PEF to recover
certain fuel and purchased power costs to the extent the FPSC 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. See Note 16 to the Financial Statements for additional information with
regard to the Company's and PEF's commodity contracts and use of derivative
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.
Progress Fuels uses natural gas hedging instruments to manage a portion of the
market risk associated with fluctuations in the future sales price of Progress
Fuels' natural gas. In addition, the Company may from time to time engage in
limited economic hedging activity using natural gas and electricity financial
instruments.
The Company performs sensitivity analysis to estimate its exposure to the market
risk of its commodity positions. The Company excludes the impact of derivative
commodity instruments which are recovered through cost-based regulation of PEF
from this analysis. 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 the Company's consolidated financial position, results
of operations or cash flows as of December 31, 2004.
35
PEF
The information required by this item is incorporated herein by reference to the
Florida Progress Quantitative and Qualitative Disclosures About Market Risk
insofar as it relates to PEF.
The following tables provide information at December 31, 2004 and 2003, about
PEF's interest rate risk sensitive instruments.
- -------------------------------------------------------------------------------------------------------------------
Fair Value
December 31, 2004 December 31,
2005 2006 2007 2008 2009 Thereafter Total 2004
- -------------------------------------------------------------------------------------------------------------------
(Dollars in millions)
Fixed rate long-term debt $ 48 $ 48 $ 89 $ 82 - $ 1,400 $ 1,667 $ 1,784
Average interest rate 6.72% 6.76% 6.80% 6.87% - 5.65% 5.83%
Variable rate long-
term debt - $ 55 - - - $ 241 $ 296 $ 296
Average interest rate - 2.95% - - - 1.67% 1.91%
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
Fair Value
December 31, 2003 December 31,
2004 2005 2006 2007 2008 Thereafter Total 2003
- -------------------------------------------------------------------------------------------------------------------
(Dollars in millions)
Fixed rate long-term debt $ 43 $ 48 $ 48 $ 89 $82 $ 1,399 $ 1,709 $ 1,820
Average interest rate 6.69% 6.72% 6.76% 6.80% 6.87% 5.65% 5.85%
Variable rate long-
term debt - - - - - $ 241 $ 241 $ 241
Average interest rate - - - - - 1.04% 1.04%
- -------------------------------------------------------------------------------------------------------------------
36
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The following consolidated financial statements, supplementary data and
consolidated financial statement schedules are included herein:
Page
Report of Independent Registered Public Accounting Firm 38
Consolidated Financial Statements - Florida Progress Corporation:
Consolidated Statements of Income for the Years Ended December 31, 2004, 2003 and 2002 39
Consolidated Balance Sheets at December 31, 2004 and 2003 40-41
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002 42
Consolidated Statements of Common Equity for the Years Ended December 31, 2004, 2003
and 2002 43
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2004,
2003 and 2002 43
Financial Statements - Florida Power Corporation d/b/a Progress Energy Florida, Inc.:
Statements of Income for the Years Ended December 31, 2004, 2003 and 2002 44
Balance Sheets at December 31, 2004 and 2003 45-46
Statements of Cash Flows for the Years Ended December 31, 2004, 2003
and 2002 47
Statements of Common Equity for the Years Ended December 31, 2004, 2003
and 2002 48
Statements of Comprehensive Income for the Years Ended December 31, 2004, 2003 and 2002 48
Notes to Financial Statements:
Note 1 - Organization and Summary of Significant Accounting Policies 49
Note 2 - Impact of New Accounting Standards 54
Note 3 - Hurricane-Related Costs 55
Note 4 - Divestitures 55
Note 5 - Acquisitions and Business Combinations 56
Note 6 - Property, Plant and Equipment 57
Note 7 - Current Assets 60
Note 8 - Regulatory Matters 61
Note 9 - Goodwill and Other Intangible Assets 64
Note 10 - Impairment of Long-Lived Assets and Investments 64
Note 11 - Equity 65
Note 12 - Debt and Credit Facilities 67
Note 13 - Fair Value of Financial Instruments 69
Note 14 - Income Taxes 69
Note 15 - Benefit Plans 72
Note 16 - Risk Management Activities and Derivatives Transactions 75
Note 17 - Related Party Transactions 77
Note 18 - Financial Information by Business Segment 78
Note 19 - Other Income and Other Expense 80
Note 20 - Environmental Matters 81
Note 21 - Commitments and Contingencies 84
Note 22 - Subsequent Events 91
Note 23 - Oil and Gas Producing Activities (Unaudited) 92
Note 24 - Quarterly Financial Data (Unaudited) 94
Report of Independent Registered Public Accounting Firm on Financial Statement Schedules 95
Financial Statement Schedules for the Years Ended December 31, 2004, 2003 and 2002:
Schedule II - Valuation and Qualifying Accounts - Florida Progress Corporation 96
Schedule II - Valuation and Qualifying Accounts - Florida Power Corporation
d/b/a Progress Energy Florida, Inc. 97
All other schedules have been omitted as not applicable or not required or
because the information required to be shown is included in the Financial
Statements or the accompanying Notes to the Financial Statements.
37
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TO THE BOARDS OF DIRECTORS OF FLORIDA PROGRESS CORPORATION AND FLORIDA POWER
CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.:
We have audited the accompanying consolidated balance sheets of Florida Progress
Corporation and its subsidiaries (Florida Progress) and the accompanying balance
sheets of Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF) as
of December 31, 2004 and 2003, and the related Florida Progress consolidated
statements of income, common equity, comprehensive income and cash flows and the
related PEF statements of income, common equity, 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 respective 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. Florida Progress and PEF are 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 Florida Progress' and PEF'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 financial statements present fairly, in all material
respects, the financial position of Florida Progress and of PEF, respectively,
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 1 and 6D to the financial statements, in 2003, Florida
Progress and PEF adopted Statement of Financial Accounting Standards No. 143.
/s/ Deloitte & Touche LLP
Raleigh, North Carolina
March 7, 2005
38
FLORIDA PROGRESS CORPORATION
CONSOLIDATED STATEMENTS of INCOME
- -----------------------------------------------------------------------------------------------------------
(in millions)
Years ended December 31 2004 2003 2002
- -----------------------------------------------------------------------------------------------------------
Operating Revenues
Utility $ 3,525 $ 3,152 $ 3,062
Diversified business 2,410 1,856 1,438
- -----------------------------------------------------------------------------------------------------------
Total Operating Revenues 5,935 5,008 4,500
- -----------------------------------------------------------------------------------------------------------
Operating Expenses
Utility
Fuel used in electric generation 1,175 870 834
Purchased power 567 566 515
Operation and maintenance 630 640 591
Depreciation and amortization 281 307 295
Taxes other than on income 254 241 228
Diversified business
Cost of sales 2,127 1,639 1,343
Depreciation and amortization 112 92 66
Impairment of goodwill and long-lived assets 8 15 281
(Gain)/loss on the sale of assets (54) 1 -
Other 134 132 94
- -----------------------------------------------------------------------------------------------------------
Total Operating Expenses 5,234 4,503 4,247
- -----------------------------------------------------------------------------------------------------------
Operating Income 701 505 253
- -----------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 5 2 7
Other, net 1 (8) (20)
- -----------------------------------------------------------------------------------------------------------
Total Other Income (Expense) 6 (6) (13)
- -----------------------------------------------------------------------------------------------------------
Interest Charges
Interest charges 183 169 186
Allowance for borrowed funds used during construction (3) (6) (3)
- -----------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 180 163 183
- -----------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Tax 527 336 57
and Minority Interest
Income Tax Expense (Benefit) 70 (110) (173)
- -----------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Minority 457 446 230
Interest
Minority Interest, net of tax (17) 3 -
- -----------------------------------------------------------------------------------------------------------
Income from Continuing Operations 474 443 230
Discontinued Operations, Net of Tax:
Net gain on disposal of discontinued operations,
(net of applicable income tax expenses of
$0, $2 and $3, respectively) - 4 5
- -----------------------------------------------------------------------------------------------------------
Net Income $ 474 $ 447 $ 235
- -----------------------------------------------------------------------------------------------------------
See Notes to Financial Statements.
39
FLORIDA PROGRESS CORPORATION
CONSOLIDATED BALANCE SHEETS (Continued)
- -------------------------------------------------------------------------------------------
(in millions)
December 31 2004 2003
- -------------------------------------------------------------------------------------------
Assets
Utility Plant
Utility plant in service $ 8,387 $ 8,155
Accumulated depreciation (2,978) (2,877)
- -------------------------------------------------------------------------------------------
Utility plant in service, net 5,409 5,278
Held for future use 8 8
Construction work in progress 420 292
Nuclear fuel, net of amortization 45 69
- -------------------------------------------------------------------------------------------
Total Utility Plant, Net 5,882 5,647
- -------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 29 27
Receivables 649 618
Receivables from affiliated companies 40 44
Deferred income taxes 68 60
Inventory 518 449
Deferred fuel cost 89 204
Assets held for sale - 75
Prepayments and other current assets 35 48
- -------------------------------------------------------------------------------------------
Total Current Assets 1,428 1,525
- -------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 524 126
Debt issuance costs 30 33
Nuclear decommissioning trust funds 463 433
Diversified business property, net 776 841
Miscellaneous other property and investments 95 90
Other assets and deferred debits 488 498
- -------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 2,376 2,021
- -------------------------------------------------------------------------------------------
Total Assets $ 9,686 $ 9,193
- -------------------------------------------------------------------------------------------
40
FLORIDA PROGRESS CORPORATION
CONSOLIDATED BALANCE SHEETS (Concluded)
- -----------------------------------------------------------------------------------------------
(in millions)
December 31 2004 2003
- -----------------------------------------------------------------------------------------------
Capitalization and Liabilities
Common Stock Equity
Common stock without par value $ 1,712 $ 1,699
Retained earnings 976 842
Accumulated other comprehensive loss (7) (17)
- -----------------------------------------------------------------------------------------------
Total Common Stock Equity 2,681 2,524
- -----------------------------------------------------------------------------------------------
Preferred Stock of Subsidiaries - Not Subject to Mandatory
Redemption 34 34
Minority Interest 32 30
Long-Term Debt, Affiliate, Net 809 809
Long-Term Debt, Net 2,052 2,045
- -----------------------------------------------------------------------------------------------
Total Capitalization 5,608 5,442
- -----------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 49 68
Accounts payable 445 413
Payables to affiliated companies 71 68
Notes payable to affiliated companies 431 636
Taxes accrued 81 33
Short-term obligations 293 -
Customer deposits 135 127
Other current liabilities 364 294
- -----------------------------------------------------------------------------------------------
Total Current Liabilities 1,869 1,639
- -----------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Noncurrent income tax liabilities 63 47
Accumulated deferred investment tax credits 36 42
Regulatory liabilities 1,362 1,315
Asset retirement obligations 358 339
Accrued pension and other benefits 229 218
Other liabilities and deferred credits 161 151
- -----------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 2,209 2,112
- -----------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes 20 and 21)
- -----------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 9,686 $ 9,193
- -----------------------------------------------------------------------------------------------
See Notes to Financial Statements.
41
FLORIDA PROGRESS CORPORATION
CONSOLIDATED STATEMENTS of CASH FLOWS
- ----------------------------------------------------------------------------------------------------------
(in millions)
Years ended December 31 2004 2003 2002
- ----------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 474 $ 447 $ 235
Adjustments to reconcile net income to net cash provided by operating
activities:
Net gain on disposal of discontinued operations - (4) (5)
Net (gain) loss on sale of operating assets (54) 1 -
Impairment of goodwill and long-lived assets 8 15 281
Depreciation and amortization 421 405 386
Deferred income taxes and investment tax credits, net (7) (134) (239)
Deferred fuel cost (credit) 37 (167) (22)
Cash provided/(used) by changes in operating assets and liabilities:
Receivables 59 (75) (34)
Receivables from affiliated companies 9 14 (15)
Inventory (87) 46 (40)
Prepayments and other current assets (118) (47) 3
Accounts payable (39) 101 53
Accounts payable to affiliated companies 4 (27) (29)
Other current liabilities 125 71 29
Changes in regulatory assets and liabilities (262) (22) 9
Other 41 18 54
- ----------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 611 642 666
- ----------------------------------------------------------------------------------------------------------
Investing Activities
Utility property additions (482) (526) (535)
Diversified business property additions (203) (424) (154)
Nuclear fuel additions - (51) -
Net contributions to nuclear decommissioning trust - - 12
Acquisition, net of cash acquired - - (17)
Proceeds from sale of subsidiaries and investments 336 100 35
Other (23) (15) 17
- ----------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (372) (916) (642)
- ----------------------------------------------------------------------------------------------------------
Financing Activities
Proceeds from issuance of long-term debt 56 935 236
Net increase (decrease) in short-term obligations 293 (258) 103
Retirement of long-term debt (68) (534) (350)
Net (decrease) increase in intercompany notes (214) 258 233
Equity contributions from parent 13 168 87
Dividends paid to parent (340) (301) (303)
Other 23 (1) (1)
- ----------------------------------------------------------------------------------------------------------
Net Cash (Used in) Provided by Financing Activities (237) 267 5
- ----------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 2 (7) 29
- ----------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Year 27 34 5
- ----------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 29 $ 27 $ 34
- ----------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized) $ 187 $ 174 $ 176
income taxes (net of refunds) $ 5 $ 32 $ 60
- ----------------------------------------------------------------------------------------------------------
See Notes to Financial Statements.
Noncash Activities
o In April 2002 Progress Fuels Corporation received an equity contribution
from Progress Energy, Inc., with which it acquired 100% of Westchester Gas
Company. In conjunction with the purchase, Progress Energy, Inc. issued
approximately $129 million in common stock (See Note 5C).
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).
42
FLORIDA PROGRESS CORPORATION
CONSOLIDATED STATEMENTS of COMMON EQUITY
- -------------------------------------------------------------------------------
(in millions)
Years ended December 31 2004 2003 2002
- -------------------------------------------------------------------------------
Beginning Balance $ 2,524 $ 2,211 $ 2,072
Net income 474 447 235
Other comprehensive income (loss) 10 (1) (13)
Equity contribution from parent, net 13 168 220
Dividend to parent (340) (301) (303)
- -------------------------------------------------------------------------------
Ending Balance $ 2,681 $ 2,524 $ 2,211
- -------------------------------------------------------------------------------
FLORIDA PROGRESS CORPORATION
CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME
- ------------------------------------------------------------------------------------------------------------
(in millions)
Years ended December 31 2004 2003 2002
- ------------------------------------------------------------------------------------------------------------
Net Income $ 474 $ 447 $ 235
Other Comprehensive Income
Changes in net unrealized losses on cash flow hedges (net of tax
benefit of $7, $7 and $4, respectively) (12) (13) (6)
Reclassification adjustment for amounts included in net income (net of
tax expense of ($9), ($6) and $0, respectively) 15 11 (1)
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
$1, ($3) and $3, respectively) (1) (3) (5)
Foreign currency translation and other 4 4 (1)
- ------------------------------------------------------------------------------------------------------------
Other Comprehensive Income (loss) $ 10 $ (1) $ (13)
- ------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 484 $ 446 $ 222
- ------------------------------------------------------------------------------------------------------------
See Notes to Financial Statements.
43
FLORIDA POWER CORPORATION
d/b/a PROGRESS ENERGY FLORIDA
STATEMENTS of INCOME
- ------------------------------------------------------------------------------------------------------------
(in millions)
Years ended December 31 2004 2003 2002
- ------------------------------------------------------------------------------------------------------------
Operating Revenues $ 3,525 $ 3,152 $ 3,062
- ------------------------------------------------------------------------------------------------------------
Operating Expenses
Fuel used in electric generation 1,175 870 834
Purchased power 567 566 515
Operation and maintenance 630 640 591
Depreciation and amortization 281 307 295
Taxes other than on income 254 241 228
- ------------------------------------------------------------------------------------------------------------
Total Operating Expenses 2,907 2,624 2,463
- ------------------------------------------------------------------------------------------------------------
Operating Income 618 528 599
- ------------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income - - 2
Other, net 5 7 (7)
- ------------------------------------------------------------------------------------------------------------
Total Other Income (Expense) 5 7 (5)
- ------------------------------------------------------------------------------------------------------------
Interest Charges
Interest charges 117 97 109
Allowance for borrowed funds used during construction (3) (6) (3)
- ------------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 114 91 106
- ------------------------------------------------------------------------------------------------------------
Income before Income Taxes 509 444 488
Income Tax Expense 174 147 163
- ------------------------------------------------------------------------------------------------------------
Net Income 335 297 325
Preferred Stock Dividend Requirement 2 2 2
- ------------------------------------------------------------------------------------------------------------
Earnings for Common Stock $ 333 $ 295 $ 323
- ------------------------------------------------------------------------------------------------------------
See Notes to Financial Statements.
44
FLORIDA POWER CORPORATION
d/b/a PROGRESS ENERGY FLORIDA
BALANCE SHEETS (continued)
- ---------------------------------------------------------------------------------------
(in millions)
December 31 2004 2003
- ---------------------------------------------------------------------------------------
Assets
Utility Plant
Utility plant in service $ 8,387 $ 8,155
Accumulated depreciation (2,978) (2,877)
- ---------------------------------------------------------------------------------------
Utility plant in service, net 5,409 5,278
Held for future use 8 8
Construction work in progress 420 292
Nuclear fuel, net of amortization 45 69
- ---------------------------------------------------------------------------------------
Total Utility Plant, Net 5,882 5,647
- ---------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 12 10
Receivables 266 250
Receivables from affiliated companies 16 7
Deferred income taxes 42 39
Inventory 279 268
Deferred fuel cost 89 204
Prepayments and other current assets 12 5
- ---------------------------------------------------------------------------------------
Total Current Assets 716 783
- ---------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 524 126
Debt issuance costs 21 25
Nuclear decommissioning trust funds 463 433
Miscellaneous other property and investments 46 40
Prepaid pension cost 234 220
Other assets and deferred debits 38 6
- ---------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 1,326 850
- ---------------------------------------------------------------------------------------
Total Assets $ 7,924 $ 7,280
- ---------------------------------------------------------------------------------------
See Notes to Financial Statements.
45
FLORIDA POWER CORPORATION
d/b/a PROGRESS ENERGY FLORIDA
BALANCE SHEETS (concluded)
- -------------------------------------------------------------------------------------------
(in millions)
December 31 2004 2003
- -------------------------------------------------------------------------------------------
Capitalization and Liabilities
Common Stock Equity
Common stock, without par value $ 1,081 $ 1,081
Retained earnings 1,240 1,062
Accumulated other comprehensive loss - (4)
- -------------------------------------------------------------------------------------------
Total Common Stock Equity 2,321 2,139
- -------------------------------------------------------------------------------------------
Preferred stock - not subject to mandatory redemption 34 34
Long-term debt, net 1,912 1,904
- -------------------------------------------------------------------------------------------
Total Capitalization 4,267 4,077
- -------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 48 43
Accounts payable 262 161
Payables to affiliated companies 80 75
Notes payable to affiliated companies 178 363
Short-term obligations 293 -
Customer deposits 135 127
Other current liabilities 161 154
- -------------------------------------------------------------------------------------------
Total Current Liabilities 1,157 923
- -------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Noncurrent income tax liabilities 489 363
Accumulated deferred investment tax credits 35 41
Regulatory liabilities 1,362 1,315
Asset retirement obligations 337 319
Accrued pension and other benefits 197 188
Other liabilities and deferred credits 80 54
- -------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 2,500 2,280
- -------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes 20 and 21)
- -------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 7,924 $ 7,280
- -------------------------------------------------------------------------------------------
See Notes to Financial Statements.
46
FLORIDA POWER CORPORATION
d/b/a PROGRESS ENERGY FLORIDA
STATEMENTS of CASH FLOWS
- ---------------------------------------------------------------------------------------------------------------------------
(in millions)
Years ended December 31 2004 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 335 $ 297 $ 325
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 310 314 321
Deferred income taxes and investment tax credits, net 110 (25) (38)
Deferred fuel cost (credit) 37 (167) (22)
Cash provided/(used) by changes in operating assets and liabilities:
Receivables (20) (7) 2
Receivables from affiliated companies (8) 36 (29)
Inventory (27) (33) (46)
Prepayments and other current assets (8) - (1)
Accounts payable 13 12 (3)
Payables to affiliated companies 14 (7) (116)
Other current liabilities 11 35 18
Regulatory assets and liabilities (262) (22) 9
Other 28 15 (1)
- ---------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 533 448 419
- ---------------------------------------------------------------------------------------------------------------------------
Investing Activities
Property additions (492) (526) (535)
Nuclear fuel additions - (51) -
Net contributions to nuclear decommissioning trust - - 12
Other (4) (1) 6
- ---------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (496) (578) (517)
- ---------------------------------------------------------------------------------------------------------------------------
Financing Activities
Proceeds from issuance of long-term debt 56 935 236
Net increase (decrease) in short-term obligations 293 (258) 103
Retirement of long-term debt (43) (476) (278)
Net increase (decrease) in intercompany notes (185) 126 358
Dividends paid to parent (155) (203) (303)
Dividends paid on preferred stock (2) (2) (2)
Other 1 2 -
- ---------------------------------------------------------------------------------------------------------------------------
Net Cash (Used in) Provided by Financing Activities (35) 124 114
- ---------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 2 (6) 16
- ---------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Year 10 16 -
- ---------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 12 $ 10 $ 16
- ---------------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized) $ 118 $ 104 $ 106
income taxes (net of refunds) $ 57 $ 177 $ 173
- ---------------------------------------------------------------------------------------------------------------------------
See Notes to Financial Statements.
47
FLORIDA POWER CORPORATION
d/b/a PROGRESS ENERGY FLORIDA
STATEMENTS of COMMON EQUITY
- -------------------------------------------------------------------------------------
(in millions)
Years ended December 31 2004 2003 2002
- -------------------------------------------------------------------------------------
Beginning Balance $ 2,139 $ 2,048 $ 2,031
Net income 335 297 325
Preferred stock dividends at stated rates (2) (2) (2)
Other comprehensive income (loss) 4 (1) (3)
Dividends paid to parent (155) (203) (303)
- -------------------------------------------------------------------------------------
Ending Balance $ 2,321 $ 2,139 $ 2,048
- -------------------------------------------------------------------------------------
FLORIDA POWER CORPORATION
d/b/a PROGRESS ENERGY FLORIDA
STATEMENTS of COMPREHENSIVE INCOME
- -----------------------------------------------------------------------------------------------------------------
(in millions)
Years ended December 31 2004 2003 2002
- -----------------------------------------------------------------------------------------------------------------
Net Income $ 335 $ 297 $ 325
Other Comprehensive Income
Reclassification of minimum pension liability to regulatory assets(net 4 - -
of tax expense of ($2))
Minimum pension liability adjustment (net of tax benefit of $0, $1 and
$1, respectively) - (1) (3)
- -----------------------------------------------------------------------------------------------------------------
Other Comprehensive Income (loss) $ 4 $ (1) $ (3)
- -----------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 339 $ 296 $ 322
- -----------------------------------------------------------------------------------------------------------------
See Notes to Financial Statements.
48
FLORIDA PROGRESS CORPORATION AND PROGRESS ENERGY FLORIDA
NOTES TO FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization
Florida Progress Corporation (the Company or Florida Progress) is a holding
company under the Public Utility Holding Company Act of 1935 (PUHCA). The
Company became subject to the regulations of PUHCA when it was acquired by
CP&L Energy, Inc. in November 2000. CP&L Energy, Inc. subsequently changed
its name to Progress Energy, Inc. (Progress Energy or the Parent). Florida
Progress' two primary subsidiaries are Florida Power Corporation (Progress
Energy Florida or PEF) and Progress Fuels Corporation (Progress Fuels).
Effective January 1, 2003, Florida Power Corporation began doing business
under the assumed name Progress Energy Florida, Inc. The legal name of the
entity has not changed. The current corporate and business unit structure
remains unchanged. Throughout the report, the terms utility and regulated
will be used to discuss items pertaining to Progress Energy Florida.
Diversified business and nonregulated will be used to discuss the
subsidiaries of Florida Progress excluding Progress Energy Florida.
B. Basis of Presentation
The financial statements are prepared in accordance with accounting
principles generally accepted in the United States of America (GAAP). The
financial statements include the financial results 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 Financial Statements of the Company and its subsidiaries include the
accounts of their 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 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 19). 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 $11
million and $12 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 NRC requirements, to fund certain costs of
decommissioning nuclear plants. The fair value of these trust funds was
$463 million and $433 million at December 31, 2004 and 2003, 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 $12 million and $13 million, respectively, of cost method
investments.
The results of operations of the Rail Services segment are reported one
month in arrears. During 2003, the Company ceased recording portions of the
Energy and Related Services 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.
49
C. Consolidation of Variable Interest Entities
Florida Progress and PEF consolidate all voting interest entities in which
they own a majority voting interest and all variable interest entities for
which they are the primary beneficiary in accordance with FASB
Interpretation No. 46R, "Consolidation of Variable Interest Entities - an
Interpretation of ARB No. 51" (FIN No. 46R). A subsidiary of Florida
Progress is the primary beneficiary of and consolidates Colona Synfuel
Limited Partnership LLLP (Colona), a synthetic fuel production facility
that qualifies for federal tax credits under Section 29 of the Internal
Revenue Code. As of December 31, 2004, Colona's total assets were $15
million. None of Florida Progress' consolidated assets are collateral for
Colona's obligations.
Florida Progress and PEF have interests in several variable interest
entities for which they are not the primary beneficiary. These arrangements
include investments in approximately five limited partnerships, limited
liability corporations and venture capital funds. The aggregate maximum
loss exposure at December 31, 2004, that Florida Progress could be required
to record in its consolidated income statement as a result of these
arrangements totals approximately $13 million. The aggregate maximum loss
exposure at December 31, 2004, that PEF could be required to record in its
income statement as a result of these arrangements totals approximately $6
million. The creditors of these variable interest entities do not have
recourse to the general credit of Florida Progress or PEF in excess of the
aggregate maximum loss exposure.
D. Significant Accounting Policies
USE OF ESTIMATES AND ASSUMPTIONS
In preparing 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 financial statements and amounts of revenues and expenses
reflected during the reporting period. Actual results could differ from
those estimates.
REVENUE RECOGNITION
PEF 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. Revenues from
sales of synthetic fuel and coal are recognized as products are shipped and
title passes. Revenues from the sale of oil and gas production are
recognized when title passes, net of royalties. Leasing activities are
accounted for in accordance with SFAS No. 13, "Accounting for Leases."
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. 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 regulators of PEF. Those clauses allow PEF
to recover fuel costs and portions of purchased power costs through
surcharges on customer rates. These deferred fuel costs are recognized in
revenue and fuel expenses as they are billable to customers.
EXCISE TAXES
PEF collects from customers certain excise taxes levied by the state or
local government upon the customer. PEF accounts for excise taxes on a
gross basis. For the years ended December 31, 2004, 2003 and 2002, gross
receipts tax and franchise taxes of approximately $151 million, $136
million and $132 million, respectively, are included in electric operating
revenues and taxes other than on income on the 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
Florida Progress and PEF 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
50
carry over of uncompensated tax benefits. Progress Energy tax benefits not
related to acquisition interest expense are allocated to profitable
subsidiaries, beginning in 2002, in accordance with a PUHCA order. Except
for the allocation of this Progress Energy tax benefit, income taxes are
provided as if Florida Progress and PEF filed separate returns.
Deferred income taxes have been provided for temporary differences. These
occur when there are differences between the book and tax bases 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 (See Note 14).
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," 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 for
Florida Progress Corporation and PEF if the fair value method had been
applied to all outstanding and unvested awards in each period:
---------------------------------------------------------------------------------------------------
(in millions)
Florida Progress 2004 2003 2002
---------------------------------------------------------------------------------------------------
Net income, as reported $ 474 $ 447 $ 235
Deduct: Total stock option expense determined under fair
value method for all awards, net of related tax effects 3 3 3
---------------------------------------------------------------------------------------------------
Pro forma net income $ 471 $ 444 $ 232
---------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------
(in millions)
Progress Energy Florida 2004 2003 2002
---------------------------------------------------------------------------------------------------
Net income, as reported $ 335 $ 297 $ 325
Deduct: Total stock option expense determined under fair
value method for all awards, net of related tax effects 2 2 2
---------------------------------------------------------------------------------------------------
Pro forma net income $ 333 $ 295 $ 323
---------------------------------------------------------------------------------------------------
UTILITY PLANT
Utility plant in service is stated at historical cost less accumulated
depreciation. PEF 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, disposal and 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.
51
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 PEF, as the
effects were offset by the establishment of a regulatory liability pursuant
to SFAS No. 71 , "Accounting for the Effects of Certain Types of
Regulation" (See Note 8A). The Florida Public Service Commission (FPSC)
issued an order to authorize deferral of all prospective effects related to
SFAS No. 143 as a regulatory asset or liability (See Note 8A).
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 its rate setting authority,
the 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 PEF's retail jurisdiction, provisions for
nuclear decommissioning costs are approved by the FPSC and are based on
site-specific estimates that include the costs for removal of all
radioactive and other structures at the site. In the wholesale
jurisdictions, the provisions for nuclear decommissioning costs are
approved by the Federal Energy Regulatory Commission (FERC).
CASH AND CASH EQUIVALENTS
The Company considers cash and cash equivalents to include 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 cost or market.
REGULATORY ASSETS AND LIABILITIES
PEF's regulated operations are subject to SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation," 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, PEF
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 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 loss is recognized on an asset, the fair
value becomes its new cost basis. The cost of renewals and betterments are
capitalized. The cost of repairs and maintenance is charged to expense as
incurred. For properties other than natural gas and oil properties,
depreciation is computed on a straight-line basis over the estimated useful
lives as indicated 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 costs to develop
proved reserves. Except for costs on 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
52
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 Regulation 210.4-10 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 PEF are amortized over the
applicable life using the straight-line method consistent with ratemaking
treatment (See Note 8A).
DERIVATIVES
The Company accounts for derivative instruments in accordance with SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities," 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 (See Note 16).
ENVIRONMENTAL
As discussed in Note 20, the Company accrues environmental remediation
liabilities when the criteria for SFAS No. 5, "Accounting for
Contingencies," 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
The Company reviews the recoverability of long-lived tangible and
intangible assets whenever indicators exist. Examples of these indicators
include current period losses, combined with a history of losses or a
projection of continuing losses, or a significant decrease in the market
price of a long-lived asset group. If an indicator exists, then the asset
group is tested for recoverability by comparing the carrying value to the
sum of undiscounted expected future cash flows directly attributable to the
asset group. If the asset group is not recoverable through undiscounted
cash flows, then an impairment loss is recognized for the difference
between the carrying value and the fair value of the asset group. The
accounting for impairment of long-lived assets is based on SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets."
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 (See
Note 10). The Company considers various factors, such as the investee's
cash position, earnings and revenue outlook, liquidity and management's
53
ability to raise capital in determining whether the decline is
other-than-temporary. If the Company determines that 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.
SUBSIDIARY STOCK TRANSACTIONS
Gains and losses realized as a result of common stock sales by the
Company's subsidiaries are recorded in the Company's 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. IMPACT OF 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), 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 benefits (OPEB) costs to
reflect prescription drug-related federal subsidies to be received under
the Medicare Act. The Company's and PEF's accumulated postretirement
benefit obligations as of January 1, 2004 were reduced by approximately $36
million and $35 million, respectively, by the impact of the Medicare Act,
and the Company's and PEF's 2004 net periodic cost was lower by
approximately $5 million due to the Medicare Act.
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" (SFAS No. 123) 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 and PEF recording no compensation
expense for stock options granted to employees (See Note 11B).
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, 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 Company and PEF
expect to record less than $1 million of pre-tax expense for stock options
in 2005.
54
PROPOSED FASB INTERPRETATION OF SFAS 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,"
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.
3. HURRICANE-RELATED COSTS
Hurricanes Charley, Frances, Ivan and Jeanne struck significant portions of
the PEF's service territory during the third quarter of 2004. As of
December 31, 2004, restoration costs of PEF's systems from
hurricane-related damage was estimated at $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. PEF 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 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., 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.
55
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 $3 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 $67 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 10). 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
Corporation (Progress Fuels), which is included in the Fuels segment. Net
proceeds were approximately $97 million and were used to reduce debt.
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. Inland Marine Transportation Divestiture
In July 2001, Progress Energy announced the disposition of the Inland
Marine Transportation segment of the Company, which was operated by MEMCO
Barge Line, Inc. Inland Marine provided transportation of coal,
agricultural and other dry-bulk commodities as well as fleet management
services. Progress Energy entered into a contract to sell MEMCO Barge Line,
Inc., to AEP Resources, Inc., a wholly-owned subsidiary of American
Electric Power. In November 2001, the Company completed the sale of the
Inland Marine Transportation segment. The net income of these operations is
reported in the Company's Consolidated Statements of Income as discontinued
operations.
The net gain on disposal of discontinued operations in the Company's
Consolidated Statements of Income for year ended December 31, 2002,
represents the after-tax gain from the resolution of approximately $5
million of contingencies in the purchase agreement of the Inland Marine
Transportation segment. In connection with the sale, the Company entered
into environmental indemnification provisions covering both unknown and
known sites. In 2003, the Company reduced the estimate for the
environmental accrual by $6 million, which is included as discontinued
operations in the Company's Consolidated Statements of Income (See Note
20).
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
56
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 Financial Statements since the transaction date. The minority
interest is included in other liabilities and deferred credits in the
Consolidated Balance Sheets.
The transaction was accounted for as a partial acquisition of EPIK through
the issuance of the stock of a consolidated subsidiary. The contributions
of PTC's and Caronet's net assets were recorded at their carrying values of
approximately $31 million. EPIK's contribution was recorded at its
estimated fair value of $22 million using the purchase method. 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 noncancellable lease payments made after certain leased properties are
vacated. The pro forma results of operations reflecting the acquisition
would not be materially different then the reported results of operation
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.
C. Westchester Acquisition
In April 2002, Progress Fuels, a subsidiary of Progress Energy, acquired
100% of Westchester Gas Company. During 2004 the name of the company was
changed to Winchester Energy Company, 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
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 in 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 Winchester have
been included in the Company's Financial Statements since the date of
acquisition. The pro forma results of operations reflecting the acquisition
would not be materially different than the reported results of operations
for the year ended December 31, 2002.
6. 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) $ 3,818 $ 3,826
Transmission plant (30-75 years) 1,070 1,012
Distribution plant (12-50 years) 3,047 2,894
General plant and other (8-75 years) 452 423
---------------------------------------------------------------
Utility plant in service $ 8,387 $ 8,155
---------------------------------------------------------------
57
Substantially all of the electric utility plant is pledged as collateral
for the first mortgage bonds of PEF (See Note 12).
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. 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 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 2.3% in 2004, 2003 and
2002. The depreciation provisions related to utility plant were $188
million, $172 million and $162 million in 2004, 2003 and 2002,
respectively. In addition to utility plant depreciation provisions,
depreciation and amortization expense also includes decommissioning cost
provisions, ARO accretion, cost of removal provisions (See Note 6D) and
regulatory approved expenses (See Note 8 and 20).
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 $34 million, $31 million and $32 million,
respectively. These amounts are charged to fuel used in electric generation
in the Statements of Income.
B. Diversified Business Property
The following is a summary of diversified business property at December 31,
with a range of depreciable lives for each:
-------------------------------------------------------------------------------
(in millions) 2004 2003
-------------------------------------------------------------------------------
Equipment (3 - 25 years) $ 418 $ 283
Land and mineral rights 95 80
Buildings and plants (5 - 40 years) 106 99
Oil and gas properties (units-of-production) (See Note 4A) 336 412
Telecommunications equipment (5 - 20 years) 80 63
Rail equipment (3 - 20 years) (See Note 4C) 35 131
Marine equipment (3 - 35 years) 87 83
Computers, office equipment and software (3 - 10 years) 36 33
Construction work in progress 18 18
Accumulated depreciation (435) (361)
-------------------------------------------------------------------------------
Diversified business property, net $ 776 $ 841
-------------------------------------------------------------------------------
Diversified business depreciation expense was $112 million, $92 million and
$66 million for the years ended December 31, 2004, 2003 and 2002,
respectively. The synthetic fuel facilities are being depreciated through
2007 when the Section 29 tax credits will expire. Oil and gas depreciation,
depletion, and amortization (DD&A) expense was $41 million, $33 million,
and $11 million for the years ended December 31, 2004, 2003, and 2002,
respectively. DD&A rates per Mcfe were $1.34, $1.31 and $0.92 for the
respective years. Oil and gas properties included costs of $55 million at
December 2004 which were excluded from capitalized costs being amortized.
This includes $48 million in costs related to acquisitions and capitalized
interest on probable reserves of $7 million.
C. Joint Ownership of Generating Facilities
PEF is entitled to shares of the generating capability and output of
Crystal River Unit No. 3 (CR3) equal to its ownership interest. PEF also
pays its ownership share of additional construction costs, fuel inventory
purchases and operating expenses. PEF's share of expenses for the jointly
owned facility is included in the appropriate expense category. The
co-owner of Intercession City Unit P-11 (P11) has exclusive rights to the
output of the unit during the months of June through September. PEF has
that right for the remainder of the year. PEF's ownership interest in CR3
and P11 is listed below with related information at December 31, ($ in
millions):
58
-----------------------------------------------------------------------------------------------
Company Construction
Ownership Plant Accumulated Work in
Facility Interest Investment Depreciation Progress
-----------------------------------------------------------------------------------------------
2004
-----------------------------------------------------------------------------------------------
Crystal River Unit No. 3 91.78% $ 889 $ 443 $9
Intercession City Unit P-11 66.67% 22 7 8
-----------------------------------------------------------------------------------------------
2003
-----------------------------------------------------------------------------------------------
Crystal River Unit No. 3 91.78% $ 875 $ 442 $ 46
Intercession City Unit P-11 66.67% 22 6 6
-----------------------------------------------------------------------------------------------
D. Asset Retirement Obligations
The asset retirement costs related to nuclear decommissioning of irradiated
plant, net of accumulated depreciation, totaled $36 million and $37 million
for regulated operations at December 31, 2004 and 2003, respectively. The
ongoing expense differences between SFAS No. 143 and regulatory cost
recovery are being deferred to the regulatory liability. Funds set aside in
PEF's nuclear decommissioning trust fund for the nuclear decommissioning
liability totaled $463 million at December 31, 2004 and $433 million at
December 31, 2003. Net unrealized gains on the nuclear decommissioning
trust fund were included in regulatory liabilities.
PEF'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 $77 million, $72 million and
$68 million in 2004, 2003 and 2002, respectively.
PEF recognizes removal, non-nuclear 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 $1,005
million, decommissioning costs for nonirradiated areas at nuclear
facilities of $61 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 $945 million, decommissioning
costs for nonirradiated areas at nuclear facilities of $62 million and
amounts previously collected for dismantlement of fossil generation plants
of $143 million.
PEF has identified but not recognized ARO liabilities related to electric
transmission and distribution and telecommunications assets as the result
of easements over property not owned by PEF. These easements are generally
perpetual and only require retirement action upon abandonment or cessation
of use of the property for the specified purpose. The ARO is not estimable
for such easements, as PEF intends to utilize these properties
indefinitely. In the event PEF 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 Corporation. The
related asset retirement costs, net of accumulated depreciation, totaled
$10 million and $5 million at December 31, 2004 and 2003, respectively.
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.
-------------------------------------------------------------------------------------------
(in millions) Regulated Nonregulated
-------------------------------------------------------------------------------------------
Asset retirement obligations as of January 1, 2003 $ 303 $ 10
Additions - 11
Accretion expense 16 1
Deductions - (2)
-------------------------------------------------------------------------------------------
Asset retirement obligations as of December 31, 2003 319 20
Additions - 6
Accretion expense 18 2
Deductions - (7)
-------------------------------------------------------------------------------------------
Asset retirement obligations as of December 31, 2004 $ 337 $ 21
-------------------------------------------------------------------------------------------
The cumulative effect of initial adoption of this statement related to
nonregulated operations was $2 million of pre-tax expense, which is
included in other, net on the Company's 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.
59
E. Insurance
PEF 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, PEF is
insured for $500 million at its nuclear plant, CR3. In addition to primary
coverage, NEIL also provides decontamination, premature decommissioning and
excess property insurance with a limit of $1.1 billion.
Insurance coverage against incremental costs of replacement power resulting
from prolonged accidental outages at nuclear generating units is also
provided through membership in NEIL. PEF is insured thereunder, following a
twelve-week deductible period, for 52 weeks in the amount of $4.5 million
per week at CR3. An additional 71 weeks of coverage is provided at 80% of
the above weekly amount. For the current policy period, PEF is subject to
retrospective premium assessments of up to approximately $6.5 million with
respect to the primary coverage, $5.2 million with respect to the
decontamination, decommissioning and excess property coverage, and $5.5
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 U.S. Nuclear
Regulatory Commission, PEF'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. PEF is responsible to the extent losses may exceed
limits of the coverage described above.
PEF is insured against public liability for a nuclear incident up to $10.76
billion per occurrence. Under the current provisions of the Price Anderson
Act, which limits liability for accidents at nuclear power plants, PEF, as
an owner of a nuclear unit, 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), PEF 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.
PEF self-insures its transmission and distribution lines against loss due
to storm damage and other natural disasters. Pursuant to a regulatory
order, PEF is accruing $6 million annually to a storm damage reserve and
may defer any losses in excess of the reserve (See Note 3 and 8A).
7. CURRENT ASSETS
RECEIVABLES
At December 31, receivables were comprised of the following:
---------------------------------------------------------------------------------------------
Florida Progress Progress Energy Florida
------------------------- -------------------------
(in millions) 2004 2003 2004 2003
---------------------------------------------------------------------------------------------
Trade accounts receivable $ 438 $ 410 $ 195 $ 187
Unbilled accounts receivable 93 135 66 59
Notes receivable 97 62 - -
Other receivables 12 15 7 6
Unbilled other receivables 28 11 - -
---------------------------------------------------------------------------------------------
Allowance for doubtful accounts (19) (15) (2) (2)
receivable
---------------------------------------------------------------------------------------------
Total receivables $ 649 $ 618 $ 266 $ 250
---------------------------------------------------------------------------------------------
60
Income tax receivables and interest income receivables are not included in
this classification. These amounts are in prepayments and other current
assets on the Consolidated Balance Sheets.
INVENTORY
At December 31, inventory was comprised of the following:
-------------------------------------------------------------------------------------
Florida Progress Progress Energy Florida
----------------------------- -------------------------
(in millions) 2004 2003 2004 2003
-------------------------------------------------------------------------------------
Fuel for production $ 103 $ 90 $ 103 $ 90
Inventory for sale 228 167 - -
Materials and supplies 187 192 176 178
-------------------------------------------------------------------------------------
Total inventory $ 518 $ 449 $ 279 $ 268
-------------------------------------------------------------------------------------
8. REGULATORY MATTERS
A. Regulatory Assets and Liabilities
As a regulated entity, PEF is subject to the provisions of SFAS No. 71.
Accordingly, PEF records certain assets and liabilities resulting from the
effects of the ratemaking process, which would not be recorded under GAAP
for nonregulated entities. The utility'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 PEF'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.
PEF has regulatory assets (liabilities) at December 31 as follows:
-------------------------------------------------------------------------------------------
(in millions) 2004 2003
-------------------------------------------------------------------------------------------
Deferred fuel cost - current (Note 8B) $ 89 $ 204
-------------------------------------------------------------------------------------------
Deferred fuel cost - long-term (Note 8B) 79 -
Storm deferral (Note 3) 291 -
Income taxes recoverable through future rates (Note 14) 49 42
Loss on reacquired debt (Note 1D) 31 33
Other 74 51
-------------------------------------------------------------------------------------------
Total long-term regulatory assets 524 126
-------------------------------------------------------------------------------------------
Deferred energy conservation cost - current (8) (7)
-------------------------------------------------------------------------------------------
Non-ARO cost of removal (Note 6D) (1,210) (1,150)
Deferred impact of ARO (Note 1D) (26) (8)
Net nuclear decommissioning trust unrealized gains (Note 6D) (99) (105)
Storm reserve (Note 3) - (41)
Other (27) (11)
-------------------------------------------------------------------------------------------
Total long-term regulatory liabilities (1,362) (1,315)
-------------------------------------------------------------------------------------------
Net regulatory assets (liabilities) $ (757) $ (992)
-------------------------------------------------------------------------------------------
Except for portions of deferred fuel and deferred storm costs, all assets
earn a return or the cash has not yet been expended, in which case the
assets are offset by liabilities that do not incur a carrying cost. The
utility expects to fully recover these assets and refund the liabilities
through customer rates under current regulatory practice.
B. Retail Rate Matters
On November 9, 2004, the FPSC approved PEF's under-recovered 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 cost has
been classified as a long-term asset. As of December 31, 2004, PEF was
under-recovered 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
61
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 $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 under runs.
Any costs that exceed this estimate will not be recoverable absent
extraordinary circumstances as found by the FPSC in subsequent proceedings.
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.
62
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.
C. 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 GridFlorida proceedings currently ongoing before the FERC.
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.
PEF has $4 million invested in GridFlorida related to startup costs at
December 31, 2004. PEF expects to recover these startup costs in
conjunction with the GridFlorida original structure or in conjunction with
any alternate combined transmission structure that emerges.
63
D. Energy Delivery Capitalization Practice
PEF 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, PEF
should revise the way that it estimates the amount of capital costs
associated with such work. PEF 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 PEF's costs will be capitalized on a
going forward basis. PEF estimates that the impact in 2005 will be that
approximately $30 million of costs that would have been capitalized under
the previous policies will be expensed. Pursuant to SFAS No. 71, PEF 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. The Company has also requested a method change from the IRS.
9. GOODWILL AND OTHER INTANGIBLE ASSETS
The Company accounts for goodwill and other intangible assets in accordance
with SFAS No. 142, "Goodwill and Other Intangible Assets." The changes in
the carrying amount of goodwill, by reportable segment, are as follows:
---------------------------------------------------------------------------
Energy and
(in millions) Related Services Other Total
---------------------------------------------------------------------------
Balance as of January 1, 2003 $ 11 $ - $ 11
Divestitures (1) - (1)
Acquisition - 7 7
---------------------------------------------------------------------------
Balance as of December 31, 2003 $ 10 $ 7 $ 17
Impairment loss (8) - (8)
Purchase accounting adjustment - (7) (7)
---------------------------------------------------------------------------
Balance as of December 31, 2004 $ 2 $ - $ 2
---------------------------------------------------------------------------
In connection with a review of strategic alternatives regarding the Fuels'
coal mining business, the Company performed an impairment test of the
goodwill of the coal mining business in the fourth quarter of 2004. As a
result of the impairment test, the Company recorded an impairment loss of
$8 million to write off all of the goodwill of the coal mining business.
The Company used a probability-weighted discounted cash flow analysis to
perform the assessment.
In December 2003, $7 million in goodwill was acquired 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 5, 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 Company has $10 million and $9 million of net amortizable intangible
assets at December 31, 2004 and 2003, respectively. The Company's
intangibles are primarily acquired customer contracts that are amortized
over their respective lives. Amortization expense recorded on intangible
assets for the years ended December 31, 2004 and 2003, and estimated annual
amortization expense for intangible assets for 2004 through 2008 are not
material to the results of operations. PEF has no intangible assets at
December 31, 2004 or 2003.
10. IMPAIRMENT OF LONG-LIVED ASSETS AND INVESTMENTS
Effective January 1, 2002, the Company adopted SFAS No. 144, which provides
guidance for the accounting and reporting of impairment or disposal of
long-lived assets. The statement supersedes SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of." In 2003 and 2002, the Company recorded impairments and other
charges of approximately $15 million and $300 million, respectively.
Due to the reduction in coal production at the Kentucky May Coal Mine, the
Company evaluated its 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 $15 million on a pre-tax basis during the
fourth quarter of 2003.
64
The 2002 amount includes an estimated impairment of assets held for sale of
$67 million related to Railcar Ltd., (See Note 4C). In 2002, the Company
also initiated an independent valuation study to assess the recoverability
of the long-lived assets of PTC. Based on this assessment, the Company
recorded asset impairments of $215 million on a pre-tax basis and other
charges of $18 million on a pre-tax basis 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.
11. EQUITY
A. Common and Preferred Stock
Common stock at December 31, 2004 and 2003 consisted of the following
------------------------------------------------------------------------------------------
(in millions except share data) 2004 2003
------------------------------------------------------------------------------------------
Florida Progress
Common stock without par value, 250,000,000 shares authorized; $ 1,712 $ 1,699
98,616,658 shares outstanding in 2004 and 2003
Progress Energy Florida
Common stock without par value, 60,000,000 shares authorized; 100 $ 1,081 $ 1,081
shares outstanding in 2004 and 2003
------------------------------------------------------------------------------------------
From time-to-time the Company and its subsidiaries may receive equity
contributions from and pay dividends to Progress Energy. The Company
received equity contributions from Progress Energy of $13 million, $168
million and $220 million during 2004, 2003 and 2002, respectively. The
Company paid dividends to Progress Energy of $340 million, $301 million and
$303 million during 2004, 2003 and 2002, respectively.
The authorized capital stock of the Company includes 10 million shares of
preferred stock, without par value, including 2 million shares designated
as Series A Junior Participating Preferred Stock. No shares of the
Company's preferred stock are issued or outstanding.
The authorized capital stock of PEF includes three classes of preferred
stock: 4 million shares of Cumulative Preferred Stock, $100 par value; 5
million shares of Cumulative Preferred Stock, without par value; and 1
million shares of Preference Stock, $100 par value. No shares of PEF's
Cumulative Preferred Stock, without par value, or Preference Stock are
issued or outstanding. All Cumulative Preferred Stock series are without
sinking funds and are 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):
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
Total Preferred Stock of PEF $ 34
-------------------------------------------------------------------------
B. Stock-Based Compensation
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. Effective January 1, 2002, Florida
Progress 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
65
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.
Florida Progress' 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 in
shares in the following year; while costs for the matching component are
typically met with shares in the same year incurred. Florida Progress'
matching and incentive cost which was and will be met with shares released
from the suspense account totaled approximately $5 million, $4 million and
$2 million for the years ended December 31, 2004, 2003 and 2002,
respectively. Matching and incentive costs totaled approximately $7
million, $11 million and $10 million for the years ended December 31, 2004,
2003 and 2002, respectively. PEF's matching and incentive cost which was
and will be met with shares released from the suspense account totaled
approximately $5 million, $4 million and $2 million for the year ended
December 31, 2004, 2003 and 2002, respectively. Matching and incentive
costs totaled approximately $7 million, $10 million and $9 million for the
years ended December 31, 2004, 2003 and 2002, respectively.
STOCK OPTION AGREEMENTS
Pursuant to the Progress Energy's 1997 Equity Incentive Plan and 2002
Equity Incentive Plans 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 approximately 28 thousand, 3.0 million and 2.9
million common stock options were granted, respectively. Of these amounts,
approximately 1.0 million and 0.8 million options, respectively, were
granted to officers and eligible employees of Florida Progress and PEF in
2003 and approximately 0.5 million and 0.4 million options, respectively,
were granted in 2002. No stock options were granted to officers and
employees of Florida Progress and PEF in 2004. The Company expects to begin
expensing stock options on July 1, 2005 by adopting new FASB guidance on
accounting for stock-based compensation that was issued (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 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.
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. The Company
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 Progress Energy. 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.
66
The total amount expensed by the Company for other stock-based compensation
under these plans was $2 million, $9 million and $5 million in 2004, 2003
and 2002, respectively. The total amount expensed by PEF for other
stock-based compensation under these plans was $2 million, $7 million and
$4 million in 2004, 2003 and 2002, respectively.
C. Accumulated Other Comprehensive Loss
Components of accumulated other comprehensive loss for Florida Progress and
PEF at December 31, 2004 and 2003 are as follows:
----------------------------------------------------------------------------------------------------
Florida Progress Progress Energy Florida
---------------------- -------------------------
(in millions) 2004 2003 2004 2003
----------------------------------------------------------------------------------------------------
Loss on cash flow hedges $ (5) $ (9) $ - $ -
Minimum pension liability adjustments (7) (9) - (4)
Foreign currency translation and other 5 1 - -
----------------------------------------------------------------------------------------------------
Total accumulated other comprehensive loss $ (7) $ (17) $ - $ (4)
----------------------------------------------------------------------------------------------------
12. DEBT AND CREDIT FACILITIES
A. Debt and Credit
At December 31, the Company's (including PEF's) long-term debt consisted of
the following (maturities and weighted-average interest rates at December
31, 2004):
------------------------------------------------------------------------------------------
(in millions) Rate 2004 2003
------------------------------------------------------------------------------------------
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 17)
Debt to affiliated trust, maturing 2039 7.10% 309 309
------------------------------------------------------------------------------------------
Progress Capital Holdings, Inc.
Medium-term notes, maturing 2006-2008 6.84% 140 165
Unsecured note with parent, maturing 2011 6.45% 500 500
Miscellaneous notes 1 1
------------------------------------------------------------------------------------------
641 666
------------------------------------------------------------------------------------------
Current portion of long-term debt (49) (68)
------------------------------------------------------------------------------------------
Total long-term debt $ 2,861 $ 2,854
------------------------------------------------------------------------------------------
In February 2005, PEF used proceeds from money pool borrowings to pay off
$55 million of RCA loans and in January 2005, PEF used proceeds from the
issuance of commercial paper to pay off $170 million of RCA loans.
At December 31, 2004, PEF had committed lines of credit which are used to
support its commercial paper borrowings. The 3-year credit facility is
included in long-term debt. The 364-day credit facility is included in
short-term obligations and had $170 million of outstanding borrowings at
December 31, 2004, at an interest rate of 3.13%. No amount was outstanding
under the committed lines of credit at December 31, 2003. PEF is required
to pay minimal annual commitment fees to maintain its credit facilities.
The following table summarizes PEF's credit facilities:
----------------------------------------------------------------------------
(in millions)
Description Total Outstanding Available
----------------------------------------------------------------------------
364-Day (expiring 3/29/05) $ 200 $ 170 $ 30
3-Year (expiring 4/01/06) 200 55 145
Less: amounts reserved(a) (123)
----------------------------------------------------------------------------
Total credit facilities $ 400 $ 225 $ 52
----------------------------------------------------------------------------
(a) To the extent amounts are reserved for commercial paper outstanding,
they are not available for additional borrowings.
67
At December 31, 2004, PEF had $123 million of outstanding commercial paper
and other short-term debt classified as short-term obligations. The
weighted-average interest rate of such short-term obligations at December
31, 2004 was 2.80%. At December 31, 2003, PEF had no outstanding commercial
paper and other short-term debt classified as short-term obligations.
The combined aggregate maturities of Florida Progress long-term debt for
2005 through 2008 are approximately, in millions, $49, $163, $124 and $127,
respectively. PEF's aggregate maturities of long-term debt for 2005 through
2008 are approximately, in millions, $48, $103, $89 and $82, respectively.
There are no long-term debt maturities in 2009 for PEF or Florida Progress.
B. Covenants and Default Provisions
FINANCIAL COVENANTS
PEF's credit line contains various terms and conditions that could affect
PEF's ability to borrow under these facilities. These include a maximum
debt to total capital ratio, an interest test, a material adverse change
clause and a cross-default provision. PEF's credit line requires a maximum
total debt to total capital ratio of 65.0%. Indebtedness as defined by the
bank agreement includes certain letters of credit and guarantees which are
not recorded on the Balance Sheets. At December 31, 2004, PEF's total debt
to total capital ratio was 50.8%.
PEF's 364-day and 3-year credit facility have a financial covenant for
interest coverage. The covenant requires PEF's EBITDA to interest expense
to be at least 3 to 1. For the year ended December 31, 2004, this ratio was
7.93 to 1.
MATERIAL ADVERSE CHANGE CLAUSE
The credit facility of PEF includes 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.
CROSS-DEFAULT PROVISIONS
PEF's credit lines include cross-default provisions for defaults of
indebtedness in excess of $10 million. PEF's cross-default provisions only
apply to defaults of indebtedness by PEF and not to other affiliates of
PEF. The credit lines of Progress Energy include a similar provision.
Progress Energy's cross-default provisions only apply to defaults of
indebtedness by Progress Energy and its significant subsidiaries, which
includes PEF, Florida Progress, Progress Fuels and Progress Capital.
In the event that either of these cross-default provisions were triggered,
the lenders could accelerate payment of any outstanding debt. Any such
acceleration would cause a MAC in the respective company's financial
condition. Certain agreements underlying the Company's indebtedness also
limit the Company's ability to incur additional liens or engage in certain
types of sale and leaseback transactions.
OTHER RESTRICTIONS
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
were restricted.
In addition, PEF's Articles of Incorporation provide that no cash dividends
or distributions on common stock shall be paid, if the aggregate amount
thereof since April 30, 1944, including the amount then proposed to be
expended, plus all other charges to retained earnings since April 30, 1944,
exceed (a) all credits to retained earnings since April 30, 1944, plus (b)
all amounts credited to capital surplus after April 30, 1944, arising from
the donation to PEF of cash or securities or transfers amounts from
retained earnings to capital surplus. At December 31, 2004, none of PEF's
retained earnings was restricted.
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.
68
C. Secured Obligations
PEF's first mortgage bonds are secured by its mortgage indenture. PEF's
mortgage constitutes a first lien on substantially all of its fixed
properties, subject to certain permitted encumbrances and exceptions. The
PEF mortgage also constitutes a lien on subsequently acquired property. At
December 31, 2004, PEF had approximately $1.571 billion in aggregate
principal amount of first mortgage bonds outstanding including those
related to pollution control obligations. The PEF mortgage allows the
issuance of additional mortgage bonds upon the satisfaction of certain
conditions.
D. Guarantees of Subsidiary Debt
See Note 17 on related party transactions for a discussion of obligations
guaranteed or secured by affiliates.
E. Hedging Activities
PEF 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 16.
13. FAIR VALUE OF FINANCIAL 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 of approximately $73
million and $66 million, respectively, included in miscellaneous other
property and investments. At PEF, these investments had carrying amounts of
$34 million and $33 million at December 31, 2004 and 2003, respectively.
The carrying amount of these investments approximates fair value due to the
short maturity. The carrying amount of the Company's long-term debt,
including current maturities, was $2,910 million and $2,922 million 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 $3,121 million and $3,105 million at December 31, 2004 and 2003,
respectively. The carrying amount of PEF's long-term debt, including
current maturities, was $1,960 million and $1,947 million 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
$2,080 million and $2,061 million 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.
14. 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 is different from
the recovery of taxes by 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 utility pursuant
to rate orders.
69
Accumulated deferred income tax assets (liabilities) at December 31 are (in
millions):
---------------------------------------------------------------------------------------------
Florida Progress 2004 2003
---------------------------------------------------------------------------------------------
Current portion of deferred income tax asset
Unbilled revenue $ 35 $ 18
Other 33 42
---------------------------------------------------------------------------------------------
Net current portion of deferred income tax asset $ 68 $ 60
---------------------------------------------------------------------------------------------
Noncurrent deferred income tax asset (liability):
Accumulated depreciation and property cost differences $ (400) $ (359)
Investments 49 (17)
Supplemental executive retirement plans 19 19
Other post-employment benefits (OPEB) 65 64
Other pension plans (89) (85)
Goodwill 34 46
Deferred storm costs (113) -
Storm damage reserve - 16
Premium on reacquired debt (12) (13)
State NOL carry forward 23 28
Federal and state income tax credit carry forward 494 437
Miscellaneous other temporary differences, net 57 25
Valuation allowance (27) (29)
---------------------------------------------------------------------------------------------
Total noncurrent deferred income tax asset 100 132
---------------------------------------------------------------------------------------------
Less amount included in other assets and deferred debits 161 172
---------------------------------------------------------------------------------------------
Net noncurrent deferred income tax liability $ (61) $ (40)
---------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------
Progress Energy Florida 2004 2003
---------------------------------------------------------------------------------------------
Current portion of deferred income tax asset
Unbilled revenue $ 35 $ 18
Other 7 21
---------------------------------------------------------------------------------------------
Net current portion of deferred income tax asset $ 42 $ 39
---------------------------------------------------------------------------------------------
Noncurrent deferred income tax asset (liability):
Accumulated depreciation and property cost differences $ (389) $ (368)
Other post-employment benefits (OPEB) 63 62
Other pension plans (89) (85)
Deferred storm costs (113) -
Storm damage reserve - 16
Miscellaneous other temporary differences, net 39 17
---------------------------------------------------------------------------------------------
Total noncurrent deferred income tax liability $ (489) $ (358)
---------------------------------------------------------------------------------------------
The Company's total deferred income tax liabilities were $997 million and
$824 million at December 31, 2004 and 2003, respectively. Total deferred
income tax assets were $1,165 million and $1,016 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 $2 and $7
million, respectively, related to contingent tax liabilities on which the
Company accrues interest that would be payable with the related tax amount
in future years.
PEF's total deferred income tax liabilities were $620 million and $476
million at December 31, 2004 and 2003, respectively. Total deferred income
tax assets were $173 million and $157 million at December 31, 2004 and
2003, respectively. Total noncurrent income tax liabilities on the Balance
Sheets at December 31, 2004 and 2003 include none and $5 million,
respectively, related to contingent tax liabilities on which the company
accrues interest that would be payable with the related tax amount in
future years.
70
The Company's federal income tax credit carry forward at December 31, 2004
consists of $484 million of alternative minimum tax credit with an
indefinite carry forward period and $9 million of general business credit
with a carry forward period that will begin to expire in 2022. The
Company's alternative minimum tax credit carry forward at December 31, 2004
includes $3 million that would be limited if a change in ownership were to
occur with respect to certain indirect wholly owned subsidiary companies.
As of December 31, 2004, the Company had a state net operating loss carry
forward of $2 million that will begin to expire in 2007.
The Company decreased its valuation allowance during 2004 by $2 million and
established additional valuation allowances of $3 million and $5 million
during 2003 and 2002, respectively, due to the uncertainty of realizing
certain future state tax benefits. The Company decreased its 2004
beginning-of-the-year valuation allowance by $8 million for a change in
circumstances related to net operating losses. 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.
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
current Taxes Accrued on the Consolidated Balance Sheets. At December 31,
2004 and 2003, PEF had recorded $7 million of tax contingency reserves,
excluding accrued interest and penalties, which are included in other
current liabilities on the 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 21E).
Reconciliations of the Company's effective income tax rate to the statutory
federal income tax rate are:
- ------------------------------------------------------------------------------------------
Florida Progress 2004 2003 2002
- ------------------------------------------------------------------------------------------
Effective income tax rate 13.3% (32.6)% (304.8)%
State income taxes, net of federal benefit (6.1) (2.5) (10.3)
AFUDC amortization (0.5) (0.7) (4.1)
Federal tax credits 24.4 63.5 311.3
Investment tax credit amortization 1.2 1.8 11.3
Progress Energy tax allocation benefit 2.7 3.8 35.2
Other differences, net -- 1.7 (3.6)
- ------------------------------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
- ------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------
Progress Energy Florida 2004 2003 2002
- ------------------------------------------------------------------------------------------
Effective income tax rate 34.2% 33.1% 33.6%
State income taxes, net of federal benefit (3.5) (3.5) (3.4)
Investment tax credit amortization 1.2 1.4 1.3
Progress Energy tax allocation benefit 2.5 2.7 3.8
Other differences, net 0.6 1.3 (0.3)
- ------------------------------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
- ------------------------------------------------------------------------------------------
71
Income tax expense (benefit) applicable to continuing operations is
comprised of (in millions):
- ---------------------------------------------------------------------------------------
Florida Progress 2004 2003 2002
- ---------------------------------------------------------------------------------------
Current - federal $ 46 $ 6 $ 43
State 31 18 23
Deferred - federal (16) (123) (220)
State 15 (5) (13)
Investment tax credit (6) (6) (6)
- ---------------------------------------------------------------------------------------
Total income tax expense (benefit) $ 70 $ (110) $ (173)
- ---------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------
Progress Energy Florida 2004 2003 2002
- ---------------------------------------------------------------------------------------
Current - federal $ 55 $ 145 $ 172
State 9 27 29
Deferred - federal 98 (16) (29)
State 18 (3) (3)
Investment tax credit (6) (6) (6)
- ---------------------------------------------------------------------------------------
Total income tax expense (benefit) $ 174 $ 147 $ 163
- ---------------------------------------------------------------------------------------
Florida Progress and each of its wholly-owned subsidiaries have entered
into a Tax Agreement with Progress Energy (See Note 1D). The Company's
intercompany tax payable was approximately $72 million and $17 million at
December 31, 2004 and 2003, respectively. Progress Energy Florida's
intercompany tax payable was approximately $21 million and $16 million at
December 31, 2004 and 2003, respectively.
Florida Progress, through its subsidiaries, is a majority owner in two
entities and a minority owner in four entities 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 21E).
15. BENEFIT PLANS
The Company and some of its subsidiaries (including PEF) have a
non-contributory defined benefit retirement (pension) plan for
substantially all full-time employees. The Company also has supplementary
defined benefit pension plans that provide benefits to higher-level
employees. In addition to pension benefits, the Company and some of its
subsidiaries (including PEF) 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.
The components of the 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 $ 22 $ 21 $ 19 $ 4 $ 5 $ 5
Interest cost 48 46 44 14 16 15
Expected return on plan assets (77) (62) (76) (1) (1) (1)
Net amortization 1 3 (7) 5 5 4
-----------------------------------------------------------------------------------------------------------
Net cost/(benefit) recognized by $ (6) $ 8 $ (20) $ 22 $ 25 $ 23
Florida Progress
-----------------------------------------------------------------------------------------------------------
Net cost/(benefit) recognized by PEF $ (8) $ 5 $ (22) $ 21 $ 24 $ 22
-----------------------------------------------------------------------------------------------------------
The net periodic cost for other postretirement benefits decreased during
2004 due to the implementation of FASB Staff Position 106-2 (See Note 2).
72
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. The Company uses fair value for the
market-related value of assets.
Reconciliations of the changes in the plans' benefit obligations and the
plans' funded status are:
--------------------------------------------------------------------------------------------------------------
Pension Benefits Other Postretirement Benefits
--------------------------- -----------------------------
(in millions) 2004 2003 2004 2003
--------------------------------------------------------------------------------------------------------------
Obligation at January 1 $ 780 $ 714 $ 224 $ 236
Service cost 22 21 4 5
Interest cost 48 46 14 15
Plan amendments 2 - - -
Benefit payments (42) (41) (17) (15)
Actuarial loss (gain) 39 40 15 (17)
--------------------------------------------------------------------------------------------------------------
Obligation at December 31 849 780 240 224
Fair value of plan assets at December 31 919 849 20 18
--------------------------------------------------------------------------------------------------------------
Funded status 70 69 (220) (206)
Unrecognized transition obligation - - 28 31
Unrecognized prior service cost (benefit) (14) (18) 6 7
Unrecognized net actuarial loss 117 111 30 15
Minimum pension liability adjustment (14) (11) - -
--------------------------------------------------------------------------------------------------------------
Prepaid (accrued) cost at December 31, net - $ 159 $ 151 $ (156) $ (153)
Florida Progress
--------------------------------------------------------------------------------------------------------------
Prepaid (accrued) cost at December 31, net - PEF $ 192 $ 183 $ (150) $ (148)
--------------------------------------------------------------------------------------------------------------
The 2003 OPEB obligation information above has been restated due to the
implementation of FASB Staff Position 106-2 (See Note 2).
The Florida Progress net prepaid pension cost of $159 million and $151
million at December 31, 2004 and 2003, respectively, is included in the
Company's Consolidated Balance Sheets as prepaid pension cost of $238
million and $223 million, respectively, which is included in other assets
and deferred debits, and accrued benefit cost of $79 million and $72
million, respectively, which is included in accrued pension and other
benefits. The PEF net prepaid pension cost of $192 million and $183 million
at December 31, 2004 and 2003, respectively, is included in the Balance
Sheets as prepaid pension cost of $234 million and $220 million,
respectively, and accrued benefit cost of $42 million and $37 million,
respectively, which is included in accrued pension and other benefits. For
Florida Progress, the defined benefit pension plans with accumulated
benefit obligations in excess of plan assets had projected benefit
obligations totaling $80 million and $74 million at December 31, 2004 and
2003, respectively. Those plans had accumulated benefit obligations
totaling $77 million and $73 million, respectively, and no plan assets. For
PEF, the defined benefit pension plans with accumulated benefit obligations
in excess of plan assets had projected benefit obligations totaling $41
million and $38 million at December 31, 2004 and 2003, respectively. Those
plans had accumulated benefit obligations totaling $39 million and $37
million, respectively, and no plan assets. For Florida Progress, the total
accumulated benefit obligation for pension plans was $797 million and $736
million at December 31, 2004 and 2003, respectively. For PEF, the total
accumulated benefit obligation for pension plans was $718 million and $659
million at December 31, 2004 and 2003, respectively. Accrued other
postretirement benefit cost is included in accrued pension and other
benefits in the respective Balance Sheets of Florida Progress and PEF.
Florida Progress and PEF recorded a minimum pension liability adjustment of
$14 million and $7 million, respectively, at December 31, 2004, with a
corresponding charge of $7 million to a regulatory asset and, for Florida
Progress, a pre-tax charge of $7 million to accumulate other comprehensive
loss, a component of common stock equity. Florida Progress and PEF recorded
a minimum pension liability adjustment of $11 million and $6 million,
respectively, at December 31, 2003, with a corresponding pre-tax charge to
accumulated other comprehensive loss, a component of common stock equity.
73
Reconciliations of the fair value of plan assets are:
-------------------------------------------------------------------------------------------------
Pension Benefits Other Postretirement Benefits
---------------------- ------------------------------
(in millions) 2004 2003 2004 2003
-------------------------------------------------------------------------------------------------
Fair value of plan assets January 1 $ 849 $ 687 $ 18 $ 16
Actual return on plan assets 108 199 1 1
Benefit payments (42) (41) (18) (15)
Employer contributions 4 4 19 16
-------------------------------------------------------------------------------------------------
Fair value of plan assets at December 31 $ 919 $ 849 $ 20 $ 18
-------------------------------------------------------------------------------------------------
In the table above, substantially all employer contributions represent
benefit payments made directly from Company assets. The remaining benefits
payments were made directly from plan assets. The OPEB benefit payments
represent the net Company cost after participant contributions. Participant
contributions represent approximately 10% 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% - - -
Equity - international 15% 21% 22% - - -
Debt - domestic 12% 9% 11% 100% 100% 100%
Debt - international 10% 11% 11% - - -
Other 15% 12% 7% - - -
--------------------------------------------------------------------------------------------------------
Total 100% 100% 100% 100% 100% 100%
--------------------------------------------------------------------------------------------------------
With regard to its pension assets, the Company sets strategic 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 five percent) in asset allocation from the strategic allocations
are made based on the near-term view of the risk and return tradeoffs of
the asset classes. The Company's OPEB assets are invested solely in fixed
income securities.
In 2005, the Company expects to make no required contributions to pension
plan assets and $1 million of discretionary contributions to 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
$43, $45, $47, $51, $55 and $337, respectively. The expected benefit
payments for the OPEB plan for 2005 through 2009 and in total for
2010-2014, in millions, are approximately $17, $19, $20, $21, $22 and $126,
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 $2, $2, $2, $2 and $14, respectively. PEF
represents a significant majority of the Company's expected benefit
payments and expected subsidies to be received. The expected benefit
payments above do not include the potential effects of a 2005 voluntary
early retirement program (see Note 22).
74
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
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 Emerging Issues
Task Force 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
------------------------ --------------------------------
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 plan 5.00% 4.00% 4.00% - - -
Expected long-term rate of return on plan
assets 9.25% 9.25% 9.25% 5.00% 5.00% 5.00%
---------------------------------------------------------------------------------------------------------------
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 pension
plan 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 OPEB expected long-term rate of return of 5.0% reflects
that the OPEB assets are invested solely in fixed income securities.
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 $13 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 $12 million.
16. RISK MANAGEMENT ACTIVITIES AND DERIVATIVES TRANSACTIONS
Under its risk management policy, the Company and PEF 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 and PEF minimize such risk by performing credit
reviews using, among other things, publicly available credit ratings of
such counterparties. Potential non-performance by counterparties is not
expected to have a material effect on the consolidated financial position
or consolidated results of operations of the Company or PEF.
75
A. Commodity Derivatives
GENERAL
Most of the Company's and PEF's commodity contracts either are not
derivatives or qualify as normal purchases or sales pursuant to SFAS No.
133. Therefore, such contracts are not recorded at fair value.
ECONOMIC DERIVATIVES
Derivative products, primarily electricity forward contracts, may be
entered into for economic hedging purposes. While management believes these
derivatives mitigate exposures to fluctuations in commodity prices, these
instruments are not designated as hedges for accounting purposes and are
monitored consistent with trading positions. The Company manages open
positions with strict policies that limit its exposure to market risk and
require daily reporting to management of potential financial exposures.
Gains and losses from such contracts were not material during 2004, 2003 or
2002, and the Company did not have material outstanding positions in such
contracts at December 31, 2004 or 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.
CASH FLOW HEDGES
The Company'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
sales. In the normal course of business, Progress Fuels through an
affiliate, Progress Ventures, Inc. (PVI), enters natural gas cash flow
hedging instruments, which PVI offsets with third party transactions.
Progress Fuels accounts for such contracts as if it were transacted with a
third party and records the contract using mark-to-market or accrual
accounting, as applicable. At December 31, 2004, Progress Fuels is hedging
exposures to the price variability of natural gas through December 2005.
The total fair value of these instruments at December 31, 2004 and 2003 was
a $9 million and a $14 million liability position, respectively. The
ineffective portion of commodity cash flow hedges was not material in 2004
and 2003. At December 31, 2004, there were $5 million of after-tax deferred
losses in accumulated other comprehensive income (OCI). The entire amount
is expected to be reclassified to earnings during the next 12 months as the
hedged transactions occur. 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 (See Note 4A). 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 and PEF manage its interest rate exposure in part by
maintaining its variable-rate and fixed rate-exposures within defined
limits. In addition, the Company and PEF also enter into financial
derivative instruments, including, but not limited to, interest rate swaps
and lock agreements to manage and mitigate interest rate risk exposure.
The Company and PEF use cash flow hedging strategies to hedge variable
interest rates on long-term debt and to hedge interest rates with regard to
future fixed-rate debt issuances. The Company and PEF held no interest rate
cash flow hedges at December 31, 2004 or 2003. At December 31, 2004, an
immaterial amount of after-tax deferred losses in OCI, related to
previously terminated hedges at PEF, is expected to be reclassified to
earnings during the next 12 months as the hedged interest payments occur.
76
The Company and PEF use fair value hedging strategies to manage its
exposure to fixed interest rates on long-term debt. At December 31, 2004
and 2003, the Company and PEF 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.
17. RELATED PARTY TRANSACTIONS
The Parent's subsidiaries provide and receive services, at cost, to and
from the Company 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 which 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. Services provided by
PESC during 2004, 2003 and 2002 to Florida Progress amounted to $199
million, $190 million and $173 million, respectively, and services provided
to PEF were $165 million, $153 million and $161 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 on 2003 was
an increase in expenses of $5 million at Florida Progress and a reduction
of expenses at PEF by $1 million. PEF and an affiliated utility also
provide and receive services at cost. Services received by PEF during 2004,
2003 and 2002 amounted to $52 million, $35 million and $72 million,
respectively. Services provided by PEF during 2004, 2003 and 2002 amounted
to $16 million, $7 million and $16 million, respectively.
Progress Fuels sells coal to PEF for insignificant profits. These
intercompany revenues and expenses are eliminated in consolidations;
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
Florida Progress' Consolidated and PEF's Statements of Income.
The Company and its subsidiaries participate in money pools, operated by
Progress Energy, to more effectively utilize cash resources and to reduce
outside short-term borrowings. The money pools are also used to settle
intercompany balances. The weighted-average interest rate for the money
pools 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 Balance Sheets. Net interest expense
related to money pool borrowings was $7 million for 2004 and $5 million for
Florida Progress for 2003 and 2002. PEF recorded insignificant interest
expense related to the money pool for the three years presented.
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 certain subsidiaries issued
guarantees of $140 million supporting obligations under coal brokering
operations and other agreements of subsidiaries. Progress Energy and
certain subsidiaries also purchased $33 million of surety bonds and
authorized the issuance of standby letters of credit by financial
institutions of $40 million. Florida Progress has fully guaranteed the
medium term notes outstanding for Progress Capital, a wholly owned
subsidiary of Florida Progress. 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
Consolidated Balance Sheets.
In April 2000, Progress Ventures, Inc. (PVI), a wholly owned subsidiary of
Progress Energy, purchased a 90% interest in an affiliate of Progress Fuels
that owns a synthetic fuel facility located at the Company-owned mine site
in Virginia. In May 2000, PVI purchased a 90% ownership interest in another
synthetic fuel facility located in West Virginia. The purchase agreements
contained a provision that would require PVI to sell, and the respective
Progress Fuels affiliate to repurchase, the 90% interest had the share
exchange among Florida Progress, Progress Energy and CP&L not occurred.
Progress Fuels has accounted for the transactions as a sale for tax
77
purposes and, because of the repurchase obligation, as a financing for
financial reporting purposes in the pre-acquisition period and as a
transfer of assets within a controlled group as of the acquisition date. At
the date of acquisition, assets of $8 million were transferred to Progress
Energy. At December 31, 2004 and 2003, the Company has a note receivable of
$28 million and $37 million from PVI that has been recorded as a reduction
to equity for financial reporting purposes. Payments included insignificant
amounts of interest for the three years presented.
PVI enters into derivative transactions on behalf of Progress Fuels, which
are discussed further with the derivatives transactions (See Note 16A). PVI
recorded $33 million, $28 million and $9 million of realized and unrealized
gains for these derivative transactions in 2004, 2003 and 2002,
respectively.
Progress Fuels sells coal feedstock to PVI to be used in its two synthetic
fuel operations and is also the sales agent and operator of the facilities.
The amount of revenue for sales and services during 2004, 2003 and 2002 was
$134 million, $182 million and $197 million, respectively.
During 2003, in order to more effectively utilize cash resources, Progress
Fuels and the two PVI synthetic fuel operations began to participate in a
money pool with cash management functions provided by Progress Fuels.
Amounts payable to the money pool of $61 million and $34 million are
included in notes payable to affiliated companies on the Consolidated
Balance Sheets. Interest related to the money pool was insignificant for
the three years presented.
A Progress Fuels subsidiary sells coal feedstock to an equity investment.
The amount of revenue during 2004, 2003 and 2002 was $150 million, $117
million and $101 million, respectively.
Long-term debt, affiliate on the Florida Progress' Consolidated Balance
Sheet consists of $500 million for Progress Fuels' unsecured note with
Parent and $309 million of debt to an affiliated trust (See Note 12A).
Progress Fuels recorded interest expense related to the unsecured note with
Parent of $32 million for 2004 and 2003. The annual interest expense to the
affiliated trust is $21 million and is reflected in the 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) (See Note 12A). 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. 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
(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. 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 Company and each of its wholly owned subsidiaries have entered into a
Tax Agreement with Progress Energy (See Note 14).
18. FINANCIAL INFORMATION BY BUSINESS SEGMENT
The Company's principal business segment is PEF, a utility engaged in the
generation, purchase, transmission, distribution and sale of electricity
primarily in Florida. The other reportable business segments are Progress
Fuels' Energy & Related Services and Rail Services. The Energy & Related
Services segment includes coal and synthetic fuel operations, natural gas
production and sales, river terminal services and off-shore marine
transportation. Rail Services' operations include railcar repair, rail
parts reconditioning and sales, railcar leasing and sales, providing rail
and track material, and scrap metal recycling. The Other category consists
primarily of PTC, the Company's telecommunications subsidiary and the
holding company, Florida Progress Corporation and eliminations. PTC markets
wholesale fiber-optic based capacity service in the Eastern United States
and also markets wireless structure attachments to wireless communication
companies and governmental entities. The Company allocates a portion of its
operating expenses to business segments.
78
The Company's significant operations are geographically located in the
United States with limited operations in Mexico and Canada. The Company's
segments are based on differences in products and services, and therefore
no additional disclosures are presented. Intersegment sales and transfers
consist primarily of coal sales from the Energy and Related Services
segment of Progress Fuels to PEF. The price Progress Fuels charges PEF is
based on market rates for coal procurement and for water-borne
transportation under a methodology approved by the FPSC. Rail
transportation is also based on market rates plus a return allowed by the
FPSC on equity in transportation equipment utilized in transporting coal to
PEF. The allowed rate of return is currently 12%. No single customer
accounted for 10% or more of unaffiliated revenues.
Segment net income (loss) for 2004 includes a gain on the sale of certain
gas properties and assets of $56 million ($31 million after-tax) and a
long-lived asset impairment on goodwill at Diamond May of $8 million before
and after tax included in the Energy and Related Services segment. Segment
net income (loss) for 2003 includes a long-lived asset impairment on
certain assets at Kentucky May Mining Company of $15 million ($10 million
after-tax) included in the Energy and Related Services segment. Segment net
income (loss) for 2002 includes an estimated impairment on the assets held
for sale of Railcar Ltd., of $67 million pre-tax ($45 million after-tax)
included in the Rail Services segment and an asset impairment and other
charges related to PTC totaling $233 million on a pre-tax basis ($144
million after-tax) included in the Other segment. The Company's business
segment information for 2004, 2003 and 2002 is summarized below.
-------------------------------------------------------------------------------------------------------------
Energy
and
Related
(in millions) Utility Services Services Other Consolidated
-------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2004
Unaffiliated revenues $ 3,525 $ 1,223 $ 1,130 $ 57 $ 5,935
Intersegment revenues - 331 1 (332) -
-------------------------------------------------------------------------------------------------------------
Total revenues 3,525 1,554 1,131 (275) 5,935
-------------------------------------------------------------------------------------------------------------
Depreciation and amortization 281 80 21 11 393
Total interest charges, net 114 20 27 19 180
Gain on sale of assets - 54 - - 54
Impairment of goodwill and
long-lived assets - 8 - - 8
Income tax expense (benefit) 174 (106) 15 (13) 70
Income (loss) from continuing
operations 333 137 16 (12) 474
Total segment assets 7,924 855 596 311 9,686
Capital and investment
expenditures 482 157 40 6 685
-------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
Unaffiliated revenues $ 3,152 $ 982 $ 846 $ 28 $ 5,008
Intersegment revenues - 346 1 (347) -
-------------------------------------------------------------------------------------------------------------
Total revenues 3,152 1,328 847 (319) 5,008
-------------------------------------------------------------------------------------------------------------
Depreciation and amortization 307 66 20 6 399
Total interest charges, net 91 22 29 21 163
Impairment of goodwill and
long-lived assets - 15 - - 15
Income tax expense (benefit) 147 (246) 2 (13) (110)
Income (loss) from continuing
operations 295 166 (1) (17) 443
Total segment assets 7,280 977 586 350 9,193
Capital and investment expenditures 526 310 103 11 950
-------------------------------------------------------------------------------------------------------------
79
Year Ended December 31, 2002
Unaffiliated revenues $ 3,062 $ 690 $ 714 $ 34 $ 4,500
Intersegment revenues - 329 5 (334) -
-------------------------------------------------------------------------------------------------------------
Total revenues 3,062 1,019 719 (300) 4,500
-------------------------------------------------------------------------------------------------------------
Depreciation and amortization 295 34 20 12 361
Total interest charges, net 106 22 33 22 183
Impairment of goodwill and
long-lived assets - - 67 214 281
Income tax expense (benefit) 163 (207) (19) (110) (173)
Income (loss) from continuing
operations 323 122 (47) (168) 230
Total segment assets 6,678 794 529 137 8,138
Capital and investment expenditures 535 121 8 42 706
-------------------------------------------------------------------------------------------------------------
Geographic Data
-------------------------------------------------------------------------------------------
U.S. Canada Mexico Consolidated
-------------------------------------------------------------------------------------------
2004
Consolidated revenues $ 5,807 $ 112 $ 16 $ 5,935
-------------------------------------------------------------------------------------------
2003
Consolidated revenues $ 4,891 $ 103 $ 14 $ 5,008
-------------------------------------------------------------------------------------------
2002
Consolidated revenues $ 4,393 $ 93 $ 14 $ 4,500
-------------------------------------------------------------------------------------------
19. OTHER INCOME AND OTHER EXPENSE
Other income and expense includes interest income and other income and
expense items as discussed below. The components of other, net as shown on
the Statements of Income for fiscal years 2004, 2003 and 2002 are as
follows:
--------------------------------------------------------------------------------------------------------
(in millions) 2004 2003 2002
--------------------------------------------------------------------------------------------------------
Other income
Nonregulated energy and delivery services income 17 14 17
AFUDC equity 7 12 2
Other 3 1 4
--------------------------------------------------------------------------------------------------------
Total other income - Progress Energy Florida $ 27 $ 27 $ 23
--------------------------------------------------------------------------------------------------------
Other income - Florida Progress 13 5 6
--------------------------------------------------------------------------------------------------------
Total other income - Florida Progress $ 40 $ 32 $ 29
--------------------------------------------------------------------------------------------------------
Other expense
Nonregulated energy and delivery services expenses $ 11 $ 11 $ 15
Donations 8 9 10
Other 3 - 5
--------------------------------------------------------------------------------------------------------
Total other expense - Progress Energy Florida $ 22 $ 20 $ 30
--------------------------------------------------------------------------------------------------------
Loss from equity investments 12 15 14
Other expense - Florida Progress 5 5 5
--------------------------------------------------------------------------------------------------------
Total other expense - Florida Progress $ 39 $ 40 $ 49
--------------------------------------------------------------------------------------------------------
Other, net $ 1 $ (8) $(20)
--------------------------------------------------------------------------------------------------------
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.
80
20. ENVIRONMENTAL MATTERS
The Company and PEF are 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, authorize the EPA to require the
cleanup of hazardous waste sites. This statute imposes retroactive joint
and several liabilities. The Company and PEF are periodically notified by
regulators such as the EPA and various state agencies of its involvement or
potential involvement in sites, other than MGP sites, that may require
investigation and/or remediation. The Company and PEF are also currently in
the process of assessing potential costs and exposures at other
environmentally impaired sites. For all sites the assessments are developed
and analyzed, the Company and PEF 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
the Company, through PEF, has some connection. In this regard, PEF 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 Florida Department of Environmental
Protection (FDEP).
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 has 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.
The Company and PEF have filed claims with the Company's general liability
insurance carriers to recover costs arising out of actual or potential
environmental liabilities. Some claims have been settled and others are
still pending. The Company and PEF cannot predict the outcome of this
matter.
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
--------------------------------------------------------------------------
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
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.
81
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 costs. 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.
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 and is included in other liabilities and deferred credits. FPC
measures its liability for this site 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.
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 the Company
and PEF's consolidated financial position or results of operations.
However, the Company and PEF 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 and PEF 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
and PEF cannot predict the outcome of this matter.
82
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 and PEF are
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 and PEF complete their 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. 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 enacted on March 10, 2005. The EPA's rule requires 28 states
and the District of Columbia, including Florida, to reduce NOx and SO2
emissions in order to attain preset state NOx and SO2 emissions levels. The
Company and PEF are 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 and PEF complete the review of the final rule.
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 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. PEF 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 $65 million to $85 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 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 and PEF cannot
predict the outcome of this matter.
Progress Energy has announced its plan to issue a report on the Progress
Energy's activities associated with current and future environmental
requirements. The report will include a discussion of the environmental
requirements that the Company and PEF currently face and expect 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.
83
21. COMMITMENTS AND CONTINGENCIES
A. Purchase Obligations
At December 31, 2004, the following table reflects the Company'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 $ 1,571 $ 1,023 $ 270 $ 102 $ 116 $ 684
Purchased power 334 342 354 364 331 4,086
Construction obligations 51 - - - - -
Other purchase obligations 44 38 36 22 20 93
----------------------------------------------------------------------------------------------------
Total $ 2,000 $ 1,402 $ 660 $ 488 $ 467 $ 4,863
----------------------------------------------------------------------------------------------------
FUEL AND PURCHASED POWER
The Company has entered into various long-term contracts for oil, gas and
coal. The Company's payments under these commitments were $1,620 million,
$1,157 million and $891 million in 2004, 2003 and 2002, respectively. PEF's
payments totaled $372 million, $208 million and $94 million in 2004, 2003
and 2002, respectively. The Company's estimated annual payments for firm
commitments of fuel purchases and transportation costs under these
contracts make up the fuel line in the previous table. PEF's future
payments under these contracts at December 31, 2004 are $375 million, $258
million, $125 million, $102 million and $116 million for 2005 through 2009,
respectively, and $684 million thereafter.
Progress Fuels had two coal supply contracts with PEF through 2005, which
require PEF to buy and Progress Fuels to supply substantially all of the
coal and transportation requirements of four of PEF's generating units.
These contracts are renewable annually. Either party may terminate the
contract with six months notice. In connection with these contracts,
Progress Fuels has entered into several contracts with outside parties for
the purchase of coal. The annual obligations for coal purchases and
transportation under these contracts are $358 million and $286 million for
2005 and 2006, respectively, with no obligations thereafter. The total cost
incurred for these commitments in 2004, 2003 and 2002 was $301 million,
$284 million and $289 million, 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.
PEF has ongoing purchased power contracts with certain cogenerators
(qualifying facilities) for 821 MW of capacity with expiration dates
ranging from 2005 to 2025. These purchased power contracts provide for
capacity and energy payments. Energy payments are based on the actual power
taken under these contracts. Capacity payments are subject to the
qualifying facilities meeting certain contract performance obligations. In
most cases, these contracts account for 100% of the generating capacity of
each of the facilities. All commitments have been approved by the FPSC.
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. The FPSC allows the capacity payments to be recovered through a
capacity cost recovery clause, which is similar to, and works in
conjunction with, energy payments recovered through the fuel cost recovery
clause.
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.
84
CONSTRUCTION OBLIGATIONS
PEF has purchase obligations related to various plant capital projects at
the Hines Complex. Total payments under these contracts were $97 million,
$137 million and $130 million for 2004, 2003, and 2002, respectively.
Future obligations under these contracts are $51 million for 2005.
OTHER PURCHASE OBLIGATIONS
PEF has long-term service agreements for the Hines Complex. Total payments
under these contracts were $11 million, $3 million and $1 million for 2004,
2003 and 2002, respectively. Future obligations under these contracts are
$6 million, $18 million, $11 million, $16 million and $14 million for 2005
through 2009, respectively, with approximately $93 million payable
thereafter.
PEF has various purchase obligations and contractual commitments related to
the purchase and replacement of machinery. At December 31, 2004, no
purchases have been made under these contracts. Future obligations under
these contracts are $34 million, $20 million and $25 million in 2005, 2006
and 2007, respectively, and $6 million in 2008 and 2009.
The Company incurred expenses related to various other purchase obligations
allocated from PESC of $6 million for 2004 and 2003 and $5 million for
2002.
B. Other Commitments
The Company has certain future commitments related to synthetic fuel
facilities purchased that provide for contingent payments (royalties). The
related agreements and amendments require the payment of minimum annual
royalties of which the Company's share is approximately $13 million through
2007. As a result of the amendment, 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 $37 million and
$47 million at December 31, 2004 and 2003, 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 approximately $13 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, $1 million in 2003
and $24 million in 2002. Future expected royalty payments are approximately
$13 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 $20 million and $22 million, respectively, pending the
establishment of the necessary escrow accounts. Once established, these
funds will be placed into escrow.
C. Leases
The Company leases transportation equipment, office buildings, computer
equipment, and other property and equipment with various terms and
expiration dates. The Company generally requires the subsidiaries to pay
all executory costs such as maintenance and insurance. Some rental payments
include minimum rentals plus contingent rentals based on mileage. These
contingent rentals are not significant. Rent expense under operating leases
totaled $45 million, $40 million and $49 million during 2004, 2003 and
2002, respectively. These amounts include rent expense allocated from PESC
to the Company of $12 million for 2004, 2003 and 2002. PEF's rent expense
totaled $14 million, $17 million and $16 million during 2004, 2003 and
2002, respectively. These amounts include rent expense allocated from PESC
to PEF of $10 million for 2004, 2003 and 2002.
In addition, PTC has entered into capital leases for equipment. Assets
recorded under capital leases totaled $2 million and $4 million at December
31, 2004 and 2003, respectively. Accumulated amortization was not
significant. These assets were written down in conjunction with the
impairments of PTC recorded during the third quarter of 2002 (See Note 10).
PEF does not have any capital leases.
85
Minimum annual rental payments, excluding executory costs such as property
taxes, insurance and maintenance, under long-term noncancelable leases at
December 31, 2004 are:
--------------------------------------------------------------------------------------------------
Operating Leases
-------------------------------------
Capital Florida Progress Energy
(in millions) Leases Progress Florida
--------------------------------------------------------------------------------------------------
2005 $ 2 $ 22 $ 11
2006 2 19 9
2007 1 36 28
2008 1 37 30
2009 1 36 29
Thereafter 8 170 132
--------------------------------------------------------------------------------------------------
$ 15 $320 $ 239
-------------------------------------
Less amount representing imputed interest (5)
-----------------------------------------------------------
Present value of net minimum lease payments
under capital lease $ 10
--------------------------------------------------------------------------------------------------
FPC, excluding PEF, is also a lessor of land, buildings, railcars and other
types of properties it owns under operating leases with various terms and
expiration dates. The leased buildings and railcars are depreciated under
the same terms as other buildings and railcars included in diversified
business property. Minimum rentals receivable under noncancelable leases
for 2005 through 2009, in millions is $31, $22, $13, $8 and $6,
respectively and $16 million thereafter. Rents received under operating
leases totaled $63 million, $46 million and $53 million for 2004, 2003 and
2002, respectively.
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 through 2009, in millions
is $5, $1, $1, $1 and $1, respectively, 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 17). At December 31, 2004, Progress Fuels 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. 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.
86
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. 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
agreement. The Court's decision should not have a material impact on the
Company.
2. DOE Litigation
Pursuant to the Nuclear Waste Policy Act of 1982, the predecessors to PEF
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, PEF filed a complaint with the United States Court of Federal
Claims against the DOE, claiming that the DOE breached the Standard
Contract for Disposal of Spent Nuclear Fuel (SNF) by failing to accept SNF
from PEF 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 SNF are currently pending in
the Court of Federal Claims.
87
DOE and the 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 are expected to be presented in the trials that are scheduled to
occur by April 2005. Resolution of these issues in other cases could
facilitate agreements by the parties in the 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 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.
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. PEF cannot predict the outcome of
this matter.
3. Advanced Separation Technologies (AST)
In 1996, Florida Progress sold its 80% interest in AST to Calgon Carbon
Corporation (Calgon) for net proceeds of $56 million in cash. In 1998,
Calgon filed a lawsuit against Florida Progress and the other selling
shareholder and amended it in April 1998, alleging misstatement of AST's
1996 revenues, assets and liabilities, seeking damages and granting Calgon
the right to rescind the sale. The lawsuit also accused the sellers of
failing to disclose flaws in AST's manufacturing process and a lack of
quality control.
All parties filed motions for summary judgment in July 2001. The summary
judgment motions of Calgon and the other selling shareholder were denied in
April 2002. The summary judgment motion of Florida Progress was withdrawn
pending a legal challenge to portions of the report of Calgon's expert,
Arthur Andersen, which had been used to oppose summary judgment. In
September 2003, the United States District Court for the Western District
of Pennsylvania issued final orders excluding from evidence in the case
that portion of Arthur Andersen's damage analysis based on the discounted
cash flow methodology of valuation. The Court did not exclude Arthur
Andersen's use of the guideline publicly traded company methodology in its
damage analysis. Florida Progress filed a renewed motion for summary
judgment in October 2003, which is pending. Because the motion has now been
outstanding for over a year, a ruling on the motion is expected at any
time.
Florida Progress believes that the aggregate total of all legitimate
warranty claims by customers of AST for which it is probable that Florida
Progress will be responsible for under the Stock Purchase Agreement with
Calgon is approximately $3 million, and accordingly, accrued $3 million in
the third quarter of 1999 as an estimate of probable loss.
The Company cannot predict the outcome of this matter, but will vigorously
defend against the allegations.
4. Synthetic Fuel Tax Credits
At December 31, 2003, Florida Progress, through its subsidiaries, was a
majority-owner in three entities and a minority owner in three entities
that own facilities that produce synthetic fuel as defined under the
Internal Revenue Code (Code). In June 2004, Progress Fuels sold, in two
transactions, a combined 49.8 percent partnership interest in Colona
Synfuel Limited Partnership, LLLP (Colona), one of its majority owned
synthetic fuel operations. The Company is now a minority owner in Colona,
but continues to consolidate Colona in accordance with FASB Interpretation
No. 46R. Florida Progress, through its subsidiaries, is currently a
majority owner in two synthetic fuel entities and a minority owner in four
synthetic fuel entities, including Colona. The production and sale of the
synthetic fuel from these facilities qualifies for tax credits under
88
Section 29 of the Code (Section 29) if certain requirements are satisfied,
including a requirement that the synthetic fuel differs significantly in
chemical composition from the coal used to produce such synthetic fuel 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 majority-owned and
minority-owned entities received private letter rulings (PLRs) from the
Internal Revenue Service (IRS) with respect to their synthetic fuel
operations. However, these PLR's do not address the placed-in-service date
determinations. The PLRs do not limit the production on which synthetic
fuel credits may be claimed. Total Section 29 credits generated to date are
approximately $918 million, of which $432 million has been used to offset
regular federal income tax liability and $481 million are being carried
forward as deferred alternative minimum tax credits. Also $5 million has
not been recognized due to the decrease in tax liability from 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 4.9 million tons of synthetic fuel and the Company recorded
$127 million of Section 29 tax credits. The amount of synthetic fuel sold
and tax credits recorded in 2004 was impacted by hurricane costs which
reduced the Company's projected 2004 regular tax liability.
For the nine months ended September 30, 2004, the Company's synthetic fuel
facilities sold 4.6 million tons of synthetic fuel, which generated an
estimated $119 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 $72 million of these
Section 29 tax credits. As a result, the Company recorded a charge of $47
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, $127 million of these Section 29 tax credits. Therefore,
the Company recorded tax credits of $55 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
4.9 million tons of synthetic fuel, which generated an estimated $132
million of Section 29 tax credits. As of December 31, 2004, the Company
anticipates that approximately $5 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 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 Florida Progress' majority-owned synthetic fuel
entities at that time, including Colona, and two of the Company's minority
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.
In February 2004, subsidiaries of the Company finalized execution of the
Colona Closing Agreement with the IRS concerning their Colona synthetic
fuel facilities. The 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 of the Code.
The 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
anticipate 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 has 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 he Company's Earthco facilities is back on
the normal procedural audit path of the Company's tax returns. Through
December 31, 2004, based on its ownership percentage, the Company has used
or carried forward $550 million of tax credits generated by Earthco
facilities. If these credits were disallowed, Florida Progress' one time
exposure for cash tax payments would be $64 million (excluding interest),
and earnings and equity would be reduced by $550 million, excluding
interest.
89
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 has adjusted its synthetic fuel
production for 2004 in response to the effects of the hurricane damage on
its 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 a 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,"
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.
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 of the Code. 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 $3 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.
90
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 of 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 it 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 results of operations and synthetic
fuel production plans.
5. Other Legal Matters
Florida Progress and PEF are involved in various other claims and legal
actions arising in the ordinary course of business, some of which involve
claims for substantial amounts. Where appropriate, accruals have been made
in accordance with SFAS No. 5, "Accounting for Contingencies," to provide
for such matters. Florida Progress and PEF believe the ultimate disposition
of these matters will not have a material adverse effect upon either
Company's consolidated and PEF's financial position or results of
operations.
22. SUBSEQUENT EVENTS
Sale of Progress Rail
On February 18, 2005, Progress Energy 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 at December 31, are as follows:
-------------------------------------------------------------------
(in millions) 2004 2003
-------------------------------------------------------------------
Total current assets $ 378 $ 373
Total property, plant & equipment (net) 202 184
Total other assets 28 64
Total current liabilities 156 114
Total long-term liabilities 3 3
Total capitalization 449 504
-------------------------------------------------------------------
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.
91
In connection with the cost management initiative, the Company expects to
incur one-time pre-tax charges of approximately $54 million. Approximately
$9 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 post-retirement 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.
23. SUPPLEMENTAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
The following supplemental unaudited information regarding the Company's
oil and gas activities is presented pursuant to disclosure requirements of
SFAS No. 69 "Disclosures About Oil and Gas Producing Activities."
A. Capitalized Costs
The aggregate amounts of costs capitalized for oil and gas producing
activities, and related aggregate amounts of accumulated depreciation,
depletion and amortization (See Notes 4A and 5B), at December 31 follows:
----------------------------------------------------------------------------
(in millions) 2004 2003
----------------------------------------------------------------------------
Capitalized Costs -
Proved Properties being amortized $ 281 $ 352
Unproved Properties not being amortized 55 60
----------------------------------------------------------------------------
336 412
Less - Accumulated depreciation, depletion,
and amortization (52) (35)
----------------------------------------------------------------------------
Net Capitalized Costs $ 284 $ 377
----------------------------------------------------------------------------
B. Costs Incurred
There were no oil or gas exploration costs for the years ended 2004, 2003
and 2002. The following costs (in millions) were included in oil and gas
producing activities during the years ended December 31,
---------------------------------------------------------------------
(in millions) 2004 2003 2002
---------------------------------------------------------------------
Property acquisition $ 7 $ 169 $ 141
Development 95 105 16
---------------------------------------------------------------------
Total Costs Incurred $ 102 $ 274 $ 157
---------------------------------------------------------------------
C. Results of Operations
The following summarizes the results of operations for the Company's oil
and gas producing activities:
------------------------------------------------------------------------------------------
(in millions) 2004 2003 2002
------------------------------------------------------------------------------------------
Revenues - Sales $ 151 $ 107 $ 36
Less:
Production (lifting) costs 28 16 7
Depreciation, depletion, and
amortization, and valuation provisions 41 33 11
------------------------------------------------------------------------------------------
Pretax Operating Income 82 58 18
Income tax expenses 33 19 6
------------------------------------------------------------------------------------------
Results of operations from producing
activities (excluding corporate
overhead and interest costs) $ 49 $ 39 $ 12
------------------------------------------------------------------------------------------
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D. Estimated Quantities of Oil and Gas Reserves
At December 31, 2004, the Company had proved oil and gas reserves of 247
Bcfe estimated by Netherland Sewell & Associates, Inc., an independent
engineering firm. These reserves are located entirely within the United
States. Estimated net quantities of proven oil and gas reserves at December
31 for each of the last three years were as follows in Bcfe. Reserve
quantities stated in Bcfe use an energy conversion factor of six units of
gas for every one unit of oil.
----------------------------------------------------------------
January 1, 2002 69
Acquisitions 87
Extensions and discoveries 62
Production (13)
----------------------------------------------------------------
December 31, 2002 205
Acquisitions 189
Extensions and discoveries 65
Production (25)
Sales (76)
----------------------------------------------------------------
December 31, 2003 358
Acquisitions 12
Extensions and discoveries 58
Production (30)
Sales (151)
----------------------------------------------------------------
December 31, 2004 247
----------------------------------------------------------------
Proved Developed Reserves included above:
At December 31, 2002 179
At December 31, 2003 225
At December 31, 2004 137
----------------------------------------------------------------
E. Standardized Measure of Discounted Future Net Cash Flows (SMOG)
The following standardized disclosures required by FASB do not represent
the results of operations based on its historical financial statements. In
addition to requiring different determinations of revenue and costs, the
disclosures exclude the impact of interest expense and corporate overhead.
The following table sets forth, at December 31, 2004, the proven reserves
and the present value, discounted at an annual rate of 10%, of future net
revenues (revenues less production and development cost) attributable to
these reserves.
- ----------------------------------------------------------------------------------------------------------------------------
2004 2003 2002
- ----------------------------------------------------------------------------------------------------------------------------
( in millions) Proved Proved Total Proved Proved Total Proved Proved Total
Developed Un-developed Proved Developed Un-developed Proved Developed Un-developed Proved
- ----------------------------------------------------------------------------------------------------------------------------
Future Cash $ 806 $ 648 $ 1,454 $ 1,283 $ 781 $ 2,064 $ 480 $ 419 $ 899
Inflows
Less:
Future production
costs 277 182 459 357 203 560 138 100 238
Future development
costs 24 133 157 40 122 162 7 58 65
Future income tax
expense at 36% 182 120 302 319 164 483 121 94 215
- ----------------------------------------------------------------------------------------------------------------------------
Future Net Cash 323 213 536 567 292 859 214 167 381
Flows
Less: annual
discount 120 115 235 300 195 495 79 83 162
- ----------------------------------------------------------------------------------------------------------------------------
Standardized
measure of
discounted
future net cash
flows $ 203 $ 98 $ 301 $ 267 $ 97 $ 364 $ 135 $ 84 $ 219
- ----------------------------------------------------------------------------------------------------------------------------
93
For purposes of determining the above cash flows, estimates were made of
quantities of proved reserves and the periods during which they are
expected to produce. Future cash flows were computed by applying year-end
prices to estimated annual future production from our proved oil and gas
reserves. The year-end prices for crude oil and natural gas used in the
estimation were $45.64 per Bbl and $6.21 per MMbtu, based on a December 31,
2004, Henry Hub spot market price. Future development and production costs
were computed by applying year-end costs expected to be incurred in
producing and further developing the proved reserves. The estimated future
net cash flows were computed by application of a 10% per annum discount
factor. The calculations assume the continuation of existing economic,
operating and contractual conditions. Other assumptions of equal validity
could give rise to substantially different results.
For the years ended, December 31, 2003 and 2002, $166 million of the
increase to the SMOG was due to acquisition of reserves. For the years
ended, December 31, 2004 and 2003, $166 million of the change was due to
the sale of reserves and $53 million was due to increased development
costs.
24. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for Florida Progress is as follows:
----------------------------------------------------------------------------------------------------
(in millions) First Quarter Second Quarter Third Quarter Fourth Quarter
----------------------------------------------------------------------------------------------------
Year ended December 31, 2004
Operating revenues $ 1,308 $ 1,495 $ 1,670 $ 1,462
Operating income 103 181 260 157
Net income 55 135 148 136
----------------------------------------------------------------------------------------------------
Year ended December 31, 2003
Operating revenues $ 1,215 $ 1,207 $ 1,391 $ 1,195
Operating income 126 122 193 64
Net income 92 114 174 67
----------------------------------------------------------------------------------------------------
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.
Certain reclassifications have been made to previously reported amounts to
conform to the current year's presentation. Fourth quarter 2004 includes a
goodwill impairment charge related to the Company's coal mining business of
$8 million before and after tax (See Note 9) and $31 million after-tax gain
on the sale of natural gas assets (See Note 4A). Fourth quarter 2004 also
includes the recording of $47 million of Section 29 tax credit (See Note
21E). Third quarter 2004 includes the reversal of $55 million of Section 29
tax credits (See Note 21E). Fourth quarter 2003 includes an impairment
charge related to Kentucky May of $15 million ($10 million after-tax) (See
Note 10).
Summarized quarterly financial data for PEF is as follows:
----------------------------------------------------------------------------------------------------
(in millions) First Quarter Second Quarter Third Quarter Fourth Quarter
----------------------------------------------------------------------------------------------------
Year ended December 31, 2004
Operating revenues $ 784 $ 860 $ 1,029 $ 852
Operating income 103 157 244 114
Net income 50 84 140 61
----------------------------------------------------------------------------------------------------
Year ended December 31, 2003
Operating revenues $ 728 $ 767 $ 904 $ 753
Operating income 135 116 184 93
Net income 71 62 115 49
----------------------------------------------------------------------------------------------------
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.
94
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TO THE BOARDS OF DIRECTORS OF FLORIDA PROGRESS COPORATION AND FLORIDA POWER
ORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
We have audited the consolidated financial statements of Florida Progress
Corporation and its subsidiaries (Florida Progress) and the financial statements
of Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF) 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 reports thereon dated March 7, 2005
(which express an unqualified opinion and include an explanatory paragraph
concerning the adoption of a new accounting principle in 2003); such reports are
included elsewhere in this Form 10-K. Our audits also included the financial
statement schedule of Florida Progress and PEF listed in Item 15. These
financial statement schedules are the responsibility of Florida Progress' and
PEF's management. Our responsibility is to express an opinion based on our
audits. In our opinion, such financial statement schedules, when considered in
relation to the basic financial statements taken as a whole, present fairly, in
all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Raleigh, North Carolina
March 7, 2005
95
FLORIDA PROGRESS CORPORATION
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 $ 15 $ 10 $ - $ (6) $ 19
Fossil dismantlement Reserve 143 1 - - 144
Nuclear refueling outage reserve 2 10 - - 12
DECEMBER 31, 2003
Uncollectible accounts $ 28 $ 12 $ - $ (25) $ 15
Fossil dismantlement reserve 142 1 - - 143
Nuclear refueling outage reserve 10 8 - (16) (b) 2
DECEMBER 31, 2002
Uncollectible accounts $ 26 $ 14 $ - $ (12) $ 28
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.
- -----------------------------------------------------------------------------------------------------------------------
96
FLORIDA POWER CORPORATION
d/b/a PROGRESS ENERGY FLORIDA
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 $ 2 $ 5 $ - $ (5) $ 2
Fossil dismantlement Reserve 143 1 - - 144
Nuclear refueling outage reserve 2 10 - - 12
DECEMBER 31, 2003
Uncollectible accounts $ 2 $ 5 $ - $ (5) $ 2
Fossil dismantlement reserve 142 1 - - 143
Nuclear refueling outage reserve 10 8 - (16) (b) 2
DECEMBER 31, 2002
Uncollectible accounts $ 3 $ 3 $ - $ (4) $ 2
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.
- -------------------------------------------------------------------------------------------------------------------------
97
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
ITEM 9A. CONTROLS AND PROCEDURES
Florida Progress Corporation
Pursuant to the Securities Exchange Act of 1934, Florida Progress carried out an
evaluation, and with the participation of its management, including Florida
Progress' Chief Executive Officer and Chief Financial Officer, of the
effectiveness of Florida Progress' 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, Florida Progress' 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 Florida Progress (including its consolidated subsidiaries) 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 Florida
Progress' management, including the Chief Executive Office and Chief Financial
Officer, as appropriate, to allow timely decisions regarding required
disclosure.
There has been no change in Florida Progress' internal control over financial
reporting during the quarter ended December 31, 2004 that has materially
affected, or is reasonably like to materially affect, Florida Progress' internal
control over financial reporting.
The Company notes, however, that as part of the Company's review of internal
controls, the Company will be implementing changes related to capitalization
practices for PEF's 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, PEF
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 8D to the Florida Progress Corporation
Consolidated Financial Statements.
Progress Energy Florida
Pursuant to the Securities Exchange Act of 1934, PEF carried out an evaluation,
and with the participation of its management, including PEF's Chief Executive
Officer and Chief Financial Officer, of the effectiveness of PEF'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,
PEF'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 PEF 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 PEF'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 PEF's internal control over financial reporting
during the quarter ended December 31, 2004 that has materially affected, or is
reasonably like to materially affect, PEF's internal control over financial
reporting.
PEF notes, however, that as part of its review of internal controls, PEF 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, PEF 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 8D to the PEF
Financial Statements.
ITEM 9B. OTHER INFORMATION
None
98
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
The information called for by ITEM 10 is omitted pursuant to Instruction I (2)
(c) to Form 10-K (Omission of Information by Certain Wholly owned Subsidiaries).
ITEM 11. EXECUTIVE COMPENSATION
The information called for by ITEM 11 is omitted pursuant to Instruction I (2)
(c) to Form 10-K (Omission of Information by Certain Wholly owned Subsidiaries).
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information called for by ITEM 12 is omitted pursuant to Instruction I (2)
(c) to Form 10-K (Omission of Information by Certain Wholly owned Subsidiaries).
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information called for by ITEM 13 is omitted pursuant to Instruction I (2)
(c) to Form 10-K (Omission of Information by Certain Wholly owned Subsidiaries).
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The Audit and Corporate Performance Committee of Progress Energy Inc.'s, Board
of Directors ("Audit Committee") has actively monitored all services provided by
its independent auditors, Deloitte & Touche LLP, the member firms of Deloitte &
Touche Tohmatsu, and their respective affiliates (collectively, "Deloitte") and
the relationship between audit and non-audit services provided by Deloitte.
Progress Energy, Inc. has adopted policies and procedures for approving all
audit and permissible non-audit services rendered by Deloitte, and the fees
billed for those services. The Audit Committee specifically pre-approved the use
of Deloitte for audit, audit-related, tax and non-audit services, subject to
certain limitations. Audit and audit-related services include assurance and
related activities, services associated with internal control reviews, reports
related to regulatory filings, certain due diligence services pertaining to
acquisitions, consultations on dispositions and discontinued operations,
employee benefit plan audits and general accounting and reporting advice. The
preapproval policy provides that any audit and audit-related services covered by
the blanket preapproval whose project scope could not be defined at the time of
blanket approval that will require expenditure of over $50,000 will require
individual approval by the Audit Committee in advance of Deloitte being engaged
to render such services. Once the cumulative total of those projects less than
$50,000 exceeds $500,000 for the year, each subsequent project, regardless of
amount, must be approved individually in advance by the Audit Committee.
The preapproval policy requires management to obtain specific preapproval from
the Audit Committee for the use of Deloitte for any permissible non-audit
services, which, generally, are limited to tax services including, tax
compliance, tax planning, and tax advice services such as return review and
consultation and assistance. Other types of permissible non-audit services will
be considered for approval only in rare circumstances, which may include
proposed services that provide significant economic or other benefits to the
Company. In determining whether to approve these services, the Audit Committee
will assess whether these services adversely impair the independence of
Deloitte. Any permissible non-audit services provided during a fiscal year that
(i) do not aggregate more than 5% of the total fees paid to Deloitte for all
services rendered during that fiscal year and (ii) were not recognized as
non-audit services at the time of the engagement must be brought to the
attention of the Controller for prompt submission to the Audit Committee for
approval. These "de minimis" non-audit services must be approved by the Audit
Committee or its designated representative before the completion of the project.
The policy also requires management to update the Audit Committee throughout the
year as to the services provided by Deloitte and the costs of those services.
The Audit Committee will assess the adequacy of this procedure on an annual
basis and revise it accordingly.
99
Set forth in the table below is certain information relating to the aggregate
fees billed by Deloitte for professional services rendered to Florida Progress
and Progress Energy Florida for the fiscal years ended December 31, 2004 and
December 31, 2003.
Florida Progress
-----------------------------------------------------------------
2004 2003
-----------------------------------------------------------------
Audit Fees $ 2,799,000 $ 1,194,000
Audit-Related Fees $ 104,000 $ 78,000
Tax Fees $ 182,000 $ 31,000
All Other Fees $ 2,000 $ 4,000
-----------------------------------------------------------------
$ 3,087,000 $ 1,307,000
-----------------------------------------------------------------
Progress Energy Florida
-----------------------------------------------------------------
2004 2003
-----------------------------------------------------------------
Audit Fees $ 1,394,000 $ 598,000
Audit-Related Fees $ 3,000 $ 8,000
Tax Fees $ 165,000 $ 24,000
All Other Fees $ 1,000 $ 3,000
-----------------------------------------------------------------
$ 1,563,000 $ 633,000
-----------------------------------------------------------------
Audit Fees include fees billed for services rendered in connection with (i) the
audits of the annual financial statements of the Company and its SEC reporting
subsidiary (Progress Energy Florida) (ii) the reviews of the financial
statements included in the Quarterly Reports on Form 10-Q of the Company and its
SEC reporting subsidiary (iii) the audits of the financial statements of certain
non-reporting subsidiaries of the Company; and (iv) SEC filings, accounting
consultations arising as part of the audits and comfort letters.
Audit-Related Fees include fees billed for (i) audits of the financial
statements of certain of the Company's non-reporting subsidiaries; (ii) special
procedures and letter reports, (iii) benefit plan audits when fees are paid by
the Company rather than directly by the plan and (iv) accounting consultations
for prospective transactions not arising directly from the audits.
Tax Fees includes fees billed for tax compliance matters and tax planning and
advisory services.
All Other Fees includes fees billed for rate case assistance and utility
accounting training.
The Audit Committee has concluded that the provision of the non-audit services
listed above as "All Other Fees" is compatible with maintaining Deloitte's
independence.
None of the services provided were approved by the Audit Committee pursuant to
the de minimis waiver provisions described above.
100
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K FOR
FLORIDA PROGRESS AND PROGRESS ENERGY FLORIDA
1. Financial Statements, notes to Financial Statements and reports
thereon of DELOITTE & TOUCHE LLP and KPMG LLP are found in ITEM 8
"Financial Statements and Supplementary Data" herein.
2. Financial Statement Schedules and the report thereon of DELOITTE &
TOUCHE LLP are found at ITEM 8 "Financial Statements and Supplementary
Data" herein.
3. Exhibits filed herewith:
Florida
Number Exhibit Progress PEF
*2 Amended and Restated Agreement and Plan of X
Exchange by 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 the Florida Progress preliminary proxy statement
on Schedule 14A, as filed with the SEC on March 6,
2000).
*3.(a) Amended Articles of Incorporation, as X
amended, of Florida Power Corporation. (Filed as
Exhibit 3(a) to the Progress Energy Florida Form
10-K for the year ended December 31, 1991,
as filed with the SEC (File No. 1-3274)
on March 30, 1992.)
*3.(b) Restated Articles of Incorporation, as X
amended, of Florida Progress (filed as
Exhibit 3(a) to Florida Progress' Form
10-K for the year ended December 31,1991,
as filed with the SEC on March 30, 1992).
*3.(c) Bylaws of Florida Progress, as amended X
September 19, 2003. (filed as Exhibit 3(ii) to
the Florida Progress Form 10-Q for the quarter
ended September 30, 2003, as filed with the SEC on
November 12, 2003).
3.(d) Bylaws of Progress Energy Florida, as amended X
October 1, 2001.
*4.(a) Indenture, dated as of January 1, 1944 (the X X
"Indenture"), between Florida Power Corporation and
Guaranty Trust Company of New York and The
Florida National Bank of Jacksonville, as
Trustees (filed as Exhibit B-18 to Florida
Power's Registration Statement on Form A-2
(No. 2-5293) filed with the SEC on January 24,
1944).
101
*4.(b) Twenty-Ninth Supplemental Indenture, dated as X X
of September 1, 1982, between Florida Power Corporation
and Morgan Guaranty Trust Company of New York
and Florida National Bank, as Trustees, with
reference to the modification and amendment
of the Indenture (filed as Exhibit 4(c) to
Florida Power Corporation's Registration Statement on
Form S-3 (No. 2-79832) filed with the SEC on
September 17, 1982).
*4.(c) Seventh Supplemental Indenture, dated as of X X
July 1, 1956, between Florida Power Corporation and
Guaranty Trust Company of New York and The
Florida National Bank of Jacksonville, as
Trustees, with reference to the modification
and amendment of the Indenture (filed as
Exhibit 4(b) to Florida Power Corporation's Registration
Statement on Form S-3 (No. 33-16788) filed
with the SEC on September 27, 1991).
*4.(d) Eighth Supplemental Indenture, dated as of X X
July 1, 1958, between Florida Power Corporation and
Guaranty Trust Company of New York and The
Florida National Bank of Jacksonville, as
Trustees, with reference to the modification
and amendment of the Indenture (filed as
Exhibit 4(c) to Florida Power Corporation's Registration
Statement on Form S-3 (No. 33-16788) filed
with the SEC on September 27, 1991).
*4.(e) Sixteenth Supplemental Indenture, dated as of X X
February 1, 1970, between Florida Power Corporation and
Morgan Guaranty Trust Company of New York and
The Florida National Bank of Jacksonville, as
Trustees, with reference to the modification
and amendment of the Indenture (filed as
Exhibit 4(d) to Florida Power Corporation's Registration
Statement on Form S-3 (No. 33-16788) filed
with the SEC on September 27, 1991).
*4.(f) Rights Agreement, dated as of November 21, X
1991, between Florida Progress and
Manufacturers Hanover Trust Company,
including as Exhibit A the form of Rights
Certificate (filed as Exhibit 4(a) to
Florida Progress' Form 8-K dated November
21, 1991, as filed with the SEC on November 27, 1991).
*4.(g) Thirty-Eighth Supplemental Indenture dated as X X
of July 25, 1994, between Florida Power Corporation and
First Chicago Trust Company of New York, as
successor Trustee, Morgan Guaranty Trust
Company of New York, as resigning Trustee,
and First Union National Bank of Florida, as
resigning Co-Trustee, with reference to
confirmation of First Chicago Trust Company
of New York as successor Trustee under the
Indenture (filed as exhibit 4(f) to Florida
Power's Registration Statement on Form S-3
(No. 33-55273) as filed with the SEC on August
29, 1994).
102
*4.(h) Thirty-Ninth Supplemental Indenture dated as of X
July 1, 2001 between Florida Power Corporation and
First Chicago Trust Company of New York,
as Trustee (filed as Exhibit 4 to Current Report on
Form 8-K filed with the SEC on July 23, 2001).
*4.(i) Fortieth Supplemental Indenture dated as of July 1, X
2002, between Progress Energy Florida and First
Chicago Trust Company of New York (filed as Exhibit
4 to Current Report on Form 8-K filed with the SEC
on February 18, 2003).
*4.(j) Forty-First Supplemental Indenture, dated as of X
February 1, 2003 between Progress Energy Florida
and First Chicago Trust Company of New York,
as successor Trustee (filed as Exhibit 4 to Current
Report on Form 8-K filed with the SEC on February
21, 2003).
*4.(k) Forty-second Supplemental Indenture, dated as of April 1, X
2003, from Progress Energy Florida, Inc. to First Chicago
Trust Company of New York (Resigning Trustee) and
Bank One, N.A. (Successor Trustee), supplement to
Indenture dated as of January 1, 1944, as supplemented
(filed as Exhibit 4 to Quarterly Report on Form 10-Q for
the quarter ended June 30, 2003 filed with the SEC on
September 11, 2003).
*4.(l) Forty-third Supplemental Indenture, dated as of X
November 1, 2003, between Progress Energy Florida, Inc.
and JPMorgan Chase Bank, as Trustee (filed as Exhibit 4
to Current Report on Form 8-K filed with the SEC
on November 21, 2003).
4.(m) Forty-fourth Supplemental Indenture, dated as of X
August 1, 2004 from Progress Energy Florida, Inc.
to JPMorgan Chase Bank, as Trustee, supplement
to Indenture dated as of January 1, 1944, as
supplemented.
*4. (n) Form of Certificate representing shares of X
Florida Progress Common Stock (filed as
Exhibit 4(b) to the Florida Progress Form
10-K for the year ended December 31, 1996,
as filed with the SEC on March 27, 1997).
10.(a)(1) Amendment and Restatement, dated March 30, 2004 X
to Progress Energy Florida, Inc.'s 364-Day Revolving
Credit Agreement dated April 1, 2003.
*10.(a)(2) Progress Energy Florida 364-Day $200,000,000 Credit X
Agreement dated as of April 1, 2003 (filed as
Exhibit 10(ii) to Progress Energy Florida Form 10-Q
for the quarter ended March 31, 2003).
*10.(a)(3) Progress Energy Florida 3-Year $200,000,000 Credit X
Agreement, dated as of April 1, 2003 (filed as
Exhibit 10(iii) to the Progress Energy Florida Form
10-Q for the quarter ended March 31, 2003).
103
+*10.(b)(1) Executive Optional Deferred Compensation X X
Plan (filed as Exhibit 10.(c) to the
Florida Progress Form 10-K for the year
ended December 31, 1996 as filed with the
SEC on March 27, 1997).
+*10.(b)(2) Management Incentive Compensation Plan X X
of Florida Progress Corporation, as amended
December 14, 1999 (filed as Exhibit 10.(a) to the
Florida Progress Form 10-K for the year ended
December 31, 1999, as filed with the SEC on
March 30, 2000).
+*10.(b)(3) Progress Energy Florida Management Incentive X
Compensation Plan, effective January 1, 2001 (filed
as Exhibit 10b(25) to Annual Report on Form 10-K
for the year ended December 31, 2000,
File No. 1-15929 and No. 1-3382).
+*10.(b)(4) Florida Progress Supplemental Executive X X
Retirement Plan, as amended and restated
effective February 20, 1997 (filed as Exhibit 10.(e)
to the Florida Progress Form 10-K for the year ended
December 31, 1999, as filed with the SEC on
March 30, 2000).
-+*10.(b)(5) Resolutions of the Board of Directors of Carolina X
Power & Light Company dated May 8, 1991, amending
the Directors Deferred Compensation Plan (filed as
Exhibit 10(b), File No. 33-48607).
-+*10.(b)(6) Carolina Power & Light Company Restricted Stock X X
Agreement, as approved January 7, 1998, pursuant
to Carolina Power & Light Company's
1997 Equity Incentive Plan (filed as Exhibit No. 10
to Carolina Power & Light Company's Quarterly
Report on Form 10-Q for the quarterly period ended
March 31, 1998, File No. 1-3382).
-+*10.(b)(7) Performance Share Sub-Plan of the Carolina X X
Power & Light Company 1997 Equity
Incentive Plan, as amended January 1, 2001
(filed as Exhibit 10b(11) to the Progress Energy, Inc.
Annual Report on Form 10-K for the fiscal year ended
December 31, 2001).
+*10.(b)(8) 1997 Equity Incentive Plan, Amended and Restated X X
as of September 26, 2001 (filed as Exhibit 4.3 to
Progress Energy, Inc. Form S-8 dated September 27,
2001,
File No. 1-3382).
+*10.(b)(9) 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).
+*10.(b)(10) Progress Energy, Inc. Form of Stock Option Award X X
(filed as Exhibit 4.5 to Form S-8 dated September
27, 2001, File No. 333-70332).
104
+*10.(b)(11) Progress Energy, Inc. 2002 Equity Incentive Plan, X X
dated July 10, 2002 (filed as Exhibit 10(i) to Quarterly
Report on form 10-Q for the quarterly period ended
September 30, 2002, File No. 1-08349 and 1-03274).
+*10.(b)(12) Amended Management Incentive Compensation Plan X X
of 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).
+*10.(b)(13) 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, (filed as Exhibit 10c(11) to the Progress Energy, Inc.
Annual Report on Form 10-K for the fiscal year ended
December 31, 2004).
+*10.(b)(14) Progress Energy, Inc. Management Change-in-Control X X
Plan Amended and Restated Effective as of January 1, 2005
(filed as Exhibit 10c(12) to the Progress Energy, Inc.
Annual Report on Form 10-K for the fiscal year ended
December 31, 2004).
+*10.(b)(15) Amended Performance Share Sub-Plan of the 2002 X X
Progress Energy, Inc. Equity Incentive Plan effective
as of January 1, 2005 (filed as Exhibit 10c(13) to the
Progress Energy, Inc. Annual Report on Form 10-K
for the fiscal year ended December 31, 2004).
+*10.(b)(16) Form of Deferred Compensation Plan for Directors-- X X
Method of Payment Agreement of Progress Energy, Inc.
Effective 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).
+*10.(b)(17) Amended and Restated Progress Energy, Inc. X X
Restoration Retirement Plan effective as of
January 1, 2005 (filed as Exhibit 10c(15) to the
Progress Energy, Inc. Annual Report on Form 10-K
for the fiscal year ended December 31, 2004).
+*10.(b)(18) Amended and Restated Supplemental Senior X X
Executive Retirement Plan of Progress Energy, Inc.,
amended effective January 1, 2005 (filed as Exhibit 10c(16)
to the Progress Energy, Inc. Annual Report on Form 10-K
for the fiscal year ended December 31, 2004).
+*10.(b)(19) Amended Non-Employee Director Stock Unit X X
Plan of Progress Energy, Inc. effective as of 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).
+*10.(b)(20) Form of Progress Energy, Inc. Restricted Stock X X
Agreement pursuant to the 2002 Progress Energy, Inc.
Equity Incentive Plan, as amended July 2002
(filed as Exhibit 10c(18) to the Progress Energy, Inc.
Annual Report on Form 10-K for the fiscal year ended
December 31, 2004).
105
+*10.(b)(21) Employment Agreement dated August 1, 2000 X
between Carolina Power & Light Company and
William S. "Skip" Orser (filed as Exhibit 10(ii) to
the Progress Energy, Inc. Quarterly Report on
Form 10-Q for the quarterly period ended
September 30, 2000, File No. 1-15929
and No. 1-3382).
+*10.(b)(22) Form of Employment Agreement dated August 1, 2000 X X
between CP&L Service Company LLC and
Peter M. Scott III(filed as Exhibit 10(v) to the
Progress Energy, Inc. Quarterly Report on Form 10-Q
for the quarterly period ended September 30, 2000,
File No. 1-15929 and No. 1-3382).
+*10.(b)(23) Form of Employment Agreement dated August 1, 2000 X
between Carolina Power & Light Company and (i)
Fred Day IV, (ii) C.S. "Scotty" Hinnant, and
(iii) E. Michael Williams (filed as Exhibit 10(vi)
to the Progress Energy, Inc. Quarterly Report on
Form 10-Q for the quarterly period ended
September 30, 2000, File No. 1-15929
and No. 1-3382).
+*10.(b)(24) Employment Agreement dated November 30, 2000 X X
between Carolina Power & Light Company, Florida
Power Corporation and H. William Habermeyer (filed
as Exhibit 10.(b)(32) to Annual Report on Form 10-K for
the year ended December 31, 2000).
+*10.(b)(25) Form of Employment Agreement between Progress Energy X
Florida, Inc. and Jeffrey J. Lyash, effective December 2003.
(filed as Exhibit 10c(27) to the Progress Energy, Inc.
Annual Report on Form 10-K for the fiscal year ended
December 31, 2002, File No. 1-15929 and No. 1-3382).
+*10.(b)(26) Form of Employment Agreement effective January X X
2003 between Progress Energy Service Company LLC
and John R. McArthur (filed as Exhibit 10c(27) to the
Progress Energy, Inc. Annual Report on Form 10-K for
the fiscal year ended December 31, 2002,
File No. 1-15929 and No. 1-3382).
+*10.(b)(27) Employment Agreement dated October 1, 2003 X X
between 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 fiscal year ended December 31, 2003,
File No. 1-15929 and No. 1-3382).
+*10.(b)(28) Form of Employment Agreement dated January 1, X X
2005 between Progress Energy Carolinas, Inc.
and William D. Johnson (filed as Exhibit 10c(29)
to the Progress Energy, Inc. Annual Report on
Form 10-K for the fiscal year ended December 31, 2004).
106
*10.(c)(1) Agreement dated November 18, 2004 between X X
Pipeline, Ltd., Progress Energy, Inc. and EnCana
Oil & Gas (USA), Inc. for the sale of certain oil
and gas interests and related assets located in Texas
(filed as Exhibit 10d(1) to the Progress Energy,
Inc. Annual Report on Form 10-K for the fiscal year
ended December 31, 2004).
**10(c)(2) Precedent and Related Agreements among Florida Power X 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.)
12 Statement of Computation of Ratios X X
23.(a) Consent of Deloitte & Touche LLP X X
X Exhibit is filed for that respective company.
* 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 by Carolina Power & Light Company to Progress
Energy, Inc., effective August 1, 2000.
107
RISK FACTORS
In this section, unless the context indicates otherwise, references to "our,"
"we," "us" or similar terms refer to Progress Energy Florida, Inc. The following
section is applicable most directly to Progress Energy Florida. However, the
risk factors below are substantially applicable to our corporate parent, Florida
Progress. Risk related to synthetic fuel operations are primarily related to
Florida Progress Corporation.
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") and the Florida Public Service Commission ("FPSC")
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.
108
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.
Congress is 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.
See additional discussion of these environmental matters in Note 20 to the
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). 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. We
cannot predict the outcome or timing of any final rules or the effect that they
may have on the GridFlorida proceedings currently ongoing before the FERC.
At the state level, significant uncertainty exists with respect to what action,
if any, the FPSC will ultimately take. The Company has $4 million invested in
GridFlorida 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 GridFlorida original
structure 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 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 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
GridFlorida or an alternate combined transmission structure, we cannot predict
whether their creation will have any material adverse effect on our future
consolidated results of operations, cash flows or financial condition.
109
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 territory in 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. 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 $385 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.
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. 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, we maintain a storm damage reserve account for major
storms. With respect to storm costs in excess of the storm damage reserve
account, we may seek recovery from retail ratepayers. On November 2, 2004, we
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 our position that the
petition presents a fair projection of total cost and does not need to be
updated at this time. We 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.
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
25% and 8% 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.
For the year ended December 31, 2004, 8% 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.
110
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 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 our financial condition, results
of operations or cash flows.
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.
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 or our utility subsidiaries do not control operating
costs.
The FPSC exercises regulatory authority for review and approval of the retail
electric power rates charged within Florida. State regulators may not allow our
utility subsidiaries to increase retail rates in the manner or to the extent
requested by those subsidiaries. The FPSC may also seek to reduce retail rates.
For example, in March 2002, we entered into a Stipulation and Settlement
Agreement (the "Agreement") that required us, among other things, to reduce our
retail rates and to operate under a revenue sharing plan through 2005 which
provides for possible rate refunds to our retail customers. The Agreement will
also require increased capital expenditures for our Commitment to Excellence
program. However, if our base rate earnings fall below a 10% return on equity,
we may petition the FPSC to amend our base rates. As discussed below, in January
2005, we petitioned the FPSC for an increase in our retail base rates.
The cash costs we incur are generally not subject to being fixed or reduced by
state regulators. We will also require dedicated capital expenditures. Thus, our
ability to maintain our profit margins depends upon stable demand for
electricity and our efforts to manage our costs.
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 our then-pending rate case, we notified the FPSC
that we intend to request an increase in its base rates, effective January 1,
2006. In our notice, we 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.
111
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 percent 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, our credit ratings 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 to Progress Energy
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 one nuclear unit that represents approximately 838 MW, or
10%, of our generation capacity for the year ended December 31, 2004. Our
nuclear facility is subject to environmental, health and financial risks such as
the ability to dispose of spent nuclear fuel, the ability to maintain adequate
capital reserves for decommissioning, potential liabilities arising out of the
operation of these facilities, and the costs of securing the facilities against
possible terrorist attacks. We maintain a decommissioning trust and external
insurance coverage to minimize the financial exposure to these risks; however,
it is possible that damages could exceed the amount of our insurance coverage.
The NRC has broad authority under federal law to impose licensing and
safety-related requirements for the operation of nuclear generation facilities.
In the event of non-compliance, the NRC has the authority to impose fines or to
shut down 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 our 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.
112
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):
- --------------------------------------------------------------------------------
Company Outstanding Commercial Paper Total Long-Term Debt,
and Bank Borrowings Net
- --------------------------------------------------------------------------------
PEF 293 1,912 (a)
- --------------------------------------------------------------------------------
(a) Net of current portion, which at December 31, 2004, was $48 million.
At December 31, 2004, we had two committed credit lines that support our
commercial paper programs totaling $400 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
$225 million and an outstanding commercial paper balance of $123 million,
leaving an additional $52 million available for future borrowing under our
credit lines.
Our credit lines impose various limitations that could impact our liquidity. Our
credit facilities include defined maximum total debt to total capital (leverage)
ratios and minimum coverage ratios. At December 31, 2004, the maximum and actual
average leverage ratios, pursuant to the terms of the credit facilities, were
65% and 50.8%, respectively and the minimum and actual coverage ratios were 3.0
to 1 and 9.22 to 1, 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.
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.
113
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
Progress Energy Carolinas. The rating outlooks continue to be stable at Progress
Energy Carolinas 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.
While our long-term target credit ratings are above the minimum investment grade
ranking, we cannot assure you that any of our current ratings 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 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.
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.
Solely for purposes of this Risk Factor, "we", "our", or "the Company" refer to
Florida Progress Corporation
114
Synthetic Fuel Risks Associated With the IRS Audit
Through our Energy and Related Services 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 our 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.
Through December 31, 2004, on a consolidated basis, we have used or carried
forward approximately $550 million of tax credits generated by the Earthco
facilities. If these credits were disallowed, our one-time exposure for cash tax
payments would be $64 million (excluding interest), and earnings and equity
would be reduced by approximately $550 million, excluding interest. If we were
required to reverse approximately $550 million of tax credits and pay $64
million for taxes, our financial condition, results of operations and liquidity
would be materially and adversely impacted.
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 $550 million until the IRS issue
is resolved. We cannot predict what actions the FASB will take or how any such
actions might ultimately affect our financial position or results of operations,
but such changes could have a material impact on our 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.
115
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
$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.
Our Energy and Related Services 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 Energy and Related Services 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.
116
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
FLORIDA PROGRESS CORPORATION
Date: March 16, 2005 (Registrant)
By: /s/Robert B. McGehee
------------------------------------
Robert B. McGehee
President and
Chief Executive Officer
By: /s/Geoffrey S. Chatas
------------------------------------
Geoffrey S. Chatas
Executive Vice President and
Chief Financial Officer
By: /s/Robert H. Bazemore, Jr.
------------------------------------
Robert H. Bazemore, Jr.
Controller
(Chief Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the date indicated.
Signature Title Date
/s/ 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)
/s/ Charles W. Coker Director March 16, 2005
- ---------------------
(Charles W. Coker)
/s/ Richard L. Daugherty Director March 16, 2005
- -------------------------
(Richard L. Daugherty)
117
/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)
118
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
FLORIDA POWER CORPORATION
Date: March 16, 2005 (Registrant)
By: /s/ H. William Habermeyer, Jr.
------------------------------------
H. William Habermeyer, Jr.
President and Chief Executive Officer
By: /s/Geoffrey S. Chatas
------------------------------------
Geoffrey S. Chatas
Executive Vice President and
Chief Financial Officer
By: /s/Robert H. Bazemore, Jr.
------------------------------------
Robert H. Bazemore, Jr.
Controller
(Chief Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the date indicated.
Signature Title Date
/s/ Robert B. McGehee Director March 16, 2005
- ---------------------
(Robert B. McGehee)
/s/H. William Habermeyer, Jr. Director March 16, 2005
- -----------------------------
(H. William Habermeyer, Jr.
/s/Geoffrey S. Chatas Director March 16, 2005
- ---------------------
(Geoffrey S. Chatas)
/s/Fred N. Day IV Director March 16, 2005
- --------------------
(Fred N. Day IV)
/s/ William D. Johnson Director March 16, 2005
- ----------------------
(William D. Johnson)
/s/ William S. Orser Director March 16, 2005
- ---------------------
(William S. Orser)
/s/Peter M. Scott III Director March 16, 2005
- ---------------------
(Peter M. Scott III)
119
PROGRESS ENERGY FLORIDA, INC.
EXHIBIT 12
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND
PREFERRED DIVIDENDS COMBINED AND RATIO OF EARNINGS TO FIXED CHARGES
- -----------------------------------------------------------------------------------------------------------------
(in millions)
Years Ended December 31 2004 2003 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------
Earnings, as defined:
Net income $ 335 $ 296 $ 325 $ 311 $ 212
Fixed charges, as below 122 103 114 117 130
Income taxes 174 147 163 183 151
- -----------------------------------------------------------------------------------------------------------------
Total earnings, as defined $ 631 $ 546 $ 602 $ 611 $ 493
- -----------------------------------------------------------------------------------------------------------------
Fixed Charges, as defined:
Interest on long-term debt $ 107 $ 103 $ 99 $ 100 $ 102
Other interest 10 (6) 10 14 26
Imputed interest factor in rentals-charged
principally to operating expenses 5 6 5 3 2
- -----------------------------------------------------------------------------------------------------------------
Total fixed charges, as defined $ 122 $ 103 $ 114 $ 117 $ 130
- -----------------------------------------------------------------------------------------------------------------
Preferred dividends, as defined $ 2 $ 2 $ 3 $ 3 $ 3
- -----------------------------------------------------------------------------------------------------------------
Total fixed charges and preferred dividends
combined $ 124 $ 105 $ 117 $ 120 $ 133
- -----------------------------------------------------------------------------------------------------------------
Ratio of earnings to fixed charges 5.17 5.30 5.28 5.22 3.79
Ratio of earnings to fixed charges and
preferred dividends combined 5.09 5.20 5.15 5.09 3.71
- -----------------------------------------------------------------------------------------------------------------
120
Exhibit 23.(a)
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No.
33-51573 on Form S-3, Registration Statement No. 2-93111 on Form S-3 and
Registration Statement No. 333-74949 on Form S-3 of our reports dated March 7,
2005, relating to the consolidated financial statements and consolidated
financial statement schedule of Florida Progress Corporation and its
subsidiaries (which report on the consolidated financial statements expresses an
unqualified opinion and includes an explanatory paragraph concerning the
adoption of a new accounting principle in 2003) appearing in this Annual Report
on Form 10-K of Florida Progress Corporation for the year ended December 31,
2004.
We also consent to the incorporation by reference in Post-Effective Amendment 1
to Registration Statement No. 333-63204 on Form S-3 and Registration Statement
No. 333-103974 on Form S-3 of our reports dated March 7, 2005, relating to the
financial statements and financial statement schedule of Florida Power
Corporation d/b/a Progress Energy Florida, Inc. (PEF) (which report on the
financial statements expresses an unqualified opinion and includes an
explanatory paragraph concerning the adoption of a new accounting principle in
2003) appearing in this Annual Report on Form 10-K of PEF for the year ended
December 31, 2004.
/s/ Deloitte & Touche LLP
Raleigh, North Carolina
March 15, 2005
121