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, 2003, were $5 billion, and assets at year-end were $9 billion. Its 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 website 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 (See ITEM 1 "Business - Utility Operations - PEF") and accounts for approximately 63% and 80% of Florida Progress' revenues and assets, respectively, at year end in 2003. 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 non-utility 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 non-utility energy company, whose principal business segments are Energy and Related Services and Rail Services. Florida Progress' 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. An SEC order approving the merger of Florida Progress with Progress Energy required Progress Energy to divest of Rail Services and certain immaterial, non-regulated investments of Florida Progress by November 30, 2003. Progress Energy pursued alternatives, but did not find the right divestiture opportunity by that date. Therefore, Progress Energy applied for and was granted a three-year extension from the SEC until 2006. 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.
ACQUISITIONS
Progress Telecommunications Corporation
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 Progress Telecom, LLC (PTC LLC), a subsidiary of PTC. Subsequently, the stock of Caronet was sold to an affiliate of Odyssey for $2 million in cash and Caronet became an indirect wholly-owned subsidiary of Odyssey. Following consummation of all the transactions described above, PTC holds a 55 percent ownership interest in, and is the parent of, PTC LLC. Odyssey holds a combined 45 percent ownership interest in PTC LLC through EPIK and Caronet. See Note 4A to the financial statements for additional discussion of this transaction.
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 primary assets in the acquisition have been contributed to Progress Fuels North Texas Gas, L.P., a wholly-owned subsidiary of Progress Fuels Corporation. The total cash purchase price for the transactions was approximately $168 million. See Note 4B to the financial statements for additional discussion of this transaction.
Westchester Acquisition
In April 2002, Progress Fuels acquired 100% of Westchester Gas Company (Westchester). The acquisition included approximately 215 natural gas-producing wells, 52 miles of intrastate gas pipeline and 170 miles of gas-gathering systems. The aggregate purchase price was approximately $153 million. See Note 4C to the financial statements for additional discussion of this transaction.
DIVESTITURES
Mesa Hydrocarbons, Inc. Divestiture
In September 2003, the Finance Committee as authorized by the Progress Energy Board of Directors adopted a resolution approving the sale of certain gas-producing properties owned by Mesa Hydrocarbons, LLC, a wholly-owned subsidiary of Progress Fuels. In October 2003, the Company completed the sale of these assets. The primary components of the assets sold were oil and gas leases and wells. Net proceeds from the sale were approximately $97 million. The Company recorded this transaction in the fourth quarter of 2003. See Note 3A to the financial statements for additional discussion of this transaction.
Railcar Ltd. Divestiture
In December 2002, the Progress Energy Board of Directors adopted a resolution authorizing the sale of the majority of the assets of Railcar Ltd., a leasing subsidiary included in the Rail Services segment. An estimated impairment on assets held for sale was recognized in December 2002 to write-down the assets to be sold to fair value less the costs to sell.
In March 2003, the Company signed a letter of intent to sell the majority of Railcar Ltd. assets to The Andersons, Inc. The asset purchase agreement was signed in November 2003, and the transaction closed in February 2004. Net proceeds from the sale were approximately $82 million. See Note 3B to the financial statements.
Sale of MEMCO Barge Line, Inc.
In July 2001, Progress Energy announced the disposition of the Inland Marine Transportation segment of FPC, which was operated by MEMCO Barge Line, Inc. Inland Marine provided transportation of coal, agricultural and other dry-bulk commodities as well as fleet management services. In November 2001, Progress Energy completed the sale of the Inland Marine Transportation segment to AEP Resources, Inc., a wholly-owned subsidiary of American Electric Power. See Note 3C to the financial statements.
UTILITY OPERATIONS - PEF
GENERAL
PEF was incorporated in Florida in 1899, and is an operating public utility primarily engaged in the generation, purchase, transmission, distribution and sale of electricity. At December 31, 2003, PEF had a total summer generating capacity (including jointly-owned capacity) of approximately 8,544 megawatts (MW).
PEF provided electric service during 2003 to an average of 1.5 million customers in west central Florida. Its service area covers approximately 20,000 square miles and includes the densely populated areas around Orlando, as well as the cities of St. Petersburg and Clearwater. PEF is interconnected with 20 municipal and nine rural electric cooperative systems. Major wholesale power sales customers include Seminole Electric Cooperative, Inc., Florida Municipal Power Agency, Florida Power & Light Company and Tampa Electric Company. PEF is subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC) and the Florida Public Service Commission (FPSC).
BILLED ELECTRIC REVENUES
PEF's electric revenues billed by customer class, for the last three years, are shown as a percentage of total electric revenues in the table below:
BILLED ELECTRIC REVENUES
Revenue Class 2003 2002 2001 ------------- ---- ---- ---- Residential 55% 55% 54% Commercial 24% 24% 24% Industrial 7% 7% 7% Others 6% 6% 6% Wholesale 8% 8% 9%
Important industries in the 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 energy mix for the last three years is presented in the following table:
ENERGY MIX PERCENTAGES
Fuel Type 2003 2002 2001 --------- ---- ---- ---- Coal (a) 36% 33% 33% Oil 16% 16% 16% Nuclear 14% 15% 15% Gas 13% 15% 14% Purchased Power 21% 21% 22%
(a) Includes synthetic fuel from unrelated third parties and petroleum coke.
PEF is generally permitted to pass the cost of recoverable fuel and purchased power to its customers through fuel adjustment clauses. The future prices for and availability of various fuels discussed in this report cannot be predicted with complete certainty. However, PEF believes that its fuel supply contracts, as described below, will be adequate to meet its fuel supply needs.
PEF's average fuel costs per million British thermal units (Btu) for the last three years were as follows:
AVERAGE FUEL COST (per million Btu)
2003 2002 2001 ---- ---- ---- Coal (a) $ 2.42 $ 2.43 $ 2.16 Oil 4.38 3.77 3.81 Nuclear 0.50 0.46 0.47 Gas 5.98 4.06 4.52 Weighted-average 3.07 2.60 2.59
(a) Includes synthetic fuel from unrelated third parties and petroleum coke.
Changes in the unit price for coal, oil and gas are due to market conditions. Since these costs are primarily recovered through recovery clauses established by regulators, the fluctuation does not materially affect net income.
Purchased Power
PEF, along with other Florida utilities, buys and sells power in the wholesale market on a short-term and long-term basis. At December 31, 2003, PEF had a variety of purchase power agreements for the purchase of approximately 1,313 MW of firm power. These agreements include (1) long-term contracts for the purchase of about 474 MW of purchased power with other investor-owned utilities, including a contract with The Southern Company for approximately 414 MWs, and (2) approximately 839 MWs of capacity under contract with certain qualifying facilities (QFs). The capacity currently available from QFs represents about 10% of PEF's total installed system capacity.
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 including 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 7B to the financial statements.
Fuel and Other Cost Recovery
PEF's operating costs not covered by the utility's base rates include fuel, purchased power, energy conservation expenses and specific environmental costs. The state commission allows electric utilities to recover certain of these costs through various cost recovery clauses, to the extent the respective commission determines in an annual hearing that such costs are prudent. In addition, in December 2002, the FPSC approved an Environmental Cost Recovery Clause (ECRC) which permits the Company to recover the costs of specified environmental projects to the extent these expenses are found to be prudent in an annual hearing and not otherwise included in base rates. Costs are recovered through this recovery clause in the same manner as the other existing clause mechanisms.
The state commission's determination results in the addition of a rider to a utility's base rates to reflect the approval of these costs and to reflect any past over- or under-recovery. Due to the regulatory treatment of these costs and the method allowed for recovery, changes from year to year have no material impact on operating results.
NUCLEAR MATTERS
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). The NRC's jurisdiction encompasses broad supervisory and regulatory powers over the construction and operation of nuclear reactors, including matters of health and safety, antitrust considerations and environmental impact. PEF has a license to operate its nuclear generating plant through December 3, 2016. PEF currently has a 91.8% ownership interest in CR3. In February 2003, PEF notified the NRC of its intent to submit an application to extend the plant license in the first quarter of 2009. A condition of the operating license for each unit requires an approved plan for decontamination and decommissioning. The nuclear unit is 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.
During 2002, the NRC issued bulletins to companies that hold licenses for pressurized water reactors (PWRs) requiring information on the structural integrity of the reactor vessel head and requiring additional inspection standards. The Company filed responses as required. Inspection of the vessel head at the Company's PWR plant was performed during the previous outage. In October 2001, at CR3, one nozzle was found to have a crack and was repaired; however, no degradation of the reactor vessel head was identified. The vessel head at CR3 was replaced during its regularly scheduled refueling outage in 2003.
OTHER MATTERS
Regional Transmission Organizations
As a result of Order 2000, PEF, along with Florida Power & Light Company and Tampa Electric Company (the Applicants) filed with the FERC in October 2000 an application for approval of a GridFlorida RTO. The GridFlorida proposal is pending before both the FERC and the FPSC. See Note 7C to the financial statements for further discussion of RTOs.
Standard Market Design
In July 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000 Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). The proposed rules set forth in the SMD NOPR would require, among other things, that all transmission owning utilities transfer control of their transmission facilities to an independent third party.
Franchise Agreements
PEF holds franchises with varying expiration dates in 107 of the municipalities in which it distributes electric energy. PEF also serves 14 other municipalities and in all its unincorporated areas without franchise agreements. The general effect of these franchises is to provide for the manner in which PEF occupies rights-of-way in incorporated areas of municipalities for the purpose of constructing, operating and maintaining an energy transmission and distribution system. See Note 19 to the financial statements for further discussion of franchise agreements.
Stranded Costs
An important issue encompassed by industry restructuring is the recovery of "stranded costs." Stranded costs primarily include the generation assets of utilities whose value in a competitive marketplace would be less than their current book value, as well as above-market purchased power commitments to QFs. Thus far, all states that have passed restructuring legislation have provided for the opportunity to recover a substantial portion of stranded costs.
Assessing the amount of stranded costs for a utility requires various assumptions about future market conditions, including the future price of electricity. The single 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 Public Utility Regulatory Policies Act of 1978 (PURPA).
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' non-utility 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. 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 also produces and sells natural gas and synthetic fuel along with operating terminal services and offshore marine transportation.
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 Trackwork (E&TW).
The LRS unit is primarily focused on railroad rolling stock that includes freight cars, transit cars and locomotives, the repair and maintenance of these units, the manufacturing or reconditioning of major components for these units and scrap metal recycling. The E&TW unit focuses on rail and other track components, the infrastructure which supports the operation of rolling stock, 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 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.
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 PTC 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 percent ownership interest in, and is the parent, of PTC LLC. The accounts of PTC LLC are included in the Company's financial statements since the transaction date.
PTC LLC has data fiber network transport capabilities that stretch from New York to Miami, Florida, with gateways to Latin America and conducts primarily a carrier's carrier business. PTC LLC markets wholesale fiber-optic-based capacity service in the Eastern United States to long-distance carriers, internet service providers and other telecommunications companies. PTC LLC also markets wireless structure attachments to wireless communication companies and governmental entities. At December 31, 2003, PTC LLC owned and managed approximately 8,500 route miles and more than 420,000 fiber miles of fiber-optic cable.
PTC LLC competes with other providers of fiber-optic telecommunications services, including local exchange carriers and competitive access providers, in the Eastern United States.
Lease revenue for dedicated transport and data services is generally billed in advance on a fixed rate basis and recognized over the period the services are provided. Revenues relating to design and construction of wireless infrastructure are recognized upon completion of services (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 9 to the financial statements.
COMPETITION
Florida Progress' non-utility 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.
ITEM 2.
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, 2003, PEF's fourteen generating plants represent a flexible mix of fossil, nuclear, combustion turbine and combined cycle resources with a total summer generating capacity (including jointly-owned capacity) of 8,544 MW. At December 31, 2003, PEF had the following generating facilities:
(a) Amounts represent PEF's net summer peak rating, gross of co-ownership interest in plant capacity. (b) Facilities are jointly-owned. The capacities shown include joint owners' share. (c) PEF and Georgia Power Company (Georgia Power) are co-owners of a 143 MW advanced combustion turbine located at PEF's Intercession City site (P11). Georgia Power has the exclusive right to the output of this unit during the months of June through September. PEF has that right for the remainder of the year. (d) During 2003, a power uprate increased the net summer capability of this unit to 838 MWs. The Maximum Dependable Capability (MDC) was restated in January 2004.
At December 31, 2003, including both the total generating capacity of 8,544 MWs and the total firm contracts for purchased power of 1,313 MWs, PEF had total capacity resources of approximately 9,857 MWs.
Several entities have acquired undivided ownership interests in CR3 in the aggregate amount of 8.22%. PEF and Georgia Power are co-owners of a 143 MW advance combustion turbine located at PEF's Intercession City site (P11). Georgia Power has the exclusive right to the output of this unit during the months of June through September. PEF has that right for the remainder of the year. Otherwise, PEF has good and marketable title to its principal plants and important units, subject to the lien of its mortgage and deed of trust, with minor exceptions, restrictions and reservations in conveyances, as well as minor defects of the nature ordinarily found in properties of similar character and magnitude. PEF also owns certain easements over private property on which transmission and distribution lines are located.
At December 31, 2003, PEF had approximately 5,000 circuit miles of transmission lines.
DIVERSIFIED OPERATIONS
Progress Fuels controls, either directly or through subsidiaries, coal reserves located in eastern Kentucky and southeastern Virginia of approximately 60 million tons and controls, through mineral leases, additional estimated coal reserves of approximately 18 million tons. The reserves controlled include substantial quantities of high quality, low sulfur coal that is appropriate for use at PEF's existing generating units. Progress Fuels' total production of coal during 2003 was approximately 3.5 million tons.
In connection with its coal operations, Progress Fuel's business units own and operate an underground mining complex located in southeastern Kentucky and southwestern Virginia. Other subsidiaries own and operate surface and underground mines, coal processing and loadout facilities, a river terminal facility in eastern Kentucky, a railcar-to-barge loading facility in West Virginia, and two bulk commodity terminals on the Kanawha River near Charleston, West Virginia. Progress Fuels and its subsidiaries employ both Company and contract miners in their mining activities.
Progress Fuels has oil and gas leases in East Texas, North Texas and Louisiana with total proven natural gas and oil reserves of approximately 358 billion cubic feet equivalent. Progress Fuels' natural gas and oil production in 2003 was 25.4 billion cubic feet equivalent.
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 5,300 railcars and 100 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. PTC LLC incorporates more than 420,000 fiber miles in its network, including over 185 Points-of-Presence, or physical locations where a presence for network access exists.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
1. Wallace Bentley, et al. v. City of Tallahassee, Interstate Fibernet, Inc. and Florida Power Corporation, Circuit Court for Leon County, Florida. Case No. 98-7107.
In December 1998, PEF was served with a class action lawsuit seeking damages, declaratory and injunctive relief for the alleged improper use of electric transmission easements. The plaintiffs contend that the licensing of fiber-optic telecommunications lines to third parties or telecommunications companies for other than PEF's internal use along the electric transmission line right-of-way exceeds the authority granted in the easements. In June 1999, the plaintiffs amended their complaint to add PTC as a defendant and adding counts for unjust enrichment and constructive trust. In January 2000, the trial court conditionally certified the class statewide. In mediation held in March 2000, the parties reached a tentative settlement of this claim. In January 2001, the trial court preliminarily approved the amended settlement agreement, certified the settlement class and approved the class notice. In November 2001, the trial court issued a final order approving the settlement. Several objectors to the settlement appealed the order to the 1st District Court of Appeal. In February 2003, the appellate court issued an opinion upholding the trial court's subject matter jurisdiction over the case, but reversing the trial court's order approving the mandatory settlement class for purposes of declaratory and injunctive relief. The appellate court remanded the case to the trial court for further proceedings. The Company filed a motion requesting discretionary review before the Florida Supreme Court, which was pending before the First District Court of Appeal. Subsequent to filing these motions, the Company and the appellants reached a settlement resolving the appellants' dispute. The settlement was contingent upon the trial court approving a mandatory class settlement consistent with the First District Court of Appeal's February 2003 opinion. In May 2003 the trial court entered an Amended Final Judgment again approving the mandatory class settlement, consistent with the First District Court of Appeals' February 2003 opinion. No appeals have been taken from that judgment, and the time to appeal has expired. In July 2003, PEF, the class representatives and the appellants filed a joint withdrawal of all pending motions with the First District Court of Appeal. The First District Court of Appeal acknowledged the withdrawal of all pending motions and issued a mandate in July 2003. Under the terms of the mandatory class settlement, PEF made settlement payments to class members in August 2003. The settlement payments did not have a material adverse effect upon PEF's financial condition or results of operations. (See Note 19 to the Financial Statements -Legal Matters.)
2. 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.
Calgon Carbon corporation (Calgon) filed a complaint in January 1998, asserting securities fraud, breach of contract and other claims in connection with the sale to it by two of the defendants in December 1996 of their interests in Advanced Separation Technologies, Incorporated (AST), a corporation engaged in the business of designing and assembling proprietary separation equipment. Prior to closing, Progress Capital, a wholly-owned subsidiary of Florida Progress, owned 80% of the outstanding stock of AST and Potomac Capital Investment Corporation (an entity unaffiliated with Progress Capital or Florida Progress) owned 20%. Calgon paid Progress Capital an aggregate of approximately $58 million (producing net proceeds of approximately $56 million after certain fees and expenses) in respect of Progress Capital's share of AST's stock. Calgon claims that AST's assets and revenues were overstated and liabilities and expenses were understated for 1996. Calgon also alleges undisclosed facts relating to accounting methodology, poor products, manufacturing and quality control problems and undisclosed warranty claims. Calgon seeks damages, punitive damages and the right to rescind the purchase. 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 of 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. The Company cannot predict the outcome of this matter, but will present a vigorous defense. (See Note 19 to the Financial Statements.)
3. 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) interests 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 was filed in the Circuit Court for Broward County, Florida on March 4, 2003 (the Florida Global Case). The Florida Global Case asserts claims for breach of the Asset Purchase Agreement and other contract and tort claims related to the Progress Affiliates' alleged interference with Global's rights under the Asset Purchase Agreement. The Florida Global Case requests an unspecified amount of compensatory damages, as well as declaratory relief. On December 15, 2003, the Progress Affiliates filed a motion to dismiss the Third Amended Complaint in the Florida Global Case.
The second suit 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 in April 2003.
In May 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. In August 2003, the Wake County Superior Court denied Global's motion to dismiss and entered an order staying the North Carolina Global Case, pending the outcome of the Florida Global Case. The Progress Affiliates have appealed the Superior Court's order staying the case; Global has cross appealed the denial of its motion to dismiss for lack of personal jurisdiction. The North Carolina Court of Appeals has not set a hearing date for the Progress Affiliates' Appeal or Global's cross appeal. The Company cannot predict the outcome of these matters, but will vigorously defend against all allegations.
ITEM 4.
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.
ITEM 5. MARKET FOR THE REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
FLORIDA PROGRESS
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.
Florida Progress receives dividends from PEF. PEF's Amended Articles of Incorporation and its Indenture dated as of January 1, 1944, under which it issues first mortgage bonds, contain provisions restricting dividends in certain circumstances. At December 31, 2003, PEF's ability to pay dividends was not limited by these restrictions.
Florida Progress and Progress Capital have entered into a Second Amended and Restated Guaranty and Support Agreement dated as of August 7, 1996, pursuant to which Florida Progress has unconditionally guaranteed the payment of Progress Capital's debt (as defined in the agreement).
Florida Progress did not issue any equity securities during 2003 that were not registered under the Securities Act.
Florida Progress 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's Amended Articles of Incorporation, and its Indenture dated as of January 1, 1944, as supplemented, under which it issues first mortgage bonds, contain provisions restricting dividends in certain circumstances. At December 31, 2003, PEF's ability to pay dividends was not limited by these restrictions.
PEF did not issue any equity securities during 2003 that were not registered under the Securities Act.
PEF does not have any equity compensation plans under which its equity securities are issued.
ITEM 6.
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).
ITEM 7.
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, 2003 and 2002 were $443 million and $230 million, respectively. The increase in income from continuing operations in 2003 is primarily due to: o Impairments recognized in 2002 related to the telecommunications and railcar business operations. o An increase in retail growth at PEF in 2003. o Growth in natural gas production and sales. o Higher synthetic fuel sales. o Lower interest charges.
Partially offsetting these items were the: o Net impact of the 2002 Florida Rate settlement. o Increased benefit-related expenses. o Higher depreciation expense at both PEF and the Energy and Related Services segment.
These and other key operating results are discussed by segment below.
PEF
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 all 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 $295 million and $323 million in 2003 and 2002, respectively. The decrease in profits in 2003, when compared to 2002, was primarily due to the impact of the 2002 rate case stipulation, higher benefit costs primarily related to higher pension expense, higher depreciation and the impact of unfavorable weather. These amounts were partially offset by continued customer growth and lower interest charges.
PEF's profits in 2003 and 2002 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 7B to the Financial Statements for further discussion of the rate case settlement.
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, 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:
PEF's electric energy sales for the years ended December 31, 2003 and 2002 and the percentage change by year and by customer class are as follows:
PEF's revenues, excluding fuel revenues of $1,487 million and $1,402 million in 2003 and 2002, respectively, increased $5 million from 2002 to 2003. Revenues were favorably impacted in 2003 by $49 million, primarily as a result of customer growth (approximately 36,000 additional customers). In addition, other operating revenues were favorable $16 million due primarily to higher wheeling and transmission revenues and higher service charge revenues (resulting from increased rates allowed under the 2002 rate settlement). These increases were partially offset by the negative impact of the rate settlement, lower wholesale sales and the impact of unfavorable weather. The provision for revenue sharing increased $12 million in 2003 compared to the $5 million provision recorded in 2002. Revenues in 2003 were also impacted by the final resolution of the 2002 revenue sharing provisions as the FPSC issued an order in July 2003 that required PEF to refund an additional $18 million to customers related to 2002. The 9.25% rate reduction from the settlement accounted for an additional $46 million decline in revenues. The 2003 impact of the rate settlement was partially offset by the absence of the prior year interim rate refund of $35 million. Lower wholesale revenues (excluding fuel revenues) of $17 million and the $8 million impact of milder weather also reduced base revenues during 2003.
Expenses
Fuel and Purchased Power Fuel used in generation and purchased power increased $87 million in 2003 when compared to $1,349 million in 2002. The increase is due to higher costs to generate electricity and higher purchased power costs as a result of an increase in volume due to system requirements and higher natural gas prices.
Operations and Maintenance (O&M) O&M expense increased $49 million in 2003, when compared to $591 million in 2002. The increase is largely related to increases in certain benefit-related expenses of $36 million which was primarily due to higher pension expense of $27 million during the year. Additionally higher operational costs related to the CR3 nuclear outage and plant maintenance contributed to the increase.
Depreciation and Amortization Depreciation and amortization increased $12 million in 2003 when compared to $295 million in 2002. Depreciation increased primarily as a result of additional assets being placed into service which was partially offset by lower amortization of the Tiger Bay regulatory asset of $2 million, which was fully amortized in September 2003.
Interest Expense Interest charges decreased $15 million in 2003 compared to $106 million in 2002 primarily due to the reversal of a regulatory liability for accrued interest related to previously resolved tax matters.
Income Tax Expense In 2003 and 2002 $13 million and $20 million, respectively, of the tax benefit that was previously held at the Company's holding company was allocated to PEF. As required by an SEC order issued in 2002, holding company tax benefits are allocated to profitable subsidiaries. Other fluctuations in income taxes are primarily due to changes in pretax income.
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 $166 million and $122 million for 2003 and 2002, respectively. The following summarizes Energy and Related Services' segment profits for the years ended 2003 and 2002:
- ---------------------------------------------------------------------- 2003 2002 - ---------------------------------------------------------------------- (in millions) - ----------------------------------------------------------------------
Synthetic fuel operations $ 134 $ 102 Natural gas operations 34 10 Coal fuel and other operations (2) 10 ----------------------------- Segment profits $ 166 $ 122 - ----------------------------------------------------------------------
Synthetic Fuel Operations
Synthetic fuel operations generated profits of $134 million and $102 million for the years ended December 31, 2003 and 2002, 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 2003 and 2002.
- --------------------------------------------------------------------------- (in millions) 2003 2002 - ---------------------------------------------------------------------------
Tons sold 7.5 6.5
After-tax losses (excluding tax credits) $ (79) $ (68) Tax credits 213 170 -------------------------------- Net Profit $ 134 $ 102 - ---------------------------------------------------------------------------
Synthetic fuels net profits for 2003 increased as compared to 2002 due to higher sales, improved margins and a higher tax credit per ton. The 2003 tax credits also include a $7.5 million favorable true-up from 2002. Additionally, synthetic fuels results in 2003 include 13 months of operations for some facilities. Prior to the fourth quarter of 2003, results of these synthetic fuels operations had been recognized one month in arrears. The net impact of this action increased net income by $2 million for the year.
Natural Gas Operations
Natural gas operations generated profits of $34 million and $10 million for the years ended December 31, 2003 and 2002, respectively. The increase in production and price resulting from the acquisitions of Westchester Gas in 2002 and North Texas Gas in the first quarter of 2003 drove increased revenue and earnings in 2003 compared to 2002. In October 2003, the Company completed the sale of certain gas-producing properties owned by Mesa Hydrocarbons, LLC. See Notes 4B, 4C and 3A to the Financial Statements for discussions of the Westchester Gas Company and the North Texas Gas acquisitions and the Mesa disposition. The following summarizes the production and revenues of the natural gas and oil operations for 2003 and 2002 by facility.
- ---------------------------------------------------------------------------- 2003 2002 - ---------------------------------------------------------------------------- Production in billion cubic feet equivalent Mesa 4.8 6.0 Westchester 13.5 5.8 NTG 7.1 - ------------------------- Total Production 25.4 11.8 -------------------------
Revenues in millions Mesa $ 13 $ 15 Westchester 65 24 NTG 38 - ------------------------- Total Revenues $ 116 $ 39 -------------------------
Gross Margin In millions of $ $ 91 $ 29 As a % 78% 74% - ----------------------------------------------------------------------------
Coal Fuel and Other Operations
Coal fuel and other operations generated losses of $2 million and profits of $10 million for the years ended December 31, 2003 and 2002, respectively. Coal segment profits decreased $12 million from 2002 to 2003. This decrease is due primarily to the recording of an impairment on certain assets at the Kentucky May Coal Mine for $10 million after-tax. See Note 9 to the financial statements.
Rail Services
Rail's operations represent the activities of Progress Rail Services Corporation (Progress Rail) and include railcar and locomotive repair, trackwork, rail parts reconditioning and sales, scrap metal recycling, railcar leasing and other rail-related services.
Rail contributed losses of $1 million and $47 million for the years ended December 31, 2003 and 2002, respectively. The net loss in 2002 includes a $45 million after-tax impairment on assets held for sale related to Railcar Ltd., a leasing subsidiary of Progress Rail. In March 2003, the Company signed a letter of intent to sell the majority of Railcar Ltd. assets to the Andersons, Inc. The asset purchase agreement was signed in November 2003, and the transaction closed on February 12, 2004. As such assets of Railcar Ltd. have been reported as assets held for sale. See Note 3B to the Financial Statements for discussion of this planned divestiture. Excluding the impairment loss recorded in 2002, profits for Rail were flat year over year 2003 compared to 2002. Rail Services' results for both years were affected by a downturn in the overall economy, decreases in rail service procurement by major railroads and a downturn in the domestic scrap market.
An SEC order approving the merger of FPC and CP&L Energy required the Company to divest of Progress Rail by November 30, 2003. However, the SEC has granted an extension until 2006.
OTHER
The Other segment includes telecommunications, holding company and financing expenses and had net losses from continuing operations of $17 million and $168 million in 2003 and 2002, respectively. The decrease in the net loss is due primarily to the absence of asset impairments and related charges in the telecommunications business unit that were recorded in the prior year.
PTC had net losses of $3 million and $156 million for 2003 and 2002, respectively. The increase in earnings in 2003, when compared to 2002, is primarily due to asset impairments and after-tax charges of $144 million. See Note 9 to the Financial Statements for further discussion of these charges. 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 PTC 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 PTC LLC. Odyssey holds a combined 45 percent ownership interest in PTC LLC through EPIK and Caronet. The accounts of PTC LLC are included in the Company's Consolidated Financial Statements since the transaction date.
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. 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 has 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. Note 7 to the financial statements provides additional information related to the impact of utility regulation on PEF.
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.
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 9 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 9 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.
Synthetic Fuels Tax Credits
Florida Progress, through the Energy and Related Services business unit, produces coal-based solid synthetic fuel from coal fines. The production and sale of the synthetic fuel qualifies for tax credits under Section 29 of the Internal Revenue Code (Section 29) if certain requirements are satisfied, including a requirement that the synthetic fuel differs significantly in chemical composition from the feedstock used to produce such synthetic fuel and that the fuel was produced from a facility that was placed in service before July 1, 1998. Any synthetic fuel tax credit amounts not utilized due to the imposition of the alternative minimum tax are carried forward indefinitely. See Note 13 to the financial statements for further information on the synthetic fuel tax credits. All of Florida Progress's synthetic fuel facilities have received private letter rulings from the Internal Revenue Service (IRS) with respect to their operations. These tax credits are subject to review by the IRS, and if Progress Energy fails to prevail through the administrative or legal process, there could be a significant tax liability owed for previously taken Section 29 credits, with a significant impact on earnings and cash flows.
Pension Costs
As discussed in Note 14 to the financial statements, Florida Progress and PEF maintains 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.
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, Florida Progress lowered the discount rate to 6.3% at December 31, 2003, which will increase the 2004 benefit costs recognized, all other factors remaining constant. However, after a few years of negative asset returns due to equity market declines, plan assets performed very well in 2003, with returns of approximately 30%. That positive asset performance will result in decreased pension cost in 2004. Evaluations of the effects of these factors have not been completed, but Florida Progress estimates that 2004 total cost recognized for pension will decrease by approximately $12 million from the amount recorded in 2003, due in large part to these factors.
Florida Progress has pension plan assets, with a fair value of approximately $849 million at December 31, 2003. 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, 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 latter 1990's, recent years' market declines and the market rebound in 2003. A 0.25% change in the expected rate of return for 2003 would have changed 2003 pension cost by approximately $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 construction expenditures. PEF's estimated capital requirements for 2004, 2005 and 2006 are approximately $430 million, $490 million and $450 million, respectively.
In addition to funding its construction commitments with cash from operations, the companies access the capital markets through the issuance of commercial paper, secured and unsecured notes, preferred securities and equity through 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 under "Risk Factors".
PEF's interim financing needs are funded primarily through its commercial paper program. 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 of $664 million decreased $17 million compared with 2002 due primarily to a change in deferred taxes. The utility's operating cash flow increased by $36 million, due primarily to changes in working capital, partially offset by increased deferred fuel costs as a result of rising prices.
CASH FLOW FROM INVESTING ACTIVITIES
Cash requirements for investing activities during 2003 of $938 million increased $281 million when compared with 2002. The increase was due primarily to diversified property additions in 2003.
PEF's construction expenditures, including nuclear fuel, totaled $599 million and $550 million for 2003 and 2002, 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.
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 at the Hines Energy Complex.
Progress Fuels' capital expenditures for 2003 and 2002 were $313 million and $102 million, respectively. These capital expenditures have been primarily for the expansion of its natural gas operations.
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.
CASH FLOW FROM FINANCING ACTIVITIES
During 2003, PEF took advantage of low interest rates and refinanced several issues of debt. Long-term debt financing activity was limited to refinancing of PEF's debt discussed below.
In February 2003 PEF issued $425 million of 4.80% First Mortgage Bonds, Due March 1, 2013 and $225 million of 5.90% First Mortgage Bonds Due March 1, 2033. Proceeds from the bond issue were used to redeem the aggregate outstanding balance ($150 million) of 8% First Mortgage Bonds Due December 1, 2022, to
refinance PEF's secured and unsecured indebtedness, $70 million of which matured on March 1, 2003, and $145 million of which matured on July 1, 2003 and to repay the balance of PEF's outstanding commercial paper, with the remaining proceeds used to reduce the outstanding balance of notes payable to affiliated companies.
PEF's 8% First Mortgage Bonds due December 1, 2022 were redeemed at a price of 103.75% of the principal amount outstanding ($150 million) plus accrued interest to the redemption date of March 24, 2003.
In July 2003, $110 million of PEF's First Mortgage Bonds, 6.0% Series and $35 million of medium-term notes, 6.62% Series, matured.
In November 2003, PEF issued $300 million of First Mortgage Bonds, 5.10% Series, Due December 1, 2015. Proceeds from this issuance were used to redeem in December 2003 the $100 million aggregate outstanding balance of its 7% First Mortgage Bonds, Due 2023 at 103.19% of the principal amount of such bonds and to reduce the outstanding balance of its notes payable to affiliated companies.
The amount of debt issued by PEF in November took into consideration debt maturities and other financing needs for 2004. As such, PEF does not anticipate the need to issue long-term debt in 2004.
The Company's financial policy precludes issuing commercial paper in excess of its supporting lines of credit. At December 31, 2003, the total amount of commercial paper outstanding was zero. The Company is required to pay minimal annual commitment fees to maintain its credit facilities.
In April 2003, PEF entered into a new $200 million 364-day credit agreement and a new $200 million three-year credit agreement, replacing its prior credit facilities (which had been a $90 million 364-day facility and a $200 million five-year facility). The new PEF credit facilities contain a defined maximum total debt to total capital ratio of 65%; at December 31, 2003 the calculated ratio, as defined, was 51.5%. The new credit facilities also contain a requirement that the ratio of EBITDA, as defined in the facilities, to interest expense to be at least 3 to 1; at December 31, 2003 the calculated ratio, as defined, was 9.22 to 1.
PEF's credit facilities include a provision under which lender could refuse to advance funds in the event of a material adverse change in the borrower's financial condition.
Each of these credit agreements contains a cross-default provision for defaults of indebtedness in excess of $10 million. Under these provisions, if the applicable borrower or certain affiliates fail to pay various debt obligations in excess of $10 million the lenders could accelerate payment of any outstanding borrowing and terminate their commitments to the credit facility.
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, 2003, there were no outstanding loans against these facilities. PEF currently has filed registration statements under which it can issue an aggregate of $50 million of various long-term debt securities.
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-1 A-2 Senior Secured Debt A1 BBB Senior Unsecured Debt A2 BBB FPC Capital I Preferred Stock* Baa1 BB+ Progress Capital Holdings, Inc. Senior Unsecured Debt* A3 BBB-
*Guaranteed by Florida Progress Corporation
These ratings reflect the current views of these rating agencies and no assurances can be given that these ratings will continue for any given period of time. However, the Company monitors its financial condition as well as market conditions that could ultimately affect its credit ratings.
The Company and its subsidiaries' debt indentures and credit agreements do not contain any "ratings 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.
In February 2003, Moody's Investors Service lowered the outlook of PEF (A1 senior secured) and Progress Capital Holdings Inc. (A3 senior unsecured) from stable to negative and lowered the trust preferred rating of FPC Capital I from A3 to Baa1 with a negative outlook.
In February 2003, Fitch Ratings Service downgraded the ratings of PEF. The ratings outlook is stable. PEF's senior secured rating was changed to A- from AA- and its senior unsecured rating was changed to BBB+ from A+. PEF's short-term rating was changed to from+.
In August 2003, Standard & Poor's Ratings Services (S&P) credit rating agency lowered its corporate credit rating on PEF and Florida Progress to BBB from BBB+. The outlook of the Companies' ratings was changed from negative to stable.
These credit rating changes have not had a material impact on the companies' access to capital or their financial results.
Interest Rate Derivatives
Progress Energy and its subsidiaries, including 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 uses interest rate derivative instruments to adjust the fixed and variable rate debt components of its debt portfolio and to hedge interest rates with regard to future fixed rate debt issuances.
Progress Fuels periodically enters into derivative instruments to hedge its exposure to price fluctuations on natural gas sales. At December 31, 2003, Progress Fuels had approximately 19 Bcf of cash flow hedges in place for its natural gas production. These positions extend through December 2005.
NEW ACCOUNTING STANDARDS
See Note 2 to the financial statements for a discussion of the anticipated impact of new accounting standards.
ITEM 7A.
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 changes in interest rates with respect to its long-term debt and fluctuations in the return on marketable securities with respect to its nuclear decommissioning trust funds. The Company manages its market risk in accordance with its established risk management policies, which may include entering into various derivative transactions.
These financial instruments are held for purposes other than trading. The risks discussed below do not include the price risks associated with non-financial instrument transactions and positions associated with Florida Progress' operations, such as sales commitments and inventory.
INTEREST RATE RISK
The Company manages its interest rate risks through the use of a combination of fixed and variable rate debt. Variable rate debt has rates that adjust in periods ranging from daily to monthly. Interest rate derivative instruments may be used to adjust interest rate exposures and to protect against adverse movements in rates.
The following tables provide information at December 31, 2003 and 2002, about the Company's interest rate risk sensitive instruments. The tables present principal cash flows and weighted-average interest rates by expected maturity dates for the fixed 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.
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, 2003 and 2002, about PEF's interest rate risk sensitive instruments.
(a) Treasury Rate Lock agreement on $35 million designed as cash flow hedge of anticipated fixed-rate debt issuance.
MARKETABLE SECURITIES PRICE RISK
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, 2003 and 2002, the fair values of these funds were approximately $433 million and $374 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 is exposed to the effects of market fluctuations in the price of natural gas, electricity and other energy-related products marketed and purchased as a result of its ownership of energy-related assets. The Company's exposure to these fluctuations is significantly limited by the cost-based regulation of PEF.
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 and trading activity using natural gas and electricity financial instruments. Refer to Note 15 to the financial statements for additional information with regard to the Company's commodity contracts and use of derivative financial instruments.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The following consolidated financial statements, supplementary data and consolidated financial statement schedules are included herein:
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.
INDEPENDENT AUDITORS' REPORT
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) at December 31, 2003 and 2002, and the related Florida Progress consolidated statements of income and comprehensive income, of common equity, and of cash flows and the related PEF statements of income and comprehensive income, of common equity, and of cash flows for each of the three years in the period ended December 31, 2003. 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 auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Florida Progress and of PEF, respectively, at December 31, 2003 and 2002, and the results of their respective operations and cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 5F to the financial statements, in 2003, the Companies adopted Statement of Financial Accounting Standards No. 143.
/s/ DELOITTE & TOUCHE LLP Raleigh, North Carolina February 20, 2004
FLORIDA PROGRESS CORPORATION CONSOLIDATED STATEMENTS of INCOME AND COMPREHENSIVE INCOME
See Notes to Financial Statements.
FLORIDA PROGRESS CORPORATION CONSOLIDATED BALANCE SHEETS
See Notes to Financial Statements.
FLORIDA PROGRESS CORPORATION CONSOLIDATED STATEMENTS of CASH FLOWS
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 4C). o In December 2003, Progress Telecommunications Corporation (PTC) and Caronet, Inc. both indirectly wholly-owned subsidiaries of Progress Energy, and EPIK Communications, Inc., a wholly-owned subsidiary of Odyssey Telecorp, Inc., contributed substantially all of their assets and transferred certain liabilities to Progress Telecom, LLC, a subsidiary of PTC (See Note 4A).
See Notes to Financial Statements.
FLORIDA PROGRESS CORPORATION CONSOLIDATED STATEMENTS of COMMON EQUITY
o In the opinion of management, all adjustments necessary to fairly present amounts shown for interim periods have been made. Results of operations for an interim period may not give a true indication of results for the year. Certain reclassifications have been made to previously reported amounts to conform to the current year's presentation. Amounts for 2003 were restated for the removal of reporting results for certain Energy and Related Service segment operations one month in arrears (See Note 1B). o Fourth quarter 2003 includes impairment related to Kentucky May of $15 million ($10 million after-tax) (See Note 9). o Third quarter 2002 includes impairment and other charges related to Progress Telecommunications Corporation, of $233 million ($137 million after-tax) (See Note 9). o Fourth quarter 2002 includes estimated impairment on assets held for sale of Railcar Ltd. of $67 million ($45 million after-tax) (See Note 3B).
See Notes to Financial Statements.
FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA STATEMENTS of INCOME AND COMPREHENSIVE INCOME
See Notes to Financial Statements.
FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA BALANCE SHEETS
See Notes to Financial Statements.
FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA STATEMENTS of CASH FLOWS
See Notes to Financial Statements.
FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA STATEMENTS of COMMON EQUITY
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.
See Notes to Financial Statements.
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.
Unconsolidated investments in companies over which the Company does not have control, but has the ability to exercise significant influence over operating and financial policies (generally 20% - 50% ownership), are accounted for under the equity method of accounting. Other investments are stated principally at cost. These equity and cost investments, which total approximately $22 and $14 million at December 31, 2003 and 2002, respectively, are included in miscellaneous property and investments on the Company's Consolidated Balance Sheets. The primary components of this balance are the Company's investment in FPC Capital I of $9 million in 2003 and the Company's investment in affordable housing of $8 and $9 million at December 31, 2003 and 2002, respectively.
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 2002 and 2001 have been reclassified to conform to the 2003 presentation.
C. 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 The Company recognizes electric utility revenues as service is rendered to customers. Operating revenues include unbilled electric utility revenues earned when service has been delivered but not billed by the end of the accounting period. Diversified business revenues are recognized at the time products are shipped or as services are rendered. Leasing activities are accounted for in accordance with SFAS No. 13, "Accounting for Leases." Revenues 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.
Excise Taxes The Company 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, 2003, 2002 and 2001, gross receipts tax and franchise taxes of approximately $136 million, $132 million and $133 million, respectively, are included in taxes other than on income on the accompanying Statements of Income and Comprehensive Income. These approximate amounts are also included in electric operating revenues.
Income Taxes Progress Energy and its affiliates file a consolidated federal income tax return. The consolidated income tax of Progress Energy is allocated to 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 carry over of uncompensated tax benefits. Progress Energy tax benefits not related to acquisition interest expense are allocated to profitable subsidiaries, beginning in 2002, in accordance with a PUHCA order. Income taxes are provided as if 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 to the extent they cannot be or have not been utilized in the annual consolidated federal income tax returns (See Note 13).
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:
Utility Plant Utility plant in service is stated at historical cost less accumulated depreciation. The Company capitalizes all construction-related direct labor and material costs of units of property as well as indirect construction costs. The cost of renewals and betterments is also capitalized. Maintenance and repairs of property, and replacements and renewals of items determined to be less than units of property, are charged to maintenance expense as incurred. The cost of units of property replaced or retired, less salvage, is charged to accumulated depreciation. Removal, disposal and decommission costs were charged to regulatory liabilities in 2003 and cost of removal in 2002. The Company follows the guidance in SFAS No. 143, "Accounting for Asset Retirement Obligations," to account for legal obligations associated with the retirement of certain tangible long-lived assets.
Depreciation and Amortization - Utility Plant For financial reporting purposes, substantially all depreciation of utility plant other than nuclear fuel is computed on the straight-line method based on the estimated remaining useful life of the property, adjusted for estimated salvage (See Note 5A). The Florida Public Service Commission (FPSC) can also grant approval to accelerate or reduce depreciation and amortization of utility assets (See Note 7).
Amortization of nuclear fuel costs, including disposal costs associated with obligations to the U.S. Department of Energy (DOE) and costs associated with obligations to the DOE for the decommissioning and decontamination of enrichment facilities is computed primarily on the units-of-production method and charged to fuel used in electric generation in the accompanying Statements of Income and Comprehensive Income. In the Company's retail jurisdictions, 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.
Allowance for Doubtful Accounts The Company maintains an allowance for doubtful accounts receivable, which totaled approximately $15 million and $28 million at December 31, 2003 and 2002, respectively, and is included in the accounts receivable balance in the accompanying Consolidated Balance Sheets. PEF's allowance for doubtful accounts receivable totaled $2 million at December 31, 2003 and 2002 and is included in the accounts receivable balance in the Balance Sheets.
Inventory The Company accounts for inventory using the average-cost method.
Regulatory Assets and Liabilities PEF's regulated operations are subject to SFAS No. 71, which allows a regulated company to record costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a nonregulated enterprise. Accordingly, 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 7A).
Diversified Business Property Diversified business property is stated at cost less accumulated depreciation. If an impairment loss is recognized on an asset, the fair value becomes its new cost basis. The costs of renewals and betterments are capitalized. The cost of repairs and maintenance is charged to expense as incurred. Depreciation is computed on a straight-line basis over the estimated useful lives as indicated in Note 5B. Depletion of mineral rights is provided on the units-of-production method based upon the estimates of recoverable amounts of clean mineral.
The Company uses the full cost method to account for its natural gas and oil properties. Under the full cost method, substantially all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of natural gas and oil reserves are capitalized. These capitalized costs include the costs of all unproved properties 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 over the life of the Company's proved reserves.
Goodwill and Intangible Assets Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142), and no longer amortizes goodwill. Instead, goodwill is subject to at least an annual assessment for impairment by applying a two-step fair value-based test. This assessment could result in periodic impairment charges. Prior to the adoption of SFAS No. 142, the Company amortized goodwill on a straight-line basis over a period not exceeding 40 years. Intangible assets are being amortized based on the economic benefit of their respective lives.
Unamortized Debt Premiums, Discounts and Expenses Long-term debt premiums, discounts and issuance expenses of PEF are amortized over the life of the related debt using the straight-line method. Any expenses or call premiums associated with the reacquisition of debt obligations by PEF are amortized over the applicable life using the straight-line method consistent with ratemaking treatment.
Derivatives Effective January 1, 2001, the Company adopted 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 (See Note 15).
Environmental The Company accrues environmental remediation liabilities when the criteria for SFAS No. 5, "Accounting for Contingencies," have been met. Environmental expenditures are expensed as incurred or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as additional information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recognized when their receipt is deemed probable.
Impairment of Long-lived Assets and Investments The Company reviews the recoverability of long-lived tangible and intangible assets whenever indicators exist. Examples of these indicators include current period losses, combined with a history of losses or a projection of continuing losses, or a significant decrease in the market price of a long-lived asset group. If an indicator exists, then the asset group is tested for recoverability by comparing the carrying value to the sum of undiscounted expected future cash flows directly attributable to the asset group. If the asset group is not recoverable through undiscounted cash flows, then an impairment loss is recognized for the difference between the carrying value and the fair value of the asset group. The accounting for impairment of long-lived assets is based on SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which was adopted by the Company effective January 1, 2002. Prior to the adoption of this standard, impairments were accounted for under SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," which was superceded by SFAS No. 144.
The Company reviews its investments to evaluate whether or not a decline in fair value below the carrying value is an other-than-temporary decline. The Company considers various factors, such as the investee's cash position, earnings and revenue outlook, liquidity and management's ability to raise capital in determining whether the decline is other-than-temporary. If the Company determines that other-than-temporary decline exists in the value of its investments, it is the Company's policy to write-down these investments to fair value. See Note 9 for a discussion of impairment evaluations performed and charges taken.
Under the full cost method of accounting for natural gas and oil properties, total capitalized costs are limited to a ceiling based on the present value of discounted (at 10%) future net revenues using current prices, plus the lower of cost or fair market value of unproved properties. If the ceiling (discounted revenues) is not equal to or greater than total capitalized costs, the Company is required to write-down capitalized costs to this level. The Company performs this ceiling test calculation every quarter. No write-downs were required in 2003, 2002 or 2001.
Subsidiary Stock Transactions Gains and losses realized as a result of common stock sales by the Company's subsidiaries are recorded in the Company's Consolidated Statements of Income and Comprehensive Income, except for any transactions that must be credited directly to equity in accordance with the provisions of SAB No. 51, "Accounting for Sales of Stock by a Subsidiary".
2. Impact of New Accounting Standards
SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" In May 2003, the Financial Accounting Standard Board (FASB) issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." The adoption of SFAS No. 150 did not have an impact on the Company's financial position or results of operations as of and for the periods ended December 31, 2003.
EITF Issue No. 03-04, "Accounting for `Cash Balance' Pension Plans" In May 2003, the FASB Emerging Issues Task Force (EITF) reached consensus in EITF Issue No. 03-04, "Accounting for `Cash Balance' Pension Plans" (EITF 03-04), to specifically address the accounting for certain cash balance pension plans. The consensus reached in EITF 03-04 requires certain cash balance pension plans to be accounted for as defined benefit plans. For cash balance plans described in the consensus, the consensus also requires the use of the traditional unit credit method for purposes of measuring the benefit obligation and annual cost of benefits earned as opposed to the projected unit credit method. The Company has historically accounted for its cash balance plan as a defined benefit plan; however, the Company was required to adopt the measurement provisions of EITF 03-04 at its cash balance plan's measurement date of December 31, 2003. Any differences in the measurement of the obligations as a result of applying the consensus were reported as a component of actuarial gain or loss. The on-going effects of this standard are dependent on other factors that also affect the determination of actuarial gains and losses and the subsequent amortization of such gains and losses. However, the adoption of EITF 03-04 is not expected to have a material effect on the Company's results of operations or financial position.
SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." The statement amends and clarifies SFAS No. 133 on accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. The new guidance incorporates decisions made as part of the Derivatives Implementation Group (DIG) process, as well as decisions regarding implementation issues raised in relation to the application of the definition of a derivative. SFAS No. 149 is generally effective for contracts entered into or modified after June 30, 2003. Interpretations and implementation issues with regard to SFAS No. 149 continue to evolve. The statement had no significant impact on the Company's accounting for contracts entered into subsequent to the statement's effective date (See Note 15). Future effects, if any, on the Company's results of operations and financial condition will be dependent on the specifics of future contracts entered into with regard to guidance provided by the statement.
FIN No. 46, "Consolidation of Variable Interest Entities" In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46). This interpretation provides guidance related to identifying variable interest entities and determining whether such entities should be consolidated. FIN No. 46 requires an enterprise to consolidate a variable interest entity when the enterprise (a) absorbs a majority of the variable
interest entity's expected losses, (b) receives a majority of the entity's expected residual returns, or both, as a result of ownership, contractual or other financial interests in the entity. Prior to the effective date of FIN No. 46, entities were generally consolidated by an enterprise that had control through ownership of a majority voting interest in the entity. FIN No. 46 originally applied immediately to variable interest entities created or obtained after January 31, 2003. During 2003, the Company did not participate in the creation of, or obtain a new variable interest in, any variable interest entity. In December 2003, the FASB issued a revision to FIN No. 46 (FIN No. 46R), which modified certain requirements of FIN No. 46 and allowed for the optional deferral of the effective date of FIN No. 46R until March 31, 2004. However, entities subject to FIN No. 46R that are deemed to be special-purpose entities (as defined in FIN No. 46R) must implement either FIN No. 46 or FIN No. 46R at December 31, 2003. The Company has elected to apply FIN No. 46 to special-purpose entities as of December 31, 2003. Because the Company expects additional transitional guidance to be issued, it has elected to apply FIN No. 46R to non-special-purpose entities as of March 31, 2004.
Prior to the adoption of FIN No. 46, the Company consolidated the FPC Capital I trust (the Trust), which holds FPC-obligated mandatorily redeemable preferred securities (See Note 11F). The Trust is a special-purpose entity as defined in FIN No. 46R, and therefore the Company applied FIN No. 46 to the Trust at December 31, 2003. The Trust is a variable interest entity, but the Company does not absorb a majority of the Trust's expected losses and therefore is not its primary beneficiary. Therefore, the Company deconsolidated the Trust at December 31, 2003. This deconsolidation resulted in recording an additional equity investment in the Trust of approximately $9 million and an increase in outstanding debt of $9 million. See Note 11F for a discussion of the Company's guarantees with the Trust.
The Company also has interests in several other variable interest entities created before January 31, 2003, for which the Company is not the primary beneficiary. These arrangements include equity investments in approximately six limited partnerships, limited liability corporations and venture capital funds. The aggregate maximum loss exposure at December 31, 2003 under these arrangements totals approximately $11 million. The creditors of these variable interest entities do not have recourse to the general credit of the Company in excess of the aggregate maximum loss exposure.
In February 2004, the Company became aware that certain long-term purchase power and tolling contracts may be considered variable interests under FIN No. 46R. The Company has various long-term purchase power and tolling contracts with other utilities and certain qualifying facility plants. The Company believes the counterparties to these contracts are not special-purpose entities and, therefore, FIN No. 46R would not apply to these contracts until March 31, 2004. The Company has not yet completed its evaluation of these contracts to determine if the Company needs to consolidate these counterparties under FIN No. 46R and will continue to monitor developing practice in this area.
3. Divestitures
A. 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, which is included in the Fuels segment. Net proceeds of approximately $97 million 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.
B. Railcar Ltd. Divestiture
In December 2002, the Progress Energy Board of Directors adopted a resolution approving the sale of Railcar Ltd., a subsidiary included in the Rail Services segment. In accordance with SFAS No. 144, an estimated pre-tax impairment of $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 Company's Consolidated Statements of Income and Comprehensive Income (See Note 9).
The assets of Railcar Ltd. have been grouped as assets held for sale and are included in other current assets on the Company's Consolidated Balance Sheets at December 31, 2003 and 2002. The assets are recorded at approximately $75 million and $24 million at December 31, 2003 and 2002, respectively, which reflects the Company's estimates of the fair value expected to be realized from the sale of these assets less costs to sell. The primary component of assets held for sale at December 31, 2003 was property and equipment of $74 million. The primary component of assets held for sale at December 31, 2002 was current assets of $22 million. The net
increase in assets held for sale from December 31, 2002 to December 31, 2003 was primarily attributable to the purchase of railcars in 2003 that were subject to off-balance sheet obligations at December 31, 2002. In addition to the assets held for sale, the Company is subject to certain commitments under operating leases (See Note 19).
In March 2003, the Company signed a letter of intent to sell the majority of Railcar Ltd. assets to The Andersons, Inc. In November 2003, the asset purchase agreement was signed, and the transaction closed in February 2004. Proceeds from the sale were approximately $82 million. The Company was relieved of the majority of the operating lease commitments when the assets were sold.
C. 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 results of operations for 2001 have been restated for the discontinued operations of the Inland Marine Transportation segment. The net income of these operations is reported in the Company's Consolidated Statements of Income and Comprehensive Income as discontinued operations.
Results of discontinued operations for year ended December 31, 2001, were as follows in millions:
Revenues $ 143
Earnings before income taxes 5 Income taxes 2 ----------- Net earnings 3 Loss on disposal of discontinued operations, including provision of $5 for pre-tax operating income during phase-out period (net of applicable income tax benefit of $8) (24) ----------- Loss from discontinued operations $ (21) ===========
The net gain on disposal of discontinued operations in the Company's Consolidated Statements of Income and Comprehensive 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 and Comprehensive Income (See Note 19E).
4. Acquisitions and Business Combinations
A. Progress Telecommunications Corporation
In December 2003, Progress Telecommunications Corporation (PTC) and Caronet, Inc. (Caronet), both wholly-owned subsidiaries of Progress Energy, and EPIK Communications, Inc. (EPIK), a wholly-owned subsidiary of Odyssey Telecorp, Inc. (Odyssey), contributed substantially all of their assets and transferred certain liabilities to Progress Telecom, LLC (PTC LLC), a subsidiary of PTC. Subsequently, the stock of Caronet was sold to an affiliate of Odyssey for $2 million in cash and Caronet become a wholly-owned subsidiary of Odyssey. Following consummation of all the transactions described above, PTC holds a 55% ownership interest in, and is the parent of PTC LLC. Odyssey holds a combined 45% ownership interest in PTC LLC through EPIK and Caronet. The accounts of PTC LLC are included in the Company's Consolidated Financial Statements since the transaction date. The minority interest is included in other liabilities and deferred credits in the Company's Consolidated Balance Sheets.
The transaction was accounted for as a partial acquisition of EPIK through the issuance of the stock of a consolidated subsidiary. The contributions of PTC's and Caronet's net assets were recorded at their carrying values of approximately $31 million. EPIK's contribution was recorded at its estimated fair value of $22 million using the purchase method, and was initially allocated as follows: property and equipment - $27 million; other current assets - $9 million; current liabilities - $21 million; and goodwill - $7 million. The goodwill was assigned to the Company's Other business segment and will not be deductible for tax purposes. The purchase price allocation is a preliminary estimate, based on available information,
internal estimates and certain assumptions management believes are reasonable. Accordingly, the purchase price allocation is subject to finalization in 2004 pending the completion of internal and external appraisals of assets acquired. No gain or loss was recognized on the transaction. The pro forma results of operations reflecting the acquisition would not be materially different than the reported results of operations for the years ended December 31, 2003 or 2002.
B. Acquisition of Natural Gas Reserves
During 2003, Progress Fuels Corporation entered into several independent transactions to acquire approximately 200 natural gas-producing wells with proven reserves of approximately 190 billion cubic feet (Bcf) from Republic Energy, Inc. and three other privately-owned companies, all headquartered in Texas. The total cash purchase price for the transactions was $168 million.
C. Westchester Acquisition
In April 2002, Progress Fuels acquired 100% of Westchester Gas Company (Westchester). The acquisition included approximately 215 natural gas-producing wells, 52 miles of intrastate gas pipeline and 170 miles of gas-gathering systems located within a 25-miles radius of Jonesville, Texas, on the Texas-Louisiana border.
The aggregate purchase price of approximately $153 million consisted of cash consideration of approximately $22 million and the issuance of 2.5 million shares of Progress Energy common stock valued at approximately $129 million. The purchase price included approximately $2 million of direct transaction costs. The final purchase price was allocated to oil and gas properties, intangible assets, diversified business property, net working capital and deferred tax liabilities for approximately $152 million, $9 million, $32 million, $5 million and $45 million, respectively. The $9 million intangible asset recorded relates to customer contracts acquired as part of the acquisition and are being amortized over their respective lives (See Note 8).
The acquisition was accounted for using the purchase method of accounting and, accordingly, the results of operations for Westchester have been included in the Company's Consolidated Financial Statements since the date of acquisition. The pro forma results of operations reflecting the acquisition would not be materially different than the reported results of operations for the years ended December 31, 2002 or 2001.
5. Property, Plant and Equipment
A. Utility Plant
The balances of utility plant in service at December 31 are listed below, with a range of depreciable lives for each:
(in millions) 2003 2002 --------------- ------------ Production plant (7-33 years) $ 3,821 $ 3,433 Transmission plant (30-75 years) 1,012 976 Distribution plant (12-50 years) 2,894 2,728 General plant and other (8-75 years) 423 340 --------------- ------------ Utility plant in service $ 8,150 $ 7,477 =============== ============
Substantially all of the electric utility plant is pledged as collateral for the first mortgage bonds of PEF (See Note 11).
Allowance for funds used during construction (AFUDC) represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated assets. As prescribed in the regulatory uniform systems of accounts, AFUDC is charged to the cost of the plant. The equity funds portion of AFUDC is credited to other income and the borrowed funds portion is credited to interest charges. Regulatory authorities consider AFUDC an appropriate charge for inclusion in the rates charged to customers by the utilities over the service life of the property. The composite AFUDC rate for PEF's electric utility plant was 7.8% in 2003, 2002 and 2001.
Depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 2.3% in 2003 and 2002 and 3.2% in 2001, respectively. The depreciation provisions related to utility plant were $172 million, $162 million and $225 million in 2003, 2002 and 2001, 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 5D) and regulatory approved expenses (See Note 7).
Amortization of nuclear fuel costs, for the years ended December 31, 2003, 2002 and 2001 were $31 million, $32 million and $29 million, respectively.
B. Diversified Business Property
The following is a summary of diversified business property at December 31, with a range of depreciable lives for each:
Diversified business depreciation expense was $92 million, $66 million and $69 million for the years ended December 31, 2003, 2002 and 2001, respectively. The synthetic fuel facilities are being depreciated through 2007 when the Section 29 tax credits will expire.
C. Joint Ownership of Generating Facilities
PEF is entitled to shares of the generating capability and output of Crystal River Unit No. 3 (CR3) equal to its ownership interest. PEF also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. PEF's share of expenses for the jointly-owned facility is included in the appropriate expense category. The co-owner of Intercession City Unit P-11 (P11) has exclusive rights to the output of the unit during the months of June through September. PEF has that right for the remainder of the year. PEF's ownership interest in CR3 and P11 is listed below with related information at December 31, ($ in millions):
D. Decommissioning, Dismantlement and Cost of Removal Provisions
PEF's nuclear plant depreciation expenses include a provision for future decommissioning costs, which are recoverable through rates charged to customers. In January 2002, PEF received regulatory approval from the FPSC to decrease its retail provision for nuclear decommissioning from approximately $21 million annually to approximately $8 million annually, effective January 2001. As a result of the settlement in the PEF rate case, PEF suspended accruals on its reserves for retail nuclear decommissioning through December 2005.
The provision for retail fossil plant dismantlement was previously suspended per a 1997 FPSC settlement agreement, but resumed mid-2001. The annual provision, approved by the FPSC in 2001, was $9 million. The accrual for retail fossil dismantlement reserves was suspended again in 2002 by the Florida Rate Case settlement (See Note 7B).
PEF's cost of removal provisions, which are included in depreciation and amortization expense, were $72 million, $68 million and $66 million in 2003, 2002 and 2001, respectively. These amounts represent the expense recognized for the disposal or removal of utility assets. The FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143), that changed the accounting for the decommissioning, dismantlement and cost of removal provisions (See Note 5F).
E. Insurance
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 110 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 million with respect to the primary coverage, $6 million with respect to the decontamination, decommissioning and excess property coverage, and $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 $10.9 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 is expected to approve revisions to the Price Anderson Act during 2004, that could include increased limits and assessments per reactor owned. The final outcome of this matter cannot be predicted at this time.
Under the NEIL policies, if there were multiple terrorism losses occurring within one year, NEIL would make available one industry aggregate limit of $3.2 billion, along with any amounts it recovers from reinsurance, government indemnity or other sources up to the limits for each claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply. For nuclear liability claims arising out of terrorist acts, the primary level available through commercial insurers is now subject to an industry aggregate limit of $300 million. The second level of coverage obtained through the assessments discussed above would continue to apply to losses exceeding $300 million and would provide coverage in excess of any diminished primary limits due to the terrorist acts aggregate.
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 7A).
F. Asset Retirement Obligations
SFAS No. 143, "Accounting for Asset Retirement Obligations," provides accounting and disclosure requirements for retirement obligations associated with long-lived assets and was adopted by the Company effective January 1, 2003. This statement requires that the present value of retirement costs for which the Company has a legal obligation be recorded as a liability with an equivalent amount added to the asset cost and depreciated over an appropriate period. The liability is then accreted over time by applying an interest method of allocation to the liability. Cumulative accretion and accumulated depreciation were recognized for the time period from the date the liability would have been recognized had the provisions of this statement been in effect, to the date of adoption of this statement.
Upon adoption of SFAS No. 143, PEF recorded asset retirement obligations (AROs) totaling $303 million for nuclear decommissioning of irradiated plant. PEF used an expected cash flow approach to measure these obligations. This amount includes accruals recorded prior to adoption totaling $284 million, which were previously recorded in cost of removal. The related asset retirement costs, net of accumulated depreciation, recorded upon adoption totaled $39 million for regulated operations. The cumulative effect of adoption of this statement had no impact on the income of PEF, as the effects were offset by the establishment of a regulatory liability in the amount of $20 million, pursuant to SFAS No. 71. The
regulatory liability represents the amount by which previously recorded accruals exceeded the cumulative accretion and accumulated depreciation for the time period from the date the liability would have been recognized had the provisions of this statement been in effect to the date of adoption.
The asset retirement costs related to nuclear decommissioning of irradiated plant, net of accumulated depreciation, totaled $37 million for regulated operations at December 31, 2003. 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 $433 million at December 31, 2003 and $374 million at December 31, 2002. Net unrealized gains on the nuclear decommissioning trust fund were included in regulatory liabilities in 2003 and cost of removal in 2002.
The Company also recorded AROs totaling $10 million for coal mine operations, synthetic fuel operations and gas production of Progress Fuels Corporation. The Company used an expected cash flow approach to measure these obligations. This amount includes accruals recorded prior to adoption totaling $5 million, which were previously recorded in other liabilities and deferred credits. The related asset retirement costs, net of accumulated depreciation, recorded upon adoption totaled $3 million for nonregulated operations. 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 and Comprehensive Income for the year ended December 31, 2003.
The Company's AROs for coal mine operations, synthetic fuel operations and gas production of Progress Fuels Corporation totaled $20 million at December 31, 2003. The related asset retirement costs, net of accumulated depreciation, totaled $4 million for nonregulated operations at December 31, 2003. The following table shows the changes to the asset retirement obligations during the year ended December 31, 2003. Additions relate primarily to additional reclamation obligations at coal mine operations of Progress Fuels Corporation.
Pro forma net income has not been presented for prior years because the pro forma application of SFAS No. 143 to prior years would result in pro forma net income not materially different from the actual amounts reported.
The Company has identified but not recognized ARO liabilities related to electric transmission and distribution and telecommunications assets as the result of easements over property not owned by the Company. These easements are generally perpetual and only require retirement action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements, as the Company intends to utilize these properties indefinitely. In the event the Company decides to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time.
PEF previously recognized removal, decommissioning and dismantlement costs as a component of accumulated depreciation in accordance with regulatory treatment. At December 31, 2003, such costs totaling $1,175 million were included in regulatory liabilities on the Balance Sheets and consist of removal costs of $970 million, decommissioning costs for non-irradiated areas at nuclear facilities of $62 million and amounts previously collected for dismantlement of fossil generation plants of $143 million. At December 31, 2002, such costs totaling $1,452 million were included in cost of removal on the Balance Sheets and consist of removal costs of $913 million, removal costs for both the irradiated and non-irradiated areas at nuclear facilities of $397 million and amounts previously collected for dismantlement of fossil generation plants of $142 million. With the adoption of SFAS No. 143 in 2003, removal costs related to the irradiated areas at nuclear facilities are reported as asset retirement obligations on the 2003 Balance Sheets.
In January 2003, the Staff of the FPSC issued a notice of proposed rule development to adopt provisions relating to accounting for AROs under SFAS No. 143. Accompanying the notice was a draft rule presented by the Staff which adopts the provisions of SFAS No. 143 along with the requirement to record the difference between amounts prescribed by the FPSC and those used in the application of SFAS No. 143 as regulatory assets or regulatory liabilities, which was accepted by all parties. The Commission approved this draft rule and a final order was issued in the third quarter of 2003. Therefore, the adoption of the statement had no impact on the income of PEF due to the establishment of a regulatory liability pursuant to SFAS No. 71.
6. Inventory
At December 31, inventory was comprised of the following:
7. Regulatory Matters
A. Regulatory Assets and Liabilities
As a regulated entity, PEF is subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." 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:
Except for portions of deferred fuel, all assets earn a return or the cash has not yet been expended, in which case the assets are offset by liabilities that do not incur a carrying cost. The utility expects to fully recover these assets and refund the liabilities through customer rates under current regulatory practice.
The Tiger Bay regulatory asset, for contract termination costs, is recovered pursuant to an agreement between PEF and several intervening parties, which was approved by the FPSC in June 1997. The amortization of the regulatory asset is calculated using revenues collected under the fuel adjustment clause as if the purchased power agreements related to the facility were still in effect, less the actual fuel costs and the related debt interest expense. Under the plan, PEF had the option to accelerate the amortization at its discretion. During 2001 PEF received approval from the FPSC to apply deferred revenues from the prior year towards the acceleration of the Tiger Bay regulatory asset amortization $63 million plus interest. Including accelerated amounts, PEF recorded amortization expense of $47 million, $49 million and $131 million in 2003, 2002 and 2001, respectively. By fourth quarter 2003 the regulatory asset was fully amortized.
In compliance with a regulatory order, PEF accrues a reserve for maintenance and refueling expenses anticipated to be incurred during scheduled nuclear plant outages.
B. Retail Rate Matters
PEF's retail rates are set by the FPSC, while its wholesale rates are governed by the FERC. PEF's last general retail rate case was approved in 1992 and allowed a 12% regulatory return on equity with an allowed range between 11% and 13%. PEF previously operated under an agreement committing several parties not to seek any reduction in its base rates or authorized return on equity. That agreement expired in June 2001. The FPSC initiated a rate proceeding in 2001 regarding PEF's future base rates. In March 2002, the parties in PEF's rate case entered into a Stipulation and Settlement Agreement (the Agreement) related to retail rate matters. The Agreement was approved by the FPSC in April 2002. The Agreement is generally effective from May 2002 through December 2005; provided, however, that if PEF's base rate earnings fall below a 10% return on equity, PEF may petition the FPSC to amend its base rates.
The Agreement provides that PEF will reduce its retail revenues from the sale of electricity by an annual amount of $125 million. The Agreement also provides that PEF will operate under a Revenue Sharing Incentive Plan (the Plan) through 2005, and thereafter until terminated by the FPSC, that establishes annual revenue caps and sharing thresholds. The Plan provides that retail base rate revenues between the sharing thresholds and the retail base rate revenue caps will be divided into two shares - a 1/3 share to be received by PEF's shareholders, and a 2/3 share to be refunded to PEF's retail customers; provided, however, that for the year 2002 only, the refund to customers was limited to 67.1% of the 2/3 customer share. The retail base rate revenue sharing threshold amounts for 2003 and 2002 were $1,333 million and $1,296 million, respectively, and will increase $37 million each year thereafter. The Plan also provides that all retail base rate revenues above the retail base rate revenue caps established for each year will be refunded to retail customers on an annual basis. For 2002, the refund to customers was limited to 67.1% of the retail base rate revenues that exceeded the 2002 cap. The retail base revenue cap for 2003 and 2002 was $1,393 million and $1,356 million, respectively, and will increase $37 million each year thereafter. Any amounts above the retail base revenue caps will be refunded 100% to customers. At December 31, 2003, $17 million has been accrued and will be refunded to customers by March 2004. Approximately $5 million was originally returned in March 2003 related to 2002 revenue sharing. However, in February 2003, the parties to the Agreement filed a motion seeking an order from the FPSC to enforce the Agreement. In this motion, the parties disputed PEF's calculation of retail revenue subject to refund and contended that the refund should be approximately $23 million. In July 2003, the FPSC ruled that PEF must provide an additional $18 million to its retail customers related to the 2002 revenue sharing calculation. PEF recorded this refund in the second quarter of 2003 as a charge against electric operating revenue and refunded this amount by October 2003.
The Agreement also provides that beginning with the in-service date of PEF's Hines Unit 2 and continuing through December 2005, PEF will be allowed to recover through the fuel cost recovery clause a return on average investment and depreciation expense for Hines Unit 2, to the extent such costs do not exceed the Unit's cumulative fuel savings over the recovery period. Hines Unit 2 is a 516 MW combined-cycle unit that was placed in service in December 2003.
PEF 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. In addition, PEF is authorized, at its discretion, to accelerate the amortization of certain regulatory assets over the term of the Agreement. In 2003, PEF recorded $16 million of accelerated amortization of a regulatory liability related to a settled tax matter. There was no accelerated depreciation or amortization expense recorded for the year ended December 31, 2002.
Under the terms of the Agreement, PEF agreed to continue the implementation of its four-year Commitment to Excellence Reliability Plan and expects to achieve a 20% improvement in its annual System Average Interruption Duration Index by no later than 2004. If this improvement level is not achieved for calendar years 2004 or 2005, PEF will provide a refund of $3 million for each year the level is not achieved to 10% of its total retail customers served by its worst performing distribution feeder lines.
The Agreement also provided that PEF was required to refund to customers $35 million of revenues PEF collected during the interim period since March 2001. This one-time retroactive revenue refund was recorded in the first quarter of 2002 and was returned to retail customers by December 2002. Any additional refunds under the Agreement are recorded when they become probable.
In February 2003, PEF petitioned the FPSC to increase its fuel factors due to continuing increases in oil and natural gas commodity prices. In March 2003, the FPSC approved PEF's petition and new rates became effective. In September 2003, PEF asked the FPSC to approve a cost adjustment in its annual fuel filing, primarily related to rising costs of fuel that will increase retail customer bills beginning January 2004. The total amount of the fuel adjustment requested above current levels was $322 million. In November 2003 the FPSC approved PEF's request and new rates became effective January 2004.
C. Regional Transmission Organizations and Standard Market Design
In 2000, the FERC issued Order No. 2000 on Regional Transmission Organizations (RTOs), which set minimum characteristics and eight functions for transmission entities, including independent system operators and transmission companies that are required to become FERC-approved RTOs. As a result of Order 2000, PEF, along with Florida Power & Light Company and Tampa Electric Company, filed and received provisional approval from the FERC, for a GridFlorida RTO. However, in July 2001, the FERC issued orders recommending that companies in the Southeast engage in mediation to develop a plan for a single RTO for the Southeast. PEF participated in the mediation. The FERC has not issued an order specifically on this mediation.
In July 2002, FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). If adopted as proposed, the rules set forth in the SMD NOPR would materially alter the manner in which transmission and generation services are provided and paid for. PEF filed comments in November 2002 and supplement comments in January 2003. In April 2003, the FERC released a White Paper on the Wholesale Market Platform. The White Paper provides an overview of what the FERC currently intends to include in a final rule in the SMD NOPR docket. The White Paper retains the fundamental and most protested aspects of SMD NOPR, including mandatory RTOs and the FERC's assertion of jurisdiction over certain aspects of retail service. FERC has not yet issued a final rule on SMD NOPR.
PEF has $4 million invested GridFlorida at December 31, 2003. Given the regulatory uncertainty of the ultimate timing, structure and operations of GridFlorida or an alternate combined transmission structure, PEF cannot predict the effect on future results of operations, cash flows or financial condition. Furthermore, the SMD NOPR presents several uncertainties, including what percentage of the investment in GridFlorida will be recovered, how the elimination of transmission charges, as proposed in the SMD NOPR, will impact PEF, and what amount of capital expenditures will be necessary to create a new wholesale market
8. Goodwill and Other Intangible Assets
Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets." This statement clarifies the criteria for recording of other intangible assets separately from goodwill. Effective January 1, 2002, goodwill was no longer subject to amortization over its estimated useful life. Instead, goodwill is subject to at least an annual assessment for impairment which could result in periodic impairment charges. As required by SFAS No. 142, the results for the prior years have not been restated. A reconciliation of net income as if SFAS No. 142 had been adopted is presented below for the year ended December 31, 2001.
(in millions) Reported net income $ 244 Goodwill amortization 2 ------------------- Adjusted net income $ 246 ===================
The Company's carrying amount of goodwill at December 31, 2003 was $10 million and at December 31, 2002 and 2001 was $11 million, in the Fuels segment. In December 2003, $7 million in goodwill was acquired as part of the PTC business combination and is in the Other segment (See Note 4A). The Company completed the annual goodwill impairment test for the Fuels segment in the second quarter of 2003, which indicated that the Company's goodwill was not impaired. The first annual test for the Other segment will be performed in 2004, since the goodwill was acquired in 2003. PEF has no goodwill at December 31, 2003 or 2002 or 2001.
The Company has $9 million of net intangible assets at December 31, 2003 and no significant intangible assets at December 31, 2002. The $9 million arose from the final purchase price allocation for a contract acquired as part of the Westchester acquisition net of amortization to date (See Note 4C). PEF has no significant intangible assets at December 31, 2003 or 2002.
9. 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, 2002 and 2001, the Company recorded impairments and other charges of approximately $15 million, $300 million and $170 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.
The 2002 amount includes an estimated impairment of assets held for sale of $67 million related to Railcar, Ltd. (See Note 3B). 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.
Due to results of divestiture efforts and the decision to retain the Rail Services business segment in the near term, coupled with prior and current year losses and a continued decline in the rail services industry, the Company evaluated the recoverability of rail long-lived assets and associated goodwill. Fair value was generally determined based on discounted cash flows. As a result of this review, the Company recorded asset impairments, primarily goodwill, of $161 million pre-tax ($108 million after-tax) during the fourth quarter of 2001.
The Company continually reviews its investments to determine whether a decline in fair value below the cost basis is other-than-temporary. During the fourth quarter of 2001, the Company determined that the decline in fair value of its affordable housing investments, held by Progress International Holdings, a subsidiary of Progress Capital Holdings, Inc. (Progress Capital) was other-than-temporary. As a result, the Company has recorded investment impairments for other-than-temporary declines in the fair value of its affordable housing investments. Investment write-downs of $9 million pre-tax are included in other, net on the Company's Consolidated Statements of Income and Comprehensive Income.
10. Equity
A. Common and Preferred Stock
Common stock at December 31, 2003 and 2002 consisted of the following
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 $168 million, $220 million and $90 million during 2003, 2002 and 2001, respectively. The Company paid dividends to Progress Energy of $301 million, $303 million and $249 million during 2003, 2002 and 2001, 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, 2003 and 2002 consisted of the following (in millions):
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 non-bargaining unit employees and certain part-time non-bargaining 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 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 $4 million and $2 million for the year ended December 31, 2003 and 2002, respectively. Matching and incentive costs totaled approximately $11 million, $10 million and $9 million for the years ended December 31, 2003, 2002 and 2001, respectively, including 2001 amounts incurred under the previous Florida Progress Plan.
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, 2003, 2002 and 2001 approximately 3.0 million, 2.9 million and 2.4 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, approximately 0.5 million and 0.4 million options, respectively, were granted in 2002 and approximately 0.4 million were granted to both companies in 2001.
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.
The total amount expensed by the Company for other stock-based compensation under these plans was $9 million, $5 million and $3 million in 2003, 2002 and 2001, respectively.
C. Accumulated Other Comprehensive Loss
Components of accumulated other comprehensive loss for Florida Progress and PEF at December 31, 2003 and 2002 are as follows:
11. Debt and Credit Facilities
A. Debt and Credit
At December 31, the Company's (including PEF) long-term debt consisted of the following (maturities and weighted-average interest rates at December 31, 2003):
At December 31, 2003, PEF had committed lines of credit which are used to support its commercial paper borrowings and had no outstanding loans. 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 ------------------------------------------------------
364-Day (expiring 3/31/04) $ 200 3-Year (expiring 4/1/06) 200 ------------------ $ 400 ==================
At December 31, 2003, PEF had no outstanding commercial paper and other short-term debt classified as short-term obligations. At December 31, 2002, PEF had $257 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, 2002 was 1.55%.
The combined aggregate maturities of Florida Progress long-term debt for 2004 through 2008 are approximately, in millions, $68, $49, $109, $124 and $127, respectively. PEF's aggregate maturities of long-term debt for 2004 through 2008 are approximately, in millions, $43, $48, $48, $89 and $82, respectively.
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, 2003, PEF's total debt to total capital ratio was 51.5%.
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, 2003, this ratio was 9.22 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 in the borrower's financial condition.
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 material adverse change 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.
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, 2003, 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, 2003, PEF's common stock equity was approximately 52.5% of total capitalization.
C. Secured Obligations
PEF's first mortgage bonds are secured by their respective mortgage indentures. 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, 2003, PEF had approximately $1,571 million 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
Florida Progress has fully guaranteed the outstanding debt obligations for Progress Capital, a wholly-owned subsidiary of Florida Progress. At December 31, 2003 and 2002, Progress Capital had $165 million and $223 million, respectively; in medium term notes outstanding which are recorded on the Company's Consolidated Balance Sheets.
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 15.
F. Company-Obligated Mandatorily Redeemable Cumulative Quarterly Income Preferred Securities of an Unconsolidated Subsidiary Trust Holding Solely Florida Progress Guaranteed Subordinated Deferrable Interest Notes
In April 1999, FPC Capital I (the Trust), an indirect wholly-owned subsidiary of FPC, issued 12 million shares of $25 par cumulative FPC-obligated mandatorily redeemable preferred securities (Preferred Securities) due 2039, with an aggregate liquidation value of $300 million and an annual distribution rate of 7.10%. Prior to the adoption of FIN No. 46, the Company consolidated the Trust, which holds the Preferred Securities. The Trust is a special-purpose entity, and therefore the Company applied FIN No. 46 to the Trust at December 31, 2003 (See Note 2). The adoption of FIN No. 46 required the Company to deconsolidate the Trust at December 31, 2003.
The existence of the Trust is for the sole purpose of issuing the Preferred Securities and the common securities and using the proceeds thereof to purchase from Florida Progress Funding Corporation (Funding Corp.) its 7.10% Junior Subordinated Deferrable Interest Notes (subordinated notes) due 2039, for a principal amount of $309 million. The subordinated notes and the Notes Guarantee (as discussed below) are the sole assets of the Trust. Funding Corp.'s proceeds from the sale of the subordinated notes were advanced to Progress Capital and used for general corporate purposes including the repayment of a portion of certain outstanding short-term bank loans and commercial paper.
FPC has fully and unconditionally guaranteed the obligations of Funding Corp. under the subordinated notes (the Notes Guarantee). In addition, FPC has guaranteed the payment of all distributions related to the $300 million Preferred Securities required to be made by the Trust, but only to the extent that the Trust has funds available for such distributions (Preferred Securities Guarantee). The Preferred Securities Guarantee, considered together with the Notes Guarantee, constitutes a full and unconditional guarantee by FPC of the Trust's obligations under the Preferred Securities.
The subordinated notes may be redeemed at the option of Funding Corp. beginning in 2004 at par value plus accrued interest through the redemption date. The proceeds of any redemption of the subordinated notes will be used by the Trust to redeem proportional amounts of the Preferred Securities and common securities in accordance with their terms. Upon liquidation or dissolution of Funding Corp., holders of the Preferred Securities would be entitled to the liquidation preference of $25 per share plus all accrued and unpaid dividends thereon to the date of payment.
Prior to December 2003, these Preferred Securities were classified as long-term debt on the Company's Consolidated Balance Sheets. After deconsolidation of the Trust at December 31, 2003, FPC's subordinated notes payable to the Trust are classified as affiliate long-term debt on the Company's December 31, 2003 Consolidated Balance Sheet.
12. Fair Value of Financial Instruments
At December 31, 2003 and 2002, there were miscellaneous investments, consisting primarily of investments in company-owned life insurance and other benefit plan assets, with carrying amounts of approximately $66 million and $64 million, respectively, included in miscellaneous other property and investments. At PEF, these investments had carrying amounts of $33 million at December 31, 2003 and 2002. 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 $2,922 million and $2,485 million at December 31, 2003 and 2002, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $3,105 million and $2,654 million at December 31, 2003 and 2002, respectively. The carrying amount of PEF's long-term debt, including current maturities, was $1,947 million and $1,461 million at December 31, 2003 and 2002, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $2,061 million and $1,592 million at December 31, 2003 and 2002, respectively.
External trust funds have been established to fund certain costs of nuclear decommissioning. These nuclear decommissioning trust funds are invested in stocks, bonds and cash equivalents. Nuclear decommissioning trust funds are presented on the Balance Sheets at amounts that approximate fair value. Fair value is obtained from quoted market prices for the same or similar investments.
13. Income Taxes
Deferred income taxes are provided for temporary differences between book and tax bases of assets and liabilities. Investment tax credits related to regulated operations are amortized over the service life of the related property. 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 utilities pursuant to rate orders.
Net Accumulated deferred income tax assets (liabilities) at December 31 are (in millions):
Florida Progress's total deferred income tax liabilities were $467 million and $484 million at December 31, 2003 and 2002, respectively. Total deferred income tax assets were $652 million and $517 million at December 31, 2003 and 2002, respectively. PEF's total deferred income tax liabilities were $396 million and $361 million at December 31, 2003 and 2002, respectively. Total deferred income tax assets were $72 million and $26 million at December 31, 2003 and 2002, respectively.
Florida Progress's federal income tax credit carry forward at December 31, 2003 consists of $429 million of alternative minimum tax credit with an indefinite carry forward period and $7 million of general business credit with a carry forward period that will begin to expire in 2022.
Florida Progress established additional valuation allowances of $3 million, $5 million and $10 million during 2003, 2002 and 2001, respectively, due to the uncertainty of realizing certain future state tax benefits. The Company believes it is more likely than not that the results of future operations will generate sufficient taxable income to allow for the utilization of the remaining deferred tax assets.
Reconciliations of the Company's effective income tax rate to the statutory federal income tax rate are:
Income tax expense (benefit) applicable to continuing operations is comprised of (in millions):
The Company and each of its wholly-owned subsidiaries have entered into a Tax Agreement with Progress Energy (See Note 1C). The Company's intercompany tax payable was approximately $22 million and $33 million at December 31, 2003 and 2002, respectively. Progress Energy Florida's intercompany tax payable was approximately $20 million and $25 million at December 31, 2003 and 2002, respectively.
Florida Progress through its subsidiaries is 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 Service Code
(Code). The production and sale of the synthetic fuel from these facilities qualifies for tax credits under Section 29 of the Code (Section 29) if certain requirements are satisfied, including a requirement that the synthetic fuel differs significantly in chemical composition from the coal used to produce such synthetic fuel and that the fuel was produced from a facility that was placed in service before July 1, 1998. Total Section 29 credits generated to date are approximately $787 million. All three majority-owned entities and all three minority-owned entities have received private letter rulings (PLRs) from the Internal Revenue Service (IRS) with respect to their synthetic fuel operations. The PLRs do not limit the production on which synthetic fuel credits may be claimed. Should the tax credits be denied on future audits, and the Company fails to prevail through the IRS or legal process, there could be a significant tax liability owed for previously taken Section 29 credits, with a significant impact on earnings and cash flows.
One of the Company's synthetic fuel entities, Colona Synfuel Limited Partnership, L.L.L.P. (Colona), is being audited by the IRS. The audit of Colona was expected. The Company is audited regularly in the normal course of business as are most similarly situated companies. The Company has been allocated approximately $279 million in tax credits to date for this synthetic fuel entity.
In September 2002, all three of Florida Progress' majority-owned synthetic fuel entities, 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. Either the Company or the IRS can withdraw from the program at any time, and issues not resolved through the program may proceed to the next level of the IRS exam process. While the ultimate outcome is uncertain, the Company believes that participation in the PFA program will likely shorten the tax exam process.
In June 2003, the Company was informed that IRS field auditors had raised questions regarding the chemical change associated with coal-based synthetic fuel manufactured at its Colona facility and the testing process by which the chemical change is verified. (The questions arose in connection with the Company's participation in the PFA program.) The chemical change and the associated testing process were described as part of the PLR request for Colona. Based on that application, the IRS ruled in Colona's PLR that the synthetic fuel produced at Colona undergoes a significant chemical change and thus qualifies for tax credits under Section 29.
In October 2003, the National Office of the IRS informed the Company that it had rejected the IRS field auditors' challenges regarding whether the synthetic fuel produced at the Company's Colona facility was the result of a significant chemical change. The National Office had concluded that the experts, engaged by Colona who test the synthetic fuel for chemical change, used reasonable scientific methods to reach their conclusions. Accordingly, the National Office will not take any adverse action on the PLR that has been issued for the Colona facility.
Although this ruling applies only to the Colona facility, the Company believes that the National Office's reasoning would be equally applicable to the other Progress Energy facilities. The Company applies essentially the same chemical process and uses the same independent laboratories to confirm chemical change in the synthetic fuel manufactured at each of its other facilities.
In February 2004, subsidiaries of the Company finalized execution of the Colona Closing Agreement with the Internal Revenue Service concerning their Colona synthetic fuel facilities. The 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 Internal Revenue 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 concludes the IRS PFA program with respect to Colona.
Although the execution of the Colona Closing Agreement is a significant event, the audits of the Company's facilities are not yet completed and the PFA process continues with respect to the four synthetic fuel facilities owned by other affiliates of Progress Energy and FPC. Currently, the focus of that process is to determine that the facilities were placed in service before July 1, 1998. In management's opinion, Progress Energy is complying with all the necessary requirements to be allowed such credits under Section 29, although it cannot provide certainty, that it will prevail if challenged by the IRS on credits taken. Accordingly, the Company has no current plans to alter its synthetic fuel production schedule as a result of these matters.
In October 2003, the United States Senate Permanent Subcommittee on Investigations began a general investigation concerning synthetic fuel tax credits claimed under Section 29 of the Internal Revenue 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.
14. 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:
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:
The Florida Progress net prepaid pension cost of $151 million and $159 million at December 31, 2003 and 2002, respectively, is included in the Company's Consolidated Balance Sheets as prepaid pension cost of $223 million and $226 million, respectively, and accrued benefit cost of $72 million and $67 million, respectively, which is included in other liabilities and deferred credits. The PEF net prepaid pension cost of $183 million and $188 million at December 31, 2003 and 2002, respectively, is included in the Balance Sheets as prepaid pension cost of $220 million and $223 million, respectively, and accrued benefit cost of $37 million and $35 million, respectively, which is included in other liabilities and deferred credits. For Florida Progress, the defined benefit pension plans with accumulated benefit obligations in excess of plan assets had projected benefit obligations totaling $74 million and $68 million at December 31, 2003 and 2002, respectively. Those plans had accumulated benefit obligations totaling $73 million and $67 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 $38 million and $35 million at December 31, 2003 and 2002, respectively. Those plans had accumulated benefit obligations totaling $37 million and $35 million, respectively, and no plan assets. For Florida Progress, the total accumulated benefit obligation for pension plans was $729 million and $662 million at December 31, 2003 and 2002, respectively. For PEF, the total accumulated benefit obligation for pension plans was $653 million and $592 million at December 31, 2003 and 2002, respectively. Accrued other postretirement benefit cost is included in other liabilities and deferred credits in the respective Balance Sheets of Florida Progress and PEF.
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. Florida Progress and PEF recorded a minimum pension liability adjustment of $7 million and $4 million, respectively, at December 31, 2002, with a corresponding pre-tax charge to accumulated other comprehensive loss, a component of common stock equity.
Reconciliations of the fair value of plan assets are:
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 2003 and 2002 and the target allocation for the plans, by asset category, are as follows:
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 2004, the Company expects to make required contributions of $1 million directly to pension plan assets and $1 million of discretionary contributions to OPEB plan assets. The expected benefit payments for the pension benefit plan for 2004 through 2008 and in total for 2009-2013, in millions, are approximately $40, $41, $42, $44, $46 and $269, respectively. The expected benefit payments for the OPEB plan for 2004 through 2008 and in total for 2009-2013, in millions, are approximately $14, $15, $17, $18, $19 and $116, respectively. The expected benefit payments include benefit payments directly from plan assets and benefit payments directly from Company assets. The benefit payment amounts reflect the net cost to the Company after any participant contributions.
The following weighted-average actuarial assumptions were used in the calculation of the year-end obligation:
The Company's primary defined benefit retirement plan for non-bargaining employees is a "cash balance" pension plan as defined in EITF Issue No. 03-4. Therefore, effective December 31, 2003, the Company began to use the traditional unit credit method for purposes of measuring the benefit obligation of this plan and will use that method to measure future benefit costs. Under the traditional unit credit method, no assumptions are included about future changes in compensation and the accumulated benefit obligation and projected benefit obligation are the same.
The following weighted-average actuarial assumptions were used in the calculation of the net periodic cost:
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 9.5% and 10.0%. The Company has chosen to use an expected long-term rate of 9.25% due to the uncertainties of future returns. 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 2003 would increase by $1 million, and the OPEB obligation at December 31, 2003, would increase by $18 million. Assuming a 1% decrease in the medical cost trend rates, the aggregate of the service and interest cost components of the net periodic OPEB cost for 2003 would decrease by $1 million and the OPEB obligation at December 31, 2003, would decrease by $15 million.
In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. In accordance with guidance issued by the FASB in FASB Staff Position FAS 106-1, the Company has elected to defer accounting for the effects of the Act due to uncertainties regarding the effects of the implementation of the Act and the accounting for certain provisions of the Act. Therefore, OPEB information presented above and in the financial statements does not reflect the effects of the Act. When specific authoritative accounting guidance is issued, it could require plan sponsors to change previously reported information. The Company is in the early stages of reviewing the Act and determining its potential effects on the Company.
15. Risk Management Activities and Derivatives Transactions
Under its risk management policy, the Company may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. The Company minimizes such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties. Potential non-performance by counterparties is not expected to have a material effect on the consolidated financial position or consolidated results of operations of the Company.
A. Commodity Contracts - General
Most of the Company's commodity contracts 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.
B. Commodity Derivatives - Cash Flow Hedges
Progress Fuels held natural gas cash flow hedging instruments at December 31, 2003 and 2002. The objective for holding these instruments is to manage a portion of the market risk associated with fluctuations in the price of natural gas for Progress Fuel's forecasted sales. At December 31, 2003, 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, 2003 and 2002 was a $14 million and a $10 million liability position, respectively. The ineffective portion of commodity cash flow hedges was not material in 2003 and 2002. At December 31, 2003, $8 million of after-tax deferred losses in accumulated other comprehensive income (OCI) are expected to be reclassified to earnings during the next 12 months as the hedged transactions occur. Due to the volatility of the commodities markets, the value in OCI is subject to change prior to its reclassification into earnings.
C. Commodity Derivatives
Nonhedging derivatives, primarily electricity forward contracts, may be entered into for trading purposes and 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 2003, 2002 or 2001, and the Company did not have material outstanding positions in such contracts at December 31, 2003 or 2002.
D. Interest Rate Derivatives - Fair Value or Cash Flow Hedges
The Company manages its interest rate exposure in part by maintaining its variable-rate and fixed rate-exposures within defined limits. In addition, the Company also enters into financial derivative instruments, including, but not limited to, interest rate swaps and lock agreements to manage and mitigate interest rate risk exposure.
The Company uses cash flow hedging strategies to hedge variable interest rates on long-term debt and to hedge interest rates with regard to future fixed-rate debt issuances. PEF held no interest rate cash flow hedges at December 31, 2003. At December 31, 2002, PEF held an interest rate cash flow hedge, with a notional amount of $35 million, related to an anticipated 2003 issuance of long-term debt. The hedge was settled at the time of issuing the related debt. At December 31, 2003, an immaterial amount of after-tax deferred losses in OCI is expected to be reclassified to earnings during the next 12 months as the hedged interest payments occur.
The Company uses fair value hedging strategies to manage its exposure to fixed interest rates on long-term debt. At December 31, 2003 and 2002, the Company 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.
16. Related Party Transactions
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 1.47%, 2.18% and 4.47% at December 31, 2003, 2002 and 2001, respectively. At December 31, 2003 and 2002, Florida Progress had $602 million and $380 million, respectively, and PEF had $363 million and $237 million, respectively, of amounts payable to the money pool that are included in notes payable to affiliated companies on the Balance Sheets. Net interest expense related to money pool borrowings was $5 million, $5 million, and $6 million for Florida Progress in 2003, 2002 and 2001 respectively. PEF recorded net interest expense of $2 million, $1 million and interest income of $2 million related to the money pool for 2003, 2002 and 2001, respectively.
Progress Energy formed Progress Energy Service Company, LLC (PESC) to provide specialized services, at cost, to the Company and its subsidiaries, as approved by the U.S. Securities and Exchange Commission (SEC). The Company and its subsidiaries have an agreement with PESC under which services, including purchasing, information technology, telecommunications, marketing, treasury, human resources, accounting, real estate, legal and tax are rendered at cost. Amounts billed by PESC for these services during 2003, 2002 and 2001 to Florida Progress amounted to $190 million, $173 million and $116 million, respectively, and amounts billed to PEF were $153 million, $161 million and $111 million, respectively. At December 31, 2003 and 2002, Florida Progress had a net payable to PESC of $32 and $43 million, respectively. PEF had a net payable to PESC of $23 million and $37 million, respectively, at December 31, 2003 and 2002. During 2002, the Office of Public Utility Regulation within the SEC completed an audit examination of Progress Energy's books and records. This examination is a standard process for all PUHCA registrants. Based on the review, the method for allocating PESC costs to the Parent and its affiliates changed for 2003 and retroactive reallocations of 2002 and 2001 charges were made during the first quarter. The net after-tax impact of the reallocation of costs for 2002 and 2001 was an increase in expenses of $5 million at Florida Progress and a reduction of expenses at PEF by $1 million.
Progress Fuels has an outstanding note due to the Parent. The principal outstanding on this note was $500 million at December 31, 2003 and 2002. Progress Fuels recorded interest expense related to this note of $32 million for 2003 and 2002.
The Company has an outstanding note due to a related trust. The principal outstanding on this note was $309 million at December 31, 2003 (See Note 11F).
Progress Fuels sells coal to PEF which are eliminated from revenues in Florida Progress' Consolidated Financial Statements. In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," profits on intercompany sales between Progress Fuels and PEF are not eliminated if the sales price is reasonable and the future recovery of sales price through the ratemaking process is probable. The profits for all the years presented were not significant.
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 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, 2003 and 2002, the Company has a note receivable of $38 million and $47 million from PVI that has been recorded as a reduction to equity for financial reporting purposes. Payments on the note during 2003 and 2002 totaled $12 million and $17 million, respectively, representing $9 million and $3 million in principal and interest, respectively, in 2003 and $13 million and $4 million in principal and interest, respectively, in 2002.
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 2003, 2002 and 2001 was $181 million, $197 million and $96 million, respectively. Amounts due from PVI at December 31, 2003 and 2002 were $19 million and $12 million, respectively. During 2003, in order to more effectively utilize cash resources, PFC and the two PVI synthetic fuel operations began to participate in a money pool with cash management functions provided by PFC. At December 31, 2003, Progress Fuels has a payable of $34 million to PVI.
The Company and each of its wholly-owned subsidiaries have entered into a Tax Agreement with Progress Energy (See Note 13).
In August 2002, PEC transferred reservation payments for the manufacture of two combustion turbines to PEF at PEC's original cost of $20 million. In December 2002, PVI transferred reservation payments for the manufacture of one combustion turbine and exhaust stack to PEF at PVI's original cost of $16 million. At December 31, 2002, PEF had a $14 million payable to PVI related to these transfers.
17. 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 Inland Marine Transportation business, formerly a business segment, was sold in November 2001 (See Note 3C). 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. 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.
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 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. Segment net income (loss) for 2001 includes a long-lived asset impairment pre-tax loss of $161 million (after-tax $108 million) included in the Rail Services segment. The Company's business segment information for 2003, 2002 and 2001 is summarized below.
18. 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 and Comprehensive Income for fiscal years 2003, 2002 and 2001 are as follows:
Net financial trading gain (loss) represents non-asset-backed trades of electricity. 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.
19. Commitments and Contingencies
A. Purchase Obligations
The following table reflects FPC's contractual cash obligations and other commercial commitments in the respective periods in which they are due.
Fuel and Purchased Power
FPC has entered into various long-term contracts for oil, gas and coal. Payments under these commitments were $703 million, $830 million and $761 million in 2003, 2002 and 2001, respectively. Estimated annual payments for firm commitments of fuel purchases and transportation costs under these contracts are approximately $796 million, $368 million, $248 million, $159 million and $102 million for 2004 through 2008, respectively, with approximately $790 payable thereafter.
Progress Fuels has two coal supply contracts with PEF through 2004, 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. 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 $172 million, $52 million and $42 million for 2004, 2005 and 2006, respectively, with no obligations thereafter. The total cost incurred for these commitments in 2003, 2002 and 2001 was $284 million, $289 million and $173 million, respectively.
PEF has long-term contracts for approximately 474 MW of purchased power with other utilities, including a contract with The Southern Company for approximately 414 MW of purchased power annually through 2010. PEF can lower these purchases to approximately 200 MW annually with a three-year notice. Total purchases, for both energy and capacity, under these agreements amounted to $141 million, $159 million and $112 million for 2003, 2002 and 2001, respectively. Total capacity payments were $57 million, $51 million and $54 million for 2003, 2002 and 2001, respectively. Minimum purchases under these contracts, representing capital-related capacity costs, are approximately $60 million annually through 2009 and $30 million annually for 2010.
PEF has ongoing purchased power contracts with certain cogenerators (qualifying facilities) for 871 MW of capacity with expiration dates ranging from 2004 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. Of the 871 MW under contract, 831 MW currently are available to PEF. All commitments have been approved by the FPSC. Total capacity purchases under these contracts amounted to $241 million, $232 million and $226 million for 2003, 2002 and 2001, respectively. Minimum expected future capacity payments under these contracts at December 31, 2003 are $257 million, $269 million, $280 million, $289 million and $297 million for 2004 through 2008, respectively.
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.
Construction Obligations
PEF has purchase obligations related to various plant capital projects at the Hines Complex. Total payments under these contracts were $159 million, $110 million, and $18 million for 2003, 2002, and 2001 respectively. Future obligations under these contracts are $99 million and $49 million for 2004 and 2005, respectively.
Other
PEF has long-term service agreements for the Hines Complex. Total payments under these contracts were $3 million, $1 million and $6 million for 2003, 2002 and 2001, respectively. Future obligations under these contracts are $16 million, $5 million, $18 million, $11 million and $16 million for 2004 through 2008, respectively, with approximately $107 million payable thereafter.
B. Other Commitments
Florida Progress has certain future commitments related to synthetic fuel facilities purchased that provide for contingent payments (royalties) of up to $25 million on synthetic fuel sales from Florida Progress' interests in these plants annually through 2007. The related agreements were amended in December 2001 to require the payment of minimum annual royalties of which Florida Progress' share is approximately $15 million through 2007. As a result of the amendment, Florida Progress 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) of approximately $52 million and $63 million at December 31, 2003 and 2002, representing the minimum amounts due through 2007, discounted at 6.05%. At December 31, 2003 and 2002, respectively, the portions of the asset and liability recorded that were classified as current were approximately $13 million and $13 million, respectively. The deferred asset will be amortized to expense each year as synthetic fuel sales are made. The maximum amounts payable under these agreements remain unchanged. Actual amounts paid under these agreements were approximately $1 million in 2003, $24 million in 2002 and $25 million in 2001. Future expected royalty payments are approximately $15 million for 2004 through 2007 and $4 million for 2008. The large decline in amount paid from 2002 to 2003 is due to the Company's right in the related agreements and their amendments that allows the Company to escrow those payments if certain conditions in the agreements are met. The Company has exercised that right and retained 2003 royalty payments of approximately $25 million 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 $42 million, $33 million and $25 million during 2003, 2002 and 2001, respectively. In addition, PTC has entered into capital leases for equipment. Assets recorded under capital leases totaled $4 million and $3 million at December 31, 2003 and 2002, 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 9).
Minimum annual rental payments, excluding executory costs such as property taxes, insurance and maintenance, under long-term noncancelable leases at December 31, 2003 are:
The Company is also a lessor of land, buildings, railcars and other types of properties it owns under operating leases with various terms and expiration dates. The leased buildings and railcars are depreciated under the same terms as other buildings and railcars included in diversified business property. Minimum rentals receivable under noncancelable leases for 2004 through 2008, in millions is $4, $4, $3, $1, and $1, respectively and $18 million thereafter. These rental receivable totals exclude all leases attributable to Railcar Ltd. which was sold during the first quarter of 2004 (See Note 3B).
PEF is the lessor of electric poles, streetlights and other facilities. Rents received are contingent upon usage and totaled $56 million, $53 million and $48 million for 2003, 2002 and 2001, respectively.
D. Guarantees
As a part of normal business, Florida Progress and certain subsidiaries including PEF enter into various agreements providing financial or performance assurances to third parties. Such agreements include guarantees, standby letters of credit and surety bonds. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended commercial purposes. At December 31, 2003, management does not believe conditions are likely for performance under these agreements.
Guarantees at December 31, 2003, are summarized in the table below and discussed more fully in the subsequent paragraphs:
(in millions) Guarantees issued on behalf of the Company and affiliates Standby letters of credit $ 33 Surety bonds - Other guarantees 21 Guarantees issued on behalf of third parties Securities of affiliated trust 300 Other guarantees 13 ------------------ Total $ 367 ==================
Standby Letters of Credit The Company has issued standby letters of credit to financial institutions for the benefit of third parties that have extended credit to the Company and certain subsidiaries. Of the total standby letters of credit issued, PEF has issued commitments totaling $2 million. These letters of credit have been issued primarily for the purpose of supporting payments of trade payables, securing performance under contracts and lease obligations and self insurance for workers compensation. If a subsidiary does not pay amounts when due under a covered contract, the counterparty may present its claim for payment to the financial institution, which will in turn request payment from the Company. Any amounts owed by the Company's subsidiaries are reflected in the Company's Consolidated Balance Sheets.
Surety Bonds At December 31, 2003, the Company had $0.2 million in surety bonds, of which PEF accounted for the entire amount, purchased primarily for purposes such as providing workers compensation coverage and obtaining licenses, permits and rights-of-way. To the extent liabilities are incurred as a result of the activities covered by the surety bonds, such liabilities are included in the Balance Sheets.
Other Guarantees The Company has total other guarantees outstanding of approximately $34 million. Included in the $34 million are $3 million of guarantees issued on behalf of third parties related to obligations on leasing arrangements and $10 million in support of synthetic fuel operations at a third party plant. The Company estimates it will have to perform under the third party guarantees related to the leasing agreements and as such $3 million has been accrued and is reflected in the Company's Consolidated Balance Sheets. The remaining $21 million in other guarantees is related primarily to prompt performance payments and other payments subject to contingencies.
Securities of Affiliated Trust The Company has guaranteed certain payments of an affiliated company, FPC Capital I (the Trust). Due to the nature of the relationship between the Trust and Florida Progress Funding Corporation, the Company has guaranteed the payment of all distributions related to the Trust's outstanding mandatorily redeemable preferred securities. At December 31, 2003, the Trust had outstanding 12 million shares of the securities with a liquidation value of $300 million. See discussion at Note 11F for further discussion of the guarantee.
Guarantees Issued by Progress Energy
Progress Energy has issued approximately $27 million of guarantees on behalf of Progress Fuels and its subsidiaries for obligations under coal trading operations.
E. Claims and Uncertainties
The Company is subject to federal, state and local regulations addressing hazardous and solid waste management, air and water quality and other environmental matters.
Hazardous and Solid Waste Management
Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. The principal regulatory agency that is responsible for a specific former manufactured gas plant (MGP) site depends largely upon the state in which the site is located. There are several MGP sites to which the Company has some connection. In this regard, PEF and other potentially responsible parties, are participating in, investigating and, if necessary, remediating former MGP sites with several regulatory agencies, including, but not limited to, the U.S. Environmental Protection Agency (EPA) and the Florida Department of Environmental Protection (FDEP). In addition, PEF is periodically notified by regulators such as the EPA and various state agencies of its involvement or potential involvement in sites, other than MGP sites, that may require investigation and/or remediation.
PEF At December 31, 2003, PEF has accrued $18 million for probable and estimable costs related to various environmental sites. Of this accrual, $12 million is for costs associated with the remediation of distribution transformers which are more fully discussed below. The remaining $6 million is related to two former MGP sites and other sites associated with PEF that have required or are anticipated to require investigation and/or remediation costs. PEF does not believe that it can provide an estimate of the reasonably possible total remediation costs beyond what is currently accrued.
In 2002, PEF accrued approximately $3 million for investigation and remediation costs associated with distribution transformers and received approval from the FPSC for annual recovery of these environmental costs through the Environmental Cost Recovery Clause (ECRC). In September 2003,
PEF accrued an additional $15 million for similar environmental costs as a result of increased sites and estimated costs per site. PEF has received approval from the FPSC to recover these costs through the ECRC. As more activity occurs at these sites, PEF will assess the need to adjust the accruals.
These accruals have been recorded on an undiscounted basis. PEF measures its liability for these sites based on available evidence including its experience in investigating and remediating environmentally impaired sites. This process often includes assessing and developing cost-sharing arrangements with other potentially responsible parties. Presently, PEF cannot determine the total costs that may be incurred in connection with the remediation of all sites.
Florida Progress In 2001, Progress Fuels sold its Inland Marine Transportation business to AEP Resources, Inc. Progress Fuels established an accrual to address indemnities and retained environmental liability associated with the transaction. Progress Fuels estimates that its contractual liability to AEP Resources, Inc. associated with Inland Marine Transportation is $4 million at December 31, 2003 and has accrued such amount. The previous accrual of $10 million was reduced in 2003 based on a change in estimate. This accrual has been determined on an undiscounted basis. Progress Fuels measures its liability for this site based on estimable and probable remediation scenarios. The Company believes that it is not reasonably probable that additional costs will be incurred related to the environmental indemnification provision beyond the amount accrued. The Company cannot predict the outcome of this matter.
PEF has 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 cannot predict the outcome of this matter.
Certain historical sites exist that are being addressed voluntarily by Progress Fuels and FPC. The Company cannot determine the total costs that may be incurred in connection with these sites. The Company cannot predict the outcome of this matter.
Rail Services is voluntarily addressing certain historical waste sites. The Company cannot determine the total costs that may be incurred in connection with these sites. The Company cannot predict the outcome of this matter.
The Company is also currently in the process of assessing potential costs and exposures at other environmentally impaired sites. As the assessments are developed and analyzed, the Company will accrue costs for the sites to the extent the costs are probable and can be reasonably estimated.
Air Quality
There has been and may be further proposed federal legislation requiring reductions in air emissions for nitrogen oxides, sulfur dioxide, carbon dioxide and mercury. Some of these proposals establish nationwide caps and emission rates over an extended period of time. This national multi-pollutant approach to air pollution control could involve significant capital costs which could be material to the Company's consolidated financial position or results of operations. Some companies may seek recovery of the related cost through rate adjustments or similar mechanisms. However, the Company cannot predict the outcome of this matter.
The EPA is conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether modifications at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. PEF was asked to provide information to the EPA as part of this initiative and cooperated in providing the requested information. During 2003, PEF received a supplemental information request from the EPA and responded to it. The EPA initiated civil enforcement actions against other unaffiliated utilities as part of this initiative. Some of these actions resulted in settlement agreements calling for expenditures ranging from $1.0 billion to $1.4 billion. A utility that was not subject to a civil enforcement action settled its New Source Review issues with the EPA for $300 million. These settlement agreements have generally called for expenditures to be made over extended time periods, and some of the companies may seek recovery of the related cost through rate adjustments or similar mechanisms. The Company cannot predict the outcome of the EPA's initiative or its impact, if any, on the Company.
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. The Company cannot predict the outcome of this matter.
In 1997, the EPA's Mercury Study Report and Utility Report to Congress conveyed that mercury is not a risk to the average American and expressed uncertainty about whether reductions in mercury emissions from coal-fired power plants would reduce human exposure. Nevertheless, the EPA determined in 2000 that regulation of mercury emissions from coal-fired power plants was appropriate. In 2003, the EPA proposed, and solicited comment on, two alternative control plans that would limit mercury emissions from coal-fired power plants. The agency has indicated that it will choose one of the alternatives as the final rule, which is expected to be promulgated in December 2004. Achieving compliance with either proposal could involve significant capital costs which could be material to the Company's financial condition or results of operations. However, the Company cannot predict the outcome of this matter.
In conjunction with the proposed mercury rule, the EPA proposed a Maximum Available Control Technology (MACT) standard to regulate nickel emissions from residual oil-fired units. The agency estimates the proposal will reduce national nickel emissions to approximately 103 tons. The rule is expected to become final in December 2004. The Company cannot predict the outcome of this matter.
In December 2003, the EPA released its proposed Interstate Air Quality Rule (commonly known as the Fine Particulate Transport Rule and/or the Regional Transport Rule). The EPA's proposal requires 28 jurisdictions, including North Carolina, South Carolina, Georgia and Florida, to further reduce nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions in order to attain pre-set NOx and SO2 emissions levels (which have not yet been determined). The rule is expected to become final in 2004. The installation of controls necessary to comply with the rule could involve significant capital costs.
In 2004, a bill was introduced in the Florida legislature that would require significant reductions in SO2, NOx and particulate emissions from certain coal, natural gas and oil-fired generating units owned or operated by investor-owned electric utilities, including PEF. The SO2 and NOx reductions would be effective beginning with calendar year 2010 and the particulate reductions would be effective beginning with calendar year 2012. Under the proposed legislation, the FPSC would be authorized to allow the utilities to recover the costs of compliance with the emission reductions over a period not greater than seven years beginning in 2005, but the utilities' rates would be frozen at 2004 levels for at least five years of the maximum recovery period. The Company cannot predict the outcome of this matter.
Water Quality
As a result of the operation of certain control equipment needed to address the air quality issues outlined above, new wastewater streams may be generated. Integration of these new wastewater streams into existing wastewater treatment processes may result in permitting, construction and water treatment challenges to the Company in the immediate and extended future.
After many years of litigation and settlement negotiations, the EPA is scheduled to publish final regulations in February 2004 for the implementation of Section 316(b) of the Clean Water Act. The purpose of these regulations is to minimize adverse environmental impacts caused by cooling water intake structures and intake systems located at existing facilities. Over the next several years, these regulations may require the facilities to mitigate the effects to aquatic organisms by undertaking intake modifications or other restorative activities. Substantial costs could be incurred by the facilities in order to comply with the new regulations. The Company cannot predict the outcome and impacts to the facilities at this time.
The EPA has published for comment a draft Environmental Impact Statement (EIS) for surface coal mining (sometimes referred to as "mountaintop mining") and valley fills in the Appalachian coal region, where Progress Fuels currently operates a surface mine and may operate others in the future. The final EIS, when published, may affect regulations for the permitting of mines and the cost of compliance with environmental regulations. Regulatory changes for mining may also affect the cost of fuel for the PEC and PEF fueled electric generating plants. The Company cannot predict the outcome of this matter.
Other Environmental Matters
The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of carbon dioxide and other greenhouse gases. The United States has not adopted the Kyoto Protocol; however, a number of carbon dioxide emissions control proposals have been advanced in Congress and by the Bush Administration. The Bush
Administration favors voluntary programs. Reductions in carbon dioxide emissions to the levels specified by the Kyoto Protocol and some legislative proposals could be materially adverse to the Company's financials and operations if associated costs cannot be recovered from customers. The Company favors the voluntary program approach recommended by the administration, and is evaluating options for the reduction, avoidance and sequestration of greenhouse gases. However, the Company cannot predict the outcome of this matter.
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 discussed below, three other cities, with a total of approximately 30,000 customers, have subsequently settled their lawsuits with PEF and signed new, 30-year franchise agreements. The lawsuits principally seek (1) a declaratory judgment that the cities have the right to purchase PEF's electric distribution system located within the municipal boundaries of the cities, (2) a declaratory judgment that the value of the distribution system must be determined through arbitration, and (3) injunctive relief requiring PEF to continue to collect from PEF's customers and remit to the cities, franchise fees during the pending litigation, and as long as PEF continues to occupy the cities' rights-of-way to provide electric service, notwithstanding the expiration of the franchise ordinances under which PEF had agreed to collect such fees. Five circuit courts have entered orders requiring arbitration to establish the purchase price of PEF's electric distribution system within five cities. Two appellate courts have upheld those circuit court decisions and authorized cities to determine the value of PEF's electric distribution system within the cities through arbitration. Arbitration in one of the cases (the City of Casselberry) was held in August 2002. Following arbitration, the parties entered settlement discussions, and in July 2003 the City approved a settlement agreement and a new, 30-year franchise agreement with PEF. The settlement resolves all pending litigation with that City. A second arbitration (with the 13,000-customer City of Winter Park) was completed in February 2003. That arbitration panel issued an award in May 2003 setting the value of PEF's distribution system within the City of Winter Park at approximately $32 million, not including separation and reintegration and construction work in progress, which could add several million dollars to the award. The panel also awarded PEF approximately $11 million in stranded costs. In September 2003, Winter Park voters passed a referendum that would authorize the City to issue bonds of up to approximately $50 million to acquire PEF's electric distribution system. The City has not yet definitively decided whether it will acquire the system, but has indicated that it will seek wholesale power supply bids and bids to operate and maintain the distribution system. At this time, whether and when there will be further proceedings regarding the City of Winter Park cannot be determined. A third arbitration (with the 2,500-customer Town of Belleair) was completed in June 2003. In September 2003, the arbitration panel issued an award in that case setting the value of the electric distribution system within the Town at approximately $6 million. The panel further required the Town to pay to PEF its requested $1 million in separation and reintegration costs and $2 million in stranded costs. The Town has not yet decided whether it will attempt to acquire the system. At this time, whether and when there will be further proceedings regarding the Town of Belleair cannot be determined. A fourth arbitration (with the 13,000-customer City of Apopka) had been scheduled for January 2004. In December 2003, the Apopka City Commission voted on first reading to approve a settlement agreement and a 30-year franchise with PEF. The settlement and franchise became effective upon approval by the Commission at a second reading of the franchise in January 2004. The settlement resolves all outstanding litigation between the parties. Arbitration in the remaining city's litigation (the 1,500-customer City of Edgewood) has not yet been scheduled.
As part of the above litigation, two appellate courts have also reached opposite conclusions regarding whether PEF must continue to collect from its customers and remit to the cities "franchise fees" under the expired franchise ordinances. PEF has filed an appeal with the Florida Supreme Court to resolve the conflict between the two appellate courts. The Florida Supreme Court held oral argument in one of the appeals in August 2003. Subsequently, the Court requested briefing from the parties in the other appeal, which was completed in November 2003. The Court has not yet issued a decision in these cases. PEF cannot predict the outcome of these matters at this time.
2) DOE Litigation
As required under the Nuclear Waste Policy Act of 1982, PEF entered into a contract with the U.S. Department of Energy (DOE) under which the DOE agreed to begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract.
In April 1995, the DOE issued a final interpretation that it did not have an unconditional obligation to take spent nuclear fuel by January 31, 1998. In Indiana & Michigan Power v. DOE, the Court of Appeals vacated the DOE's final interpretation and ruled that the DOE had an unconditional obligation to begin taking spent nuclear fuel. The Court did not specify a remedy because the DOE was not yet in default.
After the DOE failed to comply with the decision in Indiana & Michigan Power v. DOE, a group of utilities petitioned the Court of Appeals in Northern States Power (NSP) v. DOE, seeking an order requiring the DOE to begin taking spent nuclear fuel by January 31, 1998. The DOE took the position that its delay was unavoidable, and the DOE was excused from performance under the terms and conditions of the contract. The Court of Appeals did not order the DOE to begin taking spent nuclear fuel, stating that the utilities had a potentially adequate remedy by filing a claim for damages under the contract.
After the DOE failed to begin taking spent nuclear fuel by January 31, 1998, a group of utilities filed a motion with the Court of Appeals to enforce the mandate in NSP v. DOE. Specifically, this group of utilities asked the Court to permit the utilities to escrow their waste fee payments, to order the DOE not to use the waste fund to pay damages to the utilities, and to order the DOE to establish a schedule for disposal of spent nuclear fuel. The Court denied this motion based primarily on the grounds that a review of the matter was premature, and that some of the requested remedies fell outside of the mandate in NSP v. DOE.
Subsequently, a number of utilities each filed an action for damages in the Federal Court of Claims. The U.S. Circuit Court of Appeals (Federal Circuit) has ruled that utilities may sue the DOE for damages in the Federal Court of Claims instead of having to file an administrative claim with DOE.
On January 14, 2004, PEF filed a complaint with the United States Court of Federal Claims against the United States of America (Department of Energy) claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel by failing to accept spent nuclear fuel from various Progress Energy facilities on or before January 31, 1998. Damages due to DOE's breach will likely exceed $100 million. Similar suits have been initiated by over two dozen other utilities.
In July 2002, Congress passed an override resolution to Nevada's veto of DOE's proposal to locate a permanent underground nuclear waste storage facility at Yucca Mountain, Nevada. DOE plans to submit a license application for the Yucca Mountain facility by the end of 2004. On November 5, 2003, Congressional negotiators approved $580 million for fiscal year 2004 for the Yucca Mountain project, $123 million more than the previous year. PEF cannot predict the outcome of this matter.
PEF is currently storing spent nuclear fuel onsite in spent fuel pools. If PEF does not seek renewal of the Crystal River Nuclear Plant (CR3) operating license, CR3 will have sufficient storage capacity in place for fuel consumed through the end of the expiration of the license in 2016. If PEF extends the CR3 operating license, dry storage may be necessary.
3) Easement Litigation
In December 1998, PEF was served with a class action lawsuit seeking damages, declaratory and injunctive relief for the alleged improper use of electric transmission easements. The plaintiffs contended that the licensing of fiber-optic telecommunications lines to third parties or telecommunications companies for other than PEF's internal use along the electric transmission line right-of-way exceeds the authority granted in the easements. In 1999, plaintiffs amended their complaint to add PTC. After several legal motions and appeals over the years the Company and the appellants reached a settlement resolving the appellants' dispute in 2003. In May 2003 the trial court entered an Amended Final Judgment approving the mandatory class settlement. No appeals have been taken from that judgment, and the time to appeal has expired. In July 2003, PEF, the class representatives and the appellants filed a joint withdrawal of all pending motions with the First District Court of Appeal. The First District Court of Appeal acknowledged the withdrawal of all pending motions and issued a mandate in July 2003. Under the terms of the mandatory class settlement, PEF made settlement payments to class members in August 2003. The settlement payments did not have a material adverse effect upon PEF's financial condition or results of operations.
4) 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 January 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. 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. 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 of 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. The Company cannot predict the outcome of this matter, but will present a vigorous defense.
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 financial position, results of operation or liquidity.
INDEPENDENT AUDITORS' REPORT
To the Boards of Directors of Florida Progress Corporation and Florida POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.:
We have audited the consolidated balance sheets of Florida Progress Corporation and its subsidiaries (Florida Progress) and the balance sheets of Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF) at December 31, 2003 and 2002, and the related Florida Progress consolidated statements of income and comprehensive income, of common equity, and of cash flows and the related PEF statements of income and comprehensive income, of common equity, and of cash flows for each of the three years in the period ended December 31, 2003 and have issued our report thereon dated February 20, 2004 (which expresses an unqualified opinion and includes an explanatory paragraph concerning the adoption of new accounting principles in 2003); such financial statements and report are included herein. Our audits also included the financial statement schedules of Florida Progress and PEF for the years ended December 31, 2003 and 2002, listed in Item 8. These financial statement schedules are the responsibility of the respective company'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 February 20, 2004
Schedule II
FLORIDA PROGRESS CORPORATION Valuation and Qualifying Accounts For the Years Ended December 31, 2003, 2002 and 2001 (In millions)
(a) Represents write-off of uncollectible accounts, net of recoveries. (b) Represents payments of actual expenditures related to outages.
Schedule II
FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA Valuation and Qualifying Accounts For the Years Ended December 31, 2003, 2002 and 2001 (In millions)
(a) Represents write-off of uncollectible accounts, net of recoveries. (b) Represents payments of actual expenditures related to outages.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Florida Progress Corporation
Pursuant to Rule 13a-15(b) under 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 Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, Florida Progress' Chief Executive Officer and Chief Financial Officer concluded that its disclosure controls and procedures are effective in timely alerting them to material information relating to Florida Progress (including its consolidated subsidiaries) required to be included in its periodic SEC filings. There has been no change in Florida Progress' internal control over financial reporting during the quarter ended December 31, 2003 that has materially affected, or is reasonably like to materially affect, Florida Progress' internal control over financial reporting.
Progress Energy Florida
Pursuant to Rule 13a-15(b) under 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 Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, PEF's Chief Executive Officer and Chief Financial Officer concluded that its disclosure controls and procedures are effective in timely alerting them to material information relating to Florida Progress (including its consolidated subsidiaries) required to be included in its periodic SEC filings. There has been no change in PEF's internal control over financial reporting during the quarter ended December 31, 2003 that has materially affected, or is reasonably like to materially affect, PEF's internal control over financial reporting.
PART III
ITEM 10.
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.
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.
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.
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.
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.
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, 2003 and December 31, 2002.
Florida Progress
2003 2002 Audit Fees $ 1,194,000 $ 647,000 Audit-Related Fees $ 78,000 $ 471,000 Tax Fees $ 31,000 $ 91,000 All Other Fees $ 4,000 $ 32,000 ----------------------------------------------- $ 1,307,000 $ 1,241,000
Progress Energy Florida
2003 2002 Audit Fees $ 598,000 $ 432,000 Audit-Related Fees $ 8,000 $ 7,000 Tax Fees $ 24,000 $ 87,000 All Other Fees $ 3,000 $ 32,000 ----------------------------------------------- $ 633,000 $ 558,000
Audit Fees consisted of audit work performed in the preparation of financial statements, as well as work generally only the independent auditor can reasonably be expected to provide, such as statutory audits.
Audit-Related Fees consisted principally of employee benefit plans, special procedures and letter reports and accounting consultations.
Tax Fees include fees billed for tax compliance matters and tax planning and advisory services.
All Other Fees consisted principally of advisory training services.
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.
All fees were related to services that were pre-approved by the Audit Committee.
PART IV
ITEM 15.
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 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:
(b) Reports on Form 8-K filed or furnished during or with respect to the last quarter of 2003 and the portion of the first quarter of 2004 prior to the filing of this Form 10-K:
Risk factors
In this section, unless the context indicates otherwise, the terms "our," "we," "us" or similar terms refer to Progress Energy Florida. The following section is applicable most directly to Progress Energy Florida. However, the risk factors discussed below are substantially applicable to our corporate parent, Florida Progress.
Investing in our securities involves risks, including the risks described below, that could affect the energy industry, as well as us and our business. Although we have tried to discuss key factors, please be aware that other risks may prove to be important in the future. New risks may emerge at any time and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Before purchasing our securities, you should carefully consider the following risks and the other information in this Annual Report, as well as the documents we file with the SEC from time to time. Each of the risks described below could result in a decrease in the value of our securities and your investment therein.
Risks Related to the Energy Industry
We are subject to fluid and complex government regulations that may have a negative impact on our business and our results of operations.
We are subject to comprehensive regulation by several federal and state regulatory agencies, which significantly influence our operating environment and may affect our ability to recover costs from utility customers. We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations.
The Federal Energy Regulatory Commission ("FERC"), the Nuclear Regulatory Commission ("NRC"), the Environmental Protection Agency ("EPA") and the 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 the Public Utility Holding Company Act of 1935, as amended ("PUHCA"), we are subject to many of the regulatory provisions of PUHCA.
We are a wholly-owned subsidiary of Progress Energy, Inc., a registered public utility holding company under PUHCA. Repeal of PUHCA has been proposed, but it is unclear whether or when such a repeal would occur. It is also unclear to what extent repeal of PUHCA would result in additional or new regulatory oversight or action at the federal or state levels, or what the impact of those developments might be on our business.
We are unable to predict the impact on our business and operating results from future regulatory activities of these federal and state agencies. Changes in regulations or the imposition of additional regulations could have a negative impact on our business and results of operations.
We are subject to numerous environmental laws and regulations that may increase our cost of operations, impact or limit our business plans, or expose us to environmental liabilities.
We are subject to numerous environmental regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste, and hazardous waste. These laws and regulations can result in increased capital, operating and other costs, particularly with regard to enforcement efforts focused on power plant emissions obligations. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. We cannot predict the financial or operational outcome of any related litigation that may arise.
In addition, we may be a responsible party for environmental clean up at sites identified by a regulatory body. We cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties ("PRP"s).
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.
Deregulation or restructuring in the electric utility industry may result in increased competition and unrecovered costs that could adversely affect our financial condition, results of operations and cash flows.
Increased competition resulting from deregulation or restructuring efforts could have a significant adverse financial impact on our results of operations and cash flows. Increased competition could also result in increased pressure to lower rates. Retail competition and the unbundling of regulated energy and gas service could have a significant adverse financial impact on us due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. Because we have not previously operated in a competitive retail environment, we cannot predict the extent and timing of entry by additional competitors into the electric markets. Due to several factors, however, there currently is little discussion of any movement toward deregulation in 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.
The uncertain outcome regarding the timing, creation and structure of regional transmission organizations, or RTOs, may materially impact our results of operations, cash flows or financial condition.
Congress, FERC, and the state utility regulators have paid significant attention in recent years to transmission issues, including the possibility of regional transmission organizations. While these deliberations have not yet resulted in significant changes to our utilities' transmission operations, they cast uncertainty over those operations, which constitute a material portion of our assets.
For the last several years, the FERC has supported independent RTOs and has indicated a belief that it has the authority to order transmission-owning utilities to transfer operational control of their transmission assets to such RTOs. Many state regulators, including most regulators in the Southeast, have expressed skepticism over the potential benefits of RTOs and generally disagree with the FERC's interpretation of its authority to mandate RTOs.
In addition, in July 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design ("SMD NOPR"). The proposed rules set forth in the SMD NOPR would require, among other things, that 1) all transmission owning utilities transfer control of their transmission facilities to an independent third party; 2) transmission service to bundled retail customers be provided under the FERC- regulated transmission tariff, rather than state-mandated terms and conditions; and 3) new terms and conditions for transmission service be adopted nationwide, including new provisions for pricing transmission in the event of transmission congestion; 4) new energy markets be established for the buying and selling of electric energy; and 5) load-serving entities (LSEs) be required to meet minimum criteria for generating reserves. If adopted as proposed, the rules set forth in the SMD NOPR would materially alter the manner in which transmission and generation services are provided and paid for. Progress Energy, Inc. filed comments on the SMD NOPR in November 2002 and supplemental comments in January 2003. The FERC has not yet issued a final rule on SMD NOPR. 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.
In response, PEF and other investor-owned utilities filed applications with the FERC and the FPSC for approval of an RTO, currently named GridFlorida. The FERC provisionally approved the structure and governance of GridFlorida. The FPSC's most recent order in December 2003 ordered further state proceedings.
The actual structure of 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 its creation or the creation of an alternate combined transmission structure will have any material adverse effect on our future results of operations, cash flows or financial condition.
Since weather conditions directly influence the demand of and cost of providing electricity, our results of operations, financial condition and cash flows can fluctuate and be negatively affected by changes in weather conditions and severe weather.
Our results of operation, financial condition and cash flows may be affected by changing weather conditions. Weather conditions in our service territories directly influence the demand for electricity and affect the price of energy commodities necessary to provide electricity to our customers.
Electric power demand is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. 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.
Furthermore, severe weather, such as hurricanes, tornadoes and severe thunder storms, can be destructive, causing outages, downed power lines and property damage and requiring us to incur additional and unexpected expenses and causing us to lose generating revenues.
Our revenues, operating results and financial condition may fluctuate with the economy and its corresponding impact on our commercial and industrial customers, and may also fluctuate on a seasonal or quarterly basis.
Our business is impacted by fluctuations in the macroeconomy. For the year ended December 31, 2003, commercial and industrial customers represented approximately 24% and 7% of our electric revenues, respectively. As a result, changes in the macroeconomy can have negative impacts on our revenues. As our commercial and industrial customers experience economic hardships, our revenues can be negatively impacted.
Risks Related to Us and Our Business
Under a settlement agreement we entered into in 2002, we are required to reduce our retail rates annually through 2005 and to operate under a revenue sharing plan which provides for possible rate refunds to our retail customers. This agreement could affect our profit margin if we do not control our costs.
In March 2002, we entered into a Stipulation and Settlement Agreement related to retail rate matters. The agreement is generally effective from May 1, 2002 through December 31, 2005; provided, however, that if our base rate earnings fall below a 10% return on equity, we may petition the FPSC to amend our base rates. The agreement provided for a 9.25% rate reduction designed to result in a reduction of our retail revenues from the sale of electricity by an annual amount of $125 million. The agreement also provides that we will operate under a revenue sharing incentive plan through 2005, and thereafter until terminated by the FPSC, that establishes annual revenue caps and sharing thresholds.
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 unit, which may present potential exposures in excess of our insurance coverage.
We own and operate one nuclear unit that represents approximately 838 megawatts, or approximately 10%, of our generation capacity. 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 this facility, and the costs of securing the facility 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 our 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 plant. In addition, although we have no reason to anticipate a serious nuclear incident at our plant, if an incident did occur, it could materially and adversely affect our results of operations or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.
Our facility requires licenses that need to be renewed or extended in order to continue operating. We do not anticipate any problems renewing these licenses. However, as a result of potential terrorist threats and increased public scrutiny of utilities, the licensing process could result in increased licensing or compliance costs that are difficult or impossible to predict.
Our financial performance depends on the successful operation of our electric generating facilities and our ability to deliver electricity to our customers.
Operating electric generating facilities involves many risks, including:
o operator error and breakdown or failure of equipment or processes; o operating limitations that may be imposed by environmental or other regulatory requirements; o labor disputes; o fuel supply interruptions; and o catastrophic events such as fires, earthquakes, explosions, floods, terrorist attacks or other similar occurrences.
A decrease or elimination of revenues generated by our electric generating facilities or an increase in the cost of operating the facilities could have an adverse effect on our business and results of operations.
Our business is dependent on our ability to successfully access capital markets. Our inability to access capital may limit our ability to execute our business plan, or pursue improvements and make acquisitions that we may otherwise rely on for future growth.
We rely on access to both short-term money markets and long-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flow from our operations. If we are not able to access capital at competitive rates, our ability to implement our strategy will be adversely affected. We believe that we will maintain sufficient access to these financial markets based upon current credit ratings. However, certain market disruptions or a downgrade of our credit rating may increase our cost of borrowing or adversely affect our ability to access one or more financial markets. Such disruptions could include:
o an economic downturn; o the bankruptcy of an unrelated energy company; o capital market conditions generally; o market prices for electricity; o terrorist attacks or threatened attacks on our facilities or those of unrelated energy companies; or o the overall health of the utility industry.
Restrictions on our ability to access financial markets may affect our ability to execute our business plan as scheduled. An inability to access capital may limit our ability to pursue improvements or acquisitions that we may otherwise rely on for future growth.
Increases in our leverage could adversely affect our competitive position, business planning and flexibility, financial condition, ability to service our debt obligations and ability to access capital on favorable terms.
Our cash requirements arise primarily from the capital-intensive nature of our business. In addition to operating cash flows, we rely heavily on our commercial paper and long-term debt. At December 31, 2003, our commercial paper balance was zero, our notes payable to affiliated companies balance was $363 million and our long-term debt balances were approximately $2 billion (net of current portion, which at December 31, 2003, was $68 million). In February 2003, we issued $650 million aggregate principal amount of our first mortgage bonds, the proceeds from which were used to reduce, redeem, or retire our outstanding long- and short-term, secured and unsecured, indebtedness. In November 2003, we issued $300 million aggregate principal amount of our first mortgage bonds, the proceeds from which were used to redeem outstanding long-term indebtedness.
We have two committed credit lines that support our commercial paper programs totaling $400 million. At December 31, 2003, we had no outstanding borrowings under these lines. If we are unable to extend or renew these credit lines on favorable terms, or at all, we may experience a liquidity shortfall that could have a material adverse impact on us and our financial condition. We also have an uncommitted credit line for up to $100 million. At December 31, 2003, we had no outstanding borrowings under this uncommitted line of credit. In addition, under our shelf registration statement on file with the SEC, we may issue secured and unsecured debt securities up to an additional $50 million. This amount may be increased from time to time.
Our credit lines impose various limitations that could impact our liquidity. Our credit facilities include defined maximum total debt to total capital ratios. At December 31, 2003, the maximum and actual ratios, pursuant to the terms of the credit facilities, were 65% and 51.5%, respectively. Indebtedness, as defined under the credit facility agreements, includes certain letters of credit and guarantees that are not recorded on our Balance Sheets. The covenants require PEF's Earnings before interest, taxes, and depreciation and amortization to interest expense ratio to be at least 3 to 1. For the year ended December 31, 2003, the ratio was 9.22 to 1 for PEF.
In the event our capital structure changes such that we approach the permitted ratios, our access to capital and additional liquidity could decrease. A limitation in our liquidity could have a material adverse impact on our business strategy and our ongoing financing needs. Furthermore, our credit lines include provisions that preclude us from borrowing additional funds in the event of a material adverse change in our financial condition.
Our indebtedness also includes cross-default provisions which could significantly impact our financial condition. Our credit lines include cross-default provisions for defaults of indebtedness in excess of $10 million. Our cross-default provisions only apply to defaults on our indebtedness, but not defaults by our affiliates. In the event that a cross-default provision were triggered, our lenders could accelerate payment of any outstanding debt. Any such acceleration would cause a material adverse change in our financial condition.
Changes in economic conditions could result in higher interest rates, which would increase our interest expense on our floating rate debt and reduce funds available to us for our current plans. Additionally, an increase in our leverage could adversely affect us by:
o increasing the cost of future debt financing; o making it more difficult for us to satisfy our existing financial obligations; o limiting our ability to obtain additional financing, if we need it, for working capital, acquisitions, debt service requirements or other purposes; o increasing our vulnerability to adverse economic and industry conditions; o requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt, which would reduce funds available to us for operations, future business opportunities or other purposes; o limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete; o placing us at a competitive disadvantage compared to our competitors who have less debt; and o causing a downgrade in our credit ratings.
Any reduction in our credit ratings could increase our borrowing costs and limit our access to additional capital, which could materially and adversely affect our business, results of operations and financial condition.
We will seek to maintain a solid investment grade rating through prudent capital management and financing structures. We cannot, however, assure you that our current ratings will remain in effect for any given period of time or that our ratings will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Any downgrade could increase our borrowing costs and adversely affect our access to capital, which could negatively impact our financial results. Further, we may be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease. Although we would have access to liquidity under our committed and uncommitted credit lines, if our short-term rating were to fall below "A-2" or "P-1," the current ratings assigned by S&P and Moody's, respectively, it could significantly limit our access to the commercial paper market. We note that the ratings from credit agencies are not recommendations to buy, sell or hold our securities and that each rating should be evaluated independently of any other rating.
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 12, 2004 (Registrant)
By: /s/Robert B. McGehee ------------------------ Robert B. McGehee President and Chief Executive Officer
By: /s/Geoffrey Chatas ------------------------ Geoffrey 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/ William Cavanaugh III Director March 12, 2004 - ------------------------- (William Cavanaugh III, Chairman)
/s/ Edwin B. Borden Director March 12, 2004 - -------------------- (Edwin B. Borden)
/s/ James E. Bostic, Jr. Director March 12, 2004 - ------------------------- (James E. Bostic, Jr.)
/s/ David L. Burner Director March 12, 2004 - -------------------- (David L. Burner)
/s/ Charles W. Coker Director March 12, 2004 - --------------------- (Charles W. Coker)
/s/ Richard L. Daugherty Director March 12, 2004 - ------------------------- (Richard L. Daugherty)
/s/ W.D. Frederick, Jr. Director March 12, 2004 - ------------------------ (W.D. Frederick, Jr.)
/s/ William O. McCoy Director March 12, 2004 - --------------------- (William O. McCoy)
/s/ E. Marie McKee Director March 12, 2004 - ------------------- (E. Marie McKee)
/s/ John H. Mullin, III Director March 12, 2004 - ------------------------ (John H. Mullin, III)
/s/ Richard A. Nunis Director March 12, 2004 - --------------------- (Richard A. Nunis)
/s/ Peter S. Rummell Director March 12, 2004 - -------------------- (Peter S. Rummell)
/s/ Carlos A. Saladrigas Director March 12, 2004 - ------------------------- (Carlos A. Saladrigas)
/s/ J. Tylee Wilson Director March 12, 2004 - -------------------- (J. Tylee Wilson)
/s/ Jean Giles Wittner Director March 12, 2004 - ----------------------- (Jean Giles Wittner)
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 12, 2004 (Registrant)
By: /s/ H. William Habermeyer, Jr. ------------------------------ H. William Habermeyer, Jr. President and Chief Executive Officer
By: /s/Geoffrey Chatas ----------------------- Geoffrey 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/ William Cavanaugh III Director March 12, 2004 - -------------------------- (William Cavanaugh III, Chairman)
/s/ Robert B. McGehee Director March 12, 2004 - --------------------- (Robert B. McGehee)
/s/ William D. Johnson Director March 12, 2004 - ---------------------- (William D. Johnson)
/s/ Fred N. Day IV Director March 12, 2004 - ------------------ (Fred N. Day IV)
/s/ William S. Orser Director March 12, 2004 - --------------------- (William S. Orser)
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
Exhibit 23.(a)
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No. 33-53939 on Form S-8, Registration Statement No. 33-54972 on Form S-8, Registration Statement No. 333-02169 on Form S-8, Registration Statement No. 333-19037 on Form S-8, Registration Statement No. 333-75373 on Form S-8, Registration Statement No. 333-39232 on Form S-3, Registration Statement No. 33-51573 on Form S-3, Registration Statement No. 33-47623 on Form S-8, Registration Statement No. 2-93111 on Form S-3, Registration Statement No. 333-94143 on Form S-8, Registration Statement No. 333-66161 on Form S-8, and Registration Statement No. 333-07853 on Form S-3 of Florida Progress Corporation of our reports dated February 20, 2004, (which express an unqualified opinion and include an explanatory paragraph concerning the adoption of new accounting principles in 2003) appearing in this Annual Report on Form 10-K of Florida Progress Corporation for the year ended December 31, 2003.
We also consent to the incorporation by reference in Post-Effective Amendment 1 to Registration Statement No. 33-55273 on Form S-3, Post-Effective Amendment 1 to Registration Statement No. 333-29897 on Form S-3, Post-Effective Amendment 1 to Registration Statement No. 333-62210 on Form S-3, and Registration Statement No. 333-63204 on Form S-3 of Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF) of our reports dated February 20, 2004, (which express an unqualified opinion and include an explanatory paragraph concerning the adoption of new accounting principles in 2003) appearing in this Annual Report on Form 10-K of PEF for the year ended December 31, 2003.
/s/ Deloitte & Touche LLP Raleigh, North Carolina March 12, 2004