The Mansfield Plant is a three-unit, fully scrubbed, coal-fired generating facility that has a net demonstrated capacity of 2,460 MW. The Mansfield Plant is located on a 473-acre site in Shippingport, Pennsylvania on the Ohio River, approximately 25 miles northwest of Pittsburgh. Unit 1 was commissioned in 1976, followed by Unit 2 in 1977 and Unit 3 in 1980. The Mansfield Plant is operated by the Lessee, which leases a 93.825% undivided interest in Unit 1 and owns a 56.395% undivided interest in Unit 2 and a 57.839% undivided interest in Unit 3. Utility affiliates of FGCO lease the remaining portions of each Unit pursuant to the 1987 sale and leaseback arrangements described below and sell the output related to those leasehold interests to FGCO pursuant to long term contracts.
The boilers at the Mansfield Plant, which are nearly identical pulverized coal steam generator boilers originally manufactured by Foster Wheeler Corporation, burn a regional mid to high sulfur bituminous coal. This fuel is delivered to the plant via barge, truck and rail. Additionally, the plant uses fuel oil for startup and heatup. The turbine generators are all General Electric Company, or GE, tandem-compound, six-flow turbines that are mated to hydrogen-cooled generators now rated at 830 MW, 830 MW and 800 MW net for Units 1, 2 and 3, respectively. Raw water for the plant is provided from the Ohio River. Natural draft cooling towers provide condenser cooling water to each unit. Sulfur emissions are controlled through the operation of wet lime FGD systems.
These units serve as baseload capacity within the FES fleet, and generally run at their full capacity every day, 24 hours per day. The Mansfield Plant is located in the MISO wholesale electricity market and operating within the RFC reliability council.
The Mansfield Plant requires approximately 23,000 tons of coal per day. It has on-site coal storage capacity of approximately 1.5 million tons and maintains on average a 60-day coal inventory. On June 22, 2006, the Lessee entered into a new coal supply agreement with CONSOL under which CONSOL will supply a total of more than 128 million tons of high-Btu coal to FGCO over a 20-year period beginning in 2009. The new agreement will replace an existing coal supply agreement that took effect in 2003 and originally was to expire in 2020, but will now expire at the end of 2008. Under the new agreement, CONSOL will increase its coal shipments to approximately 6.5 million tons per year to provide approximately 80% of the coal for the Mansfield Plant.
In September 1987, CEI and TE entered into separate sale and leaseback transactions with 12 owner trusts for 6.50%, 45.9% and 44.38% undivided interests, respectively, in Units 1, 2 and 3 of the Mansfield Plant. The applicable leases expire in 2016, subject to CE’s and TE’s respective rights of renewal. In May 2007, one of the owner trusts, representing approximately 0.33%, 2.30% and 2.22% undivided interests, respectively, in Units 1, 2 and 3, was acquired by FGCO and liquidated resulting in the termination of such owner trust’s sale and leaseback arrangement. The 0.33% undivided interest acquired by FGCO in Unit 1 was included in the Total Undivided Interest sold and leased back by FGCO in the transactions contemplated in this prospectus. The sale and leaseback arrangements with the other 11 owner trusts remain in effect.
The Mansfield Plant currently has a total of 499 employees and is led by a site Vice President. The management team consists of a plant director and six managers. The Mansfield Plant is composed of three primary sections: Production (220 employees), Production Support (206 employees) and Technical Support (62 employees). Additionally there are 11 management and staff level employees who handle business services, human resources, safety requirement coordination and special projects.
Table of ContentsDESCRIPTION OF THE LEASE GUARANTOR AND THE LESSEE
Overview
General
FES, a wholly-owned subsidiary of FirstEnergy, was organized under the laws of the State of Ohio in 1997. FES provides energy-related products and services to wholesale and retail customers in the MISO and PJM markets. FES also owns and operates, through its subsidiary FGCO, FirstEnergy’s fossil and hydroelectric generating facilities and owns, through its NGC subsidiary, FirstEnergy’s nuclear generating facilities. FENOC, a separate subsidiary of FirstEnergy, operates and maintains NGC’s nuclear generating facilities. FES purchases the entire generation output of the facilities owned by FGCO and NGC, as well as the output relating to leasehold interests of OE, CEI and TE in certain of those facilities that are subject to sale and leaseback arrangements with non-affiliates, pursuant to full output, cost-of-service power sale agreements.
FES has a full-requirements power sale agreement with each of OE, CEI and TE to supply each of their Ohio Provider of Last Resort, or POLR, obligations through 2008, at prices that take into consideration amounts the utilities are authorized by the PUCO to bill their customers. FES has a partial-requirements wholesale power sales agreement with Met-Ed and Penelec to supply a portion of each of their POLR obligations at fixed prices through 2010. FES also has energy and capacity available to be sold into the wholesale and spot markets.
FES’ generating portfolio includes 13,273 MW (net) of diversified capacity. Approximately 7,439 MW, or 56.1%, of the portfolio consists of coal-fired capacity; 3,878 MW, or 29.2%, consists of nuclear capacity; 1,513 MW, or 11.4%, consists of oil and natural gas peaking units; and 443 MW, or 3.3%, consists of hydroelectric capacity. These nuclear and non-nuclear facilities are all operated by FENOC and FGCO, respectively, and, except for portions of certain facilities that are subject to the sale and leaseback arrangements with non-affiliates referred to above for which the corresponding output is available to FES through power sale agreements, are all owned directly by NGC and FGCO, respectively. The FES generating assets are concentrated primarily in Ohio, plus the bordering regions of Pennsylvania and Michigan. All FES units are dedicated to MISO except Beaver Valley, which is designated as a PJM resource. FES’ portfolio also includes 463 MW of gen eration through FGCO’s 20.5% entitlement to the generation output owned by OVEC and 215 MW of long-term contracts for renewable energy from wind resources.
Recent Developments
Rating Agency Actions
In late March 2007, FES received a corporate credit rating from S&P of BBB and an issuer rating from Moody’s of Baa2. In order to support these ratings, FES entered into downstream guaranties in favor of present and future holders of FGCO and NGC indebtedness, and FGCO and NGC have entered into upstream guaranties in favor of present and future holders of FES indebtedness, which provide guaranteed parties with claims against each of FES, FGCO and NGC regardless of whether their primary obligor is FES, FGCO or NGC.
The Original Certificates were rated Baa2 by Moody’s and BBB by S&P.
Intra-System Generation Asset Transfers (GAT)
On October 24, 2005, FGCO acquired the owned fossil and hydroelectric generation assets of OE, CEI, TE and Penn. Prior to the asset transfer, FGCO leased these non-nuclear plants from those utilities pursuant to a master facility lease. On December 16, 2005, NGC acquired the owned nuclear generation assets of OE, CEI, TE and Penn. These transactions were undertaken pursuant to the restructuring plans of OE, CEI, TE and Penn that were approved by the Ohio and Pennsylvania regulators under applicable electric utility restructuring legislation. Consistent with these restructuring
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Table of Contentsplans, generation assets that had been owned by OE, CEI, TE and Penn were required to be separated from the regulated delivery businesses of those companies through transfers to a separate corporate entity. The generating plant interests that were transferred do not include leasehold interests of OE, CEI and TE in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.
On December 28, 2006, the NRC approved FirstEnergy’s transfer of ownership of NGC to FES and effective December 31, 2006, NGC became a wholly-owned subsidiary of FES.
New Coal Supply Agreement
On June 22, 2006, FGCO entered into a new coal supply agreement with CONSOL under which CONSOL will supply a total of more than 128 million tons of high-Btu coal to FGCO over a 20-year period beginning in 2009. The new agreement will replace a coal supply agreement that took effect in 2003 and originally was to expire in 2020 but will now expire at the end of 2008. Under the new agreement, CONSOL will increase its coal shipments to approximately 6.5 million tons per year to provide approximately 80% of the coal for the Mansfield Plant.
Upsized Credit Facility
On August 24, 2006, FES, FirstEnergy and certain of its subsidiaries, entered into a new $2.75 billion five-year syndicated revolving credit facility, which replaced FirstEnergy’s prior $2 billion credit facility. Subject to specified conditions, FirstEnergy may request an increase in the total commitments available under the new facility to a maximum of $3.25 billion. Commitments under the new facility will be available until August 24, 2011, unless the lenders agree, at the request of the borrowers, to up to two additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each borrower are subject to a specified sublimit, as well as applicable regulatory and other limitations. FES is currently able to borrow up to $250 million under the facility.
Increased Generation Capacity
In 2005, the Mansfield Plant began modernization projects that, when fully completed, increase the net demonstrated capacity of each of Units 1, 2 and 3 to 830 MW. The Unit 1 project was completed in the fall of 2005, and the project for Unit 2 was completed in November 2006, while Unit 3, currently rated at 800 MW, is scheduled for project completion by December 2007.
On April 19, 2006, Beaver Valley Unit 1 was returned to service following a 65-day refueling and steam generator replacement outage during which the plant’s capacity was uprated from pre-outage capacity by 3 MW through the replacement of the steam generators. A further uprate of 25 MW was achieved in September 2006, in accordance with a thermal power uprate approved by the NRC.
On April 27, 2006, Davis-Besse was returned to service following a 52-day refueling and maintenance outage during which the plant’s capacity was uprated from pre-outage capacity by 14 MW through the replacement of the low pressure turbine rotors.
On November 12, 2006, Beaver Valley Unit 2 was returned to service following a 41-day refueling and maintenance outage. On February 1, 2007, a 10 MW uprate in generation capacity was approved by the NRC.
Pollution Bond Debt Refundings
In connection with the generation asset transfers, FGCO issued approximately $147 million of pollution control debt in April 2006 and approximately $393 million of additional pollution control debt in December 2006 through Ohio and Pennsylvania industrial development authorities. Similarly, NGC issued approximately $270 million, $106.5 million and $485 million of pollution control debt through these authorities in December 2005, April 2006 and December 2006, respectively. In each case, the net proceeds from the issuance and sale of the bonds were used to refund an equal aggregate
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Table of Contentsamount of pollution control bonds previously issued in various series on behalf of OE, Penn, CEI and TE. FGCO and NGC expect to effect further refundings subject to market conditions and other factors. Except as described below, all of the refunding issues are currently supported by bank LOCs for which FirstEnergy is either the account party or the guarantor of the reimbursement obligations of FGCO or NGC, as applicable. Provisions were included in the April 2006 transactions and the November 2006 transactions that permit FES to replace FirstEnergy as guarantor so long as we maintain senior unsecured debt ratings of at least BBB− by S&P and Baa3 by Moody’s. On June 1, 2007, $129.6 million of pollution control bonds were remarketed in connection with the delivery of an alternate bank LOC for which FES provided a guaranty of the reimbursement obligations of FGCO.
Environmental Compliance Developments
On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and the States of Connecticut, New Jersey and New York that resolved all issues related to the Sammis NSR Litigation. This settlement agreement, which is in the form of a consent decree, was approved by the U.S. District Court for the Southern District of Ohio on July 11, 2005, and requires reductions of NOX and SO2 emissions at Sammis, Burger, Eastlake and the Mansfield Plant through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agr eement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation settlement agreement are currently estimated to be $1.7 billion for 2007 through 2011 ($400 million of which is expected to be spent in 2007, with the largest portion of the remaining $1.3 billion expected to be spent in 2008 and 2009). All of these expenditures are to be borne by FES and FGCO. On August 26, 2005, FGCO entered into an agreement with Bechtel, under which Bechtel will engineer, procure and construct air quality control systems for the reduction of SO2 emissions at Sammis. SCR systems for the reduction of NOx emissions required by the settlement are also being installed at Sammis under a 1999 agreement with B&W.
In accordance with the Sammis NSR Litigation consent decree, FGCO is required to modernize the existing FGDs on Units 1, 2, and 3 at the Mansfield Plant to achieve an SO2 removal efficiency of at least 95%. The consent decree also requires the Mansfield Plant to achieve additional SO2 reductions, as compared to 2003 emissions levels, in amounts ranging from 4,000 tons in 2006 to 12,000 tons in 2008 and each year thereafter. The FGD efficiency improvements were completed on Units 1 and 2 in 2005 and 2006, respectively, and are expected to be completed on Unit 3 by the end of 2007. FES currently expects that its air quality control plan will satisfy all emission reducti on requirements imposed by the Sammis NSR Litigation consent decree.
On May 22, 2007, FirstEnergy and FGCO received a notice letter from PennFuture, required 60 days prior to the filing of a citizen suit under the federal Clean Air Act, alleging violations of air pollution laws at the Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Mansfield Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with applicable laws will continue. On July 25, 2007, FirstEnergy and PennFuture entered into a tolling and confidentiality agreement that provides for a 60-day negotiation period during which parties have agreed to not file a lawsuit.
On June 10, 2007, FGCO experienced a stack rain incident, which occurred when the Mansfield Plant’s environmental system was being brought back on-line following maintenance. FGCO determined a device recently added to remove moisture from flue gas malfunctioned. The device, called a mist eliminator, is part of the plant’s flue-gas desulfurization, or scrubber system, and was added to the Mansfield Plant as part of the work required by the Sammis NSR Litigation consent decree.
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Table of ContentsNRC Demand for Information
On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for Information to FENOC following FENOC’s reply to an April 2, 2007 NRC request for information about the expert witnesses’ report and another report. The NRC indicated that this information is needed for the NRC ‘‘to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.’’ FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand for Information reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains commited to operating Davis-Besse and FirstEnergy&r squo;s other nuclear plants safely and responsibly. The NRC held a public meeting on June 27, 2007 with FENOC to discuss FENOC’s response to the Demand for Information. In follow-up discussions, FENOC was requested to provide supplemental information to clarify certain aspects of the Demand for Information response and provide additional details regarding plans to implement the commitments made therein. FENOC submitted this supplemental response to the NRC on July 16, 2007. On August 15, 2007, FENOC received a Confirmatory Order issued by the NRC confirming its commitment to implement certain corrective actions designed to ensure that issues similar to those that gave rise to the May 14, 2007 Demand for Information do not recur. We can provide no assurances as to the ultimate resolution of this matter.
Strategy
FES is focused on managing the transition to competitive markets, realizing the full potential of the FES asset base, mitigating commodity-related risks and enhancing financial strength and flexibility. FES plans to execute this strategy by focusing on several fundamental business and financial goals, including:
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| • | maintaining a diversified and competitive generation portfolio; |
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| • | focusing on operational excellence and on safety, environmental compliance, reliability, and cost competitiveness performance for the generating assets; |
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| • | optimizing the profitability and performance of the generating assets and leveraging FES’ commodity and risk management functions while enhancing FES’ ability to participate in the evolving energy markets in which it competes; and |
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| • | efficiently investing in generating asset growth by exploiting the potential of FES’ existing assets to make cost-effective capacity additions that take into account market conditions, regulatory developments and environmental compliance issues. |
Competitive Strengths
FES believes that it is well positioned to grow its business and continue its solid financial performance due to its strategically located and cost-effective generation fleet, comprehensive commodity and risk management functions, experienced management and operating personnel and a stable earnings and cash flow profile. FES believes that it has significant competitive advantages, including:
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| • | Diversity, Location, Performance and Scale of Asset Base. FES has a 13,273 MW generation fleet, with 11,317 MW of coal-fired and nuclear assets. The FES generating assets are strategically located on the eastern side of MISO and in central PJM, two mature and liquid RTOs, giving FES flexibility to sell excess capacity and energy. These assets have been reliable, as evidenced by their high availability and continued performance improvement, and have benefited from diligent maintenance and significant capital improvements. The assets have demonstrated cost-competitive production performance relative to other facilities within their respectiv e markets. In addition, the NERC estimates that the amount of unused available capability at peak load as a percentage of total capability, or ‘‘reserve margin’’ for |
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| | the region in which the FES assets are located will decline from 23.0% in 2006 to 11.1% in 2015. Shrinking reserve margins are the result of demand growth outpacing net new capacity additions during the forecast period. This decline is among the steepest of all NERC regions and is expected to form a foundation for higher energy and capacity prices in the future. FES believes that it is well positioned for profitable growth benefiting from location relative to fuel infrastructure, proximity to attractive wholesale markets and operational excellence. |
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| • | Integrated Commodity and Generating Functions. FES believes that it has a disciplined commodity sourcing policy that is focused on providing predictable power profit margins and reducing volatility while optimizing the value of FES’ generating units, minimizing fuel uncertainty and related expenses and managing all electric, coal, gas and emission allowance commodities to provide margin. |
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| • | Disciplined Risk Management Approach. The general risk management philosophy of FES is to avoid unnecessary risk and to manage risks by adhering to FES-approved risk tolerances and limits. FirstEnergy’s Risk Management Group provides oversight and daily monitoring of FES’ risk limits and counterparty balances. Risk policies and counterparty credit management minimize downside risk. |
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| • | Experienced Management and Flexible Workforce. FES’ senior management is comprised of individuals with substantial industry experience and significant market expertise in PJM and MISO. FES is also distinguished by the continuity and experience of its operational personnel. See ‘‘Management’’ for a more complete description of FES’ management team. |
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| • | Stable Earnings and Cash Flow Profile. FES has current contractual arrangements to provide power to affiliated utilities. FES has a full-requirements cost-of-service contract to service the POLR load for FirstEnergy’s Ohio utilities through 2008 and has a partial-requirements contract to serve a portion of the POLR load for Met-Ed and Penelec through 2010. FES believes that low operating costs, aggressive fuel supply management and PJM/MISO expertise will enable FES to continue to produce a stable and growing earnings and cash flow profile even in more competitive markets. |
FES’ Business
FES and its affiliates generate and sell electricity and provide energy planning and procurement- related products and services. FES is a licensed electricity supplier in Ohio, Pennsylvania, New Jersey, Delaware, Maryland, Michigan and Washington, D.C.
Currently, the major portion of electric energy produced by FES’ portfolio of generating units is sold (by it) to affiliated electric utility companies in Ohio and Pennsylvania pursuant to full or partial-requirements agreements to support some or all of those companies’ POLR obligations under state utility regulation. As those affiliate contracts expire or otherwise decrease in connection with the transition to competitive electricity markets in those states over the next two to four years, a greater portion of such energy will be available to be sold by FES to third parties either (at wholesale or retail) pursuant to long-term contracts or (in the spot markets).
Principal FES Business Units
FES’ business strategy is executed through its three business units and its relationship with FENOC:
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| • | Commodity Operations is principally responsible for maximizing generation margin and the use and value of FES’ generating units while minimizing supply and commodity risk; |
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| • | Retail Operations provides FES with competitive business skills and retail market flexibility. Retail Operations works closely with FES’ Commodity Operations unit to bring added value to FES’ generation assets above the value inherent in the wholesale markets; and |
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| • | Fossil Operations is responsible for power plant operations, maintenance and engineering. The Fossil Operations unit includes over 1,800 employees at 14 plants. |
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Table of ContentsThese business units are supported by three groups within FES and, with respect to corporate shared service functions (e.g., legal, human resources and purchasing), by FirstEnergy Service Company, or FESC, the FirstEnergy subsidiary responsible for shared services across the FirstEnergy holding company system. The three groups within FES are:
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| • | The FES Finance Group, which provides financial reporting and analytical support to FES’ business units; |
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| • | The Commodity Supply Planning Group, which is principally responsible for managing the composition of the long-term asset and commodity contract portfolio to maximize profit potential and reduce margin volatility to acceptable levels. The Commodity Supply Planning Group includes these three functions: Portfolio Planning, Asset Development and Market Analytics; and |
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| • | The Air Quality Compliance Group, which is primarily responsible for identifying and installing appropriate technologies to comply with the CAIR and mercury regulations in conjunction with the goals and practices of FirstEnergy’s Environmental Department and FES’ Commodity Supply Planning Group. |
Commodity Operations
There are five subgroups within the Commodity Operations business unit. The function and responsibility of each subgroup is as follows:
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| • | Market Intelligence and Risk Mitigation, which is principally responsible for (i) identifying long-term regulatory, market structure and competitor developments that could significantly affect FES and (ii) actively participating in MISO, PJM and other industry-related organizations to appropriately represent FES; |
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| • | Fuel Procurement, which is primarily responsible for securing non-nuclear fuel and fuel-related commodities used by the generating units to optimize profitability, while minimizing price and volume risks; |
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| • | Asset Utilization, which is principally responsible for maximizing the short-term profitable use of FES’ generating units through hourly and daily dispatching measures; |
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| • | Marketing and Power Sourcing, which is principally responsible for maximizing the long-term profitable use of FES’ generating assets, utilizing purchased power only to the extent it is needed to supply POLR obligations in excess of economic generation capability as well as entering into long- and short-term wholesale sales arrangements to maximize the value of output of FES’ generating fleet; and |
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| • | Transmission Utilization, which is primarily responsible for coordinating the budgeting and performance management with the goal of minimizing MISO/PJM non-energy expenses. |
Retail Operations
The Retail Operations unit provides FES with the skills necessary to succeed in competitive markets and retail market access. It works closely with the Commodity Operations unit to bring added value to the generation portfolio above the value inherent in the wholesale markets. The Retail Operations unit has been operating in deregulated markets since 1998, having adapted to the changing regulatory structures in the Midwest and Mid-Atlantic regions. The Retail Operations Group has experience in competitive markets which it expects to apply when its largest target markets transition to market-based rates in the 2009 to 2011 timeframe. The Retail Operations unit’s strategic plan is to continue to secure long-term predictable retail load and pricing.
Retail Operations has two distinct, yet related, product lines:
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| • | Retail Electric, a regional retail electric supplier, provides strategic value to FirstEnergy by preparing FES for the continuing transition to market-based rates in Ohio and Pennsylvania; and |
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| • | The E Group, an energy consulting services provider, allows FirstEnergy to develop and transfer market intelligence across the organization and leverages Retail Operations’ core strength in managing energy. |
Retail Electric targets retail markets in the areas immediately surrounding the core regulated electric utilities in the MISO/PJM footprint. As a regional retail electricity supplier, FES focuses on selected deregulated markets served by utilities in Ohio, Pennsylvania, New Jersey, Maryland and Michigan. Operating in retail markets near its generation assets allows FES to optimize the generation portfolio by securing retail electric contracts at fixed prices, resulting in revenue streams and increased margins above those available in the wholesale spot market. As of June 30, 2007, Retail Electric provided electricity to over 50,000 commercial and industrial customers and over 250,000 residential customers in Ohio, primarily through government aggregation programs. It sold over 11.7 million MWh of energy in 2006, representing more than 1,300 MW.
The E Group offers strategic energy consulting services to commercial and industrial clients in the United States and Canada, providing them with intellectual assets and solutions for all of their energy and utility needs in today’s complicated energy markets. The E Group provides energy procurement and risk management services to residential and small commercial clients who participate in government aggregation programs. As of June 30, 2007, the E Group managed over 120,000 accounts and a total utility portfolio of approximately $1.2 billion. The services provided by the E Group include: bill payment, bill auditing and tariff auditing, energy procurement, risk management and energy reporting and energy conservation.
Fossil Operations
Fossil Operations is responsible for maximizing the use of FES’ generating units through the consistent and predictable operation of the fossil generating fleet. The Fossil Operations group encompasses everything from operations and maintenance activities at plant locations to group planning, engineering and management functions located at the corporate headquarters. Fossil Operations strives to maximize the safe and reliable output of FES’ generating units while achieving operational excellence in safety, environmental compliance, reliability and cost competitiveness.
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| • | Safety. To ensure safety in the workforce, all employees must be engaged in a number of company safety programs. Fossil Operations requires employees to commit to the prevention of accidents and unsafe acts, making safety their first priority. |
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| • | Environmental Compliance. Those managing the fossil generating fleet strive to achieve environmental compliance with all air emission and pollutant discharge standards. Fossil Operations will make significant investments to comply with and meet or exceed environmental compliance thresholds. |
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| • | Reliability. Over the past several years, the reliability of the generating assets has continuously improved and will be essential to achieving future generation forecasts and assuring predictable performance results. Reliability of FES’ fleet is measured by equivalent forced outage rate, or EFOR, a measure of the percentage of time a unit is forced off-line or unavailable. The goal of Fossil Operations is to improve the fleet level EFOR with the baseload units achieving an EFOR under 3% and the load following units achieving an EFOR under 4%. |
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| • | Cost Competitiveness. The reliable operation of generation assets provides the foundation for Fossil Operation’s financial focus on achieving generation margin goals. Managing cost of goods sold will ensure that FES remains competitive with other regional generators. Fossil Operation’s mission is to understand the cost performance drivers and identify opportunities to improve cost structures. Fossil Operations’ goal is to sustain or improve asset reliability while making incremental cost improvements. Fossil Operations seeks to optimize the period between outages and reduce the total outage duration to maximize unit outpu t without compromising the operating performance of the units. |
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Table of ContentsFES Products and Services
FES’ primary product is electric energy, which it generates and sells, or purchases for resale, in wholesale and retail markets. In the MISO and PJM wholesale energy markets in which FES participates, the applicable RTO is responsible for maintaining system reliability, ensuring the competitiveness and efficiency of the market, establishing various electricity products to be offered for sale and managing the spot market for those products. See ‘‘—Power Markets’’ below. The three primary products traded in these markets are energy, capacity and ancillary services.
Energy
Electrical energy is produced by generation plants and ultimately is delivered to customers for use in lighting, heating and air conditioning and operation of other electrical equipment. Energy is FES’ principal product and is priced on a usage basis, which is referred to herein in dollars per MWh.
In bid-based energy markets such as PJM and MISO, owners of power plants specify prices at which they are prepared to generate and sell energy for the next day. Plant operators generally establish hourly bid prices at a level that approximates the marginal cost of generating energy from each individual unit at that plant. Marginal costs consist of fuel costs, variable operation and maintenance costs and other variable costs, including air emission allowances. Generator offer prices are typically capped at $1,000 per MWh.
The bid price for each plant is submitted to the RTO. Based upon bids received, the RTO instructs the units as to when they are to generate power, generally calling on the lowest cost units first. Typically, progressively higher bid units are called on, or dispatched, in what is referred to as merit order, up until the point that the entire system’s demand for power, or load, is satisfied. The bid price of the last unit dispatched by the RTO establishes the energy market-clearing price. All units that are dispatched are paid this price for each MWh of energy produced, regardless of their specific bid prices. Since bids generally approximate the marginal cost of production, units with lower marginal costs generally run more hours over the course of a year and generate higher operating profits than units with relatively higher marginal costs.
At times, however, the transmission system becomes constrained when one or more parts of the transmission grid are at their full capability. During periods of transmission congestion, it is not possible to dispatch units in merit order without violating transmission reliability standards. Under such circumstances, the RTO will dispatch higher-cost generation out of merit order within the congested area, and power suppliers will be paid a locational marginal price, or LMP, that is higher in the congested areas reflecting the price bids of those higher-cost generation units.
In addition to bidding into the market, owners of power plants sell energy forward on a wholesale basis under contract to power marketers and to load serving entities, or LSEs, such as investor-owned and municipal utilities, and aggregators who resell energy to retail consumers.
Capacity
Capacity, as a product that is distinct from energy, is a commitment to the RTO that a given unit will be available for dispatch if it is needed to meet system demand. Capacity is typically priced in dollars per MW for a given sale period (e.g., MW-day or MW-year). Capacity generally refers to the power output rating of a generation plant, measured on an instantaneous basis. Thus, a coal-fired plant, for example, that can produce 500 MWh of energy in one hour is said to have a capacity of 500 MW.
PJM and MISO each maintain a reserve requirement as a means of ensuring power reliability and managing the energy market. Each LSE is required to secure enough capacity to meet the peak demand of its retail customers, plus an additional amount as a reserve margin. This reserve margin attempts to ensure that unpredicted peak demand increases or equipment unavailability does not cause a major system or market disruption. Owners of generation plants can sell their capacity to LSEs or to other wholesale market participants for resale. Subject to certain characteristics, a contract
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Table of Contentsfor capacity only commits the provider to make a generation unit available for dispatch by the RTO if it is needed. Should the unit actually be dispatched by the RTO, compensation for the resulting energy produced is settled in the energy market. PJM administers a market for capacity. MISO does not currently administer a separate capacity market, although MISO requires each LSE to identify the MISO resources that it will use to meet its hourly peak load plus operating reserve on a day-ahead basis.
Ancillary Services
Ancillary services, which include operating reserves, regulation and black start capability, constitute another category of energy-related activities supplied by generation unit owners to the RTO. The RTO requires such services to ensure the safe and reliable operation of the bulk power system. The market for ancillary services exists solely on a wholesale level. Owners of generation units may bid units into the Ancillary Services Market and, in turn, receive compensatory payment from the RTO. The RTO recovers the cost of paying generators for ancillary services through charges imposed on market participants. PJM has established markets for certain ancillary services. MISO Ancillary Services Markets were expected to be implemented in the second or third quarter of 2008, however, MISO’s filing to establish such a market was rejected by the FERC on June 22, 2007. Until such a market is established, ancillary services in MISO will continue to be cos t-based services.
Area regulation service entails allowing the RTO to control the output of a unit to match the constantly fluctuating system demand. Generally, this results in the unit operating at less than full output. The RTO pays the provider of area regulation services a rate which compensates it for the opportunity cost of operating at less than full output (i.e., the market price of energy which could have been produced and sold during this period) plus an incentive amount to compensate for any additional equipment wear.
Operating reserves allow the RTO to compensate for sudden changes in supply or unforeseen increases in demand that occur when there is a sudden loss of a large generation unit, a problem with a transmission line or a mismatch between forecast and actual load. By operating steam units that otherwise would not be dispatched, and synchronizing combustion turbines to the bulk power system, generators are able to provide these ancillary services to the RTO. Synchronizing a combustion turbine to the system involves starting a unit and adjusting it so that the RTO can quickly bring the unit up to full power if it is needed. Once the unit is synchronized, it is spinning at normal rotational speed but does not generate electric output until directed to do so by the RTO. The RTO pays generators operating reserve payments that reflect their bid prices for providing these services.
Generation Assets
General
As of June 30, 2007, FES’ portfolio of generation assets consisted of 13,273 MW of installed capacity including output relating to affiliate sale and leaseback arrangements. Of this total, approximately 11,551 MW, or approximately 87%, are located within MISO, which equates to approximately 8.6% of MISO’s available capacity as of that date, with Beaver Valley dedicated to PJM. These assets are diversified in terms of fuel type, technology and dispatch profile. The portfolio’s diversity represents a balance that helps to mitigate risks associated with fuel price volatility and market demand cycles and allows FES to employ its baseload/load following strategy.
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Table of ContentsThe following table provides summary profiles of FES’ fossil, hydroelectric and nuclear generation plants and the units that comprise them:
| | | | | | | | | | | | | | | | | | |
| Plant | | | Location | | | Unit
Nos. | | | Primary
Fuel Type | | | Dispatch Type
(Unit) | | | Net
Demonstrated
Capacity (MW) |
| Ashtabula | | | Ashtabula, OH | | | 5 | | | Coal | | | Load Following | | | | | 244 | |
| Bay Shore | | | Toledo, OH | | | 1-4 | | | Coal | | | Load Following(2-4) | | | | | 631 | |
| | | | | | | | | | | | | Baseload(1) | | | | | | |
| Burger | | | Shadyside, OH | | | 3-5 | | | Coal | | | Load Following(4,5) | | | | | 406 | |
| | | | | | | | | | | | | Peaking(3) | | | | | | |
| Eastlake | | | Eastlake, OH | | | 1-5 | | | Coal | | | Load Following(1-4) | | | | | 1,233 | |
| | | | | | | | | | | | | Baseload(5) | | | | | | |
| Lakeshore | | | Cleveland, OH | | | 18 | | | Coal | | | Load Following | | | | | 245 | |
| Mansfield Plant | | | Shippingport, PA | | | 1-3(a) | | | Coal | | | Baseload | | | | | 2,460 | |
| Sammis | | | Stratton, OH | | | 1-7 | | | Coal | | | Baseload(6,7) | | | | | 2,220 | |
| | | | | | | | | | | | | Load Following(1-5) | | | | | | |
| Coal Total | | | | | | | | | | | | | | | | | 7,439 | |
| Beaver Valley | | | Shippingport, PA | | | 1 and 2(b) | | | Nuclear | | | Baseload | | | | | 1,722 | |
| Davis-Besse | | | Oak Harbor, OH | | | 1 | | | Nuclear | | | Baseload | | | | | 898 | |
| Perry | | | N. Perry Village, OH | | | 1(c) | | | Nuclear | | | Baseload | | | | | 1,258 | |
| Nuclear Total | | | | | | | | | | | | | | | | | 3,878 | |
| Seneca (Pumped Storage) | | | Warren, PA | | | 1-3 | | | | | | Load Following | | | | | 443 | |
| Hydroelectric Total | | | | | | | | | | | | | | | | | 443 | |
| Richland | | | Defiance, OH | | | | | | Gas/Oil | | | Peaking | | | | | 432 | |
| Sumpter | | | Sumpter Twp, MI | | | | | | Gas | | | Peaking | | | | | 340 | |
| West Lorain | | | Lorain, OH | | | 1(A-B)
and 2-6 | | | Gas/Oil | | | Peaking | | | | | 545 | |
| Edgewater | | | Lorain, OH | | | | | | Oil | | | Peaking | | | | | 48 | |
| Mad River | | | Clark, OH | | | | | | Oil | | | Peaking | | | | | 60 | |
| Stryker | | | Williams, OH | | | | | | Oil | | | Peaking | | | | | 18 | |
| Other | | | OH | | | | | | | | | Peaking | | | | | 70 | |
| Gas/Oil Total | | | | | | | | | | | | | | | | | 1,513 | |
| Total | | | | | | | | | | | | | | | | | 13,273 | |
| (a) | Includes FGCO’s leasehold interest in Mansfield Plant Unit 1 of 93.825% (779 MW); CEI’s leasehold interest in the Mansfield Plant Unit 1 of 6.175% (51 MW); CEI’s and TE’s leasehold interests in the Mansfield Plant Unit 2 of 27.170% (226 MW) and 16.435% (136 MW), respectively, and CEI’s and TE’s leasehold interests in the Mansfield Plant Unit 3 of 23.247% (186 MW) and 18.915% (151 MW), respectively. |
| (b) | Includes OE’s and TE’s leasehold interests in Beaver Valley Unit 2 of 21.66% (185 MW) and 18.26% (156 MW), respectively. |
| (c) | Includes OE’s leasehold interest in Perry of 12.58% (158 MW). |
Diversity Among Dispatch Market Segments
There are generally three energy market segments that refer to the dispatch profile of a particular unit: baseload, load following (also referred to as mid-merit) and peaking. Generation units are typically characterized as serving one or more of these markets based on their operating capability, performance and cost characteristics. On a capacity basis, FES’ portfolio of generation assets consists of 62.3% baseload, 22.2% load following and 15.5% peaking. This balanced distribution among market
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Table of Contentssegments allows FES to implement its baseload/load following strategy, reduces FES’ risk associated with market demand cycles and allows FES to participate in the market at each segment of the dispatch curve.
The following chart provides a breakdown of FES’ installed generation assets by dispatch type in MW and as a percentage of total net demonstrated capacity:
| | | | | | | | | | | | |
| Dispatch Type | | | Net
Demonstrated
Capacity (MW) | | | As of
June 30, 2007 |
| Baseload | | | | | 8,271 | | | | | | 62.31 | % |
| Load Following | | | | | 2,952 | | | | | | 22.24 | % |
| Peaking | | | | | 2,050 | | | | | | 15.45 | % |
| Total | | | | | 13,273 | | | | | | 100.0 | % |
Baseload Units
Baseload units are the largest and most efficient units to operate. These units are typically greater than 300 MW in capacity and are characterized by high construction (capital) costs, high fixed costs (primarily labor) and low operating costs (primarily fuel). Operating costs are low due to the use of coal and nuclear fuels, which are generally lower in cost per unit of output relative to oil or natural gas. Baseload units are the primary source of FES’ energy revenues and the capacity of these units supports revenues from capacity sales.
Because of their size and operating characteristics, baseload plants are most suited to run for long periods at maximum output. Operating at a steady, high capacity tends to reduce wear on these larger units. Performance of these units is generally measured by ‘‘capacity factor,’’ or the ratio of the actual output of the unit to the theoretical maximum output of the unit if it ran continuously over a given period. Baseload units tend to be profitable to operate in most energy market conditions throughout the year and, therefore, typically are expected to run at capacity factors above 85%. In 2006, 2005, 2004, 2003 and 2002, FES’ baseload fossil units achieved average capacity factors of 89%, 87%, 85%, 80% and 76%, respectively, and its nuclear units achieved average capacity factors of 87%, 87%, 90%, 63% and 73%, respectively.
Nuclear capacity was affected in 2002 and 2003 by the extended outage at Davis-Besse. The capacity factor of a nuclear unit depends in part on the duration of the unit’s refueling outage. Beaver Valley Units 1 and 2 each have scheduled refueling outages approximately every eighteen months. Perry and Davis-Besse have scheduled refueling outages approximately every two years. Perry’s most recent refueling outage occurred on April 2, 2007. The next refueling outages are currently scheduled for 2007 for Beaver Valley Unit 1, 2008 for Davis-Besse and Beaver Valley Unit 2 and 2009 for Perry.
Load Following Units
Load following units are smaller and more flexible, but somewhat less efficient than baseload units. They generally range in size from 100 MW to 300 MW. The construction costs of these units are typically lower than those of baseload plants, but the operating costs are higher per unit of output due to lower efficiency and/or the use of higher-cost fuels, such as oil or natural gas. Load following units are designed to operate less frequently than baseload units (i.e., during those periods when system demand exceeds the baseload capacity of the system) and, therefore, typically have capacity factors that range from 50% to 75%. These units generally support revenues from capacity sales and area regulation, as well as energy revenues during periods of higher energy prices.
Due to the lower MW output of load following units relative to baseload units, a more relevant measure of performance for these units than capacity factor is equivalent availability factor, or EAF, which represents the percentage of time a unit is available to operate during the year versus the percentage of generation output. In 2006, 2005, 2004, 2003 and 2002, the weighted average EAF of FES’ load following units was 86%, 84%, 80%, 80% and 81%, respectively.
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Table of ContentsPeaking Units
Peaking units, which normally have capacities of 10 MW to 150 MW, represent the smallest and most flexible units in FES’ generation fleet. The capital costs and fixed costs of these units are low relative to baseload plants; however, peaking units are the least efficient plants in the FES portfolio and utilize higher-cost fuels such as oil and natural gas. As a result, operating costs per unit of output tend to be much higher than those of baseload units. For this reason, peaking units are operated during times of peak demand and derive the majority of their revenues from capacity and ancillary services sales. However, the operating flexibility and rapid startup characteristics of these units enable them to capture energy revenues during periods of high energy prices, which may occur during times of peak demand or as a result of transmission congestion. As with load following units, the relevant measure of performance is EAF. In 2006, 2005, 2004, 2003 and 2002, the weighted average EAF of FES’ peaking units was 96%, 96%, 95%, 94% and 92%, respectively.
One special class of peaking unit technology is pumped storage hydroelectric. These units utilize electric power during low cost periods (e.g., early morning hours when demand is generally low) to pump water to an elevated reservoir. When energy prices are high, the water is allowed to flow back into the lower reservoir through a turbine, generating electricity. FES owns one pumped storage hydroelectric facility.
Diversity of Fuel Types and Technologies
FES’ portfolio consists of generation assets that are powered by a variety of fuel types. FES’ three nuclear plants, Beaver Valley, Perry and Davis-Besse, run on enriched uranium. Coal, natural gas and oil power FES’ fossil generating stations. FES’ pumped storage hydroelectric station adds additional fuel diversity. The following table provides a breakdown of FES’ installed generation assets by fuel type in MW and as a percentage of total net demonstrated capacity as of June 30, 2007:
| | | | | | | | | | | | |
| Fuel | | | Net
Demonstrated
Capacity (MW) | | | Percentage of
Total Net
Demonstrated
Capacity |
| Nuclear | | | | | 3,878 | | | | | | 29.2 | % |
| Coal | | | | | 7,439 | | | | | | 56.1 | % |
| Gas | | | | | 1,183 | | | | | | 8.9 | % |
| Oil | | | | | 330 | | | | | | 2.5 | % |
| Pumped Storage Hydroelectric | | | | | 443 | | | | | | 3.3 | % |
FES employs conventional steam, combustion turbine and internal combustion generation technologies as well as pumped storage hydroelectric and nuclear technologies. The following table provides a breakdown of FES’ installed generation assets by generation technology in MW and as a percentage of total net demonstrated capacity as of June 30, 2007:
| | | | | | | | | | | | |
| Technology | | | Net
Demonstrated
Capacity (MW) | | | Percentage of
Total Net
Demonstrated
Capacity |
| Conventional Steam | | | | | 7,439 | | | | | | 56.1 | % |
| Nuclear | | | | | 3,878 | | | | | | 29.2 | % |
| Combustion Turbine | | | | | 1,489 | | | | | | 11.2 | % |
| Internal Combustion | | | | | 24 | | | | | | 0.2 | % |
| Pumped Storage | | | | | 443 | | | | | | 3.3 | % |
Nuclear Fuel
FENOC has uranium concentrate inventory and supply contracts sufficient to meet all of the uranium concentrate requirements of FES’ nuclear plants through 2009, with a portion covered through 2014. Contracted conversion services are sufficient to meet all uranium conversion requirements through 2009, with a portion covered through 2014. All of the enrichment requirements
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Table of Contentshave been contracted through 2011, with a portion covered under contract through 2020. Contracts for fuel fabrication have been obtained through 2013. FENOC does not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment or fabrication services for the nuclear units.
Fossil Fuel
Coal is obtained primarily through long-term contracts with the remainder supplied through either short-term contracts or spot-market purchases. Some of the fossil generation stations can use either oil or gas as fuel. Natural gas is procured through annual, monthly and spot-market purchases. Fuel oil inventories are managed such that in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months inventory levels are managed to take advantage of favorable market pricing.
Power Production Breakdown
FES’ coal-fired and nuclear baseload units represent 33.1% and 29.2%, respectively, of net demonstrated capacity, yet accounted for 41.4% and 35.6%, respectively, of total net MWh production for 2006. In contrast, FES’ coal, gas, oil and pumped storage hydroelectric load following and peaking units, which represent 37.7% of installed capacity, accounted for 23.0% of total net MWh production output for the same period. The following table shows the output by energy source of FES’ generating fleet over the twelve months ended December 31, 2006 relative to net demonstrated capacity.
| | | | | | | | | | | | |
| | | | Net
Demonstrated
Capacity as of
June 30, 2007 | | | Output for
year ended
December 31, 2006 |
| Nuclear—Baseload | | | | | 29.2 | % | | | | | 35.6 | % |
| Coal—Baseload | | | | | 33.1 | % | | | | | 41.4 | % |
| Load Following and Peaking | | | | | 37.7 | % | | | | | 23.0 | % |
Operating Licenses
Nuclear
Nuclear facilities are subject to comprehensive regulation by the NRC under the Atomic Energy Act of 1954. Nuclear units are operated under licenses granted by the NRC, which specify permitted operations of the unit and which must be amended to reflect certain changes in operation and plant modifications. Each of the nuclear units in the FES portfolio operates under a 40-year operating license granted by the NRC. FENOC expects to apply for operating license extensions from the NRC for Beaver Valley Units 1 and 2 in 2007, Davis-Besse in 2010 and Perry in 2013. The NRC review process takes approximately two to three years from the docketing of an application. Each requested license extension is expected to be for 20 years beyond the current license period. The following table summarizes operating license expiration dates for FES’ nuclear facilities in service.
| | | | | | | | | | | | |
| Station | | | In-Service
Date | | | Current License
Expiration |
| Beaver Valley Unit 1 | | | | | 1976 | | | | | | 2016 | |
| Beaver Valley Unit 2 | | | | | 1987 | | | | | | 2027 | |
| Perry | | | | | 1986 | | | | | | 2026 | |
| Davis-Besse | | | | | 1977 | | | | | | 2017 | |
Other
Fossil generation plants are generally not licensed and, therefore, the decision on when to retire plants is solely an economic one. Hydroelectric plants are licensed by the FERC. The Seneca facility (pumped storage) has a license that expires in 2015. FES will begin the renewal process for a license renewal of 40 years for this plant beginning in 2008, but the duration of any license renewal will depend on then-current FERC policies. The process of applying for a renewal to an existing hydroelectric license generally takes seven to eight years.
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Table of ContentsLong-Term Contracts
FES purchases the entire generation output of the nuclear and non-nuclear generation fleet from NGC and FGCO, respectively, pursuant to a series of PSAs. The capacity, energy, emission allowances, ancillary services and renewable energy attributes that are available from the utility operating company leasehold interests in those units subject to sale and leaseback agreements are sold to FGCO and NGC through two separate fossil and nuclear PSAs with the applicable utility companies. In turn, FGCO and NGC make available all of the capacity, energy, emission allowances, ancillary services and renewable energy attributes provided by the generating assets to FES through two additional fossil and nuclear PSAs. The agreements include cost-of-service formula rates under which FGCO and NGC are compensated by FES on the basis of costs associated with the ownership and operation of the generating facilities, rather than on the basis of market-based rates. The utility opera ting companies with non-affiliate sale and leaseback agreements are similarly compensated. This rate structure was developed to provide reasonable assurance that FGCO and NGC would be financially qualified to meet their anticipated obligations, including the need to comply with EPA requirements for the installation of pollution control equipment on certain coal-fired generating plants. The initial term of all of the PSAs ends on December 31, 2010, and automatically renews annually thereafter unless terminated by either party upon at least 60 days’ written notice prior to calendar year end.
Ohio Valley Electric Corporation
FES has an indirect long-term purchase agreement with OVEC through its subsidiary, FGCO. OVEC and its wholly-owned subsidiary, Indiana-Kentucky Electric Corporation, were each organized on October 1, 1952, by certain investor-owned utilities to provide power supply to uranium enrichment facilities built by the Atomic Energy Commission near Portsmouth, Ohio. Under the terms of the original Inter-Company Power Agreement, OVEC’s owners or its public utility affiliates, referred to as sponsoring companies, were entitled to excess power and energy not utilized by the enrichment facility for their own use.
Effective April 30, 2003, the United States Department of Energy, or the DOE, terminated its PSA with OVEC, thus making the entire output of the OVEC plants available to the sponsoring companies. An Amended and Restated Inter-Company Power Agreement was entered into on March 13, 2006, extending the sale from OVEC to the sponsoring companies or their affiliates for an additional 20 years to 2026. Under the terms of this agreement, FGCO, a party to the Amended and Restated Inter-Company Power Agreement, is entitled to 20.5% of the power and energy output of the Kyger Creek and Clifty Creek plants owned by OVEC, or approximately 463 MW. The sponsoring companies pay a monthly charge for OVEC power and energy equal to their power participation ratio of energy, demand, and transmission charges (i.e., 20.5% in the case of FGCO). Under an internal PSA, FGCO sells its entire share of OVEC output to FES at cost.
Wind Contracts
FES has entered into several long-term contracts to purchase the output from 215 MW of wind generation in Pennsylvania and West Virginia. Pennsylvania has an Alternative Energy Portfolio Standard which requires that a growing percentage of power consumed in the state be generated by renewable resources. The long-term contracts should supply renewable energy that FES can package with output from its existing generation when selling into Pennsylvania markets. Long-term contracts were used to secure renewable power without FES making substantial upfront investments or bearing the risks associated with developing wind projects. Most of the facilities linked to these contracts are scheduled to be completed during 2007. If any of these wind facilities are not completed, FES will bear no further obligation under the current contracts, but would need to seek alternative sources for renewable energy.
Power Markets
Wholesale Markets Generally
FES’ assets are located in the eastern portion of MISO and central PJM, the two wholesale markets in which FES participates. Both MISO and PJM are dynamic liquid wholesale markets that
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Table of Contentsare quickly adapting to the growing need for energy security and reliability. MISO’s and PJM’s respective reserve margins have remained relatively stable over the past three years.
As reported in the NERC 2006 Long-Term Reliability Assessment, dated October 2006, the NERC forecasts summer reserve margins within the recently-formed RFC, the NERC region which incorporates large portions of MISO and PJM including all of the FES assets, to decline from 23.0% in 2006 to 11.1% in 2015. Shrinking reserve margins are the result of demand growth outpacing net new capacity additions during the forecast period. This decline is among the steepest of all NERC regions and is expected to form a foundation for higher energy and capacity prices in future periods.
MISO
MISO was formed as the nation’s first FERC-approved RTO in December 2001. Designed as an Independent System Operator, or ISO, responsible for the regional flow of electricity in a competitive wholesale market, MISO began selling transmission service under its FERC-approved tariff on February 1, 2002. On April 1, 2005, MISO implemented an integrated real-time and day-ahead LMP energy market. With 137 gigawatts, or GW, of generation capacity and more than 97,000 miles of high voltage transmission lines, MISO serves a peak demand of over 119 GW. FES joined MISO in 2003 when it contracted for transmission services. FES’ market participation began on April 1, 2005 as MISO commenced market operations. FES’ 11,551 MW of installed generation capacity within MISO represents 8.6% of available MISO capacity.
The MISO energy market clears buyer and seller bids on a day-ahead and real time basis. It also includes market instruments such as physical and financial bilateral, and demand bids. In the day-ahead market, energy prices are calculated hourly and are based on location within MISO, thereby forming a market based on LMPs.
MISO uses financial transmission rights, or FTRs, as a financial mechanism designed to hedge against the risk of congestion charges in the day-ahead market. Market participants in MISO can bid, offer, and/or hold FTRs. FTRs are obtained through an initial allocation, FTR auctions, the purchase of new transmission service, transmission expansion and generation interconnection, or a MISO FTR secondary market transaction.
Ancillary services are services necessary to support the transmission of energy from generation resources to loads, while maintaining reliable operation of the transmission system. Unlike PJM, MISO does not have an Ancillary Services Market. Instead, all transmission customers are required to purchase certain ancillary services from MISO in order to satisfy MISO’s reliability requirements. MISO submitted documents to the FERC on February 15, 2007 to establish an Ancillary Services Market. MISO Ancillary Services Markets for regulation, spinning and operating reserve were expected to be implemented in the second or third quarter of 2008, however, on June 22, 2007, the FERC found MISO’s filing to establish such a market to be deficient in two key areas: (1) MISO has not submitted a market power analysis in support of its proposed Ancillary Services Market and (2) MISO has not submitted a readiness plan to ensure reliability during t he transition from the current reserve and regulation system managed by the individual Balancing Authorities to a centralized Ancillary Services Market managed by MISO. MISO was ordered to remedy these deficiencies and FERC provided more guidance on other issues brought up in filings by stakeholders to assist MISO to re-file a complete proposal. This Order should facilitate MISO’s timetable to incorporate final revisions to ensure a market start in Spring 2008. FirstEnergy will be participating in working groups and task forces to ensure the Spring 2008 implementation of the Ancillary Services Market.
In order to ensure long-term resource adequacy, MISO sets requirements in accordance with regional or state standards. If MISO determines that no resource adequacy standard or guideline exists for market participants within a state, it will require an annual reserve margin of 12% for the market participant obligated to serve that load in the applicable state.
There is no MISO capacity market; however, resources designated as network resources must bid into the day-ahead market.
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Table of ContentsPJM
PJM is a control area, an ISO and an RTO and is responsible for one of the largest competitive wholesale electricity markets in the world. As an ISO, PJM operates but does not own transmission systems to provide open access to the grid for all its members. With generating capacity of approximately 165 GW and 56,070 miles of transmission lines, PJM serves 51 million people and a peak load of 131 GW. FES joined PJM in 2001 when FirstEnergy acquired GPU. In 2005, Beaver Valley was dedicated to PJM by FES as part of PJM’s expansion to include Duquesne Light Company. Currently, FES’ 1,722 MW of installed generation capacity within PJM represents 1.1% of total PJM installed capacity.
The PJM energy market clears buyer and seller bids on a day-ahead and real time basis. Energy prices in the day-ahead market are calculated each hour based on location. The day-ahead price calculations and the balancing real time price calculations are based on locational marginal pricing. Market participants within PJM can submit generation bids either based on variable fuel costs or based on prices. Demand bids and virtual bids, which are purely financial in nature, are also permitted.
PJM has both a centralized commitment and dispatch. Dispatching includes system control, ancillary service monitoring, and transmission system monitoring and control. For example, PJM will direct members to adjust the output of any PJM-scheduled resource, commit unscheduled PJM resources, operate PJM’s transmission resources, commit the most cost-effective regulation and spinning reserve service available, and monitor congestion on the transmission lines.
PJM manages congestion through physical rights to transmission. If redispatch is insufficient to control congestion, transmission load relief may be initiated. As in MISO, market participants can hedge against congestion costs through FTRs, which entitle owners to congestion payments. FTRs are auctioned on an annual and monthly basis and auction revenue rights are allocated annually. PJM manages all intra-market congestion through the use of dispatch which is based on generation bid prices for both the day-ahead and real time markets.
PJM administers five ancillary services that together are designed to support the transmission of capacity and energy from resources to load while maintaining the transmission system. These services are: (1) scheduling, system control and dispatch service, which are the core administrative functions of the energy and transmission markets; (2) reactive supply and voltage control from generation sources, which maintain voltages within acceptable limits; (3) regulation and frequency response service, which provides for the continuous balancing of resources with load in order to maintain a constant electrical frequency; (4) energy imbalance service, which covers the difference between hourly scheduled and actual delivery to load; and (5) the reserve services, consisting of operating reserve, spinning reserve and black start, which together supply capacity to serve load in the event of a system contingency.
PJM administers daily, monthly and multi-monthly capacity credit markets. The capacity credit market is a market in which participants may exchange ‘‘unforced’’ capacity at a single market clearing price. On August 31, 2005, PJM proposed to the FERC a new Reliability Pricing Model, or RPM, to improve upon the current system. Key aspects of the RPM include a capacity market that is: (1) locational, (2) committed three years in advance, (3) inclusive of a demand response mechanism, and (4) inclusive of energy revenues for recovering generation investments. On December 22, 2006, the FERC conditionally approved the RPM settlement. The FERC issued an order on rehearing on June 25, 2007, directing PJM to adopt additional monitoring and reporting requirements and accepting a compliance filing with an effective date of June 1, 2007.
Regional Market Development Implications for FES
FES will continue to benefit from operating in two dynamic markets that are working proactively to continue to resolve the variety of issues that accompanied the restructuring of wholesale markets. In particular, FES will benefit from:
| | |
| • | price discovery by participating in both MISO and PJM markets; and |
| | |
| • | the ability to sell power across two markets, taking advantage of inter-market price differentials. |
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Table of ContentsRegional Reliability Organization
RFC began operations as a regional reliability council under the NERC on January 1, 2006 and in November 2006 filed to obtain certification as a ‘‘regional entity’’ under the ERO. RFC’s delegation agreement with the NERC was accepted by the FERC on April 19, 2007. RFC was created through a consolidation of three reliability councils, the ECAR, the MAAC, and the MAIN into a single new regional reliability organization. All of FES’ facilities are located within the RFC region. RFC membership currently consists of 43 regular members and 19 associate members. The members serve the electrical requirements of more than 72 million people in an area covering all of the states of Delaware, Indiana, Maryland, Ohio, Pennsylvania, New Jersey and West Virginia, plus the District of Columbia, as well as portions of Illinois, Kentucky, Michigan, Tennessee, Virginia and Wisconsin.
Fuel Supply
Fossil Fuel Procurement
The procurement and delivery of commodities including coal, natural gas, fuel oil, emission allowances and air quality control systems reagents and additives are managed by the FES Commodity Operations Fuel Procurement Department.
FES’ coal-fired units originally combusted relatively high sulfur content Northern Appalachian coal. However, low sulfur subbituminous coal from the Powder River Basin, or PRB, area of Wyoming has become a favorable economic alternative due to its historically lower price and the cost of SO2 allowances. FES has utilized PRB coal at most of its coal-fired plants. The Mansfield Plant, which utilizes SO2 scrubbers, is an exception to this strategy since the scrubbers dramatically reduce SO2 allowance consumption.
To minimize coal price risk and volatility, FES has taken a number of steps to hedge its market exposure. Every FES coal plant has more than one fuel delivery option, although for some of the plants, the second option is trucking or water delivery (added at a reasonable cost). For plants that are primarily dependent upon rail delivery, a second option is essential to ensure that competitive rail rates can be obtained. The plants with water delivery options could obtain competitive rates via different barge companies; however, water-only delivery has both price and delivery risks. Barge rates are somewhat volatile while lock outages and unanticipated river conditions can block deliveries.
To avoid commodity price volatility for coal purchases, FES’ risk policy requires 80% of the current year’s fuel requirements to be covered with contracted supplies. FGCO’s current contracts cover eastern coal requirements and PRB coal requirements (on a Btu basis) in excess of risk policy requirements through 2010. Several of these contracts have options for extension and price re-openers, which further limit price exposure. Of FES’ Northern Appalachian supply, up to 6.5 Mtpy is under contract with CONSOL through 2028. FGCO has two other mid-sulfur high Btu contracts supplying 1.5 to 2.0 Mtpy and an additional contract supplying 3.0 Mtpy of rail and river coal through 2011 and 2021, respectively. FGCO currently plans to have a total of 14 Mtpy of Northern Appalachian coal under contract by 2008 for delivery after 2010.
In recent years, rail rates have also experienced strong upward trends. FGCO is currently in negotiations to ensure supply coal transportation services via railroad to Eastlake, Lakeshore, Burger and Sammis through 2010. FGCO has all rail prices covered through 2007 via agreements with DTE Coal Services, Inc. and a separate agreement with CSX Transportation Inc. for the Mansfield Plant. To further protect against increasing rail rates and facilitate delivery success, FGCO leases 36 rail sets. In addition, Burger, Sammis and the Mansfield Plant have barge transportation agreements that extend through 2009.
Fuel oil and natural gas are used primarily for peaking units and to start the burners prior to burning coal when a plant is restarted. Fuel oil requirements have historically been low and are forecast to remain so, averaging approximately 5 million gallons per year, at a cost of approximately $8.5 million per year, over the next five-year planning period. Since the price and supply risk associated with fuel oil procurement is perceived to be low compared to the overall FES generating
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Table of Contentsfleet fuel requirements, most fuel oil is purchased through annual contracts at market prices. Natural gas is consumed primarily by the peaking units, and the demand is forecasted to range from approximately 2.8 million cubic feet, or Mcf, in 2006 to 5.8 Mcf in 2008. Because of the relatively high price volatility and unpredictability of unit dispatch, natural gas is typically purchased for the current year based on forecasted demand, and sold daily when the units do not run or supplemented by additional gas purchases on days that the units run at dispatch levels that are above planned usage.
Emission allowances are purchased on both a current and future-year basis. As illustrated by the higher than anticipated 2005 allowance prices, the allowance market reflects price uncertainty associated with the allowance market’s response to the CAIR. As a result, FES frequently reviews and analyzes its emission allowance procurement and hedging strategy. The exact prices and values cannot be determined with precision, and the costs FES incurs may be significant.
Most of FES’ air quality control system reagents and additives (ammonia, lime, sludge stabilizer and sulfite) are purchased under long-term agreements.
Nuclear Fuel Procurement
The procurement and delivery of nuclear fuel is managed by FENOC’s Fleet Fuel Management group. Uranium fuel procurement involves four basic steps, which result in the completion of fuel rods that are available for use in the reactor cores: the mining and milling of raw uranium, or U3O8; the conversion of U3O8 to uranium hexafluoride, or UF6; fuel enrichment; and fuel fabrication. The greatest nuclear fuel supply-chain risks are associated with a globally increasing demand for nuclear fuel, along with limited resources throughout the production process. These issues and the required timeline for fuel rod manufacture and delivery are closely monitored by the FENOC Fleet Fuel Management group. Its contracting strategy is driven by these factors and its success is reflected by the fact that FENOC’s 2006 fuel cost is well below what the fuel cost would be if all components were purchased at current market prices, and is also well below current industry-average fuel costs.
Raw uranium supplies are available from U.S. sources, although this represents only 10% of current demand. The industry is increasingly reliant on mines in Canada, Russia, Namibia, South Africa, Australia and several other Asian locations. The strong worldwide demand for raw uranium, along with flooding and fires at several of the largest producing mines, has led to a price increase from $8 per pound of U3O8 to more than $70 per pound since 2001. Market prices for conversion and enrichment have also increased substantially (i.e., at rates much greater than overall inflation) in the same time frame.
The total fuel preparation cycle occurs over a several year period, with the fabrication step being the only step that is specific to plant design. Utilities can buy uranium and have it converted and enriched, or they can buy uranium that is already enriched. Uranium producers sell enrichment services in separative work units, the industry term for contract quantities. FENOC’s strategy is to hedge fuel price risks by contracting for multiple production and delivery approaches for U3O8, conversion and enrichment. In some cases, the uranium is procured directly as UF6 (i.e., already converted). Fuel fabrication is currently procured from the original equipment manufacturers for all FENOC-operated nuclear plants.
The new fuel assemblies are typically shipped to the plant approximately one month before a refueling outage. The fuel lasts 36 to 72 months, depending on a range of factors that are primarily associated with plant operations and refueling frequency. Approximately 40% of the fuel is removed during each outage, with the balance rotated to maximize each fuel bundle’s utilization.
In general, the nuclear fuel rod manufacturing process is mature, and there are a number of stable suppliers associated with each process step. The NRC also provides process oversight at several steps. FENOC has not had significant problems with receipt of poor quality or defective rods, although Perry reported having a few defective rods prior to its last refueling outage, and Davis-Besse replaced several rods during its Spring 2006 refueling outage because of defects.
FENOC currently has fuel fabrication contracts with each of the industry’s three suppliers. These contracts range from several years for Beaver Valley 1 and 2 and Davis-Besse, all of which are PWRs
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Table of Contentsto a life-of-plant contract for Perry, a boiling water reactor, or BWR. At the current time, both the PWR and BWR fuel fabrication markets are competitive.
As stated above, FENOC currently has contracts with multiple suppliers covering each step of the entire fuel mining, conversion, enrichment and fabrication process. These contracts ensure an adequate fuel supply to cover all refueling outage requirements through 2009. A portion of the required raw uranium and conversion services is under further contract until 2014.
Plant Operations
Fossil Plant Operations
Technical support for FES’ 14 fossil plants is provided through the Fossil Operations unit, which currently has more than 1,800 people, including personnel assigned to the various operating plants, and approximately 60 additional staff who provide operations support and strategy services. The plant functional services are designated as Production, Production Support, Technical Support, Human Resources, Business Services and Technical Services. The Production group performs those functions often referred to as operations, whereas the Production Support group is responsible for maintenance functions. Technical Support is primarily comprised of engineers; the Technical Services personnel are focused on all technical issues at the plants, including environmental issues. At the corporate level, the Fossil Operations unit and Maintenance Services group were formed to help plants optimize their diagnostic techniques, maintenance operations, and outage strategies. In addition, FENOC operates the BETA Laboratory, which provides testing and diagnostic services to both the fossil and nuclear plant sites.
The strategic focus of the Fossil Operations unit is on safe plant operation, environmental compliance, unit reliability and cost competitiveness. To support this strategic focus, FES is implementing a series of asset management initiatives to ensure unit reliability and maintain generation capacity. These include initiatives in the areas of predictive maintenance, water chemistry, outage execution, equipment reliability, operating procedures, substation maintenance, alarms response and protective devices.
Nuclear Plant Operations
Operations, staffing and management of the FES nuclear plants is provided by FENOC under an operating agreement with NGC and the various operating companies subject to applicable sale and leaseback arrangements. Prior to the formation of FENOC in 1998, the three nuclear plants were operated as stand-alone entities. Decision-making was centralized by plant management, and each primary plant department (i.e., training, engineering, etc.) was operated autonomously. In November 2004, FirstEnergy met with the NRC to outline ongoing efforts to migrate to a central ‘‘fleet management’’ approach that would be better structured to provide consistency across the four reactor units located at the three sites. As part of this transition, the following changes were taken:
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| • | reorganization at each site to establish similar management structures at each plant; |
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| • | increased oversight from FES’ top management; and |
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| • | improved economies of scale through common procedures and best practices. |
FirstEnergy hired several key managers from other nuclear companies with experience in the fleet approach and integrated them with successful senior managers already within FENOC. The overall FENOC management structure was reorganized, including the replacement of some managers. Finally, senior executives (vice presidents) were placed at each plant to further strengthen the management structure.
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Table of ContentsCorporate groups were established at FirstEnergy’s headquarters in Akron, Ohio for specific department functions common to each plant. The departments, which are listed below, consist of a senior manager and a small staff:
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| • | Organizational Effectiveness (training, human resources, leadership and organization development); |
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| • | Business Strategies Regulatory Affairs; |
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| • | Operations Support (chemistry, radiation protection, operations, outages, work management and maintenance); and |
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| • | Engineering (equipment reliability and component engineering, procurement engineering, fuel management, asset management and engineering programs). |
Each of the above departments’ primary purpose is to serve as a resource to plant groups, provide insight on industry trends, pass ‘‘best practice’’ insight from one plant to another and assist with procedure preparation and implementation. The ultimate goal is to reduce production costs, gain economies of scale and improve communications.
FENOC believes that its fleet management approach is consistent with the practice of other large nuclear operating companies and owners of multiple reactor sites, as well as with industry best practices.
Baseload/Load Following Strategy
FES’ baseload/load following strategy focuses on defining specific operating missions for the various generating units within the fleet based upon the operating capability, performance and cost characteristics of each individual unit relative to the fleet as described under ‘‘—Generation Assets —Diversity Among Dispatch Market Segments’’ above.
The FES generation units are grouped into the following three operational segments according to their function within the baseload/load following strategy:
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| • | Baseload. The baseload units strive to run at a capacity factor greater than 85% and to operate at a baseline (i.e., flat) level of production output 24 hours a day. The baseload units are Beaver Valley 1 and 2, Davis-Besse, Perry, Bay Shore 1, Eastlake 5, the Mansfield Plant 1-3 and Sammis 6-7. |
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| • | Load Following. The load following units serve two primary functions within the baseload/load following strategy. Their production levels are adjusted according to customer and control area demand (load). These units also are used to meet ancillary services (spinning reserve and regulation) requirements. The load following units are Ashtabula 5, Bay Shore 2-4, Burger 4-5, Eastlake 1-4, Lake Shore 18, Sammis 1-5 and the pumped storage unit, Seneca. |
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| • | Peaking. The peaking units serve as a price and congestion hedge for periods when purchased power costs may be prohibitive due to either extreme demand or transmission constraints. There are more than 30 peaking units in this operating segment. Peaking units are also a low-cost source of new capacity and are used to meet resource adequacy requirements. |
A certain level of unused capacity of the fossil generation fleet reflects peaking unit MWh that are not being delivered to the wholesale power market because they (i) are uneconomical to dispatch at market prices, (ii) are required to meet regulation and spinning reserve standards established by the NERC (approximately 2 million MWh of unused capacity each year) or (iii) cannot be sold due to transmission limitations, market forecast variances or load forecast variances.
At the core of the baseload/load following strategy is the understanding that operating the baseload units at high capacity and implementing a thorough outage strategy significantly improves
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Table of Contentsthe reliability of these units. The reliability of the generation fleet is a strategic opportunity for FES and is measured in the case of nuclear plants by forced loss rate, or FLR, and in the case of non-nuclear plants by EFOR, both of which are industry measures of the percentage of time a unit is forced off-line or unavailable.
The following tables show the reliability of FES’ generation fleet as measured by FLR or EFOR, as the case may be, over the last five years:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Equivalent Forced Outage Rate |
| Plant | | | 2002 | | | 2003 | | | 2004 | | | 2005 | | | 2006 |
| Ashtabula | | | | | 5.3 | % | | | | | 2.9 | % | | | | | 12.2 | % | | | | | 1.7 | % | | | | | 2.9 | % |
| Bay Shore | | | | | 9.8 | % | | | | | 10.3 | % | | | | | 8.2 | % | | | | | 4.3 | % | | | | | 3.7 | % |
| Burger | | | | | 6.5 | % | | | | | 9.0 | % | | | | | 6.2 | % | | | | | 2.7 | % | | | | | 2.6 | % |
| Eastlake | | | | | 9.0 | % | | | | | 8.8 | % | | | | | 4.1 | % | | | | | 4.7 | % | | | | | 4.8 | % |
| Lake Shore | | | | | 3.5 | % | | | | | 3.0 | % | | | | | 4.6 | % | | | | | 14.2 | % | | | | | 15.0 | % |
| Mansfield | | | | | 3.5 | % | | | | | 1.2 | % | | | | | 2.1 | % | | | | | 2.4 | % | | | | | 3.7 | % |
| Sammis | | | | | 2.5 | % | | | | | 4.2 | % | | | | | 4.6 | % | | | | | 2.9 | % | | | | | 3.1 | % |
| Hydro | | | | | 2.2 | % | | | | | 1.9 | % | | | | | 5.0 | % | | | | | 1.1 | % | | | | | 0.1 | % |
| CT | | | | | 19.1 | % | | | | | 25.6 | % | | | | | 28.6 | % | | | | | 15.1 | % | | | | | 12.8 | % |
| Total | | | | | 4.8 | % | | | | | 5.5 | % | | | | | 4.6 | % | | | | | 3.5 | % | | | | | 3.8 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | |
| | | | Forced Loss Rate |
| Plant | | | 2002 | | | 2003 | | | 2004 | | | 2005 | | | 2006 |
| Beaver Valley | | | | | 0.6 | % | | | | | 1.8 | % | | | | | 0.2 | % | | | | | 0.7 | % | | | | | 1.5 | % |
| Davis-Besse | | | | | 0.2 | % | | | | | | (a) | | | | | 5.2 | % | | | | | 0.2 | % | | | | | 1.8 | % |
| Perry | | | | | 8.4 | % | | | | | 1.8 | % | | | | | 6.2 | % | | | | | 10.2 | % | | | | | 3.44 | % |
| Total | | | | | 4.0 | % | | | | | 1.8 | % | | | | | 3.4 | % | | | | | 3.4 | % | | | | | 2.30 | % |
| (a) | Due to an extended outage at Davis-Besse in 2003, a FLR cannot be calculated for 2003. |
Regulation
Although they are not regulated public utilities for purposes of state law, FES and its subsidiaries are subject to extensive regulation at both the federal and state levels.
FERC
FES has been authorized by the FERC to sell electricity at wholesale in interstate commerce in markets throughout the United States. FES has a market-based rate tariff on file with the FERC under which it sells electricity at wholesale. By virtue of this tariff and authority to sell electricity at wholesale, FES is regulated as a public utility under the FPA. However, because FES is not a traditional public utility, the FERC granted FES a waiver from most of the reporting, record-keeping and accounting requirements that typically apply to traditional public utilities. Along with its market-based rate authority, the FERC also granted FES blanket authority to issue securities and assume liabilities under Section 204 of the FPA. As a condition to selling electricity on a wholesale basis at market-based rates, FES, like all other entities granted market-based rate authority, must file electronic quarterly reports with the FERC, listing its sales transactions for the prior quarter.
FES, like all other entities that sell electricity at market-based rates, also must file an updated market power analysis every three years with the FERC. In April 2005, the FERC issued an order continuing FES’ grant of authority to sell electricity at market-based rates. In doing so, the FERC found that neither FES, nor any of its affiliates, have market power in generation or transmission, can raise barriers to entry or engage in affiliate abuse.
FES’ market-based rate tariff requires prior FERC authorization for wholesale sales to other FirstEnergy affiliates. FES has obtained such authorization from the FERC for sales to OE, CEI, TE,
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Table of ContentsMet-Ed, Penelec and Penn. FES’ market-based rate tariff also contains a code of conduct that restricts the sharing of market information between FES and certain of its regulated affiliates within the FirstEnergy holding company system unless such information is simultaneously made publicly available. Its tariff also contains prohibitions against market manipulation, which prohibitions apply to all entities that sell electricity at wholesale at market-based prices.
The FERC has issued a NOPR to revise the standards it applies to determine whether an applicant qualifies to sell electricity at wholesale at market-based rates. In the NOPR, the FERC considered whether to continue granting waivers of its accounting, record-keeping and reporting requirements and whether to continue granting blanket authorization for future securities issuances or assumptions of liabilities. The FERC is also proposing to adopt a uniform tariff that applies to all market-based rate sellers, and to modify its approach to the three-year market power update filing. The FERC issued a final rule on June 21, 2007 in which it declined to change its accounting, record keeping and reporting requirements, practice on blanket authorizations for securities issuances and assumptions of liabilities and adopted certan required tariff provisions.
As the ultimate owner of generation through its subsidiaries FGCO and NGC, FES has numerous generator interconnection agreements that have been accepted by the FERC. These interconnection agreements are revised and refiled as necessary due to modifications from time to time to the generating plants owned by FES’ subsidiaries.
EPACT
The EPACT greatly expanded the FERC’s jurisdiction over the activities of public utilities, including, but not limited to, the approval of mandatory reliability standards and the prohibition of manipulative or deceptive devices or contrivances in the purchase or sale of wholesale electric energy. Certain of the reliability standards under consideration by the FERC will apply to registered entities engaged in the generation and sale of power. FES has registered with the NERC, the FERC-approved ERO, as a generation operator, resource planner, a purchase-selling entity and an LSE. FGCO and NGC have registered as generation owners. FES believes that it is in compliance with all existing reliability standards. Failure to comply with FERC-approved reliability standards may result in the imposition of penalties, sanctions or remedial measures.
Public Utility Holding Company Act of 2005
The EPACT repealed PUHCA, enacted PUHCA of 2005, and shifted remaining supervision of public utility holding companies to the FERC. Under PUHCA of 2005, FES is considered a public utility holding company due to its ownership of FGCO and NGC. As a public utility holding company and associate company within the larger FirstEnergy holding company system, FES is subject to certain accounting and record-keeping requirements of the FERC promulgated as a result of PUHCA of 2005.
RTO Regulation
FES is a generator, power marketer and LSE within both MISO and PJM. FES participates actively in these markets, and is subject to the requirements of the respective open access tariffs and market monitoring provisions of the independent market monitors for MISO and PJM. FES actively participates in the FERC proceedings involving changes to the MISO and PJM tariffs that affect its operations.
State Energy Regulation
FES is also a competitive retail electric supplier and serves retail customers in Michigan, Ohio, Pennsylvania, New Jersey and Maryland. FES is subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES and its public utility affiliates. In addition, if FES or any of its subsidiaries were to engage in the construction of significant new generation facilities, they would also be subject to state siting authority.
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Table of ContentsNRC
The nuclear generating facilities owned by NGC are subject to extensive regulation by the NRC. FENOC, a direct subsidiary of FirstEnergy, is the licensee for these plants and has direct compliance responsibility for NRC matters. FES controls the economic dispatch of NGC’s plants.
Current Regulatory Proceedings
Reliability Initiatives
Although reliability-related issues pertain mainly to transmission and distribution owners and operators, and do not generally affect generators of electricity or directly impact FES or its generation assets, developments in these matters may create new regulatory requirements and costs that could be imposed on generators of electricity.
EPACT provides for the creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC review. On February 3, 2006, the FERC adopted a rule establishing certification requirements for the ERO, as well as regional entities envisioned to assume monitoring responsibility for the new reliability standards.
The NERC has been preparing the implementation aspects of reorganizing its structure to meet the FERC’s certification requirements for the ERO. The NERC made a filing with the FERC on April 4, 2006 to obtain certification as the ERO and to obtain FERC approval of pro forma delegation agreements with regional reliability organizations (regional entities). The new FERC rule referred to above further provides for reorganizing regional entities that would replace the current regional councils and for rearranging their relationship with the ERO. The ‘‘regional entity’’ may be delegated authority by the ERO, subject to FERC approval, for compliance and enforcement of reliability standards adopted by the ERO and approved by the FERC. The ERO filing was noticed on April 7, 2006, and comments and reply comments were filed in May, June and July 2006. On July 20, 2006, the FERC certified the NERC as the ERO t o implement the provisions of Section 215 of the FPA and directed the NERC to make compliance filings addressing governance and non-governance issues and the regional delegation agreements. On September 18, 2006 and October 18, 2006, the NERC submitted compliance filings addressing the governance and non-governance issues identified in the FERC ERO Certification Order, dated July 20, 2006. On October 30, 2006, the FERC issued an order accepting most of NERC’s governance filings. On January 18, 2007, the FERC issued an order largely accepting the NERC’s compliance filings addressing non-governance issues, subject to an additional compliance filing requirement.
On April 4, 2006, the NERC also submitted a filing with the FERC seeking approval of mandatory reliability standards, as well as for approval with the relevant Canadian authorities. These reliability standards are based, with some modifications and additions, on the current NERC Version 0 reliability standards. The reliability standards filing was subsequently evaluated by the FERC on May 11, 2006, leading to the FERC staff’s release of a preliminary assessment that cited many deficiencies in the proposed reliability standards. The NERC and industry participants filed comments in response to the staff’s preliminary assessment. The FERC held a technical conference on the proposed reliability standards on July 6, 2006. The FERC issued a NOPR on the proposed reliability standards on October 20, 2006. In the NOPR, the FERC proposed to approve 83 of the 107 reliability standards and directed the NERC to make technic al improvements to 62 of the 83 standards approved. The FERC also provided additional clarification within the NOPR regarding the proposed application of final standards and guidance with regard to technical improvements of the standards. On November 15, 2006, the NERC submitted several revised reliability standards and three new proposed reliability standards. Interested parties were provided the opportunity to comment on the NOPR (including the revised standards submitted by the NERC in November) by January 3, 2007. Numerous parties, including FirstEnergy, filed comments on the NOPR on January 3, 2007. The FERC issued a final rule on March 16, 2007, approving the 83 mandatory electric reliability standards proposed and making them enforceable with penalties and sanctions for noncompliance when the rule becomes effective. The final rule became effective on June 18, 2007. The FERC also directed NERC
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Table of Contentsto submit improvements to 56 standards, endorsing NERC’s process for developing reliability standards and its associated work plan. On May 4, 2007, NERC also submitted 24 proposed Violation Risk Factors. The FERC issued an order approving 22 of those factors on June 26, 2007. In a separate order issued October 24, 2006, the FERC approved the NERC’s 2007 budget and business plan subject to certain compliance filings.
On November 29, 2006, the NERC submitted an additional compliance filing with the FERC regarding the CMEP along with the proposed Delegation Agreements between the ERO and the regional reliability entities. The FERC provided opportunity for interested parties to comment on the CMEP by January 10, 2007. We, as well as other parties, moved to intervene and submitted responsive comments on January 10, 2007. This filing, which established the regulatory framework for NERC’s future enforcement program, was approved by the FERC on April 19, 2007.
FES believes that it is in compliance with all current NERC reliability standards to the extent they apply to generators. However, it is expected that the FERC will adopt more strict reliability standards than those contained in the current proposed reliability standards initially filed by the NERC. The financial impact of complying with the new standards cannot be determined at this time.
Pennsylvania Public Utility Commission Regulation
FES supplies a portion of Met-Ed’s and Penelec’s POLR requirements through a partial requirements wholesale power sales agreement which was most recently amended and restated effective January 1, 2007. Under the terms of this agreement, FES retained the supply obligation, and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed and Penelec.
Under the agreement, FES provided power to Met-Ed and Penelec for their uncommitted POLR capacity and energy costs at a fixed price.
On April 7, 2006, the parties entered into a tolling agreement that arose from FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the partial requirements agreement effective midnight December 31, 2006. Separately, on September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their POLR obligations for the period December 1, 2006 through December 31, 2008. FES was one of the successful bidders in that RFP process and on September 26, 2006 entered into a supplier master agreement to supply a certain portion of Met-Ed’s and Penelec’s POLR requirements at market prices that substantially exceed the fixed price in the partial requirements agreement. On November 29, 2006, Met-Ed, Penelec and FES agreed to suspend the tolling agreement and the supplier master agreement pending resolution of the PPUC’s pr oceedings regarding the comprehensive transition rate cases filed by Met-Ed and Penelec in April 2006.
Based on the outcome of the comprehensive transition rate filing, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one-year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their POLR obligations. The parties also have separately terminated the tolling, suspension and supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied und er the supplier master agreement will now be provided under the restated partial requirements agreement. The fixed price under the restated agreement is and is expected to remain below wholesale market prices during the term of the agreement.
FERC Rate Matters
On November 1, 2005, FES filed two affiliate PSAs for approval with the FERC. One PSA required FES to provide the POLR requirements of the Ohio Companies at a price equal to the retail
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Table of Contentsgeneration rates approved by the PUCO for a period of three years beginning January 1, 2006. The Ohio Companies will be relieved of their obligation to obtain POLR power requirements from FES if the Ohio CBP results in a lower price for retail customers. A similar PSA between FES and Penn permitted Penn to obtain its POLR power requirements from FES at a fixed price equal to the retail generation price during 2006.
On December 29, 2005, the FERC issued an order setting the two PSAs for hearing. The order criticized the Ohio CBP, and required FES to submit additional evidence in support of the reasonableness of the prices charged in the PSAs. On July 14, 2006, the Chief Judge granted the joint motion of FES and the trial staff to appoint a settlement judge in this proceeding and the procedural schedule was suspended pending settlement discussions among the parties. A settlement conference was held on September 5, 2006. FES, the Ohio Companies, Penn and the PUCO, along with other parties, reached an agreement to settle the case. The settlement was filed with the FERC on October 17, 2006, and was unopposed by the remaining parties, including the FERC trial staff. This settlement was accepted by the FERC on December 8, 2006.
The terms of the settlement provide for modification of both the Ohio Companies’ PSA and Penn’s PSA with FES. Under the Ohio Companies’ PSA, separate rates are established for the Ohio Companies’ POLR requirements, special retail contracts requirements, wholesale contract requirements and interruptible buy-through retail load requirements. For their POLR and special retail contract requirements, the Ohio Companies will pay FES no more than the lower of (i) the sum of the retail generation charge, the rate stabilization charge, the fuel recovery mechanism charge and FES’ actual incremental fuel costs for such sales; or (ii) the wholesale price cap. Different wholesale price caps are imposed for POLR sales, special retail contracts and wholesale contracts. The wholesale price for interruptible buy-through retail load requirements is limited to the actual spot price of power obtained by FES to provide this power. FES billed the Ohio Co mpanies for the additional amount payable to FES for incremental fuel costs on power supplied during 2006. The total power supply cost billed by FES was lower in each case than the wholesale price caps specified in the settlement accepted by the FERC. In addition, pursuant to the settlement, the wholesale rate charged by FES under the Penn PSA can be no greater than the generation component of charges for retail POLR load in Pennsylvania. The modifications to the Ohio Companies’ PSA and Penn’s PSA became effective January 1, 2006. Penn’s PSA expired at midnight December 31, 2006.
As a result of Penn’s POLR competitive solicitation process approved by the PPUC for the period January 1, 2007 through May 31, 2008, FES was selected as the winning bidder for a number of the tranches for individual customer classes. The balance of the tranches is supplied by unaffiliated power suppliers. On October 2, 2006, FES filed an application with the FERC under Section 205 of the FPA for authorization to make these affiliate sales to Penn. Interventions or protests were due on this filing on October 23, 2006. Penn was the only party to file an intervention in this proceeding. This filing was accepted by the FERC on November 15, 2006, and no requests for rehearing were filed.
On October 19, 2006, the FERC issued two final rules in connection with PUHCA of 2005. The final rules impose certain accounting, reporting and record-retention requirements for certain holding companies and service companies, which include FirstEnergy and certain of its subsidiaries.
On February 15, 2007, MISO filed documents with the FERC to establish an Ancillary Services Market. In the filing, MISO contends that the Ancillary Services Market will integrate operating reserves into MISO’s existing day-ahead and real-time settlements process, incorporate opportunity costs into these markets, address scarcity pricing through the implementation of a demand curve methodology, foster demand response in the provision of operating reserves, and provide for various efficiencies and optimization with regard to generation dispatch. The filing also proposes amendments to existing documents to provide for the transfer of balancing functions from existing local balancing authorities to MISO. MISO will then carry out this reliability function as the NERC-certified balancing authority for the MISO region. MISO is targeting implementation for the second or third quarter of 2008. The FERC established March 30, 2007 as the date for interested parties to submit comments addressing the filing. FESC filed comments on behalf of us on March 30, 2007. Although there are certain features of the proposal that will need to be refined and/or more fully developed
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Table of Contentsbefore the Ancillary Services Market will be fully operational, FES supports MISO’s proposal to establish a competitive Ancillary Services Market. On June 22, 2007, the FERC found MISO’s filing to establish such a market to be deficient in two key areas: (1) MISO has not submitted a market power analysis in support of its proposed Ancillary Services Market and (2) MISO has not submitted a readiness plan to ensure reliability during the transition from the current reserve and regulation system managed by the individual Balancing Authorities to a centralized Ancillary Services Market managed by MISO. MISO was ordered to remedy these deficiencies and FERC provided more guidance on other issues brought up in filings by stakeholders to assist MISO to re-file a complete proposal.
On February 16, 2007, the FERC issued a final rule that revises its decade-old open access transmission regulations and policies. The FERC explained that the final rule is intended to strengthen non-discriminatory access to the transmission grid, facilitate FERC enforcement, and provide for a more open and coordinated transmission planning process. The final rule became effective on May 14, 2007. MISO, PJM and ATSI will be filing revised tariffs to comply with the FERC’s order. As a market participant in both MISO and PJM, FirstEnergy will conform its business practices to each respective revised tariff.
On August 1, 2007, a number of filings were made with the FERC by transmission owning utilities in the MISO and PJM footprint that could affect the transmission rates paid by the FirstEnergy operating companies and FES.
FirstEnergy joined in a filing made by the MISO transmission owners that would maintain the existing ‘‘license plate’’ rates for transmission service within the MISO provided over existing transmission facilities. FirstEnergy also joined in a filing made by both the MISO and PJM transmission owners proposing to continue the elimination of transmission rates associated with service over existing transmission facilities between the MISO and PJM. If approved by the FERC, these filings would not affect the rates charged to load-serving FirstEnergy affiliates for transmission service over existing transmission facilities. In a related filing, the MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint be maintained (known as the RECB process). Each of these filings was supported by the majority of transmission owners in either the MISO or PJM, as applicable.
The Midwest Stand-Alone Transmission Companies made a filing under Section 205 of the FPA requesting that 100% of the cost of new 345 kV and higher transmission facilities be spread throughout the entire MISO footprint. Further, Indianapolis Power and Light Company separately moved the FERC to reopen the record to address the cost allocation for the RECB Process. If either proposal is adopted by the FERC, it could shift a greater portion of the cost of new 345 kV and higher transmission facilities to the FirstEnergy footprint, and increase the transmission rates paid by load-serving FirstEnergy affiliates.
AEP filed a letter with the FERC Commissioners stating its intent to file a complaint under Section 206 of the FPA challenging the justness and reasonableness of the rate designs underlying the MISO and PJM transmission tariffs. AEP stated that it will propose the adoption of a regional rate design that is expected to reallocate the cost of both existing and new high voltage transmission facilities across the combined MISO and PJM footprint. Based upon the position advocated by AEP in a related proceeding, the AEP proposal is expected to result in greater allocation of costs to FirstEnergy transmission zones in MISO and PJM. If approved by the FERC, AEP’s proposal would increase the transmission rates paid by load-serving FirstEnergy affiliates.
Any increase in rates charged for transmission service to FirstEnergy affiliates is dependent upon the outcome of these proceedings at FERC. All or some of these proceedings may be consolidated by the FERC and set for hearing. The outcome of these cases cannot be predicted. Any material adverse impact on FirstEnergy would depend upon the ability of the load-serving FirstEnergy affiliates to recover increased transmission costs in their retail rates. FirstEnergy believes that current retail rate mechanisms in place for POLR service for the Ohio Companies and for Met-Ed and Penelec would permit them to pass through increased transmission charges in their retail rates. Increased
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Table of Contentstransmission charges in the JCP&L and Penn transmission zones would be the responsibility of competitive electric retail suppliers, including FES.
Other FERC Matters
On February 6, 2007, FGCO filed an application with the FERC pursuant to Section 203 of the FPA requesting authorization to engage in the sale and leaseback transactions contemplated in this prospectus. In the application, FGCO asserted that the transactions are consistent with the public interest and, consistent with the FERC’s regulations, will not have an adverse effect on competition, rates or regulation, or result in cross-subsidization of a non-utility associate company or pledge or encumbrance of utility assets for the benefit of any associate company. The filing was noticed on February 20, 2007 and no interventions or protests were filed. On March 19, 2007, the FERC, by delegated letter order, authorized the transactions. An errata notice was issued on March 20, 2007, correcting information in the order of March 19, 2007. No requests for rehearing were filed to address the FERC’s order.
On April 2, 2007, as supplemented on April 13, 2007, FGCO filed a petition for a declaratory order asking the FERC to disclaim jurisdiction under Section 201 of the FPA over the passive participants in the sale and leaseback transactions, including the Owner Participants, equity owners of the Owner Participants, Owner Trusts, lenders, holders of the Lessor Notes and Certificateholders. On May 18, 2007, the FERC issued an order granting the requested relief. No requests for rehearing were filed to address the FERC’s order.
NRC Matters
On January 20, 2006, FENOC announced that it had entered into a deferred prosecution agreement with the U.S. Attorney’s Office for the Northern District of Ohio and the Environmental Crimes Section of the Environment and Natural Resources Division of the DOJ related to FENOC’s communications with the NRC during the fall of 2001 in connection with NRC Bulletin 2001-01, ‘‘Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity’’ at Davis-Besse. Under the agreement, the United States also acknowledged FENOC’s extensive corrective actions at Davis-Besse, FENOC’s cooperation during the investigations by the DOJ and the NRC, FENOC’s pledge of continued cooperation in any related criminal and administrative investigations and proceedings, FENOC’s acknowledgement of responsibility for the behavior of its employees, and its agreement to pay a monetary penalty. The DOJ a greed to refrain from seeking an indictment or otherwise initiating criminal prosecution of FENOC for all conduct related to the statement of facts attached to the deferred prosecution agreement, as long as FENOC remained in compliance with the agreement, which FENOC has done. A monetary penalty of $28 million (not deductible for income tax purposes) was reflected in NGC’s fourth quarter of 2005 results. The deferred prosecution agreement expired on December 31, 2006.
On April 21, 2005, the NRC issued an NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head described above. On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC indicated in the NOV that the violations do not represent current licensee performance. FENOC paid the penalty in the third quarter of 2005. On January 23, 2006, FENOC supplemented its response to the NRC’s NOV on the Davis-Besse head degradation to reflect the deferred prosecution agreement that FENOC had reached with the DOJ.
Effective July 1, 2005, the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC’s Confirmatory Order, dated March 8, 2004, that was issued at the time of startup and to address an NRC white finding related to the performance of the emergency sirens. By letter dated December 5, 2005, the NRC advised FENOC that the White Finding had been closed.
On April 30, 2007, the UCS filed a petition with the NRC under Section 2.206 of the NRC’s regulations based on a report prepared at FENOC’s request by expert witnesses for an insurance
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Table of Contentsarbitration. In December 2006, the expert witnesses for FENOC completed a report that analyzed the crack growth rates in control rod drive mechanism penetrations and wastage of the former reactor pressure vessel head at Davis-Besse. Citing the findings in the expert witness’ report, the Section 2.206 petition requested that: (1) Davis-Besse be immediately shut down; (2) the NRC conduct an independent review of the consultant’s report and that all PWRs be shut down until remedial actions can be implemented; and (3) Davis-Besse’s operating license be revoked.
In a letter dated May 18, 2007, the NRC stated that the ‘‘current reactor pressure vessel (RPV) head inspection requirements are adequate to detect RPV degradation issues before they result in significant corrosion.’’ The NRC also indicated that ‘‘no immediate safety concern exists at Davis-Besse’’ and denied UCS’ first demand (to shut down the facility). On June 18, 2007, the NRC Petition Review Board indicated that the agency had initially denied petitioner’s other requests, and provided an opportunity for UCS to provide additional information prior to the final determination. By letter dated July 12, 2007, the NRC denied the remainder of the UCS petition.
On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for Information to FENOC following FENOC’s reply to an April 2, 2007 NRC request for information about the expert witnesses’ report and another report. The NRC indicated that this information is needed for the NRC ‘‘to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.’’ FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand for Information reaffirming that is accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants s afely and responsibly. The NRC held a public meeting on June 27, 2007 with FENOC to discuss FENOC’s response to the Demand for Information. In follow-up discussions, FENOC was requested to provide supplemental information to clarify certain aspects of the Demand for Information response and provide additional details regarding plans to implement the commitments made therein. FENOC submitted this supplemental response to the NRC on July 16, 2007. On August 15, 2007, FENOC received a Confirmatory Order issued by the NRC confirming its commitment to implement certain corrective actions designed to ensure that issues similar to those that gave rise to the May 14, 2007 Demand for Information do not recur. We can provide no assurances as to the ultimate resolution of this matter.
On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee’s failure to take prompt and corrective action. On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC’s annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall, Perry operated ‘‘in a manner that preserved public health and safety’’ even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from t he Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.
On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at Perry and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC’s Reactor Oversight Process. In the NRC’s 2005 annual assessment letter dated March 2, 2006 and associated meetings to discuss the performance of Perry on March 14, 2006, the NRC again stated the plant continued to operate in a manner that ‘‘preserved public health and safety.’’ However, the NRC also stated that increased levels of regulatory oversight would continue until sustained improvement in the performance of the facility was realized.
By two letters dated March 2, 2007, the NRC closed the CAL commitments for Perry, the two outstanding white findings and crosscutting issues. Moreover, the NRC removed Perry from the
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Table of ContentsMultiple Degraded Cornerstone Column of the NRC Action Matrix and placed the plant in the Licensee Response Column (regular agency oversight).
Environmental Matters
Environmental Regulation
Various federal, state and local authorities regulate FES and its subsidiaries with regard to air and water quality and other environmental matters. The effects of compliance by FES with regard to environmental matters could have a material adverse effect on FES’ earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, FES believes it is in compliance with existing regulations but is unable to predict future changes in regulatory policies and what, if any, the effects of such changes would be. FES estimates additional capital expenditures for environmental compliance of approximately $1.8 billion for 2007 through 2011.
FES accrues environmental liabilities only when it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FES’ determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
Clean Air Act Compliance
FES and its subsidiaries are required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. FES and its subsidiaries believe they are currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006 alleging violations of various sections of the Clean Air Act. FES has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. At the time of the violation, FES’ affiliate, TE, owned the Bay Shore Power Plant, which FES now owns and operates. On June 5, 2007, the EPA requested another meeting to discuss ‘‘an appropriate compliance program’’ and a disagreement regarding the opacity limit applicable to Bay Shore Units 2, 3 a nd 4 common stack.
FES complies with SO2 reduction requirements under the 1990 CAA Amendments by burning lower-sulfur fuel, generating more electricity from lower-emitting plants and/or using emission allowances. NOX reductions required by the 1990 CAA Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOX reductions at FES’ facilities. The EPA’s NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. FES believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including SCR and SNCR systems and/or using emission allowances.
On May 22, 2007, FirstEnergy and FGCO received a notice letter from PennFuture, required 60 days prior to the filing of a citizen suit under the federal Clean Air Act, alleging violations of air
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Table of Contentspollution laws at the Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Mansfield Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On July 25, 2007, FirstEnergy and PennFuture entered into a tolling and onfidentiality agreement that provides for a 60-day negotiation period during which the parties have agreed to not file a lawsuit.
On June 10, 2007, FGCO experienced a stack rain incident, which occurred when the Mansfield Plant’s environmental system was being brought back on-line following maintenance. FGCO determined a device recently added to remove moisture from flue gas malfunctioned. The device, called a mist eliminator, is part of the plant’s flue-gas desulfurization, or scrubber system, and was added to the Mansfield Plant as part of the work required by the Sammis NSR Litigation consent decree.
National Ambient Air Quality Standards
In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter. In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the ‘‘8-hour’’ ozone NAAQS in other states. The CAIR allowed each affected state until 2006 to develop implementing regulations to achieve additional reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2). As a result, FES’ Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to caps on SO2 and NOX emissions. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states at 2.5 million tons annually. NOX emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOX cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FES’ subsidiaries operate affected facilities.
Mercury Emissions
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 (as a ‘‘co-benefit’’ from implementation of SO2 and NOX emission caps under the EPA’s CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the CAMR have been challenged in the United States Court of Appeals for the District of Columbia. FES’ future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FES’ subsidiaries operate affected facilities.
The model rules for both the CAIR and the CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. FES would prefer an output-based generation-neutral methodology in which allowances are allocated based on MWs of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, FES will be disadvantaged if these model rules were implemented as proposed because FES’ substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command and control approach
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Table of Contentsimposing emission limits on individual sources. Pennsylvania’s mercury regulation would deprive FES of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving FES system-wide compliance. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Mansfield Plant, FES’ only Pennsylvania coal-fired power plant, until 2015, if at all.
W. H. Sammis Plant
In 1999 and 2000, the EPA issued NOV or compliance orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including Sammis, which was owned at that time by OE and Penn, and is now owned by FGCO. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio.
On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR Litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield Plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FGCO and its affiliates, OE and Penn, could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation settlement agreement are currently estimated to be $1.7 billion for 2007 through 2011 ($400 million of which is expected to be spent in 2007, with the largest portion of the remaining $1.3 billion expected to be spent in 2008 and 2009).
The Sammis NSR Litigation consent decree also requires FGCO to spend up to $25 million toward environmentally beneficial projects, $14 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.
On August 26, 2005, FGCO entered into an agreement with Bechtel under which Bechtel will engineer, procure and construct air quality control systems for the reduction of SO2 emissions. FGCO also entered into an agreement with B&W on August 25, 2006 to supply flue gas desulfurization systems for the reduction of SO2 emissions. SCR systems for the reduction of NOX emissions also are being installed at Sammis under a 1999 agreement with B&W.
On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. On May 8, 2007, the EPA proposed to change the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.
Climate Change
In December 1997, delegates to the United Nations’ climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. At the international level, efforts have begun to develop climate change agreements for post-2012 GHG reductions. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.
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Table of ContentsAt the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as ‘‘air pollutants’’ under the Clean Air Act. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the Clean Air Act to regulate ‘‘air pollutants’’ from those and other facilities.
FES cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions could require significant capital and other expenditures. The CO2 emissions per KWh of electricity generated by FES is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FES’ plants. In addition, Ohio and Pennsylvania have water quality standards applicable to FES’ operations. As provided in the Clean Water Act, authority to grant federal NPDES water discharge permits can be assumed by a state. Ohio and Pennsylvania have assumed such authority.
On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, which occurs when aquatic organisms are pinned against screens or other parts of a cooling water intake system, and entrainment, which occurs when aquatic life is drawn into a facility’s cooling water system. On January 26, 2007, the U.S. Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking, while noting that the EPA had impermissibly allowed compliance through restoration and reaffirming its reasoning in an earlier decision that the EPA could not construe restoration as a permissible means of complying with Section 316(b). On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment (BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. FES is evaluating various control options and their costs and effectiveness. Depending on the outcome of such studies, the EPA’s further rulemaking and any action taken by the states exercising BPJ, the future cost of compliance with these standards may require material capital expenditures.
Regulation of Hazardous Waste
As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. FES is unable to predict the outcome of such standards, and the future costs of compliance with these standards may require material capital expenditures.
Under NRC regulations, NGC and its affiliates, OE and TE, must ensure that adequate funds will be available to decommission its nuclear facilities in proportion to their respective ownership or leased interests in the nuclear units. As of June 30, 2007, NGC and such affiliates had approximately $1.3 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley and Perry. As part of the application to the NRC to transfer the ownership of these nuclear facilities to NGC, FirstEnergy agreed to contribute another
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Table of Contents$80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a ‘‘real’’ rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FENOC plans to seek for these facilities.
Environmental Compliance Strategy
Daily Compliance
As part of daily operations, the Fossil Operations unit works closely with members of the Environmental Department to identify potential issues with regard to compliance with all air emission and NPDES standards and mitigate them before non-compliance can result. Additionally, the Fossil Operations unit has budgeted approximately $75 million of capital expenditures during 2007 through 2010 for projects related to environmental compliance, including installation and modernization of emissions monitors at fossil facilities to further enhance responsiveness. This amount is in addition to the spending related to Air Quality Control Compliance discussed below.
Air Quality Control Compliance
Fleet Status—In 2006, over 60% of FES generation was produced by non-emitting or low-emitting generating units, including approximately 36% from nuclear, 23% from coal units retrofitted with best available control technology, and 1% from hydroelectric and combustion turbine units. FES expects this percentage to be more than 75% in 2010 and beyond.
Nitrogen Oxide (NOX)—FGCO’s Fossil Operations unit strives to utilize assets to generate maximum output while complying with all NOX emissions limits. To the extent fleet NOX emissions exceed governmental allowances under the CAIR, a NOX allowance purchase strategy will be employed t o comply with the CAIR until installation of emission control equipment is completed. FGCO uses low NOX burners throughout the system, and SNCR systems are now operating on eight units. SCRs are installed at the Mansfield Plant and are being installed at Sammis Units 6 and 7 under the Sammis NSR Litigation consent decree. In addition, a neural net (computer control) combustion optimization system is in use at Sammis and Eastlake.
Sulfur Dioxide (SO2)—As in the NOX strategy, the Fossil Operations unit expects to comply with all SO2 emission standards and limits. SO2 emissions (measured in tons) are expected to decline 45 – 50% by 2010 compared to 2005 levels. FGCO’s Fossil Operations unit is investing in SO2 emissions control equipment consistent with its long-term compliance strategy to control emissions through equipment additions rather than through purchases of emission allowances. Since 2003, SO2 emission levels have declined significantly due to:
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| • | a decision to shift generation from higher emission rate units to the Mansfield Plant where the three units have SO2 scrubbers; and |
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| • | increased use of western coal. |
In addition, scrubber upgrades for SO2 emissions compliance at Sammis and the Mansfield Plant are expected to further reduce SO2 emissions over the next five years.
Mercury—The CAMR requires reductions in nationwide power plant mercury emissions from 44 tons in 1999 to 38 tons by 2010 and to 15 tons by 2018. No additional controls in this regard are planned, as current planned air emission control equipment installations are expected to result in the removal of sufficient mercury emissions to comply with the 2010 reduction requirements. Further retrofits to FGCO’s fossil units to comply with the 2018 reduction requirements will be evaluated over the next several years. Future compliance with the CAMR may require material capital expenditures.
Sammis NSR Litigation Consent Decree—In 2005, a consent decree was entered to resolve the Sammis NSR Litigation. The decree requires specific equipment installations at Sammis, the Mansfield Plant, Burger, and Eastlake by certain specified deadlines. Additional consent decree requirements affecting FGCO are as follows:
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| • | an annual cap on SO2 and NOX emissions at Sammis; |
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| • | a monthly cap (May through September) on SO2 emissions at Sammis Units 1 – 5 (starts in 2010); |
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| • | a 30-day rolling emission rate limit for SO2 and NOX at Sammis; |
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| • | reductions in SO2 and NOX emissions at Burger Units 4 and 5 (which FES can elect to satisfy as to SO2 by (i) installing Wet Flue Gas Desulfurization or Electro-Catalytic Oxidation by the end of 2010, (ii) shutting down by the end of 2010, or (iii) repowering by the end of 2012); |
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| • | reductions in SO2 emissions at the Mansfield Plant; |
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| • | reduction in NOX emissions at Eastlake Unit 5; |
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| • | interim reductions through 2010 in NOX emissions from any combination of reductions from Burger, the Mansfield Plant and/or NOX emissions below the annual cap at Sammis; |
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| • | interim reductions through 2010 in SO2 emissions at Burger Units 4 and 5; |
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| • | interim reductions by the end of 2010 in SO2 emissions from any combination of reductions from Burger, the Mansfield Plant, other FES units and/or SO2 emissions below the annual cap at Sammis; |
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| • | a limit on particulate emission rate at Sammis Units 6 and 7; and |
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| • | funding and/or implementation of up to $25 million of environmentally beneficial projects, $14.385 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006. |
The consent decree provides for stipulated penalties for failure to install and operate the required pollution controls in accordance with the agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation settlement agreement are currently estimated to be $1.7 billion for 2007 through 2011 ($400 million of which is expected to be spent in 2007, with the largest portion of the remaining $1.3 billion expected to be spent in 2008 and 2009). All of these expenditures are to be borne by FES and FGCO.
On August 26, 2005, FGCO entered into an agreement with Bechtel under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of SO2 emissions. FGCO also entered into an agreement with B&W on August 25, 2006 to supply flue gas desulfurization systems for the reduction of SO2 emissions. SCR systems for the reduction of NOX emissions also are being installed at Sammis under a 1999 agreement with B&W.
Future Regulatory Compliance—Momentum is building in the United States for some form of GHG regulation. Several bills that include CO2 regulation have been introduced during the recent sessions of Congress. The most prominent is McCain-Lieberman, which would limit CO2 emissions to year 2000 levels by 2010. Seven northeastern states (including New Jersey) have reached preliminary agreement to freeze power plant emissions at slightly above current levels through 2015 and then reduce them by 10% by 2020. The DOE sponsors Climate Vision, a voluntary public/private partnersh ip designed to help U.S. businesses respond to President Bush’s challenge to reduce GHG intensity.
While FES has relatively low carbon intensity (i.e., CO2 emitted per MWh) due to its non-emitting nuclear fleet, FES’ total CO2 emissions will continue to increase as fossil plant utilization increases. FES is involved in the following activities as part of its GHG strategy:
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| • | pilot testing of CO2 removal technology at the Burger plant; |
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| • | active participation and funding of Electric Power Research Institute’s Coal Fleet for Tomorrow; |
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| • | nuclear uprates and license renewals to increase and maintain FES’ non-emitting nuclear units; and |
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| • | participation in the DOE Midwest Regional Carbon Sequestration Partnership, New Jersey’s Clean Energy Program, and the EPA’s Sulfur Hexafluoride Reduction Partnership. |
Intra-System Generation Asset Transfers (GAT)
On October 24, 2005, FGCO acquired the owned fossil and hydroelectric generation assets of OE, CEI, TE and Penn. Prior to the asset transfer, FGCO leased these non-nuclear plants from those
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Table of Contentsutilities pursuant to a master facility lease. FGCO paid an aggregate purchase price of approximately $1.6 billion (OE—$980 million; CEI—$389 million; TE—$88 million; and Penn—$125 million) under the master facility lease’s purchase option and also assumed certain assets and liabilities relating to the purchased units. As consideration, FGCO delivered to each utility a promissory note that is secured by a lien on the units purchased from such utility, bears interest at a fixed rate per annum based on the then weighted cost of long-term debt of such utility (OE—$1.0 billion at 3.98%; CEI—$383 million at 5.99%; TE—$101 million at 4.38%; Penn—at $124 million at 5.39%) and matures in 2025.
On December 16, 2005, NGC acquired the owned nuclear generation assets of OE, CEI, TE and Penn. The transfers to NGC were accomplished through, in the case of OE and Penn, an asset spin-off in the form of a dividend and, in the case of CEI and TE, a sale at net book value. At closing, Penn made a capital contribution of its owned nuclear generation and related assets to NGC, Penn’s then wholly-owned subsidiary, and subsequently distributed the common stock of NGC as a dividend to its parent, OE. After a similar capital contribution was made by OE to NGC, OE distributed the common stock of NGC as a dividend to FirstEnergy. In connection with these capital contributions and distributions, NGC issued new pollution control bond debt, the proceeds of which were used to refund certain outstanding pollution control bond debt of OE and Penn (approximately $115 million and $63 million, respectively) and delivered to each of OE and Penn a promiss ory note in principal amounts of approximately $371 million and $240 million, respectively, representing the net book value of the applicable contributed assets as of September 30, 2005, less other liabilities assumed. Also at closing, NGC purchased CEI’s and TE’s respective owned nuclear generation and related assets for a purchase price equal to net book value as of September 30, 2005, less liabilities assumed. As consideration, NGC delivered to each of CEI and TE a promissory note in a principal amount equal to the applicable consideration (approximately $1.0 billion and $726 million, respectively). Each promissory note bears interest at a fixed rate per annum based on the applicable utility’s then weighted average cost of long-term debt (OE—3.98%; CEI—5.99%; TE—4.38%; and Penn—5.39%). Each note matures in 2025 and is subject to prepayment at any time, in whole or in part, by NGC at its option without penalty. The promissory notes to CEI and TE are secured by a lien on the transferred assets.
These transactions were undertaken pursuant to the FirstEnergy utility subsidiaries’ restructuring plans that were approved by the Ohio and Pennsylvania regulators under applicable electric utility restructuring legislation. Consistent with these restructuring plans, generation assets that had been owned by the utility subsidiaries were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. These transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to FGCO and NGC without impacting the operation of the plants. The generating plant interests that were transferred do not include leasehold interests of OE, CEI and TE in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates. Included in the transfers, however, was OE’s and Penn’s combined 93.5% und ivided ownership interest in Unit 1 of the Mansfield Plant. Effective December 31, 2006, direct ownership of NGC was transferred from FirstEnergy to FES.
In conjunction with the nuclear asset transfers, FirstEnergy made a cash capital contribution to NGC of approximately $750 million. NGC used the proceeds from the capital contribution to prepay a portion of the promissory notes to CEI and TE described above for $375 million each. In addition, at the time of the transfer, NGC refunded certain pollution control debt of OE and Penn, as described above, and an additional $91 million of TE pollution control debt associated with the transferred units. During 2006, NGC refunded approximately $591.5 million of additional pollution control debt of the utilities in order to prepay an equivalent portion of its promissory notes described above (OE—$241.0 million; CEI—$213.2 million; and TE—$137.2 million). Also during 2006, FGCO refunded approximately $539.4 million of pollution control debt of the utilities in order to prepay an equivalent portion of its promissory notes described above (OE -$250.6 million; CEI—$162.9 million; TE—$65.4 million; and Penn—$60.5 million). Further refunding activity will be subject to market conditions and other factors.
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Table of ContentsAs of June 30, 2007, the outstanding balances under FGCO’s notes to OE, CEI, TE and Penn were approximately $220 million, $199 million, $4 million and $3 million, respectively, and the outstanding balances under NGC’s notes to OE, CEI, TE and Penn were approximately $56, million, $154 million, $55 million and $164 million, respectively. As a result of the reductions in the note balances due from FGCO to OE and Penn, the liens securing Unit 1 of the Mansfield Plant were released prior to the consummation of the sale and leaseback transaction described in this prospectus.
Employees
As of June 30, 2007, FES had 2,148 employees, of whom 1,253 were covered by collective bargaining agreements.
Legal Proceedings
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FES’ normal business operations pending against FES and various of its subsidiaries. The other potentially material items not otherwise discussed above are described below.
On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from Sammis air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members. On October 18, 2006, the Ohio Supreme Court transferred this case to a Tuscarawas County Common Pleas Court judge due to concerns over potential class membership by the Jefferson County Common Pleas Court. Although FES is not a party to this proceeding, any relief that may ultimately be granted in favor of the plaintiffs could materially and adversely impact the operation or availability of Sammis, which in turn could have a material adverse effect on FES’ financial conditio n, results of operations and cash flows.
In February 2003, FES was sued in the U.S. District Court for the Western District of Pennsylvania for alleged breach of a gas purchase contract and for alleged interference with a third party gas purchase contract. The plaintiff, DL Resources, Inc., alleged that the gas purchase contract between it and FES was limited to the output of specified wells while FES contended that the gas purchase contract entitled it to specific minimum volumes of gas for a specified period of time. In addition, plaintiff alleged that FES improperly interfered with plaintiff’s contract with a third-party gas producer, Mid American. Mediation was held on January 25, 2005 and, on February 8, 2005, the court granted summary judgment for the plaintiff on the claims for declaratory judgment, breach of contract, restitution/unjust enrichment and tortious interference with prospective advantage and summary judgment for FES on tortious interference with the ex isting contract. Because the court’s order did not specify damages, on February 18, 2005, plaintiff filed a motion to amend judgment to specify damages, alleging damages of over $6 million. FES filed an Opposition to this motion in early March 2005. A May 31, 2005 hearing with respect to the damages claim was adjourned to allow the parties to attempt to agree on an order that would be appealable to the United States Court of Appeals for the Third Circuit. For purposes of the appeal, the parties tentatively agreed to a stipulated contract damages amount of approximately $2.5 million. The parties, however, were not able to agree to a tort damages amount and, on November 21, 2005, the tort damages claim was submitted to a bench trial. On December 19, 2005, the court awarded the plaintiff approximately $2.4 million for tort damages, although plaintiff’s request for pre-judgment and post-judgment interest was denied. FES is now proceeding wit h its appeal to the United States Court of Appeals for the Third Circuit. The matter was fully briefed and oral argument took place on January 23, 2007. A decision has not yet been rendered. FES cannot predict the outcome of this appeal.
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Table of ContentsMANAGEMENT
Set forth below is the name, age, position and a brief account of the business experience of each of FES’ executive officers and directors and key employees.
| | | | | | |
| Name | | | Age | | | Position(s) |
| Charles E. Jones | | | 51 | | | President |
| Richard H. Marsh | | | 56 | | | Senior Vice President, Chief Financial Officer and Director |
| Leila L. Vespoli | | | 47 | | | Senior Vice President and General Counsel |
| Charles D. Lasky | | | 44 | | | Vice President of Fossil Operations and Air Quality Compliance |
| Ali Jamshidi | | | 52 | | | Vice President of Commodity Operations |
| Arthur Yuan | | | 49 | | | Vice President of Sales and Marketing |
| James F. Pearson | | | 52 | | | Vice President and Treasurer |
| Alfred G. Roth | | | 59 | | | Vice President of Marketing Intelligence and Risk Mitigation |
| Harvey L. Wagner | | | 54 | | | Vice President and Controller |
| Anthony J. Alexander | | | 56 | | | Director |
| Joseph J. Hagan | | | 57 | | | Director |
Charles E. Jones has served as President of FES since March 1, 2007 and joined FirstEnergy in 1978 as a substation engineer at OE. Mr. Jones was named President of Penn in 1995, President of FirstEnergy’s Northern Region in 1997, Vice President of FirstEnergy’s Regional Operations in 2001 and Senior Vice President of FirstEnergy’s Energy Delivery & Customer Service in 2003.
Richard H. Marsh has served as Senior Vice President, Chief Financial Officer and a Director of FES since January 1, 2002. Mr. Marsh also serves as Senior Vice President and Chief Financial Officer of FirstEnergy. Mr. Marsh joined OE in 1980 and has served in a number of positions in the financial area.
Leila L. Vespoli served as Vice President and General Counsel of FES from February 1, 2000 until December 31, 2001 and has served as Senior Vice President and General Counsel of FES since January 1, 2002. Ms. Vespoli joined OE in 1984 as an associate attorney. She was named attorney in 1985 and promoted to senior attorney in 1995. She was named Associate General Counsel of FirstEnergy in November 1997, Vice President and General Counsel of FirstEnergy in 2000, and Senior Vice President and General Counsel of FirstEnergy in 2001.
Charles D. Lasky served as Vice President of FES from September 5, 2004 until May 16, 2007 and has served as Vice President of Fossil Operations & Air Quality Compliance of FES since May 17, 2007. Mr. Lasky joined OE in 1986 as an engineer at the Sammis Plant. After holding various engineering positions at Sammis and other locations, he was promoted to Planning Supervisor at the R. E. Burger Plant in 1992. Mr. Lasky served as Industrial Relations Coordinator from 1994 to 1995, and held various fossil operations and plant management positions before being named Director of the Mansfield Plant in 2001 and Vice President of Fossil Operations in 2004.
Ali Jamshidi served as Vice President of FES from June 1, 2006 until May 16, 2007 and has served as Vice President of Commodity Operations of FES since May 17, 2007. Mr. Jamshidi joined FirstEnergy in 1982 and served in a variety of operations, management and strategic planning positions before being named Vice President and Chief Information Officer of FirstEnergy in 2001. He was appointed to Vice President in the Energy Delivery group of FirstEnergy in 2004.
Arthur Yuan served as Vice President of FES from December 26, 2005 until May 16, 2007 and has served as Vice President of Sales and Marketing of FES since May 17, 2007. Prior to his appointment as Vice President of FES, Mr. Yuan served as Vice President and Chief Operating Officer of FirstEnergy Facilities Services Group, LLC from December 17, 2000 to December 25, 2005.
James F. Pearson served as Treasurer of FES from June 21, 2005 until September 30, 2006 and has served as Vice President and Treasurer of FES since October 1, 2006. He also serves as Vice President and Treasurer of FirstEnergy. Prior to his appointment as Vice President and Treasurer of FES, Mr. Pearson served in various management capacities at FES from January 1, 2002 until 2003
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Table of Contentsand Group Controller from 2003 to 2004. Mr. Pearson also served as Group Controller of Strategic Planning and Operations of FESC from 2004 to 2005.
Alfred G. Roth served as Vice President of FES from January 1, 2002 until May 16, 2007 and has served as Vice President of Marketing Intelligence & Risk Mitigation of FES since May 17, 2007.
Harvey L. Wagner served as Controller of FES from November 7, 1997 until December 31, 2001 and has served as Vice President and Controller of FES since January 1, 2002. Mr. Wagner also serves as Vice President, Controller and Chief Accounting Officer of FirstEnergy.
Anthony J. Alexander has served as a Director of FES since September 27, 1999. Mr. Alexander has also served as the President and Chief Executive Officer of FirstEnergy since 2004 and has been a Director of FirstEnergy since 2002. Prior to his appointment as Chief Executive Officer of FirstEnergy, Mr. Alexander was President and Chief Operating Officer of FirstEnergy from 2001 to 2004. Mr. Alexander currently serves as an officer and director of many other subsidiaries of FirstEnergy.
Joseph J. Hagan has served as a Director of FES since March 1, 2007. Mr. Hagan joined FENOC in March 2003 and became its President and Chief Nuclear Officer of FENOC in March 2007. Prior to this, Mr. Hagan owned Hagan Consulting Services. From 2000-2002, he was Senior Vice President for Nuclear Operations for Exelon Generation. He also served as Vice President of Nuclear Operations for Salem Nuclear Generating Station units 1 and 2, and for Hope Creek Nuclear Power Plant for Public Service Enterprise in New Jersey.
Executive Compensation
The following information relates to FirstEnergy. FES and FGCO do not establish their own executive compensation policy and procedures and there is no separate Compensation Committee of either of their Board of Directors.
Compensation Discussion and Analysis
FES is a subsidiary of FirstEnergy. FirstEnergy designs, evaluates and administers all compensation plans for FES and other subsidiaries. FirstEnergy’s Board of Directors and/or FirstEnergy’s Compensation Committee reviews and approves all compensation for FirstEnergy and its subsidiaries, including FES. The role of the FES Board of Directors is to carry out the activities generally performed by a Board of Directors and make decisions with regard to operational and financial aspects of FES. The FES Board of Directors does not make compensation decisions for FES.
References in this prospectus to the Compensation Committee mean the Compensation Committee of the FirstEnergy Board of Directors. Mr. Pipitone, Mr. Lasky, Mr. Roth and Mr. Yuan were employees of FES for all of 2006. Mr. Pipitone served as Chief Executive Officer of FES for 2006. Mr. Marsh was an employee of FirstEnergy and Chief Financial Officer of FES in 2006. Mr. Schneider served as an officer of FES until May 31, 2006. Disclosure regarding Mr. Schneider is included in this prospectus because had he remained an officer of FES until year-end he would have been included as one of the five most highly compensated named executive officers. On June 1, 2006, Mr. Schneider, formerly Vice President Commodity Operations of FES was named Vice President Energy Delivery of FirstEnergy and thereafter rendered no additional services to FES. On March 1, 2007, Mr. Schneider was named S enior Vice President Energy Delivery and Customer Service of FirstEnergy.
FirstEnergy provides a competitive compensation program to attract, retain and reward employees whose performance and contributions drive FirstEnergy’s success. The compensation philosophy targets total compensation at the market median for FirstEnergy’s peer group, with the opportunity to earn above-median compensation for strong company and/or individual performance. As a result, the executive compensation program is intended to reward and retain executives responsible for leading the organization in the achievement of business objectives in the complex energy services industry.
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Table of ContentsFirstEnergy’s compensation programs apply to all executives and reflect the following principles:
| | |
| �� | Total compensation is competitive and reflects a pay-for-performance orientation. |
| | |
| • | The peer group used to evaluate competitive levels of compensation is comprised of comparable energy services companies. |
| | |
| • | Base salaries are generally targeted at or near the median of the peer group. |
| | |
| • | Incentive opportunities are targeted at the median competitive level for the achievement of specified corporate goals and include the opportunity to achieve above median compensation rewards. |
| | |
| • | Short-term incentive opportunities are based on a combination of corporate and business unit goals. |
| | |
| • | Long-term incentive awards are based on both FirstEnergy’s absolute performance and performance relative to peer companies. |
The elements of FirstEnergy’s compensation program include base salary and short-term and long-term incentive opportunities. Under FirstEnergy’s pay-for-performance philosophy, executive rewards are directly linked to short-term and long-term results for key stakeholders including shareholders and customers. A significant portion of an executive’s actual pay reflects corporate and business unit performance as defined by various financial and operational measures.
Variations of base salary from median levels for individual executives reflect the relative responsibilities of the position and facilitate internal equity. Further, base salaries reflect the qualifications, experience and sustained performance level of the executive.
Short-term incentive opportunities provide executives the potential to achieve total cash compensation at approximately the 75th percentile of the peer group if corporate performance is superior. However, there is significant risk if performance is below expectations. As an executive’s responsibility increases, a greater percentage of the annual incentive is driven by corporate performance. Corporate goals reflect targeted performance objectives for the year and are heavily weighted toward financial targets.
Long-term incentive awards consisting of restricted stock units and performance shares are based on the achievement of corporate goals and the annualized total shareholder return generated by FirstEnergy common stock over a three-year period relative to a peer group, respectively.
The components of the compensation programs are evaluated both individually and in the aggregate. Fundamentally, the proportion of pay at risk increases as an executive’s responsibilities increase. Thus, executives with greater responsibilities for the achievement of company performance targets bear a greater risk if those goals are not achieved, and also receive a greater reward if the goals are met or surpassed. The appropriate balance of annual, medium-term and longer-term incentives facilitates the retention of talented executives, recognizes the achievement of short-term goals, rewards long-term strategic results and encourages equity ownership. In determining compensation, the Compensation Committee balances the pay to achieve competitive parity with the amount required to retain and motivate executives. The philosophy of FirstEnergy is to use a variety of compensation vehicles, primarily driven by financial and operational performance metrics.
As is indicated in the following chart, as the level of responsibility increases, the percentage of base salary decreases and the percentage of at-risk pay, including short-term incentive and equity, increases. The chart represents the actual percentage of each pay element in relation to total target compensation for the named executives in 2006.
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| | | | | | | | | | | | | | | | | | |
| | | | Base Salary | | | Short-term
Incentive | | | Equity |
| Richard H. Marsh | | | | | 34 | % | | | | | 22 | % | | | | | 44 | % |
| Guy L. Pipitone | | | | | 41 | % | | | | | 22 | % | | | | | 37 | % |
| Donald R. Schneider | | | | | 41 | % | | | | | 22 | % | | | | | 37 | % |
| Charles D. Lasky | | | | | 45 | % | | | | | 23 | % | | | | | 32 | % |
| Alfred G. Roth | | | | | 53 | % | | | | | 21 | % | | | | | 26 | % |
| Arthur W. Yuan | | | | | 53 | % | | | | | 21 | % | | | | | 26 | % |
Although the Compensation Committee has established share ownership guidelines for executives, such equity ownership is not considered when establishing compensation levels. However, the Compensation Committee does review prior awards, both vested and unvested, on a regular basis through the use of the tally sheets described later.
Compensation Setting Process
Consultant
The Compensation Committee employs an independent external compensation consultant at FirstEnergy’s expense. Consistent with NYSE rules, the Compensation Committee has the sole authority to retain and dismiss the consultant and to approve the consultant’s fees. The consultant provides objective independent advice and analysis to the Compensation Committee with respect to executive compensation. During 2006, the Compensation Committee conducted a review of executive compensation consultants as part of its due diligence. In September 2006, the Compensation Committee retained Hewitt Associates based on its expertise, independence and utility industry experience. The Compensation Committee felt Hewitt Associates would better serve FirstEnergy and its Board of Directors at this time than the previous consultant. Management uses Hewitt Associates to provide compensation, actuarial and benefit plan consulting services to FirstEnergy and advises the Com pensation Committee of the work performed by Hewitt. The Compensation Committee determined that these relationships do not impair the ability of the consultant to render impartial services to the Compensation Committee.
The Compensation Committee relies on the consultant to provide an annual review of executive compensation practices at other companies. This review includes companies that FirstEnergy competes with for executive talent and is further discussed below under ‘‘—Benchmarking.’’ This review encompasses base pay, annual incentives, long-term incentives and perquisites. In addition, the Compensation Committee may request advice concerning the design, communication and implementation of incentive plans or other compensation programs. The services provided by the consultant in 2006 included:
| | |
| • | A review of the alignment of executive compensation practices to FirstEnergy’s compensation philosophy; |
| | |
| • | Benchmarking and analysis of competitive compensation practices for executives and directors; |
| | |
| • | Advice related to the modification of incentive programs for executive officers and other key employees; |
| | |
| • | A review of FirstEnergy’s severance agreements to ensure alignment with competitive practice; and |
| | |
| • | Advice and guidance regarding the impact new rules and regulations would have on the compensation programs of FirstEnergy. |
Benchmarking
As referenced above under ‘‘—Consultant,’’ in early 2006 the Compensation Committee’s consultant compared FirstEnergy’s executive compensation against 24 large utilities in the United States. These are generally the energy services organizations that FirstEnergy competes with for executive talent. The consultant identified the following peer group:
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| | | | | | |
| Allegheny Energy | | | Ameren | | | American Electric Power |
| CenterPoint Energy | | | CMS Energy | | | Consolidated Edison |
| DTE Energy | | | Dominion Resources | | | Duke Energy |
| Edison International | | | Energy East | | | Entergy |
| Exelon | | | FPL Group | | | PG&E |
| PPL | | | Pepco | | | Pinnacle West |
| Progress Energy | | | Sempra Energy | | | Southern Company |
| TECO Energy | | | TXU | | | Xcel Energy |
Targeted base pay and short-term and long-term incentive opportunities are based on a review of the compensation of these companies. Since FirstEnergy is larger than the typical firm in the sample, results were adjusted based on revenues to make the comparison relevant. In addition, consideration may be given to broader general industry data when that is the relevant pool in which FirstEnergy competes for talent. The consultant evaluated the competitive data and provided recommendations for FirstEnergy consistent with FirstEnergy’s compensation philosophy.
The elements of compensation as previously stated and defined later, and the mix of the elements are determined based on an annual analysis of these peer companies. The Compensation Committee has determined that the compensation elements, both individually and in the aggregate, are appropriately aligned with FirstEnergy’s compensation philosophy.
Management and/or the Compensation Committee reviews the compensation philosophy annually to ensure that it continues to align with company goals and offers competitive levels of compensation. FirstEnergy’s recent success in filling executive positions from the external market, its relatively low executive turnover, and its success with ongoing recruitment efforts, indicate FirstEnergy’s compensation programs are meeting the goals of providing competitive pay.
Tally Sheets
The Compensation Committee reviewed a comprehensive summary of all components of the compensation, including base salary, incentive awards based on corporate and business unit performance, equity compensation, stock option and restricted stock performance, perquisites and other personal benefits, and actual and projected payout obligations under several termination scenarios (i.e., voluntary resignation, retirement, severance and change in control) for the named executive officers of FirstEnergy, including Mr. Marsh. Based on the review of these tally sheets, the Compensation Committee determined that the total compensation provided (and, in the case of termination scenarios, the potential payout) was reasonable. This review is performed by the Compensation Committee at each January meeting. Tally sheets f or Mr. Pipitone, Mr. Schneider, Mr. Lasky, Mr. Roth and Mr. Yuan were not reviewed by the Compensation Committee, as none was one of the five highest paid executive officers of FirstEnergy.
Role of Executives
The executives of FES are not involved in planning, setting or determining compensation. FirstEnergy’s Board of Directors has delegated authority to Anthony J. Alexander, Chief Executive Officer of FirstEnergy, or CEO, to establish the compensation of other senior executives whose compensation is not determined by the Compensation Committee pursuant to its charter, provided that this authority is exercised only after consultation with the Compensation Committee. As such, the CEO makes recommendations to the Compensation Committee for these other executives’ total compensation. In all cases, these recommendations are presented to the Compensation Committee for review.
The CEO and other senior executives of FirstEnergy play an increased role in the early stages of design and evaluation of compensation programs and policies. The executives review, discuss and provide comments when FirstEnergy is planning a design change to a compensation program. They have a vested interest in ensuring that the compensation programs and policies will engage employees and provide incentives to strive for excellence in their daily responsibilities in order to produce outstanding financial and operating results for FirstEnergy and its shareholders.
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Table of ContentsElements of Compensation
Base Salary
Executives are paid a base salary for performing their job responsibilities. Executives’ base salaries are reviewed annually by the Compensation Committee. Adjustments to base salary are made, if appropriate, generally on March 1 of each year, after considering factors such as company performance, individual performance, changes in executives’ responsibilities and changes in the competitive marketplace. The consultant provides the median competitive data for each executive’s position as described above. Generally, a range of 85% to 115% of this competitive data is used to promote the pay-for-performance philosophy. The base salaries for all named executive officers fall within this range.
On March 1, 2007, the Compensation Committee provided a base salary increase to Mr. Pipitone of 2.44%. The Compensation Committee provided base salary increases of 7.45%, 15.94%, 9.43%, 0.0%, and 7.14% for Mr. Marsh, Mr. Schneider, Mr. Lasky, Mr. Roth and Mr. Yuan, respectively, based on the results of the annual compensation review and in the case of Mr. Schneider, in recognition of his new broadened responsibilities. On March 1, 2007, Mr. Schneider was named Senior Vice President, Energy Delivery and Customer Service of FirstEnergy. In lieu of a base salary increase, Mr. Roth received a 3% lump sum award of $6,500.
Short-Term Incentive Program
The short-term incentive program, or STIP, provides awards to executives whose contributions support the achievement of corporate financial and operational goals. The program supports FirstEnergy’s compensation philosophy by linking executive awards directly to annual performance results on key corporate and business unit objectives. Similar to base salaries, the short-term incentive program provides executives with opportunities targeted to the median of the utility industry. The Compensation Committee annually reviews these target award opportunities, which are expressed as a percentage of base salary. During the first quarter, adjustments to target levels for the current year are made as appropriate and warranted by competitive market practice and internal equity considerations.
FirstEnergy’s STIP is based on performance targets, and in 2006 these included, but were not limited to, objectives relative to the following goals:
| | |
| • | Free cash flow from operations; |
| | |
| • | Customer service excellence; |
| | |
| • | Transmission outage frequency; |
| | |
| • | Distribution System Average Interruption Duration Index; |
| | |
| • | Financial contribution to earnings; |
| | |
| • | Safety (including nuclear safety); and |
In addition to the above, performance targets included but were not limited to, objectives relative to the following goals for executives of FES:
| | |
| • | Normalized generation margin; |
| | |
| • | Generation asset utilization; |
| | |
| • | Fossil environmental excursions; and |
| | |
| • | Fossil production cost. |
Executives are assigned and evaluated on goals applicable to their responsibilities within the organization. These performance goals were chosen because they have a significant impact on
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Table of ContentsFirstEnergy’s operational and financial success. The specific targets for these performance goals reflect FirstEnergy’s confidential strategic plans and are not disclosed publicly for competitive reasons. FirstEnergy establishes targets for incentive compensation performance measures based on earnings growth aspirations and achieving continuous improvement in operational performance to reach industry top quartile/decile levels. Over the last five years, FirstEnergy has achieved target performance levels for the performance measures held by senior executives approximately 56% of the time. For that same five-year period, FES has achieved target performance levels for the performance measures held by senior executives approximately 55% of the time. The weightings of financial and operational targets for executives are determined at the beginning of each year. In 2006, the weightings were 50% financial and 50% operational for Mr. Pipitone, Mr. Schneider, Mr. Lasky, Mr. Roth and Mr. Yuan. For Mr. Marsh, the weightings were 70% financial and 30% operational.
The process for allocating awards is similar for all executives. The target levels are established in February and performance is measured throughout the year. In 2006, STIP target award opportunities for the named executive officers ranged from 40% of salary to 65% of salary. Awards for the short-term incentive based on operational performance range from 50% of target for performance at the threshold level to 150% of target for outstanding performance. Awards for the short-term incentive portion based on financial performance range from 50% of target for performance at threshold to a maximum of 200% of target for outstanding performance. Awards are not made if threshold performance is not achieved. Awards are mathematically interpolated for performance between threshold and maximum and no positive or negative discretion is applied to the final awards. The Compensation Committee has no authority to adjust upwards the amount payable to a covered employee wit h respect to a particular award.
In 2006, FirstEnergy as well as FES, achieved outstanding financial and operational performance relative to its goals which had a positive impact on the short-term incentive payout. For 2006, Mr. Pipitone’s award was $348,996. The remaining named executive officers’ awards were as follows: Mr. Marsh—$514,003; Mr. Schneider—$282,742; Mr. Lasky—$205,051; Mr. Roth—$140,847, and Mr. Yuan—$134,873.
Long-Term Incentive Program
Long-term incentive awards are awarded under the terms of the FirstEnergy Executive and Director Incentive Compensation Plan, or the Incentive Plan. The long-term incentive program, or LTIP, is designed to reward executives for achievement of company goals which ultimately result in increased shareholder value. This program is equity-based to align the long-term interests of executives with those of shareholders. In 2006, FirstEnergy delivered long-term incentives through a combination of restricted stock units and performance shares. FirstEnergy has not issued stock options under its LTIP since 2004. Similar to the STIP, during the first quarter of each year the Compensation Committee reviews and adjusts executives’ long-term incentive target opportunities as appropriate and warranted by competitive market practice and internal equity considerations. The Compensation Committee has no authority to adjust upwards the amount payable to a covered employee wit h respect to a particular award.
FirstEnergy’s restricted stock unit program contains two components: performance-adjusted and discretionary restricted stock units. Performance-adjusted restricted stock units are designed to focus participants on key financial and operational metrics that drive FirstEnergy’s success, foster management ownership, and aid retention. These metrics are earnings per share, safety and an operational performance index. The actual number of shares issued may be adjusted upward or downward by 25% based on FirstEnergy’s performance against these three key metrics. The specific targets for these metrics reflect FirstEnergy’s confidential strategic plans and are not disclosed publicly for competitive reasons.
Performance-adjusted restricted stock units are granted to all eligible executives. Based on competitive analysis, each eligible executive received an initial grant of performance-adjusted restricted stock units, at a target level based on the executive’s annual salary as of March 1, 2006, and calculated using the average of the high and low stock price on March 1, 2006. These performance-adjusted restricted stock units are granted to each executive with the right to receive, at
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Table of Contentsthe end of the three-year restriction period, shares of FirstEnergy common stock. In 2006, performance-adjusted restricted stock grants were issued as follows: Pipitone—3,221 units, Marsh—6,000 units, Schneider—2,711 units, Lasky—1,822 units, Roth—1,066 units and Yuan—1,032 units.
Discretionary restricted stock units are granted in limited circumstances to high performing and/or high potential employees or to retain critical talent. Discretionary restricted sock units do not have a performance component. These discretionary restricted stock units are granted to each executive with the right to receive, at the end of the five-year restriction period, shares of FirstEnergy common stock. In 2006, Mr. Schneider and Mr. Lasky were granted 2,848 and 2,750 discretionary restricted stock units, respectively.
FirstEnergy’s performance share program provides executives with the opportunity for awards based on FirstEnergy’s total shareholder return over a three-year period relative to the Edison Electric Institute’s Index of Investor-Owned Electric Utility Companies, or the EEI Index. The number of performance shares granted is calculated by multiplying the executive’s March 1 salary by the eligible incentive percent and dividing by the average high and low common stock price during December of the previous year. Performance share grants in 2006 were issued as follows: Pipitone—3,384 shares, Marsh—4,848 shares, Schneider—2,847 shares, Lasky—1,640 shares, Roth—1,119 shares and Yuan—1,083 shares.
Performance shares typically payout in cash at the end of the performance cycle. For the three-year period ending December 2006, FirstEnergy ranked 8th out of 63 companies in the EEI Index which positively impacted the performance share payout. The performance shares for the 2004-2006 period were paid as follows: Pipitone—$383,373, Marsh—$593,655, Schneider—$236,031, Lasky— $73,004, Roth—$155,208 and Yuan—$133,251.
The process for allocating awards is similar for all executives. The target levels are established in February, and performance is measured throughout the cycle. In 2006, performance-adjusted restricted stock unit target award opportunities for the named executive officers ranged from 25% of salary to 65% of salary. In 2006, performance share target award opportunities for the named executive officers ranged from 25% of salary to 50% of salary. The mix of the types and the range of the awards are established based on competitive benchmarking and are intended to encourage operational excellence and to increase shareholder value.
Payment of restricted stock units and performance shares upon termination from FirstEnergy are discussed below under ‘‘—Post-Termination Compensation and Benefits.’’ All long-term incentive awards granted to the named executive officers are subject to the share ownership guidelines discussed below under in ‘‘—Stock Ownership/Retention Guidelines.’’
The Compensation Committee has determined that an equity grant date of March 1 is appropriate for restricted stock units. Performance shares are granted effective January 1. The timing of the grants enables FirstEnergy to consider competitive market data and prior year company performance in establishing target levels. Any equity grants awarded in proximity to an earnings announcement or other market event are coincidental in nature.
Restricted stock units and performance shares are discussed in further detail below under ‘‘—Grants of Plan-Based Awards’’ following the Grants of Plan-Based Awards table.
Other Equity Awards
FirstEnergy has a restricted stock program, which is utilized solely for recruitment, retention and special recognition purposes. Award sizes, grant dates and vesting periods vary to allow flexibility. As a result of superior performance and FirstEnergy’s Board of Directors’ strong desire to retain Mr. Schneider and Mr. Lasky, the Compensation Committee recommended and FirstEnergy’s Board of Directors approved grants to Mr. Schneider and Mr. Lasky of 17,000 shares of restricted stock each on December 19, 2006. Fifty percent of the shares will vest on December 19, 2011 and 50% of the shares will vest on December 19, 2016. The Compensation Committee has the authority to modify all or select stock grants, however the Compensation Committee has not taken such action since 2002.
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Table of ContentsPayment of restricted stock upon termination from FirstEnergy is discussed below under ‘‘—Post-Termination Compensation and Benefits.’’ All equity awards granted to the named executive officers are subject to the share ownership guidelines discussed below under ‘‘—Stock Ownership/Retention Guidelines.’’
Restricted stock grants are discussed in further detail below under ‘‘—Grants of Plan-Based Awards’’ following the Grants of Plan-Based Awards table.
Retirement
The FirstEnergy Supplemental Executive Retirement Plan, or the SERP, is limited to certain key executives. Mr. Pipitone and Mr. Marsh are participants in the SERP. Mr. Schneider, Mr. Lasky, Mr. Roth and Mr. Yuan do not participate in the SERP. The SERP is part of the integrated compensation program intended to attract, motivate and retain top executives who are in positions to make significant contributions to the operation and profitability of FirstEnergy for the benefit of its customers and shareholders. The SERP benefit is equal to the greater of (i) 65% of the executive’s highest annual salary, or (ii) 55% of the average of the executive’s highest three consecutive years of salary plus annual incentive awards. The SERP benefit is reduced by the executive’s pensions under tax-qualified pension plans of FirstEnergy or other employers, any supplemental pension under the FirstEnergy Executive Deferred Compensa tion Plan, or EDCP, and Social Security benefits. In some cases, an executive’s tax-qualified pension and supplemental pension may exceed the SERP benefit, which eliminates any benefit payments under the FirstEnergy Executive Deferred Compensation SERP. This is not the case for the named executive officers reported in this registration statement as of December 31, 2006. The SERP also provides for disability and surviving spouse benefits. At the end of 2006, only 14 active employees are eligible participants for a SERP benefit upon retirement and no new participants have been provided eligibility since 2001. Any new participants must be approved by the Compensation Committee.
Earnings on Deferred Compensation
The EDCP offers executives the opportunity to accumulate assets on a tax-favored basis and acquire additional FirstEnergy stock. The EDCP is part of an integrated executive compensation program to attract, retain and motivate key executives who are in positions to make significant contributions to the operation and profitability of FirstEnergy.
Above-market interest earnings on the deferred compensation cash accounts of executives are provided as an incentive for executives to defer base salary and short-term incentive awards. Additionally, a 20% company matching contribution on deferrals from short-term and long-term incentive awards directed to investment in FirstEnergy stock further ties management investment performance to the success of FirstEnergy. FirstEnergy has determined that the levels of executive benefits in the aggregate are competitive and aligned with FirstEnergy’s philosophy.
Personal Benefits and Perquisites
Executives may be eligible to receive limited perquisites offered by FirstEnergy, including financial planning and tax preparation services, country club dues and personal use of the corporate aircraft. FirstEnergy believes that financial planning by experts reduces the time that executives spend on that topic and assists in making the most of the financial rewards received from FirstEnergy. Some executives belong to a golf or country club so that they have an appropriate entertainment forum for customers and appropriate interaction with their communities. The named executive officers, may from time to time, with CEO approval, use FirstEnergy’s corporate aircraft for personal travel. FirstEnergy has a written policy that sets forth guidelines regarding the personal use of the corporate aircraft by executive officers and other employees. The Compensation Committee believes these perquisites are reasonable, competitive and consistent with the overall compens ation philosophy.
Stock Ownership/Retention Guidelines
FirstEnergy believes it is critical that the interests of executives and shareholders be clearly aligned. As such, share ownership requirements, defined as a multiple of salary, are in place for FirstEnergy’s executives as follows:
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Table of ContentsPresident and CEO—5 times salary
Executive Vice President and COO—4 times salary
Senior Vice Presidents and the Equivalent—3 times salary
Vice Presidents and the Equivalent—1 to 2 times salary
For 2006, the following were included to determine ownership status:
| | |
| • | Shares directly or jointly owned in certificate form or in a stock investment plan, |
| | |
| • | Shares owned through the FirstEnergy Savings Plan, or Savings Plan, |
| | |
| • | Shares held in the executive deferred compensation plan, and |
| | |
| • | Shares granted through the LTIP (restricted stock units and performance shares). |
Once guidelines are attained, executives subject to the guidelines may exercise any or all vested stock options; however, they may sell only 50% of the shares granted by FirstEnergy after January 1, 2005. Additionally, FirstEnergy’s Insider Trading Policy prohibits executive officers from hedging their economic exposure to the FirstEnergy stock that they own.
The guidelines are reviewed for competitiveness on an annual basis and were last reviewed at the February 2007 Compensation Committee meeting. The named executives officers listed have met the share ownership guidelines. As of March 1, 2007, Mr. Pipitone owned 70,077 shares of FirstEnergy’s stock, which more than satisfies his requisite stock ownership requirements.
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Table of ContentsPost-Termination Compensation and Benefits
The following table sets forth the payment of post-termination compensation and benefits under different scenarios for all named executive officers. Additional information regarding change in control agreements and provisions follows the table.
2006 Post-Termination Compensation and Benefits
| | | | | | | | | | | | | | | | | | |
| | | | Retirement(1) | | | Severance
(Absent a change in
control) | | | Change In
Control | | | Voluntary
Termination (pre-retirement eligible)(1) | | | Death(1) | | | Disability(1) |
| Base Salary | | | Accrued though date of retirement | | | Accrued through date of severance | | | Accrued through date of change-in-control termination | | | Accrued through date of termination | | | Accrued through date of qualifying event | | | Accrued through date of qualifying event |
| Severance Salary | | | N/A | | | 3 weeks of pay for every one year of service, including the current year, calculated using base salary at the time of severance | | | 2.99 times the sum of base salary plus average incentive award over the past three years(2) | | | N/A | | | N/A | | | N/A |
Accrued and Banked
Vacation | | | Paid in a lump sum | | | Paid in a lump sum | | | Paid in a lump sum | | | Paid in a lump sum | | | Paid in a lump sum | | | Paid in a lump sum |
Health and Wellness
Benefits | | | Retiree/spouse health and wellness provided | | | Provided at active employee rates for the severance period(3) | | | Based on the terms of the Special Severance Agreement, if applicable(4) | | | Forfeited | | | Survivor health and wellness provided as eligible | | | Health and wellness provided as eligible |
| Short-term Incentive Program Award | | | Issued a prorated award based on full months of service | | | Issued a prorated award based on full months of service | | | Issue a prorated award based on full months of service | | | Forfeited | | | Issued a prorated award based on full months of service | | | Issued a prorated award based on full months of service |
| Performance-Adjusted Restricted Stock Units(5) | | | Issued a prorated award, and all dividends earned, must have a minimum of 12 months in a cycle | | | Issued a prorated award, and all dividends earned, must have a minimum of 12 months in a cycle | | | For 2005 grants issued, 100% of shares and all dividends earned For 2006 grants payout based on share value protection rights | | | Forfeited | | | Issued 100% of shares and all dividends earned | | | Issued 100% of shares and all dividends earned |
| Discretionary Restricted Stock Units(5) | | | Issued a prorated award, and all dividends earned, must have a minimum of 36 months in a cycle | | | Issued a prorated award, and all dividends earned, must have a minimum of 36 months in a cycle | | | For 2005 grants issued, 100% of shares and all dividends earned For 2006 grants payout based on share value protection rights | | | Forfeited | | | Issued 100% of shares and all dividends earned | | | Issued 100% of shares and all dividends earned |
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Table of Contents
| | | | | | | | | | | | | | | | | | |
| | | | Retirement(1) | | | Severance
(Absent a change in
control) | | | Change In
Control | | | Voluntary
Termination (pre-retirement eligible)(1) | | | Death(1) | | | Disability(1) |
| Performance Shares(5) | | | Issued a prorated award of shares and dividends earned, must have a minimum of 12 months in a cycle | | | Issued a prorated award of shares and dividends earned, must have a minimum of 12 months in a cycle | | | For 2004 and 2005 grants, issued prorated award of shares and dividends earned For 2006 grants payout based on change in control value protection rights | | | Forfeited | | | Issued a prorated award of shares and dividends earned, must have a minimum of 12 months in a cycle | | | Issued a prorated award of shares and dividends earned, must have a minimum of 12 months in a cycle |
| Stock Options(6) | | | All options vest as scheduled and must be exercised prior to the expiration date | | | All vested options must be exercised within 90 days or the date of expiration, whichever is earliest. All unvested options are forfeited | | | All options become immediately exercisable and must be exercised prior to the expiration date | | | All vested options must be exercised within 90 days or the date of expiration, whichever is earliest. All unvested options are forfeited | | | All options become immediately exercisable and must be exercised within one year of date of death | | | All options become immediately exercisable and must be exercised prior to the expiration date |
| Restricted Stock | | | Forfeited, if unvested | | | Forfeited | | | Issued 100% of shares and all dividends earned | | | Forfeited | | | Issued 100% of shares and all dividends earned | | | Issued 100% of shares and all dividends earned |
| Qualified Retirement Plan | | | Payable in a monthly benefit at earliest retirement age | | | Payable in a monthly benefit at earliest retirement age | | | Payable in a monthly benefit at earliest retirement age | | | Payable in a monthly benefit at earliest retirement age | | | Payable to survivor in a monthly benefit | | | Payable in a monthly benefit at earliest retirement age |
Nonqualified
Retirement Plan | | | Payable in a monthly benefit at earliest retirement age | | | Payable in a monthly benefit at earliest retirement age | | | Payable in a monthly benefit at earliest retirement age | | | Payable in a monthly benefit at earliest retirement age | | | Payable to survivor in a monthly benefit | | | Payable in a monthly benefit at earliest retirement age |
| SERP(7) | | | Payable in a monthly benefit at earliest retirement age | | | Payable in a monthly benefit at earliest retirement age | | | Payable in a monthly benefit at earliest retirement age | | | Forfeited if voluntarily terminated prior to retirement age | | | Payable to survivor in a monthly benefit | | | Payable in a monthly benefit at earliest retirement age |
Vested Executive
Deferred Compensation | | | Payable as elected | | | Payable as elected | | | Payable as elected | | | Payable as elected | | | Payable to survivor as elected | | | Payable as elected |
| Non-vested Executive Deferred Compensation | | | Payable as elected(8) | | | Payable as elected | | | Payable as elected | | | Forfeited | | | Payable to survivor as elected | | | Payable as elected |
Additional Age and
Service for Pension, EDCP and Benefits | | | N/A | | | N/A | | | Two/three years(9) | | | N/A | | | N/A | | | N/A |
Reimburse Code
Section 280G | | | No | | | No | | | Yes, if covered by a Special Severance Agreement | | | No | | | No | | | No |
| (1) | Benefits provided in these scenarios also provided to all FirstEnergy employees, if applicable. |
| (2) | FirstEnergy has in place separate Special Severance Agreements with Mr. Pipitone and Mr. Marsh. Benefit shown would be provided to Mr. Marsh. Mr. Pipitone would be provided a cash payment of 2.0 times the sum of the base salary plus the target amount of the annual incentive award whether or not actually paid. Mr. Schneider. Mr. Lasky, Mr. Roth and Mr. Yuan would be provided severance pay benefits as described in the severance column in the event of a discharge without cause after a change in control. |
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Table of Contents| (3) | Active employee health and wellness benefits are provided to the named executive officers for the severance period, which is equal to three weeks for every year of service, including the current year (52-week minimum). At the end of the severance period, retiree health and wellness benefits are provided, if retirement eligible. |
| (4) | Mr. Pipitone and Mr. Marsh are eligible for retirement and would receive retiree health and wellness benefits in the event of a change in control. Mr. Schneider, Mr. Lasky, Mr. Roth and Mr. Yuan would be provided health and welfare benefits as provided in the event of a severance (absent a change in control). |
| (5) | Beginning in 2007, payout of restricted stock units and performance shares will not occur until the completion of the performance cycle or the end of the vesting period. |
| (6) | FirstEnergy has not granted any stock options under the annual long-term incentive program since 2004 when the use of restricted stock units replaced stock options. |
| (7) | The SERP benefit is limited to certain key executives. Mr. Pipitone and Mr. Marsh are eligible for a SERP benefit. |
| (8) | If an executive voluntarily leaves FirstEnergy prior to age 60 (early retirement), any non-vested premium is forfeited. |
| (9) | Mr. Pipitone would be granted two years of age and service. Mr. Marsh would be granted three years of age and service. |
Change In Control
Change in Control Special Severance Agreements, or Special Severance Agreements, are intended to ensure that certain executives are free from personal distractions in the context of a potential change in control, when FirstEnergy’s Board of Directors needs the objective assessment and advice of these executives to determine whether an offer is in the best interests of FirstEnergy and its shareholders. FirstEnergy has in place separate Special Severance Agreements with Guy L. Pipitone and Richard H. Marsh. In each case, the agreements provide for the payment of severance benefits if the individual’s employment with FirstEnergy or its subsidiaries is terminated under specified circumstances within three years after a change in control of FirstEnergy. Circumstances defining a change in control are explained below under ‘‘—Potential Post-Employment Payments.’’
FirstEnergy executed agreements consistent with competitive practice with Mr. Pipitone on March 7, 2005 and with Mr. Marsh on December 31, 2003. The Special Severance Agreements have initial three-year terms. The Special Severance Agreements are reviewed annually by FirstEnergy’s Board of Directors at a regular meeting held between October 1 and December 31 of each year. FirstEnergy’s Board of Directors decides in this meeting whether or not to extend the terms of the Special Severance Agreement for an additional year. In the 2006 review, both of the Special Severance Agreements were extended for an additional year.
The severance benefits provided reflect the fact that it may be difficult for employees to find comparable employment within a short period of time. In September 2006, as is the annual practice, the compensation consultant reviewed the current Special Severance Agreements in light of competitive practice and market trends. Their findings indicate FirstEnergy’s Special Severance Agreements are consistent with competitive practices including the definition of change in control, eligibility for change in control agreements, levels of cash severance provided and the types of benefits covered. Under each of the above Special Severance Agreements, the executives would be prohibited for two years from working for or with competing entities after receiving severance benefits pursuant to the Special Severance Agreement. Additional details are provided in the 2006 Post-Termination Compensation and Benefits table provided above. A detailed representation of the termination benefits provided under a change in control scenario as of December 31, 2006, is provided below in the Potential Post-Employment Payments tables appearing later in this prospectus.
Impact of Regulatory Requirements on Compensation
The Compensation Committee is responsible for addressing pay issues associated with Section 162(m) of the Code. Code Section 162(m) limits to $1 million FirstEnergy’s tax deduction for certain compensation paid to FirstEnergy’s most highly compensated executive officers. FirstEnergy, through the Compensation Committee, intends to attempt to qualify executive compensation as tax deductible to the extent feasible and where it believes it is in the best interests of FirstEnergy and its shareholders. It does not intend to permit this tax provision to distort the effective development and execution of FirstEnergy’s compensation program. Thus, the Compensation Committee is permitted to and will continue to exercise discretion in those instances where satisfaction of tax law requirements could compromise the interests of FirstEnergy’s shareholders. In addition, because of the uncertainties associated with the application and interpretation of Code Section 162(m) and the regulations issued
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Table of Contentsthereunder, there can be no assurance that compensation intended to satisfy the requirements for deductibility under Code Section 162(m) will in fact be deductible.
FirstEnergy’s compensation vehicles are primarily performance based awards that are not subject to the $1 million deduction limitation. However, base salary in excess of $1 million is subject to the deduction limitation. The STIP and the performance share component of the LTIP qualify as performance based compensation and are not subject to the $1 million deduction limit. A portion of the restricted stock unit component also qualifies as performance based compensation. Therefore, base salary in excess of $1 million and a portion of the restricted stock units are subject to the $1 million deduction limit. In 2006, for the FES named executive officers there was no lost deductibility under Code Section 162(m).
Conclusion
The foundation of FirstEnergy’s compensation philosophy is the concept of pay-for-performance. FirstEnergy provides a competitive total compensation program designed to attract, retain and reward employees whose performances drive company success. As a result, the executive compensation programs are designed to reward and retain executives who are responsible for leading the organization in achieving FirstEnergy’s business objectives in the highly complex utility industry.
In evaluating each element of compensation (individually and in the aggregate), FirstEnergy has deemed total compensation provided to its executives reasonable, competitive and not excessive. Each element of direct compensation is linked to a performance measure that impacts either financial or operational performance. These performance measures drive profitability, safety and productivity which have a positive impact on FirstEnergy as well as providing for an increased return on investment for shareholders.
SUMMARY COMPENSATION TABLE
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Name and Principal Position(1) | | | Year | | | Salary
($) | | | Bonus
($) | | | Stock
Awards
(2) ($) | | | Option
Awards
(3) ($) | | | Non-Equity
Incentive
Plan
Compensation
(4) ($) | | | Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings (5)
($) | | | All Other
Compensation
(6) ($) | | | Total ($) |
| Guy L. Piptone Senior Vice President Operations Strategy and Development | | | | | 2006 | | | | | $ | 408,193 | | | | | $ | 0 | | | | | $ | 1,024,150 | | | | | $ | 88,671 | | | | | $ | 348,996 | | | | | $ | 554,574 | | | | | $ | 17,728 | | | | | $ | 2,442,311 | |
| Richard H. Marsh Senior Vice President and Chief Financial Officer | | | | | 2006 | | | | | $ | 461,865 | | | | | $ | 0 | | | | | $ | 842,871 | | | | | $ | 123,805 | | | | | $ | 514,003 | | | | | $ | 491,772 | | | | | $ | 25,139 | | | | | $ | 2,459,456 | |
| Donald R. Schneider Senior Vice President Energy Delivery and Customer Service | | | | | 2006 | | | | | $ | 341,385 | | | | | $ | 0 | | | | | $ | 521,098 | | | | | $ | 28,835 | | | | | $ | 282,742 | | | | | $ | 202,541 | | | | | $ | 18,486 | | | | | $ | 1,395,087 | |
| Charles D. Lasky Vice President Fossil Operations and Air Quality Compliance | | | | | 2006 | | | | | $ | 257,769 | | | | | $ | 0 | | | | | $ | 232,334 | | | | | $ | 13,717 | | | | | $ | 205,051 | | | | | $ | 123,235 | | | | | $ | 27,570 | | | | | $ | 859,676 | |
| Alfred G. Roth Vice President Commodity Sourcing | | | | | 2006 | | | | | $ | 217,000 | | | | | $ | 0 | | | | | $ | 205,170 | | | | | $ | 20,272 | | | | | $ | 140,847 | | | | | $ | 58,364 | | | | | $ | 3,743 | | | | | $ | 645,396 | |
| Arthur W. Yuan Vice President Sales and Marketing | | | | | 2006 | | | | | $ | 210,000 | | | | | $ | 0 | | | | | $ | 191,893 | | | | | $ | 16,954 | | | | | $ | 134,873 | | | | | $ | 24,936 | | | | | $ | 16,264 | | | | | $ | 594,920 | |
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Table of Contents| (1) | Mr. Pipitone served as President of FES in 2006. Mr. Marsh was an employee of FirstEnergy and Chief Financial Officer of FES in 2006. Mr. Schneider served as an officer of FES until May 31, 2006. Mr. Schneider is included in this table because had he remained an officer of FES until year-end he would have been included as one of the five most highly compensated named executive officers. On June 1, 2006 Mr. Schneider, formerly Vice President Commodity Operations was named Vice President Energy Delivery of FirstEnergy. On March 1, 2007 Mr. Schneider was named Senior Vice President Energy Delivery and Customer Service of FirstEnergy. On March 1, 2007 Mr. Roth, formerly Vice President Market Intelligence and Risk Mitigation was named Vice President Commod ity Sourcing. |
| (2) | Amounts shown in the Stock Awards column include amounts from awards granted in and prior to 2006 before forfeitures and reflect the dollar amount of compensation cost recognized for financial statement reporting purposes for the fiscal year ended December 31, 2006, in accordance with the Statement of Financial Accounting Standards No. 123R, or SFAS 123R, of awards pursuant to the Plan. Compensation costs under SFAS 123R are recognized for financial reporting purposes over the period in which the employee is required to provide service in exchange for the award (typically the vesting period). Assumptions used in the calculation of these amounts are included in footnote 4 to FirstEnergy’s audited financial statements for the fiscal year ended December 31, 2006, included in FirstEnergy’s Annual Repor t on Form 10-K filed with the SEC on February 28, 2007. |
| For restricted common stock, the amounts recognized in 2006 are as follows: Pipitone—$477,770; Marsh—$1,515; Schneider—$5,438; and Lasky—$5,438. These amounts represent awards granted in and prior to 2006. These awards are not payable to the executive until the vesting date or other qualifying event shown in the 2006 Post-Termination Compensation and Benefits table described earlier in this registration statement. Mr. Schneider and Mr. Lasky’s grants issued in 2006 are described above under ‘‘—Other Equity Awards.’’ |
| For restricted stock units, the amounts recognized in 2006 are as follows: Pipitone—$102,402; Marsh—$203,106; Schneider —$130,696; Lasky—$83,662; Roth—$33,415; and Yuan—$36,470. These amounts represent awards granted in 2005 and 2006. These awards are not payable to the executive until the vesting date or other qualifying event shown in the 2006 Post-Termination Compensation and Benefits table. The actual 2006 grants are described above under ‘‘—Long-Term Incentive Program.’’ |
| For performance shares, the amounts recognized in 2006 are as follows: Pipitone—$408,572; Marsh—$591,337; Schneider—$296,105; Lasky—$131,995; Roth—$150,605; and Yuan—$133,379. These amounts represent awards granted in 2004, 2005, and 2006. These awards are not payable to the executive until the conclusion of the performance cycle or other qualifying event shown in the 2006 Post-Termination Compensation and Benefits table. The actual 2006 grants are described above under ‘‘—Long-Term Incentive Program.’’ |
| For matching contributions to the EDCP, the amounts recognized in 2006 are as follows: Pipitone—$35,406; Marsh— $46,913; Schneider—$ 88,859; Lasky—$11,239; Roth—$21,150; and Yuan—$22,044. These amounts represent the compensation cost associated with matching contributions made from 2003 to 2006. |
| (3) | FirstEnergy has not issued stock option awards since 2004. Amounts shown in the Option Awards column include amounts from awards granted in and prior to 2004 and reflect the dollar amount of compensation cost recognized for financial statement reporting purposes for the fiscal year ended December 31, 2006, in accordance with SFAS 123R of awards pursuant to the LTIP. Compensation costs under SFAS 123R are recognized for financial reporting purposes over the period in which the employee is required to provide service in exchange for the award (typically the vesting period). Assumptions used in the calculation of this amount are included in footnote 4 to FirstEnergy’s audited financial statements for the fiscal year ended December 31, 2006, included in FirstEnergy’s Annual Report on Form 10-K filed wi th the SEC on February 28, 2007. |
| (4) | The Non-Equity Incentive Plan Compensation column is comprised of the annual STIP award earned in 2006 and paid March 1, 2007. |
| (5) | The Change in Pension Value and Nonqualified Deferred Compensation Earnings column reflects the aggregate increase in actuarial value to the executive officer of all defined benefit and actuarial plans (including supplemental plans) accrued during the year and above-market earnings on nonqualified deferred compensation. The change in values for the pension plans are as follows: Pipitone—$518,196; Marsh—$436,877; Schneider—$181,093; Lasky—$118,068; Roth—$55,244; and Yuan—$20,133. The above-market earnings on compensation that are deferred on a basis that is not tax-qualified are also included in this column. The formula used to determine the above market earnings equals (2006 total interest x {difference in the 1999 Applicable Federal Rate for long-term rates (AFR) and the plan rate}) divid ed by the plan rate. The above market earnings on nonqualified deferred compensation for the named executive officers are: Pipitone—$36,378; Marsh— $54,895; Schneider—$21,448; Lasky—$5,167; Roth—$3,120 and Yuan—$4,803. |
| (6) | The All Other Compensation column includes compensation not required to be included in any other column. This includes matching company common stock contributions under the Savings Plan: Pipitone—$7,484; Marsh—$8,969; Schneider—$8,995; Lasky—$11,220; Roth—$3,743; and Yuan—$8,724. |
| In addition, certain executives are eligible to receive limited perquisites offered by FirstEnergy. In 2006, the named executives were provided: (1) financial planning and tax preparation services for Mr. Pipitone, Mr. Marsh, Mr. Schneider and Mr. Lasky; (2) country club dues for Mr. Marsh and Mr. Yuan; (3) entertainment expenses during FirstEnergy’s Board of Directors meeting for Mr. Pipitone, Mr. Schneider and Mr. Lasky; (4) the dollar value of the Executive Supplemental Life Insurance for Mr. Pipitone, Mr. Marsh and Mr. Lasky; and (5) holiday gifts for Mr. Pipitone, Mr. Marsh, Mr. Schneider and Mr. Lasky. All perquisites are valued at the invoice cost charged to FirstEnergy. |
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Table of ContentsGRANTS OF PLAN-BASED AWARDS
AS OF DECEMBER 31, 2006
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Name | | | Grant Date | | | Estimated
Future Payouts
Under Non-Equity
Incentive Plan Awards(1) | | | Estimated Future
Payouts Under Equity
Incentive Plan Awards(2) | | | All Other
Stock
Awards:
Number of
Shares of
Stock or
Units | | | All Other
Option
Awards:
Number of
Securities
Underlying
Options | | | Exercise
or Base
Price of
Option
Awards | | | Grant
Date Fair
Value of
Stock and
Option
Awards(3) |
| | | | | | | Threshold
($) | | | Target
($) | | | Maximum
($) | | | Threshold
(#) | | | Target
(#) | | | Maximum
(#) | | | (#)(2) | | | (#) | | | ($/Sh) | | | |
| Guy L. Pipitone | | | | | | | $ | 112,750 | | | | | $ | 225,500 | | | | | $ | 394,625 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 3/1/2006(4) | | | | | | | | | | | | | | | | | | | | | | | 2,474 | | | | | | 3,298 | | | | | | 4,123 | | | | | | | | | | | | | | | | | $ | 209,943 | |
| | | | 3/1/2006(5) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 534 | | | | | | | | | | | $ | 26,404 | |
| | | | 4/1/2006(6) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 3,496 | | | | | | 5,244 | | | | | | | | | | | | | | | | | $ | 256,432 | |
| Richard H. Marsh | | | | | | | $ | 152,750 | | | | | $ | 305,500 | | | | | $ | 565,175 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 3/1/2006(4) | | | | | | | | | | | | | | | | | | | | | | | 4,608 | | | | | | 6,144 | | | | | | 7,680 | | | | | | | | | | | | | | | | | $ | 391,066 | |
| | | | 3/1/2006(5) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 605 | | | | | | | | | | | $ | 29,951 | |
| | | | 3/1/2006(7) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 5,028 | | | | | | | | | | | $ | 256,026 | |
| | | | 4/1/2006(6) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 5,009 | | | | | | 7,514 | | | | | | | | | | | | | | | | | $ | 367,435 | |
| Donald R. Schneider | | | | | | | $ | 94,876 | | | | | $ | 189,750 | | | | | $ | 332,064 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 3/1/2006(4) | | | | | | | | | | | | | | | | | | | | | | | 2,082 | | | | | | 2,776 | | | | | | 3,470 | | | | | | | | | | | | | | | | | $ | 176,692 | |
| | | | 3/1/2006(5) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,232 | | | | | | | | | | | $ | 60,928 | |
| | | | 3/1/2006(7) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,916 | | | | | | | | | | | $ | 148,483 | |
| | | | 4/1/2006(6) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,941 | | | | | | 4,412 | | | | | | | | | | | | | | | | | $ | 215,747 | |
| | | | 12/19/2006(8) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 17,000 | | | | | | | | | | | $ | 1,037,340 | |
| Charles D. Lasky | | | | | | | $ | 66,250 | | | | | $ | 132,500 | | | | | $ | 231,875 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 3/1/2006(4) | | | | | | | | | | | | | | | | | | | | | | | 1,400 | | | | | | 1,866 | | | | | | 2,333 | | | | | | | | | | | | | | | | | $ | 118,796 | |
| | | | 3/1/2006(5) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 160 | | | | | | | | | | | $ | 7,894 | |
| | | | 3/1/2006(7) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,816 | | | | | | | | | | | $ | 143,391 | |
| | | | 4/1/2006(6) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,695 | | | | | | 2,543 | | | | | | | | | | | | | | | | | $ | 124,353 | |
| | | | 12/19/2006(8) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 17,000 | | | | | | | | | | | $ | 1,037,340 | |
| Alfred G. Roth | | | | | | | $ | 43,400 | | | | | $ | 86,800 | | | | | $ | 151,900 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 3/1/2006(4) | | | | | | | | | | | | | | | | | | | | | | | 819 | | | | | | 1,091 | | | | | | 1,364 | | | | | | | | | | | | | | | | | $ | 69,455 | |
| | | | 3/1/2006(5) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 304 | | | | | | | | | | | $ | 15,060 | |
| | | | 4/1/2006(6) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,156 | | | | | | 1,734 | | | | | | | | | | | | | | | | | $ | 84,793 | |
| Arthur W. Yuan | | | | | | | $ | 42,000 | | | | | $ | 84,000 | | | | | $ | 147,000 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 3/1/2006(4) | | | | | | | | | | | | | | | | | | | | | | | 792 | | | | | | 1,056 | | | | | | 1,320 | | | | | | | | | | | | | | | | | $ | 67,214 | |
| | | | 3/1/2006(5) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 318 | | | | | | | | | | | $ | 15,721 | |
| | | | 3/1/2006(7) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 704 | | | | | | | | | | | $ | 35,848 | |
| | | | 4/1/2006(6) | | | | | | | | | | | | | | | | | | | | | | | | | | 1,119 | | | | | | 1,679 | | | | | | | | | | | | | | | | | $ | 82,103 | |
| (1) | Reflects the possible payout range of the STIP. Actual awards earned in 2006 and paid March 1, 2007 are reported in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. |
| (2) | Includes dividend equivalent units and dividends earned on grants of restricted stock units, the 20% matching contribution, performance shares and restricted stock. |
| (3) | Fair market value calculation for each grant is explained below under ‘‘—Grants of Plan-Based Awards.’’ In cases where equity grants have performance factors, the highest number of shares that could be issued was used in the calculation. |
| (4) | Performance-adjusted restricted stock unit grant described above under ‘‘—Long-Term Incentive Program’’ and below under ‘‘—Grants of Plan-Based Awards.’’ |
| (5) | Represents 20% matching contribution applied to funds deferred into the EDCP stock account described above under ‘‘—Long-Term Incentive Program’’ and below under ‘‘—Nonqualified Deferred Compensation.’’ |
| (6) | Performance share grant described above under ‘‘—Long-Term Incentive Program’’ section and below under ‘‘—Grants of Plan-Based Awards.’’ |
| (7) | Discretionary restricted stock unit grant described above under ‘‘—Long-Term Incentive Program’’ and below under ‘‘—Grants of Plan-Based Awards.’’ |
| (8) | Restricted stock grant described above under ‘‘—Long-Term Incentive Program’’ and below under ‘‘—Grants of Plan-Based Awards.’’ |
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Table of ContentsGrants of Plan-Based Awards
The STIP provides awards to executives whose contributions support the achievement of corporate financial and operational goals. In 2006, target award opportunities for the named executive officers ranged from 40% of salary to 65% of salary. Awards for the short-term incentive based on operational performance range from 50% of target for performance at the threshold level to 150% of target for outstanding performance. Awards for the short-term incentive portion based on financial performance range from 50% of target for performance at threshold to a maximum of 200% of target for outstanding performance. Awards are not made if threshold performance is not achieved. Awards are mathematically interpolated for performance between threshold and maximum and no positive or negative discretion is applied to the final awards. The Compensation Committee has no authority to adjust upwards the amount payable to a covered employee with respect to a particular award.
Long-term incentive awards are awarded under the terms of the Incentive Plan. In 2006, FirstEnergy delivered long-term incentives through a combination of restricted stock units and performance shares. FirstEnergy has not issued stock options under its LTIP since 2004.
The process for allocating awards is similar for all executives. The target levels are established in February, and performance is measured throughout the cycle. In 2006, performance-adjusted restricted stock unit target award opportunities for the named executive officers ranged from 25% of salary to 65% of salary. In 2006, performance share target award opportunities for the named executive officers ranged from 25% of salary to 50% of salary.
Performance-adjusted restricted stock units are granted to all eligible executives. A restricted stock unit is equivalent to one share of FirstEnergy common stock and does not carry voting rights. Based on competitive analysis, each eligible executive received an initial grant of performance- adjusted restricted stock units, at a target level based on the executive’s annual salary as of March 1, 2006, and calculated using the average of the high and low stock price on March 1, 2006 ($50.92). These performance-adjusted restricted stock units were granted to each executive with the right to receive, at the end of the three-year restriction period, shares of FirstEnergy common stock.
The actual number of shares issued may be adjusted upward or downward by 25% based on FirstEnergy’s performance against the three key metrics described above under ‘‘—Long-Term Incentive Program.’’ The actual performance result for each of the three years during the restriction period will be averaged and compared to the average of the target level set for each performance metric as determined by the Compensation Committee. During the three-year cycle, dividends accrue on the performance-adjusted restricted stock units at the same rate paid to shareholders and convert to additional units at the end of each quarter during the restriction period. Once restrictions lapse, if applicable, the performance factor multiplier is applied to the original grant and all dividend equivalent units earned and the appropriate number of shares is purchased in the name of the executive.
Discretionary restricted stock units do not have a performance component. Dividends accrue on the discretionary restricted stock units at the same rate paid to shareholders and convert to additional units at the end of each quarter during the period of restriction. The period of restriction is five years. Once restrictions lapse, the appropriate number of shares are purchased in the name of the executive.
FirstEnergy’s performance share program provides executives with the opportunity for awards based on FirstEnergy’s total shareholder return over a three-year period relative to the EEI Index. The number of performance shares granted is calculated by multiplying the executive’s March 1 salary by the eligible incentive percent and dividing by the average high and low common stock price during December of the previous year ($48.47).
Performance shares are not actual voting shares; rather they are equivalent units, or ‘‘phantom shares,’’ which track the market performance of FirstEnergy’s common stock. During the three-year cycle, performance shares earn dividend equivalent units, applied quarterly, at the same rate paid to shareholders. If the performance factors are met, the 2006-2008 performance share grant will payout in March 2009. If FirstEnergy’s performance is below threshold (defined as the 40th percentile), no award is paid. If FirstEnergy’s performance is above the 86th percentile, awards are paid at the
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Table of Contentsmaximum of 150% of target. Awards are interpolated for performance between these two points. Performance shares typically payout in cash at the end of the performance cycle.
FirstEnergy has a restricted stock program, which is utilized solely for recruitment, retention and special recognition purposes. Award sizes, grant dates and vesting periods vary to allow flexibility. Restricted stock differs from restricted stock units in that the appropriate number of shares are purchased on the open market ($61.02 for the 2006 grants), as soon as practicable, after the date the signed restricted stock grant agreement is received. The vesting terms and conditions of restricted stock grants vary. Executives receiving restricted stock grants have full voting rights during the period of restriction. During the restriction period, dividends are earned and applied quarterly, at the same rate as shareholders. Cash dividends are converted automatically into shares and are subject to the same restrictions as the original grant. The purpose and methods of granting restricted stock, in general, and detailed information regarding Mr. Schneider and Mr. Lasky’s 2006 grants are explained further above under ‘‘—Other Equity Awards’’ and are reflected in the Summary Compensation Table.
Contributions of STIP and LTIP awards to the EDCP stock account are provided with a 20% matching contribution made by FirstEnergy. Stock units are earned on the 20% matching contribution based on the same dividend rate paid to shareholders. The number of shares associated with the 20% matching contribution is calculated by dividing the calculated 20% dollar matching contribution by the average closing price of $49.47 for the month of February 2006.
Executives are generally responsible for paying all tax obligations regarding any grant(s) received. Grants are not grossed-up by FirstEnergy to cover tax obligations unless the award is accelerated under the terms of a Special Severance Agreement (Special Severance Agreements are discussed above under ‘‘—Change in Control’’). Taxes are paid in cash for performance shares but may be paid in cash or by withholding shares for restricted stock units or EDCP share payouts. Starting with the March 1, 2007, performance-adjusted and discretionary restricted stock unit grants, FirstEnergy will require payment of taxes by selling shares on the open market. No consideration, other than services rendered, is paid by an executive when receiving a grant.
The grant date fair value of stock and option awards values are calculated in accordance with SFAS 123R as follows:
Performance shares are treated as a liability, where the value is determined by multiplying the closing price of FirstEnergy common stock on the date of grant by the number of performance shares granted. The fair market value for the April 1, 2006 grant is $48.90 per share. Performance shares values are recalculated at each financial statement reporting date, through the date the award is settled in order to reflect the market fluctuations of FirstEnergy common stock.
Performance-adjusted and discretionary restricted stock units are treated as a fixed cost, where the value is determined by multiplying the average high and low price of FirstEnergy’s common stock on the date of grant by the number of restricted stock units granted. The fair market value for the March 1, 2006 grant is $50.92 per share. Contrary to performance shares, the compensation cost associated with restricted stock units remains constant through the date the award is settled without regard to market fluctuations of FirstEnergy common stock.
The grant date fair market value for restricted stock is the purchase price plus commission paid for the restricted stock multiplied by the number of shares granted. The purpose and methods of granting restricted stock, in general, and detailed information regarding Mr. Schneider and Mr. Lasky’s 2006 grants are explained further above under ‘‘—Other Equity Awards’’ and are reflected in the Summary Compensation Table.
The shares in the EDCP are recorded as a liability. The fair market value is determined by multiplying the 20% matching contribution and all dividends earned up to December 31, 2006, by the average closing price of $49.47 for the month of February 2006.
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Table of Contents outstanding Equity Awards
AS OF DECEMBER 31, 2006
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Option Awards | | | Stock Awards |
| Name | | | Number of
Securities
Underlying
Unexercised
Options (#)
Exercisable | | | Number of
Securities
Underlying
Unexercised
Options (#)
Unexercisable(1) | | | Equity
Incentive
Plan
Awards:
Number of
Securities
Underlying
Unexercised
Unearned
Options (#) | | | Option
Exercise
Price ($) | | | Option
Expiration
Date | | | Number of
Shares or
Units of
Stock That
Have Not
Vested (#)(2)(3) | | | Market Value
of Shares or
Units of
Stock That
Have Not
Vested ($) | | | Equity
Incentive
Plan Awards:
Number of
Unearned
Shares, Units,
or Other
Rights That
Have Not
Vested (#)(2) | | | Equity
Incentive
Plan Awards:
Market or
Payout Value
of Unearned
Shares, Units,
or Other
Rights That
Have Not
Vested ($) | | | |
| Guy L. Pipitone | | | | | 35,000 | | | | | | — | | | | N/A | | | | $ | 34.45 | | | | 4/1/2012 | | | | | 37,844 | | | | | $ | 2,283,885 | | | | | | 4,094 | (4) | | | | $ | 247,073 | | | | |
| | | | | | 41,900 | | | | | | — | | | | N/A | | | | $ | 29.71 | | | | 3/1/2013 | | | | | | | | | | | | | | | | | 3,298 | (4) | | | | $ | 199,034 | | | | |
| | | | | | 28,875 | | | | | | 8,625 | | | | N/A | | | | $ | 38.76 | | | | 3/1/2014 | | | | | | | | | | | | | | | | | 6,352 | (5) | | | | $ | 383,373 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 6,533 | (6) | | | | $ | 394,260 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 5,243 | (7) | | | | $ | 316,438 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 250 | (9) | | | | $ | 15,092 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 534 | (10) | | | | $ | 32,211 | | | | |
| Richard H. Marsh | | | | | 17,500 | | | | | | — | | | | N/A | | | | $ | 34.45 | | | | 4/1/2012 | | | | | 5,028 | | | | | $ | 303,440 | | | | | | 5,438 | (4) | | | | $ | 328,183 | | | | |
| | | | | | 23,750 | | | | | | — | | | | N/A | | | | $ | 29.71 | | | | 3/1/2013 | | | | | | | | | | | | | | | | | 6,144 | (4) | | | | $ | 370,790 | | | | |
| | | | | | 38,475 | | | | | | 12,825 | | | | N/A | | | | $ | 38.76 | | | | 3/1/2014 | | | | | | | | | | | | | | | | | 9,837 | (5) | | | | $ | 593,655 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 8,676 | (6) | | | | $ | 523,626 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 7,513 | (7) | | | | $ | 453,432 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 568 | (9) | | | | $ | 34,288 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 605 | (10) | | | | $ | 36,538 | | | | |
| Donald R. Schneider | | | | | 4,000 | | | | | | — | | | | N/A | | | | $ | 29.71 | | | | 3/1/2013 | | | | | 17,260 | | | | | $ | 1,041,641 | | | | | | 3,326 | (4) | | | | $ | 200,724 | | | | |
| | | | | | 9,450 | | | | | | 4,725 | | | | N/A | | | | $ | 38.76 | | | | 3/1/2014 | | | | | 3,326 | | | | | $ | 200,724 | | | | | | 2,776 | (4) | | | | $ | 167,532 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,916 | | | | | $ | 175,981 | | | | | | 3,911 | (5) | | | | $ | 236,032 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 6,533 | (6) | | | | $ | 394,260 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 4,412 | (7) | | | | $ | 266,271 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 823 | (8) | | | | $ | 49,662 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 968 | (8) | | | | $ | 58,443 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,232 | (10) | | | | $ | 74,328 | | | | |
| Charles D. Lasky | | | | | 8,000 | | | | | | — | | | | N/A | | | | $ | 34.45 | | | | 4/1/2012 | | | | | 17,260 | | | | | $ | 1,041,660 | | | | | | 1,727 | (4) | | | | $ | 104,224 | | | | |
| | | | | | 9,400 | | | | | | — | | | | N/A | | | | $ | 29.71 | | | | 3/1/2013 | | | | | 1,713 | | | | | $ | 103,380 | | | | | | 1,866 | (4) | | | | $ | 112,613 | | | | |
| | | | | | 6,150 | | | | | | 2,050 | | | | N/A | | | | $ | 38.76 | | | | 3/1/2014 | | | | | 2,816 | | | | | $ | 169,946 | | | | | | 1,210 | (5) | | | | $ | 73,004 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,756 | (6) | | | | $ | 166,328 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,542 | (7) | | | | $ | 153,395 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 21 | (8) | | | | $ | 1,270 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 104 | (9) | | | | $ | 6,307 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 160 | (10) | | | | $ | 9,630 | | | | |
| Alfred G. Roth | | | | | 10,000 | | | | | | — | | | | N/A | | | | $ | 34.45 | | | | 4/1/2012 | | | | | | | | | | | | | | | | | 1,388 | (4) | | | | $ | 83,766 | | | | |
| | | | | | 10,875 | | | | | | — | | | | N/A | | | | $ | 29.71 | | | | 3/1/2013 | | | | | | | | | | | | | | | | | 1,091 | (4) | | | | $ | 65,842 | | | | |
| | | | | | 8,925 | | | | | | 2,975 | | | | N/A | | | | $ | 38.76 | | | | 3/1/2014 | | | | | | | | | | | | | | | | | 2,215 | (5) | | | | $ | 133,679 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,734 | (6) | | | | $ | 104,675 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,734 | (7) | | | | $ | 104,675 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 217 | (9) | | | | $ | 13,086 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 304 | (10) | | | | $ | 18,372 | | | | |
| Arthur W. Yuan | | | | | 2,975 | | | | | | — | | | | N/A | | | | $ | 29.71 | | | | 3/3/2013 | | | | | 704 | | | | | $ | 42,486 | | | | | | 1,241 | (4) | | | | $ | 74,894 | | | | |
| | | | | | 7,650 | | | | | | 2,550 | | | | N/A | | | | $ | 38.76 | | | | 3/1/2014 | | | | | | | | | | | | | | | | | 1,056 | (4) | | | | $ | 63,730 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,208 | (5) | | | | $ | 133,251 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,215 | (6) | | | | $ | 133,679 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,679 | (7) | | | | $ | 101,299 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 136 | (8) | | | | $ | 8,209 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 88 | (9) | | | | $ | 5,290 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 318 | (10) | | | | $ | 19,179 | | | | |
| (1) | Options with an exercise price of $38.76 vest on March 1, 2008. Options vested March 1, 2007 but not vested December 31, 2006 are included in the Number of Securities Underlying Unexercised Options Exercisable column. |
| (2) | Includes dividends and dividend equivalent units earned through December 31, 2006. |
| (3) | Vesting dates for restricted stock or discretionary restricted stock units are as follows: Mr. Pipitone’s restricted stock grant vests on September 20, 2007; Mr. Marsh and Mr. Yuan’s discretionary restricted stock units vest on March 1, 2011; |
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Table of Contents | Mr. Schneider and Mr. Lasky’s restricted stock grants vest 50% on December 19, 2011 and 50% on December 19, 2016; and Mr. Schneider and Mr. Lasky’s discretionary restricted stock units vest on March 1, 2010 and March 1, 2011. The market value is based on FirstEnergy common stock closing price $60.35 on December 31, 2006. |
| (4) | Performance-adjusted restricted stock units were granted March 1, 2005 and March 1, 2006, respectively. The March 1, 2005 grant will pay out on March 1, 2008 based on FirstEnergy’s performance from 2005-2007. The projected payout value shown represents target. |
| (5) | Performance shares granted in 2004 for the 2004-2006 performance cycle which vested December 31, 2006. The performance measures for this grant were achieved and paid out at the maximum level (150%) on March 1, 2007. |
| (6) | Performance shares granted in 2005 for the 2005-2007 performance cycle which vest December 31, 2007 shown at the estimated maximum payout value of 150%. |
| (7) | Performance shares granted in 2006 for the 2006-2008 performance cycle which vest December 31, 2008 shown at the estimated maximum payout value of 150%. |
| (8) | Represents 20% matching contribution on funds deferred into the EDCP stock account in 2004 which vested on March 1, 2007. |
| (9) | Represents 20% matching contribution on funds deferred into the EDCP stock account in 2005 which vests on March 1, 2008. |
| (10) | Represents 20% matching contribution on funds deferred into the EDCP stock account in 2006 which vests on March 1, 2009. |
option exercises and STOCK VESTED
AS OF DECEMBER 31, 2006
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Option Awards | | | Stock Awards |
| Name | | | Number of Shares
Acquired on Exercise
(#) | | | Value Realized on
Exercise
($) | | | Number of Shares
Acquired on Vesting
(1)(#) | | | Value Realized on
Vesting
($) |
| Guy L. Pipitone | | | | | | | | | | | | | | | | | 4,235 | (4) | | | | $ | 255,582 | |
| | | | | | | | | | | | | | | | | | 2,669 | (5) | | | | $ | 132,021 | |
| Richard H. Marsh(2) | | | | | 20,625 | | | | | $ | 359,063 | | | | | | 1,167 | (3) | | | | $ | 57,942 | |
| | | | | | | | | | | | | | | | | | 6,558 | (4) | | | | $ | 395,770 | |
| | | | | | | | | | | | | | | | | | 3,027 | (5) | | | | $ | 149,756 | |
| Donald R. Schneider(2) | | | | | 11,725 | | | | | $ | 185,813 | | | | | | 2,607 | (4) | | | | $ | 157,354 | |
| | | | | | | | | | | | | | | | | | 6,158 | (5) | | | | $ | 304,639 | |
| Charles D. Lasky(2) | | | | | 6,000 | | | | | $ | 141,120 | | | | | | 806 | (4) | | | | $ | 48,669 | |
| | | | | | | | | | | | | | | | | | 798 | (5) | | | | $ | 39,470 | |
| Alfred G. Roth | | | | | | | | | | | | | | | | | 1,715 | (4) | | | | $ | 103,472 | |
| | | | | | | | | | | | | | | | | | 1,522 | (5) | | | | $ | 75,301 | |
| Arthur W. Yuan | | | | | 4,975 | | | | | $ | 112,913 | | | | | | 1,472 | (4) | | | | $ | 88,834 | |
| | | | | | | | | | | | | | | | | | 1,589 | (5) | | | | $ | 78,606 | |
| (1) | Includes dividends earned through December 31, 2006. |
| (2) | In accordance with established 10b5-1 plans, Mr. Marsh exercised options on April 3, 2006, Mr. Schneider on March 1, 2006, and April 3, 2006, and Mr. Lasky on May 16, 2006. Mr. Yuan exercised options on May 9, 2006 and August 31, 2006. |
| (3) | Restricted stock grant vested on February 20, 2006. |
| (4) | Performance shares for the 2004-2006 performance cycle vested on December 31, 2006 and paid out in cash on March 1, 2007. The dollar amount reflects the fair market value of $60.35 on the date of vesting and the maximum payout value of 150%. The performance shares were paid as follows: Mr. Pipitone—$383,372, none of which was deferred into the EDCP stock account; Mr. Marsh—$593,655, of which $558,036 was deferred into the EDCP stock account; Mr. Schneider—$236,032, of which $219,510 was deferred into the EDCP stock account; Mr. Lasky—$73,004, of which none was deferred into the EDCP stock account; Mr. Roth— $155,209, of which $38,802 was deferred into the EDCP stock account; and Mr. Yuan—$133,250, of which $121,258 was deferred into the EDC P stock. |
| (5) | Represents funds deferred in 2006 to the EDCP stock account described above under ‘‘—Nonqualified Deferred Compensation.’’ These funds are converted to shares based on the closing stock price on March 1, 2006 ($49.47) and are fully vested. The 20% matching contribution applied to the deferral is not included, as these shares are not vested for three years. |
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Table of Contents Pension Benefits
AS OF DECEMBER 31, 2006
Pension Benefits
| | | | | | | | | | | | | | | | | | | | | |
| Name | | | Plan Name | | | Number of
Years
Credited
Service
(#) | | | Present Value of
Accumulated
Benefit
($)(1) | | | Payments
During Last
Fiscal Year
($) |
| Guy L. Pipitone | | | Qualified Plan | | | | | 33 | | | | | $ | 1,060,506 | | | | | $ | 0 | |
| | | | Nonqualified (Supplemental) Plan | | | | | | | | | | $ | 1,719,840 | | | | | $ | 0 | |
| | | | Supplemental Executive Retirement Plan | | | | $ | 103,201 | | | | | $ | 0 | |
| | | | Total | | | | | | | | | | $ | 2,883,547 | | | | | | | |
| Richard H. Marsh | | | Qualified Plan | | | | | 26 | | | | | $ | 835,249 | | | | | $ | 0 | |
| | | | Nonqualified (Supplemental) Plan | | | | | | | | | | $ | 1,599,588 | | | | | $ | 0 | |
| | | | Supplemental Executive Retirement Plan | | | | $ | 380,082 | | | | | $ | 0 | |
| | | | Total | | | | | | | | | | $ | 2,814,919 | | | | | | | |
| Donald R. Schneider | | | Qualified Plan | | | | | 24 | | | | | $ | 307,343 | | | | | $ | 0 | |
| | | | Nonqualified (Supplemental) Plan | | | | | | | | | | $ | 543,289 | | | | | $ | 0 | |
| | | | Supplemental Executive Retirement Plan | | | | $ | 0 | | | | | $ | 0 | |
| | | | Total | | | | | | | | | | $ | 850,632 | | | | | | | |
| Charles D. Lasky | | | Qualified Plan | | | | | 20 | | | | | $ | 286,973 | | | | | $ | 0 | |
| | | | Nonqualified (Supplemental) Plan | | | | | | | | | | $ | 174,687 | | | | | $ | 0 | |
| | | | Supplemental Executive Retirement Plan | | | | $ | 0 | | | | | $ | 0 | |
| | | | Total | | | | | | | | | | $ | 461,660 | | | | | | | |
| Alfred G. Roth | | | Qualified Plan | | | | | 5 | | | | | $ | 178,770 | | | | | $ | 0 | |
| | | | Nonqualified (Supplemental) Plan | | | | | | | | | | $ | 42,691 | | | | | $ | 0 | |
| | | | Supplemental Executive Retirement Plan | | | | $ | 0 | | | | | $ | 0 | |
| | | | Total | | | | | | | | | | $ | 221,461 | | | | | | | |
| Arthur W. Yuan | | | Qualified Plan | | | | | 6 | | | | | $ | 139,057 | | | | | $ | 0 | |
| | | | Nonqualified (Supplemental) Plan | | | | | | | | | | $ | 28,141 | | | | | $ | 0 | |
| | | | Supplemental Executive Retirement Plan | | | | $ | 0 | | | | | $ | 0 | |
| | | | Total | | | | | | | | | | $ | 167,198 | | | | | | | |
| (1) | The Present Value of Accumulated Benefit is determined as of December 29, 2006, using the following assumptions: discount rate of 6%, the RP-2000 Combined Healthy Life Mortality Table, and retirement at the earliest unreduced retirement ages as defined later. The calculations for all pension benefits are based on current base and incentive compensation and do not consider salary increases. |
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Pension Benefits
Qualified and Nonqualified Plans
FirstEnergy offers a Qualified and Nonqualified Plan to all of the named executive officers. FirstEnergy pays the entire costs of these plans. Payments from the Qualified Plan are maximized considering base salary earnings and the applicable federal and plan limits. The Nonqualified Plan is designed to provide a comparable benefit to the executive without restrictions of federal and plan limits and as a method to provide a competitive retirement benefit. The pension benefit from the Qualified and Nonqualified Plans provided to the named executive officers is the greater benefit determined using the following two formulas:
| | |
| 1. | Career Earnings Benefit Formula: A fixed (2.125%) factor is applied to the executive’s total career earnings to determine the accrued (age 65) career earnings benefit. Career earnings generally include base salary, overtime pay, shift premiums, annual incentive awards and other similar compensation. |
| | |
| 2. | Adjusted Highest Average Monthly Base Earnings Benefit Formula: The benefit is equal to the sum of A and B where A is the highest average monthly base earnings, or HAMBE, times the sum of: |
| | |
| • | 1.58% times the first 20 years of benefit service; |
| | |
| • | 1.18% times the next 10 years of benefit service; |
| | |
| • | 78% times the next 5 years of benefit service; and |
| | |
| • | 1.10% times each year of benefit service in excess of 35 years. |
and B is an amount equal to 0.32% times number of years of service (up to 35 years) times the greater of the difference between the highest average monthly base earnings and the lesser of 150% of covered compensation or the Social Security Wage Base, and zero.
The HAMBE for the Qualified Plan are the highest 48 consecutive months of base earnings the executive had in the 120 months before retirement or other separation of employment. Base earnings are the employee’s straight time rate of pay without overtime, deferred compensation, incentive compensation, other awards, or accrued or unused vacation paid at termination. The HAMBE for the Nonqualified Plan are the same as the Qualified Plan described above except that incentive and deferred compensation are included. Covered compensation is the average (without indexing) Social Security Taxable Wage Base in effect for each calendar year during the 35-year period that ends when the executive reaches the Social Security normal retirement age.
According to the FirstEnergy Pension Plan, or Pension Plan, which also covers FES, normal retirement is at age 65, and the earliest retirement is at age 55 if the employee has at least ten years of credited service. Mr. Pipitone and Mr. Marsh currently are eligible for a reduced pension benefit based on the Early Retirement Reduction Table below. Mr. Schneider, Mr. Lasky and Mr. Yuan do not meet the age requirement, and Mr. Roth does not meet the service requirement for retirement. The earliest retirement age without reduction for the Qualified and Supplemental Plans is age 60 for Mr. Pipitone, Mr. Marsh, Mr. Schneider, Mr. Lasky and Mr. Yuan and age 64 for Mr. Roth.
Mr. Pipitone has a Special Severance Agreement for change in control which would credit him with two additional years of age and service for the purposes of the nonqualified benefit calculations. Mr. Marsh also has a Special Severance Agreement for change in control which would credit him with three additional years of age and service for the purposes of the nonqualified benefit calculations.
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Early Retirement Reduction Table
| | | | | | |
If payment
begins at age... | | | The benefit is
multiplied by... |
| 60 and up | | | | | 100 | % |
| 59 | | | | | 88 | % |
| 58 | | | | | 84 | % |
| 57 | | | | | 80 | % |
| 56 | | | | | 75 | % |
| 55 | | | | | 70 | % |
The accrued benefits vest upon the completion of 5 years of service. The benefits generally are payable in the case of a married executive in the form of a qualified spouse 50% joint and survivor annuity or in the case of an unmarried executive in the form of a single life annuity. There is also an option to receive the benefit as a joint and survivor annuity with or without a pop-up provision or a period certain annuity. A pop-up provision in an annuity provides a reduced monthly benefit, payable to the executive until death. Upon death, the executive’s named beneficiary will receive 25%, 50%, 75% or 100 % of the executive’s benefit based on the executive and the beneficiary’s age and the percentage to be continued after the executive’s death. However, if the beneficiary predeceases the executive, the monthly payment ‘‘pops-up’’ to the payment which would have been payable as a single life annuity.
Supplemental Executive Retirement Plan
In addition to the Qualified and Nonqualified Plans, Mr. Pipitone and Mr. Marsh are also eligible to receive an additional nonqualified benefit from the SERP. The earliest retirement age without reduction for the SERP is age 65. Mr. Schneider, Mr. Lasky, Mr. Roth and Mr. Yuan are not participants in the SERP. The SERP is also discussed above under ‘‘—Retirement.’’
An executive participating in the SERP shall be eligible to receive a supplemental benefit after termination of employment due to retirement, death, disability or involuntary separation that directly is related to either the executive’s: (a) average of the highest 12 consecutive full months of base salary earnings paid to the executive in the 120 consecutive full months prior to termination of employment, including any salary deferred in the EDCP or the Savings Plan, or (b) average of the highest 36 consecutive full months of base salary earnings and annual incentive awards paid to the executive in the 120 consecutive full months prior to termination of employment, including any salary and annual incentive awards deferred into the EDCP and Savings Plan.
A supplemental benefit under the SERP will be determined in accordance with and shall be non-forfeitable upon the date the executive terminates employment under the conditions described in the following sections:
Retirement Benefit—
An executive retiring from FirstEnergy on or after age 55 who has completed 10 years of service will be entitled to receive, commencing at retirement, a monthly supplemental retirement benefit under the SERP equal to 65% of (a) above or 55% of (b) above, whichever is greater, multiplied by the number of months of service the executive has completed after having completed 10 years of service, up to a maximum of 60 months, divided by 60, 1ess:
| | |
| i) | The monthly primary Social Security benefit to which the executive may be entitled at such retirement (or the projected age 62 benefit if retirement occurs prior to age 62), irrespective of whether the executive actually receives such benefit at the time of retirement, and |
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| | |
| ii) | The monthly early, normal or deferred retirement income benefit to which the executive may be entitled at such retirement under the Pension Plan, the monthly supplemental pension benefit under the EDCP and the monthly benefit, or actuarial equivalent, under the pension plans of previous employers, all calculated by an actuary selected by FirstEnergy, with the following assumptions based on the executive’s marital status at the time of such retirement: |
| | |
| • | In the case of a married executive, in the form of a 50% joint and survivor annuity. |
| | |
| • | In the case of an unmarried executive, in the form of a single-life annuity. |
For an executive who retires prior to attaining age 65, the net dollar amount above shall be further reduced by one-fourth of 1% for each month the commencement of benefits under the SERP precedes the month the executive attains age 65.
Death Benefit—
If the executive dies, 50% of the executive’s supplemental retirement benefit actuarially adjusted for the executive and spouse’s ages will be paid to the executive’s surviving spouse. Payment will begin the month following death and continue for the remainder of the surviving spouse’s life. For an executive who dies prior to attaining age 65, the benefit shall be reduced further by one-fourth of 1% for each month the commencement precedes the executive’s age 65, with a maximum of 30%.
Disability Benefit—
An executive terminating employment due to a disability may be entitled to receive, commencing at disability, a monthly supplemental retirement benefit under the SERP equal to 65% of (a) above or 55% of (b) above, whichever is greater, less disability benefits from:
| | |
| c) | the long-term disability plan; and |
The disability benefit continues until the executive attains age 65, retires from FirstEnergy, dies, or is no longer disabled, whichever occurs first. Upon retirement, benefits are calculated as described above under ‘‘—Retirement Benefits.’’ In the event of death, benefits are calculated as described above under ‘‘—Death Benefit.’’
NONqualified Deferred Compensation
AS OF DECEMBER 31, 2006
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Name | | | Executive
Contributions in
Last FY(1)
($) | | | Registrant
Contributions in
Last FY(2)
($) | | | Aggregate
Earnings in Last
FY(1)(3)
($) | | | Aggregated
Withdrawals/
Distributions(4)
($) | | | Aggregate
Balance at
Last FYE
($) |
| Guy L. Pipitone | | | | $ | 338,917 | | | | | $ | 25,783 | | | | | $ | 190,762 | | | | | $ | 0 | | | | | $ | 2,023,274 | |
| Richard H. Marsh | | | | $ | 443,151 | | | | | $ | 29,247 | | | | | $ | 468,076 | | | | | $ | 0 | | | | | $ | 3,903,075 | |
| Donald R. Schneider | | | | $ | 468,446 | | | | | $ | 59,495 | | | | | $ | 277,872 | | | | | $ | 0 | | | | | $ | 2,041,418 | |
| Charles D. Lasky | | | | $ | 106,971 | | | | | $ | 7,708 | | | | | $ | 40,079 | | | | | $ | 0 | | | | | $ | 370,084 | |
| Alfred G. Roth | | | | $ | 133,948 | | | | | $ | 14,706 | | | | | $ | 50,863 | | | | | $ | 16,524 | | | | | $ | 356,315 | |
| Arthur W. Yuan | | | | $ | 158,233 | | | | | $ | 15,351 | | | | | $ | 60,426 | | | | | $ | 0 | | | | | $ | 456,071 | |
| (1) | Executive contributions include the deferral of base salary and STIP and LTIP program payments, as follows: Pipitone—$81,696 from 2006 base salary, $128,304 from the STIP deferred in 2006, and $128,917 from the 2003-2005 performance share cycle award deferred in 2006; Marsh—$155,789 from 2006 base salary, $141,127 from 2005 STIP deferred in 2006 and $146,235 from the 2003-2005 performance share cycle award deferred in 2006; Schneider—$170,970 from 2006 base salary, $192,111 from 2005 STIP deferred in 2006, and $105,365 from the 2003-2005 performance share cycle award deferred in 2006; Lasky—$39,151 from 2006 base salary, $29,278 from 2005 STIP deferred in 2006, and $38,542 from the 2003-2005 performance share cycle award deferred in 2006; Roth—$39,078 from 2006 base salary, $21,339 from 200 5 STIP deferred in 2006, and $73,531 from the 2003-2005 performance share cycle award deferred in 2006; and |
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| Yuan—$28,280 from 2006 base salary, $53,196 from 2005 STIP deferred in 2006, and $76,757 from the 2003-2005 performance share cycle award deferred in 2006. The executive contributions from 2006 base salary are also included in the Salary column of the current year Summary Compensation Table. Deferrals of 2006 STIP and the 2004-2006 performance share cycle award deferred in 2007 are not included in the above Nonqualified Deferred Compensation table, but are as follows: Pipitone—$174,498 from 2006 STIP; Marsh—$483,163 from 2006 STIP and $558,036 from the 2004-2006 performance share cycle award; Schneider—$265,777 from 2006 STIP and $219,510 from the 2004-2006 performance share cycle award; Lasky—$41,010 from 2006 STIP ; Roth—70,424 from 2006 STIP and $38,802 from the 2004-2006 performance sh are cycle award; and Yuan—$94,411 from 2006 STIP and $121,258 from the 2004-2006 performance share cycle award. |
| (2) | Registrant contributions include 20% company matching contributions on 2005 earned incentives which were deferred in 2006 as follows: Pipitone—$25,783; Marsh—$29,247; Schneider—$59,495; Lasky—$7,708; Roth—$14,706; and Yuan—$15,351. Registrant contributions of the 20% company matching contributions on the 2006 earned incentives reported in the Stock Awards column of the current year Summary Compensation Table and deferred in 2007 are not included in the above Nonqualified Deferred Compensation table but are as follows: Pipitone—none ; Marsh—$111,607; Schneider— $97,057 ; Lasky—none; Roth—$14,803; and Yuan—$33,693. |
| (3) | The compounded annual rate of return on cash accounts was 8.63%. The compounded annual rate of return on stock accounts was 27.2% which includes both dividends and appreciation. The Aggregate Earnings and Aggregate Balance columns include above-market earnings which have been reported in the Change in Pension Value and Nonqualified Deferred Compensation Earnings column of the current year Summary Compensation Table as follows: Pipitone—$36,378; Marsh—$54,895; Schneider—$21,448; Lasky—$5,167; Roth—$3,120; and Yuan—$4,803. |
| (4) | At the time of deferral, participants may elect to receive Stock Accounts at the close of the three-year vesting period or at termination of employment. Aggregated withdrawals and distributions included the distribution of the vested 2003 Stock Accounts in the form of FirstEnergy stock at the end of the three-year vesting period, as follows; Pipitone—none; Marsh —none; Schneider—none; Lasky—none; Roth—$16,524; and Yuan—none. |
Nonqualified Deferred Compensation
The EDCP is a nonqualified defined contribution plan which provides for the voluntary deferral of compensation. Participants may defer up to 50% of base salary, up to 100% of short-term incentive compensation, and up to 100% of cash long-term incentive compensation. Participation in the EDCP is limited to management employees of FirstEnergy.
Two investment options are available under the EDCP. Participants may direct deferrals of base salary and short-term incentive compensation to an annual cash retirement account, which accrues interest. Participants may direct deferrals of short-term incentive compensation and long-term incentive compensation to an annual stock account.
Interest is credited to the retirement accounts. The interest rate changes annually and is based upon the Moody’s Corporate Bond Index rate plus three percentage points.
The stock accounts are tracked in stock units and accrue additional stock units based on the same dividend rate paid to shareholders. The stock accounts are valued at the fair market value of FirstEnergy’s common stock. Contributions to the stock accounts are provided with a 20% matching contribution made by FirstEnergy. Stock units are earned on the 20% matching contribution based on the same dividend rate paid to shareholders. The number of shares associated with the 20% matching contribution is calculated by dividing the calculated 20% dollar matching contribution by the average closing price of $49.47 for the month of February 2006.
The participant’s contribution and additional dividend units are vested immediately; FirstEnergy’s 20% matching contributions and additional dividend units thereon vest at the end of a three-year period and are subject to forfeiture prior to the conclusion of that vesting period. These shares can be further deferred into a retirement stock account. A matching contribution is not applied to shares further deferred into the retirement stock account. Participants may elect to receive payments from the retirement accounts in any combination of lump sum payment and/or monthly installment payments for up to 25 years, provided that the account balance is at least $100,000. Differing distribution elections may be made for retirement, disability and pre-retirement death. In the event of involuntary severance prior to retirement eligibility, the account will be paid in a single lump sum payment or, for accounts grandfathered and not subject to Code Sectio n 409A, in either a lump sum payment or in three annual installments at the participant’s previously established election. Payments may not commence until termination of employment.
There is no in-service withdrawal option for retirement accounts which are subject to Code Section 409A. Amounts that were vested as of December 31, 2004, are available for an in-service withdrawal of the full grandfathered account, subject to a 10% penalty.
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Stock account distributions are limited to a lump sum payment in the form of FirstEnergy common stock at the end of the three-year company match vesting period, or to a further deferral until termination. If further deferred until termination, the account will be converted to cash, based upon the fair market value of the account at termination, and the balance will be rolled over to the corresponding annual cash retirement account for distribution in lump sum or monthly installments as elected under the cash retirement account.
The 20% matching contribution shares received by our named executive officers, and all dividends earned through December 31, 2006, are reported on the Grants of Plan-Based Awards table under the All Other Stock Awards: Number of Shares of Stock or Units column.
Stock paid out on March 1, 2006, or further deferred into the retirement stock account in 2006 is valued at $51.00, the closing price on March 1, 2006. No named executive officer elected to receive a payout of their EDCP deferred stock account in 2006.
Potential Post-Employment Payments
The 2006 Post-Termination Compensation and Benefits table above describes the treatment of all elements of compensation in the event of a retirement/voluntary termination, severance (absent a change in control), change in control, death or disability. The amounts shown in the following tables do not include payments and benefits to the extent they are provided on a non-discriminatory basis to salaried employees generally upon termination of employment.
The post-termination calculations are based on the following assumptions:
| | |
| • | The amounts disclosed are estimates of the amounts which would be paid out to the executives upon their termination. The actual amounts paid can be determined only at the time of such executive’s separation from FirstEnergy; |
| | |
| • | December 29, 2006, is the date of termination; |
| | |
| • | The STIP award is based on 2006 performance and payable March 1, 2007; |
| | |
| • | The LTIP award includes stock options, performance shares, performance-adjusted and discretionary restricted stock units and restricted stock; |
| | |
| • | The closing common stock price for the month of December 2006: $60.30; applied to value stock options, restricted stock units and restricted stock; |
| | |
| • | The average high/low common stock price for the month of December 2006: $60.81; applied to value performance shares (2005-2007 and 2006-2008 cycles); |
| | |
| • | The average high/low common stock price for December 29, 2006: $60.35; applied to value performance shares (2004-2006 cycle); and |
| | |
| • | Total shareholder return factors of 150% for both the 2004-2006 and 2005-2007 performance share cycles and 126.47% for the 2006-2008 performance share cycle. |
Retirement/Voluntary Termination
Mr. Pipitone (56) and Mr. Marsh (55) are currently eligible for early retirement at or above age 55 with ten years of credited service. The earliest retirement age without reduction is age 60 for Mr. Pipitone, Mr. Marsh, Mr. Schneider, Mr. Lasky and Mr. Yuan and age 64 for Mr. Roth. Normal retirement age is 65. Mr. Schneider (45), Mr. Lasky (44), Mr. Roth (59) and Mr. Yuan (49) are not eligible for retirement in 2006 as Mr. Schneider, Mr. Lasky and Mr. Yuan do not meet the minimum age requirement, and Mr. Roth does not meet the service requirement. In the event of a retirement/voluntary termination, the named executive officers would not be entitled to any additional benefits generally not available to all salaried employees.
Severance
All named executive officers are covered under FirstEnergy’s Executive Severance Benefits Plan. For the purposes of the plan, executives are offered severance benefits if involuntarily separated when
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business conditions require the closing of a facility, corporate restructuring, a reduction in workforce or job elimination. Severance is also offered if an executive rejects a job assignment that would result in a reduction in current base pay, contain a requirement that the executive must relocate his/her current residence for reasons related to the new job, or result in a daily commute from the executive’s current residence to a new reporting location of more than one hour each way and that is more than 30 minutes longer than the executive’s present commute.
Severance (Absent a change in control)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Severance(1) | | | Short-Term
Incentive
Plan Award | | | Incremental
Pension
Benefit
(present
value) | | | Accelerated
Long-Term
Incentive
Program
Award(2) | | | Health
Care | | | Total |
| Guy L. Pipitone | | | | $ | 402,104 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 402,104 | |
| Richard H. Marsh | | | | $ | 352,498 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 352,498 | |
| Donald R. Schneider | | | | $ | 238,853 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 653,613 | | | | | $ | 0 | | | | | $ | 892,465 | |
| Charles D. Lasky | | | | $ | 152,880 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 294,142 | | | | | $ | 0 | | | | | $ | 447,022 | |
| Alfred G. Roth | | | | $ | 185,701 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 327,653 | | | | | $ | 0 | | | | | $ | 513,354 | |
| Arthur W. Yuan | | | | $ | 173,654 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 289,555 | | | | | $ | 0 | | | | | $ | 463,210 | |
| Mr. Pipitone, Mr. Marsh, Mr. Schneider, Mr. Lasky, Mr. Roth and Mr. Yuan shall be provided the following severance benefits generally not available to all salaried employees: |
| (1) | An additional one and one-half weeks’ base pay for each full year of credited service. For the purposes of the severance plan the number of full years of credited service will be equal to the number of whole years of credited service under the Pension Plan(s) as of January 1 of the year involuntarily severed plus the current year. The minimum severance amount is 52 weeks’ base pay. |
| Mr. Pipitone and Mr. Marsh are retirement eligible and would receive benefits available in retirement irrespective of a severance. Therefore, there is no incremental value represented in the table for these benefits. Mr. Schneider, Mr. Lasky, Mr. Roth and Mr. Yuan shall be provided the following severance benefits generally not available to all salaried employees: |
| (2) | Mr. Schneider, Mr. Lasky, Mr. Roth and Mr. Yuan will receive Accelerated Long-Term Incentive Program and Other Equity Awards payable as follows: |
| • | Performance shares granted in 2004 are prorated based on the number of full months in the performance cycle with a minimum of 12 months to be eligible. The amounts shown are calculated by multiplying the accelerated number of shares by the total shareholder return factor (150%) by the average of the high and low common stock price on the last trading day of the three-year performance cycle ($60.35). The incremental benefit is as follows: Schneider —$236,032; Lasky—$73,004; Roth—$155,209; and Yuan—$133,250. |
| • | Performance shares granted in 2005 and 2006 are prorated based on the number of full months in the performance cycle with a minimum of 12 months to be eligible. The amounts shown are calculated by multiplying the accelerated number of shares by the December 31, 2006, estimated total shareholder return factors (150% and 126.47% for 2005 and 2006, respectively) by the average of the high and low common stock price for the thirty days prior to the date of termination ($60.81) The incremental benefit is as follows: Schneider—$290,589; Lasky—$155,170; Roth—$119,441; and Yuan—$108,909. |
| • | Performance-adjusted restricted stock units are prorated based on the number of full months in the restriction period with a minimum of 12 months to be eligible. The amounts shown are calculated by multiplying the number of accelerated restricted stock units by the closing price of FirstEnergy’s common stock on December 29, 2006 ($60.30). The incremental benefit is as follows: Schneider—$126,992; Lasky—$65,968; Roth—$53,004; and Yuan—$47,396. |
Change in Control
FirstEnergy executed agreements consistent with competitive practice with Mr. Pipitone on March 7, 2005 and Mr. Marsh on December 31, 2003. Mr. Schneider, Mr. Lasky, Mr. Roth and Mr. Yuan do not have Special Severance Agreements.
Generally, pursuant to the Special Severance Agreements, a change in control is deemed to occur:
(1) if any person acquires 50% or more of FirstEnergy’s voting securities (or 25% or more of FirstEnergy’s voting securities if such person proposes any individual for election to FirstEnergy’s Board of Directors or such person already has a representative on FirstEnergy’s Board of Directors), excluding acquisitions (i) directly from FirstEnergy, (ii) by FirstEnergy, (iii) by certain employee benefit plans, and (iv) pursuant to a transaction meeting the requirements of item (3) below; or
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(2) if a majority of FirstEnergy’s directors as of the date of the Special Severance Agreement are replaced (other than in specified circumstances); or
(3) upon the consummation of a reorganization, merger, consolidation, sale or other disposition of all or substantially all of FirstEnergy’s assets, unless, following such transaction:
(a) the same person or persons who owned FirstEnergy’s voting securities prior to the transaction own more than 75% of FirstEnergy’s voting securities in the same proportions as their ownership prior to the transaction,
(b) no person or entity (with certain exceptions) owns 25% or more of FirstEnergy’s voting securities, and
(c) at least a majority of the directors resulting from the transaction were directors at the time of the execution of the agreement providing for such transaction; or
(4) if the shareholders of FirstEnergy approve a complete liquidation or dissolution of FirstEnergy.
The change in control severance benefits are triggered only when the individual is terminated without cause or resigns for good reason. Good reason is defined as a material change, following a change in control, inconsistent with the individual’s previous job duties or compensation. The following table was prepared as though the named executive officers’ employment was terminated following the change in control.
Change in Control (Resigns for Good Reason)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Severance(1) | | | Short-Term
Incentive
Program
Award(2) | | | Incremental
Pension
Benefit
(present
value)(3) | | | Accelerated
Long-Term
Incentive
Program
Award and
Other Equity
Awards(4) | | | Section 280G
Gross-up(5) | | | Health
Care(6) | | | Total |
| Guy L. Pipitone | | | | $ | 1,499,723 | | | | | $ | 0 | | | | | $ | 615,738 | | | | | $ | 3,489,906 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 5,605,367 | |
| Richard H. Marsh | | | | $ | 1,930,371 | | | | | $ | 0 | | | | | $ | 415,506 | | | | | $ | 2,037,307 | | | | | $ | 1,317,611 | | | | | $ | 39,800 | | | | | $ | 5,740,595 | |
| Donald R. Schneider | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 2,905,447 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 2,905,447 | |
| Charles D. Lasky | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 2,008,146 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 2,008,146 | |
| Alfred G. Roth | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 753,902 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 753,902 | |
| Arthur W. Yuan | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 622,997 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 622,997 | |
Change in Control (Discharged Without Cause/Severed)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Severance(1) | | | Short-Term
Incentive
Program
Award(2) | | | Incremental
Pension
Benefit
(present
value)(3) | | | Accelerated
Long-Term
Incentive
Program
Award and
Other Equity
Awards(4) | | | Section
280G
Gross-up(5) | | | Health
Care(6) | | | Total |
| Guy L. Pipitone | | | | $ | 1,499,723 | | | | | $ | 0 | | | | | $ | 615,738 | | | | | $ | 3,489,906 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 5,605,367 | |
| Richard H. Marsh | | | | $ | 1,930,371 | | | | | $ | 0 | | | | | $ | 415,506 | | | | | $ | 2,037,307 | | | | | $ | 1,317,611 | | | | | $ | 39,800 | | | | | $ | 5,740,595 | |
| Donald R. Schneider | | | | $ | 238,853 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 2,905,447 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 3,144,299 | |
| Charles D. Lasky | | | | $ | 152,880 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 2,008,146 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 2,161,026 | |
| Alfred G. Roth | | | | $ | 185,701 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 753,902 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 939,603 | |
| Arthur W. Yuan | | | | $ | 173,654 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 622,997 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 796,651 | |
| If, within a period of thirty-six full calendar months after a change in control of FirstEnergy, the named executive officer is discharged without cause or resigns for good reason they shall be entitled to the following payments that generally are not available to all salaried employees: |
| (1) | An amount equal to 2.00 multiplied by the sum of the amount of annual base salary at the rate in effect as of the date of termination plus the target annual incentive award whether or not fully paid for Mr. Pipitone—$1,494,243. An amount equal to 2.99 multiplied by the sum of the amount of annual base salary at the rate in effect as of the date of termination plus the average three previous years incentive awards paid for Mr. Marsh—$1,916,371. An additional lump sum cash |
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| payment as follows: Pipitone—$5,480 and Marsh—$14,000. This amount is included in the severance column. In the event of a resignation for good reason after a change in control, Mr. Schneider, Mr. Lasky, Mr. Roth and Mr. Yuan would not be entitled to severance pay. If Mr. Schneider, Mr. Lasky, Mr. Roth and Mr. Yuan were discharged without cause after a change in control they would be entitled to severance pay based on the terms of FirstEnergy’s Executive Severance Benefits Plan. |
| (2) | Mr. Pipitone and Mr. Marsh are retirement eligible and would receive the short-term incentive award irrespective of a change in control. In the event of a resignation for good reason Mr. Schneider, Mr. Lasky, Mr. Roth and Mr. Yuan would forfeit the short-term incentive award. In the event of a discharge without cause, the above named executive officers would receive a prorated portion of the short-term incentive award similar to all salaried employees. There is no incremental benefit. |
| (3) | The Incremental Pension Benefit is the increased benefit provided to the named executive officer as a result of a change in control based on the terms of the Special Severance Agreements. |
| (4) | Accelerated Long-Term Incentive Program and Other Equity Awards are payable as follows: |
| • | Unvested stock options become immediately exercisable. The amounts shown are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of FirstEnergy’s common stock on December 29, 2006 ($60.30). Pipitone—$691,995; Marsh—$915,757; Schneider—$325,913; Lasky—$160,201; Roth—$239,052; and Yuan—$109,854. |
| • | Performance shares granted in 2004 are prorated based on the number of full months in the performance cycle with a minimum of 12 months to be eligible. The amounts shown are calculated by multiplying the accelerated number of shares by the total shareholder return factor (150%) by the average of the high and low common stock price on the last trading day of the three-year performance cycle ($60.35). The incremental benefit is as follows: Schneider —$236,032; Lasky—$73,004; Roth—$155,209; and Yuan—$133,250. |
| • | Performance shares granted in 2005 are prorated based on the number of full months in the performance cycle with a minimum of 12 months to be eligible. The amounts shown are calculated by multiplying the accelerated number of shares by the total shareholder return factor (150%) by the average of the high and low common stock price for the thirty days prior to the date of change in control ($60.81). The incremental benefit is as follows: Schneider—$215,185; Lasky—$111,731; Roth—$89,798; and Yuan—$80,223. |
| • | Performance shares granted in 2006 are payable based on the change in control value protection rights as follows: the whigher of (a) the account balance on the date of such termination of employment using the average high and low stock price for the prior thirty day period ($60.81) and the most recent total shareholder return factor (126.47%) or (b) the account balance on the date of the grant. The incremental benefit is as follows: Pipitone— $179,222; Marsh—$256,812; Schneider—$226,213; Lasky—$130,318; Roth—$88,928; and Yuan—$86,059. |
| • | Performance-adjusted and discretionary restricted stock units are payable as follows: |
| The restriction is lifted from restricted stock units granted in 2005. 2006 grant is payable based on the share value protection rights in the agreement as follows: 1) A lump sum cash payment of the difference of the fair market value on the date of the change in control and the fair market value on the date of termination multiplied by the number of shares and 2) A payment of the total number of shares of common stock equal to the number of restricted stock units. The amounts shown are calculated by multiplying the number of accelerated restricted stock units by the closing price of FirstEnergy’s common stock on December 29, 2006 ($60.30). The incremental benefit is as follows: Pipitone—$289,440; Marsh—$793,970; Schneider—$744,343; Lasky—$490,601; Roth—$149,484; and Yuan—$180,959. |
| • | The restriction is lifted from restricted stock shares. The 2006 grant is payable based on the share value protection rights in the agreement as follows: 1) A cash payment if the fair market value of a share of stock on the date of grant or the fair market value of a share of stock on the date of the change in control is greater than the fair market value of a share of stock on the date of termination of employment. The cash payment is determined by subtracting the fair market value of a share of stock on the date of termination of employment from the greater of: (a) the fair market value of a share of stock on the date of grant, or (b) the fair market value of a share of stock on the date of the change in control. The difference is multiplied by the number of shares granted and paid within ten days of the terminat ion of employment. The amounts shown are calculated by multiplying the number of accelerated restricted stock units by the closing price of FirstEnergy’s common stock on December 29, 2006 ($60.30). The incremental benefit is as follows: Pipitone—$2,281,984; Schneider—$1,025,100; and Lasky—$1,025,100. Mr. Marsh, Mr. Roth and Mr. Yuan do not have restricted stock. |
| • | In the event of a change in control, the 20% company matching contribution in the stock account of the EDCP described earlier in this prospectus would fully vest. Matching contributions made by FirstEnergy payable under the EDCP are as follows: Pipitone—$47,265; Marsh—$70,768; Schneider—$132,661; Lasky—$17,192; Roth—$31,432; and Yuan—$32,651. |
| (5) | The Section 280G Gross-up represents the estimated excise tax charged to the named executive officer upon receiving any change in control payments. |
| (6) | Mr. Marsh will be credited with three years of age and service which will provide him with the maximum points for the purposes of determining the company contribution toward the cost of retiree health coverage. This amount is calculated based on the assumptions used for financial reporting purposes under generally accepted accounting principles. |
Death/Disability
The death/disability benefits provided to the named executive officers are provided on a non-discriminatory basis to all salaried employees generally upon eligible termination of employment, with the following exceptions:
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Death/Disability
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Severance | | | Short-Term
Incentive
Program
Award | | | Incremental
Pension
Benefit
(present
value)(1) | | | Accelerated
Long-Term
Incentive
Program and
Other Equity
Awards(2) | | | Executive
Supplemental
Life
Insurance
Death
Benefit(3) | | | Health
Care | | | Total |
| Guy L. Pipitone | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 3,263,419 | | | | | $ | 319,000 | | | | | $ | 0 | | | | | $ | 3,582,419 | |
| Richard H. Marsh | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 1,709,727 | | | | | $ | 359,000 | | | | | $ | 0 | | | | | $ | 2,068,727 | |
| Donald R. Schneider | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 824,488 | | | | | $ | 2,621,977 | | | | | $ | 226,000 | | | | | $ | 0 | | | | | $ | 3,672,465 | |
| Charles D. Lasky | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 289,177 | | | | | $ | 1,904,075 | | | | | $ | 151,200 | | | | | $ | 0 | | | | | $ | 2,344,452 | |
| Alfred G. Roth | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 663,185 | | | | | $ | 207,000 | | | | | $ | 0 | | | | | $ | 870,185 | |
| Arthur W. Yuan | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 0 | | | | | $ | 532,974 | | | | | $ | 170,000 | | | | | $ | 0 | | | | | $ | 702,974 | |
| (1) | The Incremental Pension Benefit is the increased benefit provided to Mr. Schneider and Mr. Lasky’s beneficiaries as a result of death. There is no enhanced benefit in the event of a disability. Mr. Pipitone and Mr. Marsh are retirement eligible so there is no increased benefit. Mr. Roth and Mr. Yuan are not eligible for retirement so there is no incremental pension benefit in the event of death or disability. |
| (2) | Accelerated Long-Term Incentive Program and Other Equity Awards are payable as follows: |
| • | Unvested stock options become immediately exercisable upon death. Unvested options continue to vest according to the vesting schedule upon disability. The amounts shown are calculated by multiplying the number of accelerated/unvested options by the difference between the exercise price and the closing price of FirstEnergy’s common stock on December 29, 2006 ($60.30): Pipitone—$691,995; Marsh—$915,757; Schneider—$325,913; Lasky—$160,201; Roth—$239,052; and Yuan—$109,854. |
| • | Performance shares granted in 2004 are prorated based on the number of full months in the performance cycle with a minimum of 12 months to be eligible. The amounts shown are calculated by multiplying the accelerated number of shares by the total shareholder return factor (150%) by the average of the high and low common stock price on the last trading day of the three-year performance cycle ($60.35). The incremental benefit is as follows: Schneider—$236,032; Lasky—$73,004; Roth—$155,209; and Yuan—$133,250. |
| • | Performance shares granted in 2005 and 2006 are prorated based on the number of full months in the performance cycle with a minimum of 12 months to be eligible. The amounts shown are calculated by multiplying the accelerated number of shares by the total shareholder return factor (150% and 126.47% for 2005 and 2006, respectively) by the average of the high and low common stock price for the thirty days prior to the date of termination ($60.81) The incremental benefit is as follows: Schneider—$290,589; Lasky—$155,170; Roth—$119,441; and Yuan—$108,910. |
| • | The restriction is lifted from all performance-adjusted and discretionary restricted stock units and restricted stock shares. The amounts shown are calculated by multiplying the number of accelerated restricted stock units and restricted stock by the closing price of FirstEnergy’s common stock on December 29, 2006 ($60.30), and subtracting the amount of benefit provided in voluntary termination or retirement scenario as appropriate. The incremental benefit is as follows: Pipitone—$2,571,424; Marsh—$793,970; Schneider—$1,769,443; Lasky—$1,515,701; Roth—$149,484; and Yuan—$180,959. |
| (3) | The Executive Supplemental Life Insurance Death Benefit is payable in the event of death. |
Compensation of Directors
The FES Board is comprised of Anthony J. Alexander, Richard H. Marsh, and Joseph J. Hagan. Only non-employee directors receive director compensation. As Mr. Alexander, Mr. Marsh and Mr. Hagan are employees of FirstEnergy, they do not receive compensation for their service as members of FES’ Board of Directors.
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Security Ownership of Management
The following table shows shares of FirstEnergy stock beneficially owned as of August 7, 2007, by each director; the executive officers of FES named in the Summary Compensation Table above; and all directors and executive officers of FES as a group. Also listed, as of that date, are common stock equivalents credited to executive officers as a result of participation in incentive compensation plans. None of the shares below are pledged by the directors or named executive officers.
| | | | | | | | | | | | | | | | | | |
| Name | | | Class of Stock | | | Shares Beneficially
Owned(1) | | | Common Stock
Equivalents(2) |
| Charles E. Jones | | | | | Common | | | | | | 70,748 | | | | | | 43,052 | |
| Charles D. Lasky | | | | | Common | | | | | | 27,147 | | | | | | 22,700 | |
| Guy L. Pipitone | | | | | Common | | | | | | 45,298 | | | | | | 25,782 | |
| Alfred G. Roth | | | | | Common | | | | | | 20,317 | | | | | | 11,865 | |
| Donald R. Schneider | | | | | Common | | | | | | 17,348 | | | | | | 57,430 | |
| Arthur W. Yuan | | | | | Common | | | | | | 4,715 | | | | | | 14,665 | |
| Anthony J. Alexander | | | | | Common | | | | | | 550,128 | | | | | | 292,291 | |
| Joseph J. Hagan | | | | | Common | | | | | | 16,154 | | | | | | 26,068 | |
| Richard H. Marsh | | | | | Common | | | | | | 733 | | | | | | 75,971 | |
| | | | | | | | | | | | | | | | | | | |
| All FES Directors and Executive Officers as a Group | | | | | Common | | | | | | 975,464 | | | | | | 670,383 | |
| (1) | Shares beneficially owned include (a) any shares with respect to which the person has a direct or indirect pecuniary interest, and (b) shares that the person has the right to acquire beneficial ownership within 60 days of August 7, 2007, and are as follows: (Jones—0 shares; Lasky—6,150 shares; Pipitone—0 shares; Roth—19,363 shares; Schneider—0 shares; Yuan—2,100 shares; Alexander—363,275 shares; Hagan—0 shares; Marsh—0 shares; and all directors and executive officers of FES as a group—523,188 shares). The percentage of shares beneficially owned by any director, or by all directors and executive officers as a group, does not exceed one percent of the class owned. Each individual or member of the group has sole voting and investment power with respect t o the shares beneficially owned. |
| (2) | Common stock equivalents represent the cumulative number of shares deferred under the EDCP, performance shares and restricted stock units credited to each executive officer. The value of these shares is measured, in part, by the market price of FirstEnergy’s common stock. Final payments for performance shares may vary due to performance factors, as discussed above under ‘‘—Long-Term Incentive Program.’’ In regard to performance-adjusted restricted stock units, at the end of the restriction period, the actual number of shares issuable may be adjusted upward or downward by 25% based on FirstEnergy’s performance against three predetermined metrics. In addition, the common stock equivalents reflected for ‘‘All FES Directors and Executive Officers as a Group’’ incl udes discretionary restricted stock units awarded to certain FES executive officers that will be issuable five years after the date awarded, except for specified provisions if the executive dies, is terminated due to disability, or there is a change in control. Common stock equivalents do not have voting rights or other rights associated with ownership of common stock. |
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Table of Contentscertain relationships and related transactions
Based on its size and varied business operations, FirstEnergy and its subsidiaries, including FES, may from time to time engage in transactions and business arrangements with companies and other organizations in which one of the members of their Board, executive officers or their respective immediate family members also may be a board member, executive officer or significant investor, or in which such person has a direct or indirect material interest. FirstEnergy recognizes that related person transactions have the potential to create perceived or actual conflicts of interest and could create the appearance that decisions are based on considerations other than the best interests of FirstEnergy and its shareholders. Accordingly, as a general matter, it is FirstEnergy’s preference to avoid related person transactions. However, there are situations where related person transactions are either in, or not i nconsistent with, FirstEnergy’s best interests and the best interests of its shareholders. FirstEnergy’s Board has determined that it is, therefore, appropriate and necessary to have a review process in place with respect to any related person transactions.
Based on the foregoing, the Board of FES’ parent, FirstEnergy, established a Related Person Transactions Policy to be implemented by its Corporate Governance Committee, in order to effectuate the review, approval, and ratification process surrounding related person transactions. For purposes of this discussion any reference to the Corporate Governance Committee is a reference to the FirstEnergy Corporate Governance Committee. This Policy supplements FirstEnergy’s other conflict of interest policies set forth in the FirstEnergy Conflicts-Of-Interest Policy, Code of Business Conduct, and Board of Directors Code of Ethics and Business Conduct. Related person transactions shall be consummated or shall continue only if a majority of the disinterested members of the Corporate Governance Committee or the FirstEnergy Board approves or ratifies the transaction in accordance with this Policy. In makin g its decisions, the Corporate Governance Committee will review transactions and proposed transactions submitted for approval by FES’ management, who will have internally reviewed the submitted transactions by taking into consideration the Policy, which includes the definitions and terms set forth in Item 404 of Regulation S-K under the federal securities laws.
As part of this Policy, the management of FirstEnergy and its subsidiaries has established review procedures for any transaction or proposed transaction, in which FirstEnergy or any of its subsidiaries are currently, or may be, a participant in which the amount exceeds $120,000, and in which the related person, as defined in Item 404 of Regulation S-K, had or will have a direct or indirect material interest or any amendment to such a transaction. FirstEnergy and its subsidiaries also have established procedures to identify such related persons. The identities of these related persons will be distributed to business units and function/department leaders to ensure senior management is made aware of any transaction or proposed transaction involving FirstEnergy and its subsidiaries and anyone on that list. Management will bring any such transactions to the attention of the Corporate Governance Committee for its review, approval, or ratification.
When reviewing a proposed transaction, the Corporate Governance Committee will review the material facts of the related person’s relationship to FirstEnergy and its subsidiaries, his or her interest in the proposed transaction, and any other material facts of the proposed transaction, including, but not limited to, the aggregate value and benefits of such transaction to FirstEnergy and its subsidiaries, the availability of other sources of comparable products or services (if applicable), and an assessment of whether the transaction is on terms that are the same as, or comparable to, the terms available to an unrelated third party or to employees generally. Additionally, the Corporate Governance Committee requires FirstEnergy’s CEO to review the business merits of the transaction prior to its review.
During fiscal year 2006, FES participated in the transactions described below, in which the amount involved exceeded $120,000 and in which any related person, as defined in Item 404 of Regulation S-K, had or will have a direct or indirect material interest.
Kimberly F. Jones, wife of President Charles E. Jones, Jr., served as Director, Corporate Services Supply Chain in 2006. In 2006, she was paid a base salary of $159,800, and was issued a performance share grant of 165 performance shares (a value of $7,990), 628 performance-adjusted Restricted Stock Units (a value of $31,978), and 99 discretionary Restricted Stock Units (a value of $5,041). Her incentive compensation bonus payout was $36,650. Mrs. Jones was employed by FirstEnergy prior to her marriage to Mr. Jones, and her compensation is commensurate to employees with comparable qualifications and responsibilities and is consistent with the terms of FirstEnergy’s programs governing that element of compensation.
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Table of ContentsRISK FACTORS
You should consider the following risk factors, in addition to the other information presented in this prospectus and the documents incorporated by reference into this prospectus, in evaluating us, our business and whether to participate in this exchange offer. Any of the following risks, as well as other risks and uncertainties, could harm the value of the Exchange Certificates directly or our business and financial results and thus indirectly cause the value of the Exchange Certificates to decline, which in turn could cause you to lose all or part of your investment. The risks below are not the only ones related to us or the Exchange Certificates. Additional risks not currently known to us or that we currently deem immaterial also may impair our business and cause the value of the Exchange Certificates to decline. See ‘‘Cautionary Note Regarding Forward-Looking Statements.’’
Risks Related to this Exchange Offer
If you do not properly tender your Original Certificates for Exchange Certificates, you will continue to hold unregistered certificates that are subject to transfer restrictions.
We will only issue Exchange Certificates in exchange for Original Certificates that are received by the exchange agent in a timely manner together with all required documents. Therefore, you should allow sufficient time to ensure timely delivery of the Original Certificates, and you should carefully follow the instructions on how to tender your Original Certificates set forth under ‘‘The Exchange Offer—Procedures For Tendering Original Certificates’’ and in the letter of transmittal that you receive with this prospectus. Neither we nor the exchange agent are required to tell you of any defects or irregularities with respect to your tender of the Original Certificates.
If you do not tender your Original Certificates or if we do not accept your Original Certificates because you did not tender your Original Certificates properly, you will continue to hold Original Certificates. Any Original Certificates that remain outstanding after the expiration of this exchange offer will continue to be subject to restrictions on their transfer in accordance with the Securities Act. After the expiration of this exchange offer, holders of Original Certificates will not (with limited exceptions) have any further rights to have their Original Certificates registered under the Securities Act. In addition, if you tender your Original Certificates for the purpose of participating in a distribution of the Exchange Certificates, you will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the Exchange Certificates. If you continue to hold any Original Certificates aft er this exchange offer is completed, you may have difficulty selling them because of the restrictions on transfer and because there will be fewer Original Certificates outstanding. The value of the Remaining Original Certificates could be adversely affected by the conclusion of this exchange offer. There may be no market for the remaining Original Certificates and thus you may be unable to sell such Original Certificates.
If an active trading market does not develop for the Exchange Certificates, you may be unable to sell the Exchange Certificates or to sell them at a price you deem sufficient.
The Exchange Certificates will be new securities for which there is no established trading market. We do not intend to apply for listing of the Exchange Certificates on any national securities exchange or to arrange for the Exchange Certificates to be quoted on any automated system. We provide no assurance as to:
| | |
| • | the liquidity of any trading market that may develop for the Exchange Certificates; |
| | |
| • | the ability of holders to sell their Exchange Certificates; or |
| | |
| • | the price at which holders would be able to sell their Exchange Certificates. |
Even if a trading market develops, the Exchange Certificates may trade at higher or lower prices than their principal amount or purchase price, depending on many factors, including:
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| • | prevailing interest rates; |
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| • | the number of holders of the Exchange Certificates; |
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| • | the interest of securities dealers in making a market for the Exchange Certificates; and |
If a market for the Exchange Certificates does not develop, purchasers may be unable to resell the Exchange Certificates for an extended period of time. Consequently, a holder of Exchange Certificates may not be able to liquidate its investment readily, and the Exchange Certificates may not be readily accepted as collateral for loans. In addition, market-making activities will be subject to restrictions of the Securities Act and the Exchange Act.
In addition, if a large number of holders of Original Certificates do not tender Original Certificates or tender Original Certificates improperly, the limited amount of Exchange Certificates that would be issued and outstanding after we complete this exchange offer could adversely affect the development of a market for the Exchange Certificates.
If you are a broker-dealer, your ability to transfer the Original Certificates may be restricted.
A broker-dealer that purchased Original Certificates for its own account as part of market-making or trading activities must deliver a prospectus when it sells the Exchange Certificates. Our obligation to make this prospectus available to broker-dealers is limited. Consequently, we cannot guarantee that a proper prospectus will be available to broker-dealers wishing to resell their Exchange Certificates.
Risks Associated with the Leasing Transaction
If the Lessee were to go into bankruptcy, the Leases may be rejected.
The Exchange Certificates are not direct obligations of the Lessee. Payments of distributions on the Exchange Certificates depend upon the Lessee’s payments of rent to each Lessor under the Leases. If the Lessee were to become a debtor in a case under the Bankruptcy Code (11 U.S.C. Sections 101 et seq.), the right to exercise virtually all remedies against it would be stayed, including the right of each Lessor to terminate its Lease (and, consequently, the right of each Indenture Trustee, as collateral assignee, to terminate such Lease). In addition, the Lessee or its bankruptcy trustee could reject the Leases as ‘‘executory’’ contracts under Section 365 of the Bankruptcy Code. If that happens, rent payments under the Leases would terminate, leaving each Lessor without regular rent payments and with a claim for damages for breach of the Lease. While each Lessor could then file a claim for damages, the amount of any recover y on such claim and the amount of time that would pass between the commencement of the bankruptcy case and the receipt of any recovery cannot be determined. If the Lessee were to become a debtor in a case under the Bankruptcy Code, an event of default under the Lease Indenture would occur.
If a lease is rejected in a bankruptcy case, Section 502(b)(6) of the Bankruptcy Code limits the claims of the lessor under unexpired leases of real property (but not personal property). Under Pennsylvania law, it is likely that the Leases would be viewed as leases of real, rather than personal, property. If the Leases were to be viewed as leases of real property and the Leases were to be rejected in a bankruptcy case of the Lessee, Section 502(b)(6) of the Bankruptcy Code limits the claims against the Lessee under such Leases to the greater of one year’s rent under such Leases or 15% of the remaining rent under the Leases (not to exceed three years’ rent). Any such claims against the Lessee would be unsecured. Any recovery ultimately received on a claim for rejection of the Leases may not be sufficient to satisfy the Lessor Notes and, accordingly, the Exchange Certificates.
In a bankruptcy case of the Lessee, it is possible that a court could recharacterize the Leases as ‘‘financing leases.’’ Resolution of this issue would depend on a bankruptcy court’s analysis of the particular facts and circumstances associated with the leveraged lease transaction. Therefore, the Lessee cannot predict with any degree of certainty whether a court would conclude that the Leases constitute ‘‘financing leases’’ for purposes of a bankruptcy case. If the Leases are recharacterized as ‘‘financing leases,’’ the Facility would be included as part of the Lessee’s bankruptcy estate and the Leases would be treated as financing obligations of the Lessee. The obligations of the Lessee under the Leases in such case should not be limited by Section 502(b)(6) of the Bankruptcy Code.
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Table of ContentsFurthermore in a bankruptcy case, a bankruptcy court may permit the Lessee, among other things, to cure defaults under the Leases and to assign the Leases, notwithstanding the terms of the Leases. If the Lessee were to assign the Leases, the ultimate source of payments under the Leases would be an entity other than the Lessee. While the assignee would have to demonstrate to the bankruptcy court its ability to perform under the assigned Leases, there can be no definitive assurances that the assignee would satisfy the Lessee’s obligations under the Leases.
Each Guaranty states that the obligations of FES thereunder will remain in full force and effect regardless of a bankruptcy of the Lessee and any rejection of the applicable Lease. Thus, in the event the Lessee were to become a debtor in a case under the Bankruptcy Code, but FES was not a debtor in a case under the Bankruptcy Code, the obligations of FES under the Guaranties should not be limited by Section 502(b)(6) of the Bankruptcy Code. Any claims against FES under this scenario would rank equally with all other unsecured and unsubordinated claims of creditors of FES.
If FES were to go into bankruptcy, claims against FES may be limited.
If FES were to become a debtor in a case under the Bankruptcy Code, the right to exercise virtually all remedies against FES would be stayed. In addition, it is likely, as noted above, that the Leases would be viewed as leases of real property. In that event, Section 502(b)(6) of the Bankruptcy Code may limit a Lessor’s claims against FES, as Lease Guarantor under its applicable Guaranty, for amounts due under the applicable Lease in the same manner that it would limit such Lessor’s claims against the Lessee for those amounts in the Lessee’s bankruptcy case. Regardless of how a bankruptcy court characterizes any Lease or any Guaranty, the amount of recovery on any claims against FES and the amount of time that would pass between the commencement of FES’ bankruptcy case and the receipt of such recovery cannot be predicted with any degree of certainty. Any claims against FES under the Guaranties would rank equally with all other general uns ecured and unsubordinated claims of creditors of FES.
In the event FES were to become a debtor in a case under the Bankruptcy Code, in the absence of the Lessee being a debtor in a case under the Bankruptcy Code, claims against the Lessee under a Lease should not be limited by Section 502(b)(6) of the Bankruptcy Code, but claims against FES under a Guaranty may be so limited.
If a Lessor were to become a debtor in a case under the Bankruptcy Code, the Lessee’s right to exercise virtually all remedies against such Lessor would be stayed. The bankruptcy court, subject to the rights of holders of valid liens on Lease payments, could permit such Lessor to use or dispose of payments made to it under its Lease for purposes other than making payments on its Lessor Notes and could reduce the amount of, and modify the time for making, payments due under its Lessor Notes (and, accordingly, the Exchange Certificates), subject to procedural and substantive safeguards for the benefit of the holders of the Exchange Certificates. In such event, payments on such Lessor Notes (and, accordingly, the Exchange Certificates) could be reduced or delayed. In addition, the amount of recovery on any claims against a Lessor and the amount of time that would pass between commencement of such Lessor’s bankruptcy case and the receipt o f such recovery cannot be predicted with any degree of certainty.
No assurance can be given that, if the Lessee were to become a debtor in a case under the Bankruptcy Code, a court would not order that the assets and liabilities of each Lessor be consolidated with those of the Lessee.
In the event of a Lessor bankruptcy, it is possible that such Lessor may reject its Lease as an executory contract or unexpired lease, which, if successful, would leave the applicable Indenture Trustee as a creditor in respect of such Lessor’s interest in its Lease with a claim against the bankrupt estate in the amount owing under such Lessor Notes. Such rejection could terminate the Lessee’s obligation to make any further payments to such Lessor under such Lease. In this circumstance, FES has agreed in each Guaranty to make payments for amounts that otherwise would have been due under any Lease, but no assurances can be given that the corresponding Guaranty will be enforceable in the event of the bankruptcy of any Lessor.
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Table of ContentsIt may be difficult to realize the value of the Collateral pledged to secure the Exchange Certificates, and the proceeds received from a sale of the Collateral may be insufficient to repay the Exchange Certificates.
Under each Lease Indenture, the Lessor Notes are secured by an assignment of the applicable Lessor’s rights and interests in the applicable Lease, the Facility, the applicable Ground Interest and the applicable Guaranty (excluding certain excepted payments and excepted rights reserved to each Lessor and Owner Participant). If a default occurs with respect to such Lessor Notes, there can be no assurance that an exercise of remedies, including foreclosure on the related Collateral, would provide sufficient funds to repay all amounts due on the Lessor Notes and, accordingly, the Exchange Certificates.
If an Indenture Trustee exercises its right to foreclose on a particular Undivided Interest in the Facility, transfer of legal or operational control of such interest would be subject to regulatory approval, which cannot be assured. In addition, transferring government approvals to, or obtaining new approvals by, a purchaser or, if applicable, new operator of the Facility may require further governmental proceedings with consequent delays.
If the Lessee defaults under any Lease and the related Indenture Trustee exercises its right to foreclose on the Facility, the Indenture Trustee must rely on certain rights and covenants in the applicable Site Lease in order to operate the Facility. In a bankruptcy case, the Site Lease might be regarded as an executory contract that the Lessee, as debtor, or a bankruptcy trustee could reject. If the Lessee or a bankruptcy trustee were to reject the Site Lease, the related Indenture Trustee might not have authority to operate the Facility in order to provide revenues for payments of lease rentals or might incur significant additional costs in doing so.
If the Lessee defaults under any Lease, the related Indenture Trustee may also require the Lessee to pay liquidated damages in amounts referred to as Termination Amount or PVRR Amount. Under New York law, liquidated damages clauses are generally enforced when, among other things, (i) the damages were not easily determinable at the time of execution of the relevant document and (ii) the damages constituted a reasonable approximation of the damages at the time determined. No assurance can be given that the Lessee’s obligation to pay liquidated damages will be determined to be enforceable. In the event that a court finds such liquidated damages clauses unenforceable, such Indenture Trustee’s recovery under such Lease would be limited to its actual proven damages. Consequently, the Pass Through Trustee may not have sufficient funds to pay the Exchange Certificates in full.
In addition, the Leases and the other Operative Documents do not contain cross-collateralization provisions. Accordingly, each Indenture Trustee’s security interests in each Lessor’s Undivided Interest and the Collateral pertaining to each Undivided Interest are separate and secure separate amounts. If each Indenture Trustee exercises its right to foreclose on and sell such Collateral, the proceeds from the sale of each Undivided Interest and the Collateral pertaining to the Undivided Interest would be separately applied against the amount secured by that particular Undivided Interest and could not be used to satisfy any deficiency in the proceeds from the sale of the other Undivided Interests and the Collateral pertaining to such other Undivided Interests. Any excess of sale proceeds would be remitted to the applicable Lessor. As a result, if the amount of sale proceeds from the foreclosure of the Collateral related to a particular Undivided Interes t is less than the amount required to pay all amounts payable on the Lessor Notes secured by that Collateral, the holders of Exchange Certificates would suffer a permanent loss, even though aggregate sale proceeds from the foreclosure of the Collateral related to all Undivided Interests were equal to or greater than all principal, Make-Whole Amount, if any, and interest due on all outstanding Lessor Notes.
Risks Related to Business Operations of the Lessee and FES
Risks arising from the reliability of power plants could result in lost revenues or increased cost.
Operation of generation facilities involves risk, including potential breakdown or failure of equipment or processes, accidents, labor disputes and performance below expected levels. In addition,
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Table of Contentsweather-related incidents and other natural disasters can disrupt generation systems. Because FES’ generating stations are interconnected with transmission systems, the operation of those facilities could be adversely affected by unexpected or uncontrollable events occurring on those transmission systems.
Operation of FES’ power plants below expected capacity levels could result in lost revenues or increased expenses, including higher maintenance costs. Unplanned outages may require significant replacement power costs. Moreover, if FES were unable to perform under contractual obligations, penalties or liability for damages could result.
Changes in commodity prices could adversely affect profit margins.
Increases in fuel costs for FES’ generation facilities can affect profit margins. Changes in market prices of electricity, which are affected by changes in other commodity costs and other factors, may impact FES’ results of operations and financial position by increasing the amount it pays to purchase power to satisfy power supply obligations under existing power sale agreements.
Electricity and fuel prices may fluctuate substantially over relatively short periods of time for a variety of reasons, including:
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| • | changing weather conditions or seasonality; |
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| • | changes in electricity usage by customers; |
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| • | illiquidity in wholesale power and other markets; |
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| • | transmission congestion or transportation constraints, inoperability or inefficiencies; |
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| • | availability of competitively priced alternative energy sources; |
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| • | changes in supply and demand for energy commodities; |
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| • | changes in power production capacity; |
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| • | outages at the FES power production facilities or those of its competitors; |
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| • | changes in production and storage levels of natural gas, coal, crude oil and refined products; and |
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| • | natural disasters, wars, acts of sabotage, terrorist acts, embargoes and other catastrophic events. |
FES is exposed to operational, price and credit risks associated with selling and marketing products in the power markets and may not fully hedge against these risks.
If FES were unable to deliver firm capacity and energy under its power sales agreements, it may be required to pay damages. These damages generally would be based on the difference between the market price to acquire replacement capacity or energy and the contract price of the undelivered capacity or energy. Depending on price volatility in the wholesale energy markets, such damages could be significant. Extreme weather conditions, unplanned power plant outages, transmission disruptions, and other factors could affect FES’ ability to meet its obligations, or cause increases in the market price of replacement capacity and energy.
FES attempts to mitigate risks associated with satisfying its contractual power sales arrangements by reserving generation capacity to deliver electricity to satisfy its net firm sales contracts and, when necessary, by purchasing firm transmission service. FES also routinely enters into contracts, such as fuel and power purchase and sale commitments, to hedge its exposure to fuel requirements and other energy-related commodities. FES may not, however, hedge the entire exposure of its operations from commodity price volatility. To the extent that commodity price volatility is not hedged, results of operations and financial position could be negatively affected.
FES’ risk management policies relating to energy and fuel prices, and counterparty credit are by their very nature risk related, and FES could suffer economic losses despite such policies.
FES attempts to manage the market risk inherent in its energy and fuel positions. Procedures have been implemented to enhance and monitor compliance with risk management policies, including
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Table of Contentsvalidation of transaction and market prices, verification of risk and transaction limits, sensitivity analysis and daily portfolio reporting of various risk measurement metrics. Nonetheless, FES cannot economically hedge all exposures in these areas and the risk management program may not operate as planned. For instance, actual electricity and fuel prices may be significantly different or more volatile than the historical trends and assumptions upon which FES based its risk management positions. Also, FES’ power plants might not produce the expected amount of power during a given day or time period due to weather conditions, technical problems or other unanticipated events, which could require FES to make energy purchases at higher prices than the prices under existing energy supply contracts. In addition, the amount of fuel required for FES’ power plants during a given day or time period could be more than expected, which could require the purchase of additional fuel at prices less favorable th an the prices under existing fuel contracts. As a result, FES cannot always predict the impact that its risk management decisions may have on it if actual events lead to greater losses or costs than those against which its risk management positions were intended to hedge.
FES also faces credit risks that parties with whom it contracts could default in their performance, in which cases FES could be forced to sell power into a lower-priced market or make purchases in a higher-priced market than existed at the time of contract. Although risk management policies and programs, including credit policies to evaluate counterparty credit risk, have been established, there can be no assurance that FES will be able to fully meet its obligations, that it will not be required to pay damages for failure to perform or that it will not experience counterparty non-performance or that it will collect for voided contracts. If counterparties to these arrangements fail to perform, FES may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices. In that event, financial results would likely be adversely affected.
Nuclear generation involves risks that include uncertainties relating to health and safety, additional capital costs, the adequacy of insurance coverage and nuclear plant decommissioning.
FES is subject to the risks of nuclear generation, including but not limited to the following:
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| • | the potential harmful effects on the environment and human health resulting from certain unplanned radiological releases associated with the operation of nuclear facilities and the storage, handling and disposal of radioactive materials; |
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| • | limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with its nuclear operations or those of others in the United States; |
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| • | uncertainties with respect to contingencies and assessments if insurance coverage is inadequate; and |
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| • | uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed operation. |
The NRC has broad authority under federal law to impose licensing, security 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 and/or shut down a unit, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants, including those of NGC.
FES’ nuclear facilities are insured under Nuclear Electric Insurance Limited, or NEIL, policies issued for each plant. Under these policies, insurance coverage is provided for property damage and decontamination and decommissioning costs in an amount up to $2.75 billion for each of Perry and Beaver Valley and up to $1.3 billion for Davis-Besse. NGC has also obtained approximately $1.96 billion of insurance coverage for replacement power costs. Under these policies, NGC can be assessed a maximum of approximately $62 million for incidents at any covered nuclear facility occurring during a policy year that are in excess of accumulated funds available to the insurer for paying losses.
The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $10.8 billion (assuming 104 units licensed to operate in the United States) for a single
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Table of Contentsnuclear incident, which amount is covered by: (i) private insurance amounting to $300 million and (ii) $10.5 billion provided by an industry retrospective rating plan. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $100.6 million (but not more than $15 million per year) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on NGC’s present nuclear ownership, the maximum potential assessment under these provisions would be $349.6 million per incident but not more than $52.1 million in any one year for each incident.
On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for Information to FENOC following FENOC’s reply to an April 2, 2007 NRC request for information about an expert witnesses’ report cited in a petition filed with the NRC by the UCS on April 30, 2007 calling for, among other things, a shutdown of the Davis-Besse Plant. See ‘‘—Regulation—NRC Matters’’ above. The NRC indicated that this information is needed for the NRC ‘‘to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202 to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.’’ FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand for Informat ion reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FES’ other nuclear plants safely and responsibly. On June 18, 2007, the NRC Petition Review Board indicated that the agency had initially denied petitioner’s other requests and provided an opportunity for UCS to provide additional information prior to a final determination. The NRC held a public meeting on June 27, 2007 with FENOC to discuss FENOC’s response to the Demand for Information. In follow-up discussions, FENOC was requested to provide supplemental information to clarify certain aspects of the Demand for Information response and provide additional details regarding plans to implement the commitments made therein. FENOC submitted this supplemental response to the NRC on July 16, 2007. On August 15, 2007, FENOC received a Confirmatory Order issued by the NRC confirming its commitment to implement certain corrective actions designed to ensure that issues similar to those that gave rise to the May 14, 2007 Demand for Information do not recur. FES can provide no assurances as to the ultimate resolution of this matter.
Disruptions in FES’ fuel supplies could occur, which could adversely affect FES’ ability to operate its generation facilities.
FES purchases fuel from a number of suppliers. The lack of availability of fuel, or a disruption in the delivery of fuel, including disruptions as a result of weather, increased transportation costs or other difficulties, labor relations or environmental or other regulations affecting fuel suppliers, could adversely affect FES’ ability to operate its facilities, which could result in lower sales and/or higher costs and thereby adversely affect its results of operations.
Seasonal temperature variations, as well as weather conditions or other natural disasters could have a negative impact on FES’ results of operations.
Weather conditions directly influence the demand for electric power. In FES’ service areas, demand for power peaks during the summer months, with market prices also typically peaking at that time. As a result, overall operating results may fluctuate on a seasonal and quarterly basis. In addition, FES has historically sold less power, and consequently received less revenue, when weather conditions are milder. Severe weather, such as tornadoes, hurricanes, ice or snow storms or droughts, or other natural disasters, may cause outages and property damage that may require FES to incur additional costs that are generally not insured and that may not be recoverable through its prices. The effect of the failure of FES’ facilities to operate as planned under these conditions would be particularly burdensome during a peak demand period.
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Table of ContentsFES’ full-requirements power sales agreements with OE, CEI and TE to supply Ohio POLR obligations through 2008 and FES’ partial-requirements contract with Met-Ed and Penelec to supply a portion of their Pennsylvania POLR obligations at fixed prices through 2010, could adversely affect its energy margins.
Demand that FES satisfies pursuant to its sales agreements with OE, CEI, TE, Met-Ed and Penelec could increase as a result of severe weather conditions, economic developments or other factors over which FES has no control. FES satisfies its electricity supply obligations through a portfolio approach of providing electricity from its generation assets, contractual relationships and market purchases. A significant increase in demand would adversely affect FES’ energy margins because FES is required under the terms of its sales agreements to provide the energy supply to fulfill this increased demand at capped rates, which FES expects to remain significantly below the wholesale prices at which FES would have to purchase the additional supply if needed or, if FES had available capacity, the prices at which it could otherwise sell the additional supply. Accordingly, any significant change in demand could have a material adverse effect on FES’ results of op erations or financial position.
FES is subject to financial performance risks related to the economic cycles of the electric utility industry.
FES’ business follows the economic cycles of its customers. Sustained downturns or sluggishness in the economy generally affects the markets in which FES operates and negatively influences energy operations. Declines in demand for electricity as a result of economic downturns will reduce overall electricity sales and lessen cash flows, especially as industrial customers reduce production, resulting in less consumption of electricity. Economic conditions also impact the rate of delinquent customer accounts receivable.
FES faces certain human resource risks associated with the availability of, and its ability to attract and retain, trained and qualified management and labor to meet future staffing requirements.
Workforce demographic issues challenge employers nationwide and are of particular concern to the electric utility industry. The median age of utility workers is significantly higher than the national average. Today, nearly one-half of the industry’s workforce is age 45 or older. Consequently, FES faces the difficult challenge of finding ways to retain its aging skilled workforce while recruiting new talent to mitigate losses in critical knowledge and skills due to retirements. Mitigating these risks could require additional financial commitments.
In addition, FES’ current key executives have substantial experience in the power industry. The unexpected loss of services of one or more of these individuals could temporarily constrain FES’ ability to execute its business strategy. Likewise, FES’ inability to attract management talent of a similar caliber in the future could have a material negative impact on FES’ plans for continued growth and business success.
Acts of war or terrorism could negatively impact operations.
The possibility that FES’ infrastructure, or that of any interconnected company, such as electric transmission facilities, could be direct targets of, or indirect casualties of, an act of war or terrorism could affect FES’ operations. Any such disruption could result in a decrease in revenues and additional costs to purchase electricity and to replace or repair assets, which could have a material adverse impact on results of operations and financial condition.
Risks Associated with Regulation
Complex and changing government regulations could have a negative impact on results of operations.
FES is subject to comprehensive regulation by various federal, state and local regulatory agencies that significantly influence its operating environment. Changes in or reinterpretations of existing laws or regulations or the imposition of new laws or regulations could require FES to incur additional costs or change the way that business is conducted, and therefore could have an adverse impact on results of operations and financial condition.
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Table of ContentsRegulatory changes in the electric industry could affect FES’ competitive position and adversely affect business and results of operations.
As a result of the actions taken by state legislative bodies over the last few years, changes in the electric utility business have occurred and are continuing to take place throughout the United States, including in Ohio and Pennsylvania. These changes have resulted, and are expected to continue to result, in fundamental alterations in the way utilities and power marketing entities conduct their business.
Some deregulated electricity markets have experienced difficulty in transition to a competitive market regime. In some of these markets, both state and federal government agencies and other interested parties have made proposals to delay market restructuring or even re-regulate areas of these markets that have previously been deregulated. For example, in 2001, the FERC instituted a series of price controls designed to mitigate or cap prices in the entire western U.S. to address the extreme volatility in the California electricity markets. These price controls have had the effect of significantly reducing spot and forward electricity prices in the western market. In addition, the ISOs that oversee the transmission systems in certain wholesale electricity markets have from time to time been authorized to impose price limitations and other mechanisms to address volatility in the power markets. Similar types of price limitations and other mechanisms could reduce the profits that FES’ wholesale power marketing business would have realized based on competitive market conditions absent such limitations and mechanisms. Although FES expects the deregulated electricity markets to continue to be competitive, other proposals to re-regulate this industry may be made, and legislative or other actions affecting the electric power restructuring process may cause the process to be delayed, discontinued or reversed in the states in which FES currently operates or may operate in the future. Such delays, discontinuations or reversals of electricity market restructurings in the markets in which FES operates could have an impact on its results of operations and financial condition. At a minimum, these types of actions raise uncertainty concerning the continued development of competitive power markets.
The FERC and the U.S. Congress propose changes from time to time in the structure and conduct of the electric utility industry. If the restructuring and deregulation efforts result in increased competition or unrecoverable costs, FES’ business and results of operations may be adversely affected. FES cannot predict the extent or timing of further efforts to restructure, deregulate or re-regulate its business or the industry.
FES’ profitability is subject to continued authorization to sell power at market-based rates.
In 2005, the FERC granted FES, FGCO and NGC authority to sell electricity at market-based rates. The FERC’s orders that grant this market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that these companies can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. As a condition to the orders granting these generating companies market-based rate authority, every three years they are required to file a market power update to show that they continue to meet the FERC’s standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates. If any of these companies were to lose its market-based rate authority or fail to have such authority renewed, it would be required to obtain the FERC’s acceptance to sell power at cost-based rates. That company then woul d become subject to the accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rate schedules.
The FERC has issued a proposed rulemaking to revise the standards used to determine whether an applicant qualifies for market-based authority. In addition, the FERC is considering modifications to other aspects of its market-based rate authorizations, including whether to continue granting waivers of the FERC’s accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rates, whether to continue granting blanket authorization for future securities issuances or assumptions of liabilities to entities with market-based rate authority, whether to adopt a uniform tariff that applies to all market-based rate sellers, and whether to modify the approach to the
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Table of Contentsthree-year market power update filing. The FERC has solicited comments from interested parties on these and other issues. The FERC issued a final rule on June 21, 2007 in which it declined to change its accounting, record keeping and reporting requirements, practice on blanket authorizations for securities issuances and assumptions of liabilities and adopted certain required tariff provisions.
There are uncertainties relating to participation in the PJM and MISO Regional Transmission
Organizations.
Market rules that govern the operation of RTOs could affect FES’ ability to sell power produced by its generating facilities to users in certain markets due to transmission constraints and attendant congestion costs. The prices in day-ahead and real-time RTO markets have been subject to price volatility. Administrative costs imposed by RTOs, including the cost of administering energy markets, have also increased. The rules governing the various regional power markets may change from time to time, which could affect costs or revenues. Although a significant portion of the fees and costs related to transmission, ancillary services, congestion and administration are borne by most of its utility affiliates under their current supply contracts with FES, FES is incurring significant additional fees and increased costs to participate in an RTO. Because it remains unclear which companies will be participating in the various regional power markets, or how RTOs will ultimately develop and operate or what region they will cover, FES cannot fully assess the impact that these power markets or other ongoing RTO developments may have.
Costs of compliance with existing environmental laws are significant, and costs of compliance with future environmental laws could adversely affect cash flow and profitability.
FES’ operations are subject to extensive federal, state and local environmental statutes, rules and regulations. Compliance with these legal requirements requires FES to incur costs for environmental monitoring, installation of pollution control equipment, emission fees, maintenance, upgrading, remediation and permitting at all facilities. These expenditures have been significant in the past and may increase in the future. If the cost of compliance with existing environmental laws and regulations does increase, it could adversely affect business and results of operations, financial position and cash flows. Moreover, changes in environmental laws or regulations may materially increase costs of compliance or accelerate the timing of capital expenditures. The compliance strategy, although reasonably based on available information, may not successfully address future relevant standards and interpretations. If FES fails to comply with environmental laws and reg ulations, even if caused by factors beyond its control or new interpretations of longstanding requirements, that failure could result in the assessment of civil or criminal liability and fines.
The EPA’s CAIR, CAMR, and Clean Air Visibility Rule, or CAVR, require significant reductions beginning in 2009 in air emissions from coal-fired power plants and the states have been given substantial discretion in developing their own rules to implement these programs. In addition, both the CAIR and the CAMR have been challenged in the U.S. Court of Appeals for the District of Columbia. As a result, the ultimate requirements under these air emission reduction programs may not be known for several years and may differ significantly from the current rules. If the final rules are remanded by the U.S. Court of Appeals for the District of Columbia, if states elect not to participate in the various federal programs under the rules, or if the states elect to impose additional requirements on individual units that are already subject to the CAIR, the CAMR and/or the CAVR, costs of compliance could increase significantly and could have an adverse effect on future r esults of operations, cash flows and financial condition.
Alternatively, if the final rules are remanded by the U.S. Court of Appeals for the District of Columbia and their implementation is postponed, FGCO could be competitively disadvantaged because it is currently obligated to comply with essentially this same level of emission controls as a result of the Sammis NSR Litigation described under ‘‘Description Of The Lease Guarantor And The Lessee—Environmental Matters.’’ This settlement, which was approved by the U.S. District Court for the Southern District of Ohio on July 11, 2005, requires reductions of NOX and SO2 emissions at Sammis, Burger, Eastlake and the Mansfield Plant, as we ll as installation of pollution control devices
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Table of Contentsat those plants, irrespective of any current or future law that would require or delay NOX and SO2 emission reductions from coal-fired power plants. In addition, the settlement provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FGCO fails to install such pollution control devices for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FGCO could be exposed to penalties under the settlement agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation settlement agreement are currently estimated to b e $1.7 billion for 2007 through 2011 ($400 million of which is expected to be spent in 2007 with the largest portion of the remaining $1.3 billion expected to be spent in 2008 and 2009). All of these expenditures are to be borne by FES and FGCO.
There is also a growing concern nationally and internationally about global warming. Further, many states and environmental groups have also challenged certain of the federal laws and regulations relating to air emissions as not being sufficiently strict. As a result, it is possible that state and federal regulations will be developed that will impose more stringent limitations on emissions than are currently in effect. Any such additional limitation on emissions may require FES to make increased expenditures for pollution control devices which could have an adverse impact on results of operations, cash flows and financial condition.
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FES’ plants. In addition, Ohio and Pennsylvania have water quality standards applicable to FES’ operations. As provided in the Clean Water Act, authority to grant federal NPDES water discharge permits can be assumed by a state. Ohio and Pennsylvania have assumed such authority.
FES may be subject to legal claims arising from the presence of asbestos or other regulated substances at some of its facilities.
Asbestos and other regulated substances are, and may continue to be, present at FES’ facilities where suitable alternative materials are not available. FES believes that any remaining asbestos at its facilities is contained. The continued presence of asbestos and other regulated substances at these facilities, however, could result in asbestos-related claims being brought against FES in the future.
The continuing availability and operation of generating units is dependent on retaining the necessary permits, approvals, certifications and licenses, and operating authority from governmental entities, including the NRC.
FES is required to have numerous permits, approvals, certifications and licenses from the agencies that regulate its business. FES believes the necessary permits, approvals, certifications and licenses have been obtained for existing operations and that its business is conducted in accordance with applicable laws; however, FES is unable to predict the impact on operating results from future regulatory activities of any of these agencies and FES is not assured that any such permits, approvals, certifications or licenses will be renewed.
Risks Associated with Financing and Capital Structure
Interest rates and/or a credit rating downgrade could negatively affect financing costs and FES’ ability to access capital.
FES has near-term exposure to interest rates from outstanding indebtedness indexed to variable interest rates, and will have exposure to future interest rates to the extent it seeks to raise debt in the capital markets in the future to meet optional or mandatory debt redemptions or maturities or to fund construction or other investment opportunities. Interest rates could change in significant ways as a result of economic or other events that the FES risk management processes were not established to address. As a result, FES cannot always predict the impact that its risk management decisions may have if actual events lead to greater losses or costs than its risk management positions were intended
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Table of Contentsto hedge. Although FES employs risk management techniques to hedge against interest rate volatility, significant and sustained increases in market interest rates could materially increase financing costs and negatively impact reported results.
FES expects to increasingly rely on access to bank and capital markets as sources of liquidity for future cash requirements not satisfied by cash from operations. A downgrade in FES’ credit ratings from the credit rating agencies, particularly to a level below investment grade, could negatively affect FES’ ability to access the bank and capital markets, especially in a time of uncertainty in either of those markets, and may require FES to post cash collateral to support outstanding commodity positions in the wholesale market, or as an alternative to the delivery of letters of credit or guarantees. However, FES currently satisfies its liquidity needs by borrowing from and participating in the FirstEnergy non-regulated money pool. High levels of leverage tend to increase the possibility of a rating downgrade. As recently as December 31, 2005, FES’ debt-to-total capitalization was at approximately a 68% level when recast to give effect t o the generation asset transfers and the transfer of NGC to FES as if they had occurred at the end of 2003. Although this level has declined to 62% as of December 31, 2006, unexpected changes in revenues and cash expenditures may delay any anticipated reduction in, or may increase, leverage in the future, which could adversely affect FES’ credit ratings. A rating downgrade would also increase the fees paid on various credit facilities, thus increasing the cost of working capital. A rating downgrade could also impact FES’ ability to grow its businesses by substantially increasing the cost of, or limiting access to, capital. FES’ issuer credit rating is Baa2 from Moody’s and corporate credit rating is BBB from S&P.
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Table of ContentsDESCRIPTION OF THE EXCHANGE CERTIFICATES
General
On July 13, 2007, The Pass Through Trustee issued the Original Certificates in an aggregate principal amount of $1,135,300,000. The Exchange Certificates will be issued in minimum denominations of $2,000 or integral multiples of $1,000 in excess thereof, and in fully registered form without coupons. Each Exchange Certificate will represent a fractional undivided interest in the Pass Through Trust and corresponds to a pro rata share of the property of such Pass Through Trust, including the outstanding principal amount of the Lessor Notes. The property of the Pass Through Trust, or the Trust Property, will consist solely of the Lessor Notes, all monies due or paid on, or the liquidation proceeds of, such Lessor Notes and any other monies deposited with the Pass Through Trustee.
A person owning a beneficial interest in the Exchange Certificates, or a Certificate Owner, will not be entitled to receive a definitive certificate representing such person’s interest in the Exchange Certificates, except as described under ‘‘—Book-Entry; Delivery and Form’’ below. Unless definitive certificates are issued under the limited circumstances described below, all references to actions by Certificateholders mean actions taken by DTC upon instructions from its participants, and all references made herein to distributions, notices, reports and statements to Certificateholders will refer, as the case may be, to distributions, notices, reports and statements to DTC or its nominee, Cede & Co., as the registered holder of the Exchange Certificates, or to DTC participants for distribution to Certificate Owners in accordance with DTC procedures. See ‘‘—Book-Entry; Delivery and Form’’ below. You should consult with each bank or broker through which you hold a beneficial interest in an Exchange Certificate for information on how you will receive notices and payments with respect to the Exchange Certificates.
The Pass Through Trust has been formed for the exclusive purpose of making the investment in the Lessor Notes and for that purpose, issuing its certificates. The Pass Through Trust will have no property other than the Trust Property. Each Exchange Certificate will represent a fractional undivided interest in the Pass Through Trust and will not represent a direct obligation of, or an obligation guaranteed by, or an interest in the Lessee, FES, any Lessor, any Owner Participant or the Pass Through Trustee or any of their respective affiliates. The Pass Through Trustee will make distributions to the Certificateholders solely from the Trust Property to the extent such Trust Property contains sufficient proceeds to make such distributions. By accepting an Exchange Certificate, each Certificateholder or Certificate Owner, as the case may be, agrees that it will look only to the income and proceeds of the Trust Property for distributions. FES has entered into a Guarant y to unconditionally and irrevocably guarantee all of the Lessee’s obligations under the related lease documents with respect to each applicable Lessor. See ‘‘Description Of The Guaranties.’’
The registrar shall not be required to register the transfer or exchange of any Exchange Certificate during the 10 days preceding the due date of any payment on such Exchange Certificate.
Distributions
Scheduled Distributions. The Pass Through Trustee will pay each Certificateholder a pro rata share of all scheduled principal and interest payments on the Lessor Notes received by the Pass Through Trustee. Scheduled distributions on the Exchange Certificates are to be made on June 1 and December 1 of each year, commencing December 1, 2007. These payments and dates are referred to as ‘‘Scheduled Distributions’’ and ‘‘Scheduled Distribution Dates,’’ respectively. For a description of the timing and amount of payments of principal and interest on the Lessor Notes, see ‘‘Description Of The Lessor Notes And Lease Indentures—The Lessor Notes and Payment.’’ The Pass Through Trustee has established and will maintain with itself, on behalf of and for the benef it of the Certificateholders, one or more non-interest bearing accounts, referred to as ‘‘Certificate Accounts,’’ for the deposit of scheduled principal and interest payments on the Lessor Notes. Under the Pass Through Trust Agreement, the Pass Through Trustee must immediately deposit any scheduled principal and interest payments received in a Certificate Account.
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Table of ContentsThe Pass Through Trustee will distribute to Certificateholders of record all Scheduled Payments received by 1:00 pm, New York time, on the date that receipt of such amounts is confirmed or it will distribute such payments on the following Business Day if payments are received after 1:00 pm, New York time. The record date will be the 15th day preceding the applicable Scheduled Distribution Date, subject to certain exceptions.
Special Distributions. The Pass Through Trustee will pay each Certificateholder a pro rata share of all payments of principal, Make-Whole Amount, if any, and interest received by the Pass Through Trustee because of a full or partial redemption or prepayment of the Lessor Notes, including payments received as a result of redemption of the Lessor Notes, amounts received by the Pass Through Trustee following an Indenture Event of Default under the Lessor Notes, including payments received from the sale of Lessor Notes by the Pass Through Trustee, and any Special Distribution or Scheduled Distribution which is not paid within five days of the Special Distribution Date or Scheduled Distribution Date applicable thereto. These payments to the Pass Through Trustee are referred to as ‘‘Special Payments.’’ The Lessor Notes (and conse quently the Exchange Certificates) are subject to redemption and prepayment under the circumstances described in this prospectus. The Pass Through Trustee has established and will maintain with itself, on behalf of and for the benefit of the Certificateholders, one or more non-interest bearing accounts, or Special Distribution Accounts, for the deposit of Special Payments. Under the Pass Through Trust Agreement, the Pass Through Trustee must immediately deposit any Special Payments received in a Special Distribution Account.
The Pass Through Trustee will distribute Special Payment funds to Certificateholders of record on the Special Distribution Date, which shall be (i) with respect to the prepayment of a Lessor Note, the day on which such prepayment is scheduled to occur pursuant to the terms of the applicable Indenture upon at least 20 days’ notice of such anticipated Special Distribution Date and (ii) with respect to any other Special Distribution, the earliest second day of a month for which it is practicable for the Pass Through Trustee to give notice of such prepayment after it has confirmed receipt of funds. Special Payment funds will be distributed on such Special Distribution Dates so long as relevant payment is received by the Pass Through Trustee by 1:00 pm, New York time, on such Special Distribution Dates, or on the Business Day following receipt by the Pass Through Trustee if such payment is received after 1:00 pm, New York time on such Special Distribution Date. The Pass Through Trustee will mail notice of each Special Distribution to the Certificateholders of record and, upon a validly made request, with such pertinent information as the Pass Through Trustee shall reasonably request, Certificate Owners, and describe, among other things, the Special Distribution Date, the record date, the amount of the Special Distribution per $1,000 of face amount of Exchange Certificates and the allocation of principal, the Make-Whole Amount, if any, interest with respect to such Lessor Note, the reason for the Special Payment and, if the date of the Special Distribution is the same date as a Scheduled Distribution, the total amount to be received on such date per $1,000 of face amount of Exchange Certificates. The record date for each distribution of a Special Distribution on a Special Distribution Date will be the 15th day preceding the Special Distribution Date. See ‘‘Description Of The Lessor Notes And Lease Indentures—Redemption of Lessor Notes’&rsquo ; and ‘‘Description Of The Lessor Notes And Lease Indentures—Indenture Events of Default.’’
Business Day means, with respect to any Lessor Note and the Operative Documents relating thereto, any day other than a Saturday, Sunday or a day on which banking institutions in New York, New York or the city and state in which the applicable Owner Trustee, the Pass Through Trustee or the applicable Indenture Trustee maintains its corporate trust office is authorized or obligated by law, regulation, executive order or governmental decree to be closed.
Method of Payment. Distributions with respect to Certificates in book-entry form made from the Certificate Account or the Special Distribution Account of the Pass Through Trust will be made by the Pass Through Trustee in accordance with the procedures described under ‘‘—Book-Entry; Delivery and Form’’ below.
Distributions with respect to Exchange Certificates in definitive form made from the Certificate Account or the Special Distribution Account of the Pass Through Trust will be made on a Scheduled Distribution Date or a Special Distribution Date by wire transfer in immediately available funds to an
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Table of Contentsaccount maintained by such Certificateholder with a bank if the Certificateholder of record (i) holds such Exchange Certificates in an aggregate amount greater than $10,000,000 or (ii) holds such Exchange Certificates in an aggregate amount greater than $1,000,000 and requests that such distributions be made by wire transfer. Otherwise, the Pass Through Trustee will make such distributions by check mailed to each Certificateholder of record on the applicable record date at its address appearing on the register maintained by the Pass Through Trustee. The Pass Through Trustee will mail notice of the final distribution (at maturity, redemption or otherwise) to the Certificateholders of record between 60 days and 20 days before the final distribution, specifying the date set for such final distribution, the amount of such distribution and that the Record Date otherwise applicable to such Scheduled Distribution Date or Special Distribution Date is not applicable, distributions being made only upon presentati on and surrender of such Certificates at the specified office or agency of the Pass Through Trustee. See ‘‘—Termination of the Pass Through Trust’’ below.
If any Scheduled Distribution Date or Special Distribution Date is not a Business Day, distributions scheduled to be made on such Scheduled Distribution Date or Special Distribution Date may be made on the next succeeding Business Day without interest or any additional distributions accruing during the intervening period.
Pool Factors
The Pool Balance for the Exchange Certificates indicates, as of any date, the original aggregate face amount of the Exchange Certificates less the aggregate amount of all payments made in respect of the Exchange Certificates. The Pool Balance for the Exchange Certificates as of any Scheduled Distribution Date shall be computed after giving effect to any payment of principal of the Lessor Notes and the distribution thereof to be made on that date.
The Pool Factor as of any Scheduled Distribution Date is the quotient (rounded to the seventh decimal place) computed by dividing (i) the Pool Balance by (ii) the original aggregate face amount of the Exchange Certificates. The Pool Factor for the Exchange Certificates as of any Scheduled Distribution Date shall be computed after giving effect to any payment of principal of the Lessor Notes and the distribution thereof to be made on that date. The Pool Factor was 1.0000000 on the Closing Date; thereafter, the Pool Factor will decline as described herein to reflect reductions in the Pool Balance. The amount of a Certificateholder’s pro rata share of the Pool Balance can be determined by multiplying the face amount of the holder’s Exchange Certificate by the Pool Factor as of the applicable Scheduled Distribution Date.
The following table sets forth the scheduled aggregate principal amortization payments for the Lessor Notes and resulting Pool Factors.
| | | | | | | | | | | | |
| Date | | | Distributions of
Principal | | | Pool Factor |
| Closing Date | | | | $ | — | | | | | | 1.0000000 | |
| December 1, 2007 | | | | | — | | | | | | 1.0000000 | |
| June 1, 2008 | | | | | — | | | | | | 1.0000000 | |
| December 1, 2008 | | | | | — | | | | | | 1.0000000 | |
| June 1, 2009 | | | | | 9,350,000 | | | | | | 0.9917643 | |
| December 1, 2009 | | | | | — | | | | | | 0.9917643 | |
| June 1, 2010 | | | | | 12,100,000 | | | | | | 0.9811063 | |
| December 1, 2010 | | | | | — | | | | | | 0.9811063 | |
| June 1, 2011 | | | | | 12,950,000 | | | | | | 0.9696996 | |
| December 1, 2011 | | | | | — | | | | | | 0.9696996 | |
| June 1, 2012 | | | | | 50,750,000 | | | | | | 0.9249978 | |
| December 1, 2012 | | | | | — | | | | | | 0.9249978 | |
| June 1, 2013 | | | | | 61,450,000 | | | | | | 0.8708711 | |
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| | | | | | | | | | | | |
| Date | | | Distributions of
Principal | | | Pool Factor |
| December 1, 2013 | | | | | — | | | | | | 0.8708711 | |
| June 1, 2014 | | | | | 65,850,000 | | | | | | 0.8128688 | |
| December 1, 2014 | | | | | — | | | | | | 0.8128688 | |
| June 1, 2015 | | | | | 70,500,000 | | | | | | 0.7507707 | |
| December 1, 2015 | | | | | — | | | | | | 0.7507707 | |
| June 1, 2016 | | | | | 63,300,000 | | | | | | 0.6950145 | |
| December 1, 2016 | | | | | — | | | | | | 0.6950145 | |
| June 1, 2017 | | | | | 19,850,000 | | | | | | 0.6775302 | |
| December 1, 2017 | | | | | — | | | | | | 0.6775302 | |
| June 1, 2018 | | | | | 45,050,000 | | | | | | 0.6378490 | |
| December 1, 2018 | | | | | — | | | | | | 0.6378490 | |
| June 1, 2019 | | | | | 47,000,000 | | | | | | 0.5964503 | |
| December 1, 2019 | | | | | — | | | | | | 0.5964503 | |
| June 1, 2020 | | | | | 22,550,000 | | | | | | 0.5765877 | |
| December 1, 2020 | | | | | — | | | | | | 0.5765877 | |
| June 1, 2021 | | | | | 49,250,000 | | | | | | 0.5332071 | |
| December 1, 2021 | | | | | — | | | | | | 0.5332071 | |
| June 1, 2022 | | | | | 51,400,000 | | | | | | 0.4879327 | |
| December 1, 2022 | | | | | — | | | | | | 0.4879327 | |
| June 1, 2023 | | | | | 25,750,000 | | | | | | 0.4652515 | |
| December 1, 2023 | | | | | — | | | | | | 0.4652515 | |
| June 1, 2024 | | | | | 54,000,000 | | | | | | 0.4176870 | |
| December 1, 2024 | | | | | — | | | | | | 0.4176870 | |
| June 1, 2025 | | | | | 56,400,000 | | | | | | 0.3680085 | |
| December 1, 2025 | | | | | — | | | | | | 0.3680085 | |
| June 1, 2026 | | | | | 29,450,000 | | | | | | 0.3420682 | |
| December 1, 2026 | | | | | — | | | | | | 0.3420682 | |
| June 1, 2027 | | | | | 62,200,000 | | | | | | 0.2872809 | |
| December 1, 2027 | | | | | — | | | | | | 0.2872809 | |
| June 1, 2028 | | | | | 65,150,000 | | | | | | 0.2298952 | |
| December 1, 2028 | | | | | — | | | | | | 0.2298952 | |
| June 1, 2029 | | | | | 29,100,000 | | | | | | 0.2042632 | |
| December 1, 2029 | | | | | — | | | | | | 0.2042632 | |
| June 1, 2030 | | | | | 68,800,000 | | | | | | 0.1436625 | |
| December 1, 2030 | | | | | — | | | | | | 0.1436625 | |
| June 1, 2031 | | | | | 52,050,000 | | | | | | 0.0978156 | |
| December 1, 2031 | | | | | 17,800,000 | | | | | | 0.0821369 | |
| June 1, 2032 | | | | | 26,600,000 | | | | | | 0.0587069 | |
| December 1, 2032 | | | | | — | | | | | | 0.0587069 | |
| June 1, 2033 | | | | | 65,350,000 | | | | | | 0.0011451 | |
| December 1, 2033 | | | | | — | | | | | | 0.0011451 | |
| June 1, 2034 | | | | | 1,300,000 | | | | | | 0.0000000 | |
Security and Source of Payment
The Pass Through Trust has been formed for the exclusive purpose of making the investment in the Lessor Notes and for that purpose, facilitating the issuance of its certificates and has no property other than the Trust Property. As such, the source of payments of principal of, and distributions on the Exchange Certificates will be derived from payments made on the Lessor Notes pursuant to the Indenture and payments made to the Pass Through Trustee pursuant to the Registration Rights Agreement. The aggregate principal amount of the Lessor Notes to be delivered to the Pass Through
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Table of ContentsTrustee equals the aggregate principal amount of the Exchange Certificates. The payment schedules for the Lessor Notes are structured to coincide as to dates and amounts with the payment schedules for the Exchange Certificates. Each of these schedules, in turn, is structured to coincide as to dates and amounts with the rental payment dates under the Leases. The Lessee’s obligation to pay Basic Lease Rent and other amounts pursuant to the Leases provide the sources of payment for the Lessor Notes. Accordingly, the timely payment of the principal of, and Make-Whole Amount, if any, and interest on, the Lessor Notes will provide for the payment in full of the principal of, and distributions on, the Exchange Certificates when due.
The Lessor Notes and, subject to certain exceptions, all obligations related thereto are nonrecourse to any Lessor and any Owner Participant. Each Indenture Trustee and the holder of the related Lessor Notes shall look exclusively to the applicable Collateral for all payments related thereto.
Each Lease is a net lease. See ‘‘Description Of The Leases And Other Operative Documents.’’
Security for the Lessor Notes
Each Lessor Note was issued under an Indenture by the applicable Lessor without recourse to the general credit of such Lessor or the applicable Owner Participant. Such Lessor granted a security interest in certain of its property and rights to the applicable Indenture Trustee for the benefit of the Pass Through Trustee to secure such Lessor Note. This Collateral includes an assignment of: (i) such Lessor’s rights under the applicable Lease, including the right to receive payments of Periodic Rent and Supplemental Rent thereunder; (ii) such Lessor’s rights under the applicable Guaranty; (iii) such Lessor’s interest in the Facility and the Ground Interest granted to such Lessor pursuant to the applicable Site Lease; and (iv) such Lessor’s interest in certain of the other related Operative Documents described herein (excluding in all cases Excepted Payments).
Voting of Lessor Notes
The Pass Through Trustee, as holder of the Lessor Notes in the Pass Through Trust, has the right, under certain circumstances under any Lease Indenture, including after the occurrence and during the continuance of an event or events of default under such Lease Indenture, to vote and give consents and waivers in respect of those Lessor Notes based on instructions from the Certificateholders (except in limited circumstances). Generally, a majority in interest of the fractional undivided interests evidenced by all Original Certificates and Exchange Certificates at the time outstanding under the Pass Through Trust Agreement will be required to deliver such instructions. The principal amount of the Lessor Notes held in the Pass Through Trust directing any action or being voted for or against any proposal will be in proportion to the principal amount of the Original Certificates and Exchange Certificates held by the Certificateholders making the corresponding directio n. See ‘‘Description Of The Lessor Notes And Lease Indentures—Modification of Operative Documents.’’
Reports to Certificateholders and Certificate Owners
On each Scheduled Distribution Date and Special Distribution Date, if any, the Pass Through Trustee will include with each Scheduled Distribution or Special Distribution, if any, to Certificateholders and, upon a valid request providing such pertinent information as the Pass Through Trustee shall reasonably request, a Certificate Owner, a statement giving effect to such distribution to be made on such Scheduled Distribution Date or Special Distribution Date, as the case may be, setting forth the following information (per $1,000 in aggregate principal Certificate amount): (i) the amount of such distribution allocable to principal and the amount allocable to Make-Whole Amount, if any, and (ii) the amount of such distribution allocable to interest; in each case, with respect to the Lessor Note. In addition, within a reasonable time after the end of each calendar year, but not later than the last date permitted by law, the Pass Through Trustee will furnish to each Certificateholder and, upon the valid request of each Certificate Owner who has provided the Pass Through Trustee with such pertinent information as the Pass Through Trustee shall reasonably request, each person who at any time during such calendar year was such a Certificate Owner, a statement specifying the
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Table of Contentssum of the amounts determined pursuant to clauses (i), (ii) and (iii) above for such calendar year or, if the person was a Certificateholder or Certificate Owner during a portion of such calendar year, for the applicable portion of such calendar year, and any other items as are readily available to the Pass Through Trustee and which a Certificateholder or Certificate Owner reasonably will request as necessary in preparing its federal income tax returns. The Pass Through Trustee will prepare these reports based on information the DTC participants and the Certificate Owners supply to the Pass Through Trustee when the Exchange Certificates are not issued in definitive form.
The Pass Through Trustee will notify the Certificateholders of all events of default or default under the Pass Through Trust Agreement known to a responsible officer of such Pass Through Trustee within 10 Business Days after the occurrence of such event of default or default. The term ‘‘default’’ for the purpose of the provision described in this paragraph only, will mean the occurrence of any event of default under the Pass Through Trust Agreement, except that in determining whether any event of default has occurred any grace period or notice in connection therewith will be disregarded. The Pass Through Trustee will be protected if it withholds notice from the Certificateholders of an event of default or default, other than a failure to pay principal of, or Make-Whole Amount, if any, or interest on, any Lessor Notes; provided, however, that such protection shall extend only so long as the board of directors, the executive committee or a trust committee of directors or specified responsible officers of the Pass Through Trustee determine in good faith that the withholding of such notice is in the interests of the Certificateholders and the Certificate Owners.
When Exchange Certificates are issued in the form of definitive certificates, the Pass Through Trustee will prepare and deliver the information described above to each Certificateholder as the name and period of record ownership of such Certificateholder appear on the records of the registrar of such Exchange Certificates.
The Pass Through Trustee will, upon request (which may include a request to receive such information on an ongoing basis), furnish all such reports and other information directly to the applicable Certificateholders and Certificate Owners which may, from time to time, be required to be furnished to the Pass Through Trustee pursuant to any Operative Document.
Currently, neither the Lessee nor FES is subject to the periodic reporting and other informational requirements of the Exchange Act, and they do not file reports with the SEC. Upon the effectiveness of the registration statement with respect to this exchange offer, or a shelf registration with respect to resales, of the Exchange Certificates, FES will become subject to the periodic reporting and informational requirements of the Exchange Act. The Lessee is required to furnish annually to the Pass Through Trustee, a statement as to the fulfillment of its covenants and obligations under the Pass Through Trust Agreement and the other Operative Documents. FES has agreed to furnish to the Pass Through Trustee, within 30 days after it is or would be required to file the same with the SEC, copies of the annual reports and information, documents and other reports which it is or otherwise would be required to file with the SEC under the Exchange Act, including year-end a udited consolidated financial statements and quarterly unaudited consolidated financial statements.
Events of Default and Certain Rights Upon an Event of Default
For a description of Indenture Events of Default, see ‘‘Description Of The Lessor Notes And Lease Indentures—Indenture Events of Default.’’ Under any Indenture, the applicable Lessor has the right under certain circumstances to cure Indenture Events of Default that result from the occurrence of a Lease Event of Default. For a description of Lease Events of Default, see ‘‘Description Of The Leases And Other Operative Documents—Lease Events of Default.’’ If such Lessor chooses to exercise such cure right and so cures the Lease Event of Default, the Indenture Event of Default and consequently the event of default under the Pass Through Trust Agreement will be deemed to be cured. See ‘‘Description Of The Lessor Notes And Lease Indentures—Right to Cure.’’
The Pass Through Trust Agreement provides that, so long as an Indenture Event of Default has occurred and is continuing and upon the direction of the Certificateholders evidencing fractional undivided interests aggregating a majority in interest of the Pass Through Trust, the Pass Through
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Table of ContentsTrustee will vote a corresponding majority of the aggregate principal amount of the Lessor Notes in favor of directing the applicable Indenture Trustee to declare the unpaid principal amount of such Lessor Notes then outstanding and any accrued interest thereon to be due and payable. The Pass Through Trust Agreement in addition provides that, if an Indenture Event of Default has occurred and is continuing, the Pass Through Trustee will, upon the direction of the Certificateholders evidencing fractional undivided interests aggregating a majority in interest of the Pass Through Trust, vote all of the Lessor Notes that are held in such Pass Through Trust to direct the applicable Indenture Trustee regarding the exercise of remedies provided in such Lease Indenture and consistent with the terms thereof.
Each Lease Indenture provides that, if an Indenture Event of Default shall occur and be continuing thereunder, the applicable Indenture Trustee will, upon the instructions of the holders of a majority in aggregate principal amount of the Lessor Notes outstanding under such Lease Indenture, declare the unpaid principal and accrued interest of the Lessor Notes issued under such Lease Indenture to be due and payable. Each Lease Indenture further provides that, if an Indenture Event of Default shall occur and be continuing thereunder, the holders of a majority in aggregate principal amount of the Lessor Notes outstanding under such Lease Indenture may direct the applicable Indenture Trustee with respect to the exercise of remedies thereunder. See ‘‘Description Of The Lessor Notes And Lease Indentures—Remedies.’’
As an additional remedy, if an Indenture Event of Default has occurred and is continuing, the Pass Through Trustee may in its discretion and, upon the direction of the Certificateholders evidencing fractional undivided interests aggregating a majority in interest of the Pass Through Trust, shall, sell all or part of the Lessor Notes held in such Pass Through Trust to any person, including any Certificateholder or the Pass Through Trustee, in its individual capacity or any other capacity. In addition, if an applicable Lessor elects to exercise its right to purchase its Lessor Notes upon the occurrence and continuance of an Indenture Event of Default under the applicable Lease Indenture, the Pass Through Trustee may sell such Lessor Notes to such Lessor. See ‘‘Description Of The Lessor Notes And Lease Indentures—Lessors’ Right to Purchase the Lessor Notes.’’ Any proceeds received by the Pass Through Trustee upon any such sale wi ll be deposited in the Special Distribution Account and will be distributed to the Certificateholders on a Special Distribution Date. If an applicable Lessor does not exercise its purchase right, the market for its Lessor Notes in default may be very limited, and there can be no assurance that they could otherwise be sold for a reasonable price. If the Pass Through Trustee sells any such Lessor Notes with respect to which an Indenture Event of Default exists for less than its outstanding principal amount, the Certificateholders will receive a smaller amount of principal distributions than anticipated and will not have any claim for the shortfall against the Lessee, the applicable Lessor, the applicable Indenture Trustee or the Pass Through Trustee.
Any amount distributed to the Pass Through Trustee by an Indenture Trustee on account of the related Lessor Notes following an Indenture Event of Default under the applicable Lease Indenture will be deposited in the Special Distribution Account and will be distributed to the Certificateholders on a Special Distribution Date. In addition, if, following an Indenture Event of Default under the applicable Lease Indenture, the applicable Lessor exercises its option to purchase or redeem the related Lessor Notes, the purchase price paid by such Lessor to the Pass Through Trustee for such Lessor Note will be deposited in the Special Distribution Account and will be distributed to the Certificateholders on a Special Distribution Date.
Any funds representing payments received with respect to any Lessor Notes in default, or the proceeds from the sale by the Pass Through Trustee of any such Lessor Notes in the Special Distribution Account, will, to the extent practicable, be invested by the Pass Through Trustee in permitted government investments pending the distribution of such funds on a Special Distribution Date. Permitted government investments are obligations of the United States maturing in not more than 60 days or such lesser time as is required for the distribution of any such funds on a Special Distribution Date. The Pass Through Trustee is prohibited from selling any permitted government investment prior to its maturity and has no liability with respect to any such investment other than by reason of its willful misconduct, gross negligence or simple negligence in the handling of funds.
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Table of ContentsThe Pass Through Trust Agreement entitles the Pass Through Trustee, subject to the duty of the Pass Through Trustee during a default to act with the required standard of care, to be indemnified by the Certificateholders before proceeding to exercise any right or power under the Pass Through Trust Agreement at the request of such Certificateholders.
In certain cases, Certificateholders evidencing fractional undivided interests aggregating a majority in interest of the Pass Through Trust may waive on behalf of all Certificateholders any default or event of default and its consequences under the Pass Through Trust Agreement and thereby annul any direction given by the Pass Through Trustee on behalf of such Certificateholders to the applicable Indenture Trustee with respect thereto, except a default in payment of the principal of, or Make-Whole Amount or interest on, any of the Lessor Notes or a default in respect of a covenant or provision thereof which cannot be modified or amended without the consent of each Certificateholder affected. The holders of a majority in aggregate unpaid principal amount of the Lessor Notes may waive any past default or Indenture Event of Default on behalf of all such holders, with certain exceptions.
Modification of the Pass Through Trust Agreement
The Pass Through Trust Agreement contains provisions permitting the Lessee and the Pass Through Trustee to enter into a supplemental trust agreement without the consent of any Certificateholders among other things:
| | |
| • | to evidence the succession of another entity to the Lessee and the assumption by any such successor of the Lessee’s obligations under the Pass Through Trust Agreement; |
| | |
| • | to add to the Lessee’s covenants for the protection of the Certificateholders or to surrender any right or power of the Lessee; |
| | |
| • | to cure any ambiguity in, or to correct or supplement any defective or inconsistent provision of, the Pass Through Trust Agreement or any supplemental trust agreement, or to make any other provisions with respect to matters or questions arising under the Pass Through Trust Agreement, as long as such actions will not materially adversely affect the interests of the Certificateholders; |
| | |
| • | to comply with requirements of the SEC or any regulatory body or any applicable law, rules or regulations, including, without limitation, if at any time that the Certificates are subject to the Trust Indenture Act of 1939, as amended, or the Trust Indenture Act, to modify, eliminate or add to the provisions of the Pass Through Trust Agreement to the extent as will be necessary to qualify or continue the qualification of the Pass Through Trust Agreement under the Trust Indenture Act (if such qualification is required) or under any similar federal statute enacted after the execution of the Pass Through Trust Agreement, or to add to the Pass Through Trust Agreement such other provisions as may be expressly permitted by the Trust Indenture Act, excluding, ho wever, the provisions referred to in Section 316(a)(2) of the Trust Indenture Act as in effect at the date the Pass Through Trust Agreement was executed or any corresponding provision in any similar federal statute enacted after the execution of the Pass Through Trust Agreement; |
| | |
| • | to add, eliminate or change any provision of the Pass Through Trust Agreement that is ministerial or administrative and will not materially adversely affect the interests of the Certificateholders; |
| | |
| • | to correct or amplify the description of property that constitutes Trust Property or the conveyance of such property to the Pass Through Trustee; or |
| | |
| • | to evidence and provide for a successor Pass Through Trustee. |
The Pass Through Trust Agreement also contains provisions permitting the Lessee, FES and the Pass Through Trustee, with the consent of the Certificateholders evidencing fractional undivided interests aggregating a majority in interest of the Original Certificates and Exchange Certificates, to execute supplemental trust agreements adding provisions to or changing or eliminating any of the
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Table of Contentsprovisions of the Pass Through Trust Agreement or modifying the rights of the Certificateholders. No such supplemental trust agreement may, without the consent of each Certificateholder so affected:
| | |
| • | reduce in any manner the amount of, or delay the timing of, any receipt by the Pass Through Trustee of payments with respect to the Lessor Notes held in the Pass Through Trust or distributions in respect of any Certificate or make distributions payable on any date, at any place or in currency other than that provided for in the Certificates or impair the right of any Certificateholder to institute suit for the enforcement of any such payment when due; |
| | |
| • | permit the disposition of any Lessor Note or the creation of a Lien on the Trust Property or otherwise deprive any Certificateholder of the benefit of ownership of the Lessor Notes or the Lien of the applicable Indenture, except as provided in the Pass Through Trust Agreement; |
| | |
| • | reduce the percentage of the aggregate fractional undivided interest of the Pass Through Trust required to approve any such supplemental trust agreement or reduce the percentage required for any waiver provided for in the Pass Through Trust Agreement; or |
| | |
| • | alter any of the provisions of the Pass Through Trust Agreement stipulating such restrictions on passing supplemental trust agreements or waiving defaults, except as would make such provisions more restrictive. |
Any supplemental trust agreement described under this heading must not cause the Pass Through Trust to be subject to certain material adverse tax treatment, and the Pass Through Trustee shall have received a legal opinion to that effect prior to entering into any such supplemental trust agreement.
Termination of the Pass Through Trust
The Pass Through Trust, and the obligations of the Lessee and the Pass Through Trustee created by the Pass Through Trust Agreement, will terminate upon the distribution to Certificateholders of all amounts required to be distributed to them pursuant to the Pass Through Trust Agreement and the disposition of all property held in the Pass Through Trust. The Pass Through Trustee will mail to each Certificateholder notice of the termination of the Pass Through Trust, the amount of the proposed final payment and the proposed date for the distribution of such final payment for the Pass Through Trust. The final distribution to any Certificateholder will be made only upon surrender of such Certificateholder’s Original or Exchange Certificates at the office or agency of the Pass Through Trustee specified in such notice of termination. In the event that not all of the Certificateholders shall have surrendered their Original or Exchange Certificates for can cellation within six months after the date specified in the above-mentioned written notice, the Pass Through Trustee shall give a second written notice to the remaining Certificateholders to surrender their Certificates for cancellation and receive the final distribution with respect thereto. In the event that any money held by the Pass Through Trustee for the payment of distributions on the Original or Exchange Certificates shall remain unclaimed for two years (or such lesser time as the Pass Through Trustee shall be satisfied, after 60 days’ written notice from the Lessee, is one month prior to the escheat period provided under applicable law) after the final distribution date with respect thereto, the Pass Through Trustee shall pay to each Indenture Trustee the appropriate amount of money and shall give written notice thereof to each Lessor, the Owner Participants and the Lessee.
The Pass Through Trustee
The Bank of New York Trust Company, N.A. is the Pass Through Trustee for the Pass Through Trust. The Pass Through Trustee and any of its affiliates may hold Exchange Certificates in their own names. With certain exceptions, the Pass Through Trustee makes no representations as to the validity or sufficiency of the Pass Through Trust Agreement, the Original or Exchange Certificates, the Lessor Notes, the Lease Indentures, the Leases or the other Operative Documents. The Bank of New York Trust Company, N.A. is also the Indenture Trustee for the Lessor Notes issued under each Lease Indenture.
The Pass Through Trustee may resign at any time, in which event the Lessee will be obligated to appoint a successor trustee. The Certificateholders holding a majority in interest of the Original
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Table of ContentsCertificates and Exchange Certificates may remove the Pass Through Trustee at any time by notice to the Pass Through Trustee, the Lessee, each Lessor and each Indenture Trustee. If the Pass Through Trustee ceases to be eligible to continue as such under the Pass Through Trust Agreement or becomes incapable of acting or shall be adjudged bankrupt or insolvent, the Lessee (or the applicable Lessor if a Lease Event of Default has occurred and is continuing) may remove the Pass Through Trustee, or any Certificateholder which has held its Original or Exchange Certificate for at least six months may, on behalf of itself and all others similarly situated, petition any court of competent jurisdiction for the removal of such Pass Through Trustee and the appointment of a successor trustee. Any resignation or removal of the Pass Through Trustee and the appointment of a successor trustee for the Pass Through Trust does not become effective until acceptance of the appointment by the successor trustee.
Each Participation Agreement further provides that the Pass Through Trustee, in its individual and trustee capacities, will be entitled to indemnification by the Lessee for any loss, liability, fee or expense arising out of certain circumstances in connection with the acceptance or administration of the Pass Through Trust and, solely in its individual capacity, for any tax (other than any tax attributable to the Pass Through Trustee’s compensation for serving as such) incurred without gross negligence, willful misconduct or bad faith, on its part, arising out of or in connection with the acceptance or administration of the Pass Through Trust.
Book-Entry; Delivery and Form
The Exchange Certificates will be represented by one or more global certificates, in fully registered form without coupons. Upon issuance, the Exchange Certificates will be deposited with, or on behalf of, DTC and registered in the name of Cede & Co., as DTC’s nominee or will remain in the custody of the Pass Through Trustee pursuant to a FAST Balance Certificate Agreement between DTC and the Pass Through Trustee. All payments made by the Lessee under a Lease to the applicable Indenture Trustee (as assignee of the applicable Lessor) and by such Indenture Trustee to the Pass Through Trustee will be in immediately available funds and passed through DTC in immediately available funds.
Certificate Owners may hold beneficial interests in the Exchange Certificates through DTC if they are participants in DTC, or indirectly through organizations that are participants in DTC. Except as set forth herein, (i) global certificates may be transferred, in whole but not in part, only to another nominee of DTC or to a successor of DTC or its nominee, (ii) beneficial interests in global certificates may not be exchanged for certificates in definitive form and (iii) owners of beneficial interests in global certificates will not be entitled to receive physical delivery of certificates in definitive form.
Certificate Owners may hold their interests directly through Clearstream Banking, société anonyme, or Clearstream, or Euroclear Bank S.A./N.V., or Euroclear, if they are participants in such systems, or indirectly through organizations that are participants in such systems. Beginning 40 days after the date of original issuance of the Exchange Certificates but not earlier, Certificate Owners may also hold such interests through organizations other than Clearstream or Euroclear that are participants in the DTC system. Clearstream and Euroclear will hold interests in the global certificates representing Exchange Certificates on behalf of their participants through DTC.
Secondary trading in long-term notes and debentures of corporate issuers generally is settled in clearinghouse or next-day funds. In contrast, secondary trading in securities (such as the Exchange Certificates offered hereby) generally is settled in immediately available funds. The Exchange Certificates will trade in DTC’s Same-Day Funds Settlement System until maturity, and secondary market trading activity in such Exchange Certificates will therefore be required by DTC to settle in immediately available funds. No assurance can be given as to the effect, if any, of settlement in immediately available funds on trading activity in the Exchange Certificates.
DTC is a limited-purpose trust company organized under the New York Banking Law, a ‘‘banking organization’’ within the meaning of the New York Banking Law, a member of the Federal Reserve System, a ‘‘clearing corporation’’ within the meaning of the New York Uniform Commercial Code and a ‘‘clearing agency’’ registered pursuant to the provisions of Section 17A of the Exchange Act. DTC holds securities that its participants deposit with DTC. DTC also facilitates the settlement among its
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Table of Contentsparticipants of securities transactions, such as transfers and pledges, in deposited securities through electronic computerized book-entry changes in participants’ accounts, thereby eliminating the need for physical movement of securities certificates. Direct participants in DTC include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. DTC is owned by a number of its direct participants and by The New York Stock Exchange, Inc., the American Stock Exchange, Inc., and the National Association of Securities Dealers, Inc. Access to the DTC system is also available to others such as securities brokers and dealers, banks and trust companies that clear through or maintain a custodial relationship with a direct participant, either directly or indirectly. The rules applicable to DTC and its direct and indirect participants are on file with the SEC.
Purchases of beneficial interests in the Exchange Certificates under the DTC system must be made by or through direct participants, which will receive a credit for the Exchange Certificates on DTC’s records. The ownership interest of each Certificate Owner is then to be recorded on the direct and indirect participants’ records. Certificate Owners will not receive written confirmation from DTC of their purchase, but Certificate Owners are expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the direct or indirect participant through which the Certificate Owner entered into the transaction. Transfers of ownership interests in the Exchange Certificates are to be accomplished by entries made on the books of direct and indirect participants acting on behalf of Certificate Owners. No beneficial owner of an interest in a global certificate representing the Exchange Certificate s will be able to transfer the interest except in accordance with DTC’s applicable procedures, in addition to those provided for under the Pass Through Trust Agreement and, if applicable, those of Clearstream and Euroclear. Except as set forth herein, Certificate Owners will not receive certificates representing their ownership interests in Exchange Certificates.
To facilitate subsequent transfers, the global certificates deposited by participants with DTC are registered in the name of DTC’s partnership nominee, Cede & Co. The deposit of the global certificates with DTC or its nominee or pursuant to a FAST Balance Certificate Agreement, and their registration in the name of Cede & Co. effect no change in beneficial ownership of the Exchange Certificates. DTC has no knowledge of the actual Certificate Owners of the Exchange Certificates. DTC’s records reflect only the identity of the direct participants to whose accounts Exchange Certificates are credited, which may or may not be the Certificate Owners. Direct and indirect participants will remain responsible for keeping account of their holdings on behalf of their customers.
Conveyance of notices and other communications by DTC to direct participants, by direct participants to indirect participants and by direct participants and indirect participants to Certificate Owners will be governed by arrangements among them, subject to any statutory or regulatory requirements in effect from time to time.
Neither DTC nor Cede & Co. will consent or vote with respect to Exchange Certificates. Under its usual procedures, DTC mails an omnibus proxy to an issuer as soon as possible after the record date. The omnibus proxy assigns Cede & Co.’s consenting or voting rights to those direct participants to whose accounts the securities are credited on the record date (identified in a listing attached to the omnibus proxy).
Payments of distributions with respect to Exchange Certificates in book-entry form will be made to Cede & Co., as nominee of DTC. DTC’s practice is to credit direct participants’ accounts upon DTC’s receipt of funds and corresponding detail information from an issuer in accordance with direct participants’ respective holdings shown on DTC’s records. Payments by direct and indirect participants to Certificate Owners will be governed by standing instructions and customary practices, as is the case with securities held for the accounts of customers in bearer form or registered in ‘‘street name.’’ These payments will be the responsibility of direct participants and indirect participants only and not of DTC, the Pass Through Trustee or the Lessee, subject to any statutory or regulatory requirements in effect. Payment of distributions to Cede & Co. is the responsibility of the Pass Through Trustee. Disburse ment of these payments to direct participants shall be the responsibility of DTC. Disbursement of these payments to the Certificate Owners shall be the responsibility of direct participants and indirect participants.
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Table of ContentsAlthough DTC, Clearstream and Euroclear are expected to follow the foregoing procedures in order to facilitate transfers of interests in the Exchange Certificates represented by one or more global certificates among their respective participants, they are under no obligation to perform or continue to perform such procedures, and such procedures may be discontinued at any time. Neither the Lessee nor the Pass Through Trustee will have any responsibility for the performance by DTC, Clearstream or Euroclear or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.
The information under this caption ‘‘—Book-Entry; Delivery and Form’’ concerning DTC and DTC’s book-entry system has been obtained from information provided by DTC. The foregoing descriptions of the operations and procedures of DTC have been provided solely as a matter or convenience. The operations and procedures are solely within the control of DTC and are subject to change by DTC from time to time. You are urged to contact DTC or its participants directly to discuss these matters.
Governing Law
The Pass Through Trust Agreement and the Original and Exchange Certificates are governed by and construed in accordance with the laws of New York, except to the extent that the Trust Indenture Act shall be applicable.
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Table of ContentsDESCRIPTION OF THE LESSOR NOTES AND LEASE INDENTURES
The following is a description of the material provisions of the Lessor Notes and the related Lease Indentures. Each Lease Indenture and the Lessor Notes delivered thereunder is separate from and operates independently of each other Lease Indenture and Lessor Notes delivered thereunder, and the occurrence of an Indenture Event of Default under one Lease Indenture or the Lessor Notes delivered thereunder will not constitute an Indenture Event of Default under any other Lease Indentures or the Lessor Notes delivered thereunder. Each Lease Indenture contains substantially the same terms and provisions. The following is not a complete description of the Lessor Notes and Lease Indentures and is subject to, and qualified in its entirety by, reference to the Lessor Notes and the Lease Indentures, including the definitions of terms used in the Lessor Notes and the Lease Indentures.
The Lessor Notes and Payment
General
Each Lessor issued the Lessor Notes under a separate Lease Indenture dated as of July 1, 2007, between each Lessor and the applicable Indenture Trustee.
Payments of Interest and Principal and Maturity
Each Lessor must pay accrued interest in arrears on the unpaid principal amount of the Lessor Notes issued under its respective Lease Indenture commencing on December 1, 2007 and on each June 1 and December 1 thereafter at the rate of 6.85% per annum calculated on the basis of a 360-day year of twelve 30-day months, until the final Scheduled Distribution Date. Interest accrues from the Closing Date. The Lessor Notes will mature on June 1, 2034.
Principal payments will be made on the Lessor Notes on June 1 and December 1 in certain years, commencing on June 1, 2009. Scheduled payments of principal on the Lessor Notes, in the aggregate, are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Payment Dates | | | Payments of
Principal
of Series A
Lessor Note | | | Payments of
Principal
of Series B
Lessor Note | | | Payments of
Principal
of Series C
Lessor Note | | | Payments of
Principal
of Series D
Lessor Note | | | Payments of
Principal
of Series E
Lessor Note | | | Payments of
Principal
of Series F
Lessor Note | | | Aggregated
Payments of
Principal
of Lessor
Notes |
| December 1, 2007 | | | | $ | — | | | | | $ | — | | | | | $ | — | | | | | $ | — | | | | | $ | — | | | | | $ | — | | | | | $ | — | |
| June 1, 2008 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| December 1, 2008 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2009 | | | | | 1,683,000 | | | | | | 1,496,000 | | | | | | 1,496,000 | | | | | | 1,496,000 | | | | | | 1,496,000 | | | | | | 1,683,000 | | | | | | 9,350,000 | |
| December 1, 2009 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2010 | | | | | 2,178,000 | | | | | | 1,936,000 | | | | | | 1,936,000 | | | | | | 1,936,000 | | | | | | 1,936,000 | | | | | | 2,178,000 | | | | | | 12,100,000 | |
| December 1, 2010 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2011 | | | | | 2,331,000 | | | | | | 2,072,000 | | | | | | 2,072,000 | | | | | | 2,072,000 | | | | | | 2,072,000 | | | | | | 2,331,000 | | | | | | 12,950,000 | |
| December 1, 2011 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2012 | | | | | 9,135,000 | | | | | | 8,120,000 | | | | | | 8,120,000 | | | | | | 8,120,000 | | | | | | 8,120,000 | | | | | | 9,135,000 | | | | | | 50,750,000 | |
| December 1, 2012 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2013 | | | | | 11,061,000 | | | | | | 9,832,000 | | | | | | 9,832,000 | | | | | | 9,832,000 | | | | | | 9,832,000 | | | | | | 11,061,000 | | | | | | 61,450,000 | |
| December 1, 2013 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2014 | | | | | 11,853,000 | | | | | | 10,536,000 | | | | | | 10,536,000 | | | | | | 10,536,000 | | | | | | 10,536,000 | | | | | | 11,853,000 | | | | | | 65,850,000 | |
| December 1, 2014 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2015 | | | | | 12,690,000 | | | | | | 11,280,000 | | | | | | 11,280,000 | | | | | | 11,280,000 | | | | | | 11,280,000 | | | | | | 12,690,000 | | | | | | 70,500,000 | |
| December 1, 2015 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2016 | | | | | 11,394,000 | | | | | | 10,128,000 | | | | | | 10,128,000 | | | | | | 10,128,000 | | | | | | 10,128,000 | | | | | | 11,394,000 | | | | | | 63,300,000 | |
| December 1, 2016 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2017 | | | | | 3,573,000 | | | | | | 3,176,000 | | | | | | 3,176,000 | | | | | | 3,176,000 | | | | | | 3,176,000 | | | | | | 3,573,000 | | | | | | 19,850,000 | |
| December 1, 2017 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2018 | | | | | 8,109,000 | | | | | | 7,208,000 | | | | | | 7,208,000 | | | | | | 7,208,000 | | | | | | 7,208,000 | | | | | | 8,109,000 | | | | | | 45,050,000 | |
| December 1, 2018 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
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Table of Contents
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Payment Dates | | | Payments of
Principal
of Series A
Lessor Note | | | Payments of
Principal
of Series B
Lessor Note | | | Payments of
Principal
of Series C
Lessor Note | | | Payments of
Principal
of Series D
Lessor Note | | | Payments of
Principal
of Series E
Lessor Note | | | Payments of
Principal
of Series F
Lessor Note | | | Aggregated
Payments of
Principal
of Lessor
Notes |
| June 1, 2019 | | | | | 8,460,000 | | | | | | 7,520,000 | | | | | | 7,520,000 | | | | | | 7,520,000 | | | | | | 7,520,000 | | | | | | 8,460,000 | | | | | | 47,000,000 | |
| December 1, 2019 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2020 | | | | | 4,059,000 | | | | | | 3,608,000 | | | | | | 3,608,000 | | | | | | 3,608,000 | | | | | | 3,608,000 | | | | | | 4,059,000 | | | | | | 22,550,000 | |
| December 1, 2020 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2021 | | | | | 8,865,000 | | | | | | 7,880,000 | | | | | | 7,880,000 | | | | | | 7,880,000 | | | | | | 7,880,000 | | | | | | 8,865,000 | | | | | | 49,250,000 | |
| December 1, 2021 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2022 | | | | | 9,252,000 | | | | | | 8,224,000 | | | | | | 8,224,000 | | | | | | 8,224,000 | | | | | | 8,224,000 | | | | | | 9,252,000 | | | | | | 51,400,000 | |
| December 1, 2022 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2023 | | | | | 4,635,000 | | | | | | 4,120,000 | | | | | | 4,120,000 | | | | | | 4,120,000 | | | | | | 4,120,000 | | | | | | 4,635,000 | | | | | | 25,750,000 | |
| December 1, 2023 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2024 | | | | | 9,720,000 | | | | | | 8,640,000 | | | | | | 8,640,000 | | | | | | 8,640,000 | | | | | | 8,640,000 | | | | | | 9,720,000 | | | | | | 54,000,000 | |
| December 1, 2024 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2025 | | | | | 10,152,000 | | | | | | 9,024,000 | | | | | | 9,024,000 | | | | | | 9,024,000 | | | | | | 9,024,000 | | | | | | 10,152,000 | | | | | | 56,400,000 | |
| December 1, 2025 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2026 | | | | | 5,301,000 | | | | | | 4,712,000 | | | | | | 4,712,000 | | | | | | 4,712,000 | | | | | | 4,712,000 | | | | | | 5,301,000 | | | | | | 29,450,000 | |
| December 1, 2026 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2027 | | | | | 11,196,000 | | | | | | 9,952,000 | | | | | | 9,952,000 | | | | | | 9,952,000 | | | | | | 9,952,000 | | | | | | 11,196,000 | | | | | | 62,200,000 | |
| December 1, 2027 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2028 | | | | | 11,727,000 | | | | | | 10,424,000 | | | | | | 10,424,000 | | | | | | 10,424,000 | | | | | | 10,424,000 | | | | | | 11,727,000 | | | | | | 65,150,000 | |
| December 1, 2028 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2029 | | | | | 5,238,000 | | | | | | 4,656,000 | | | | | | 4,656,000 | | | | | | 4,656,000 | | | | | | 4,656,000 | | | | | | 5,238,000 | | | | | | 29,100,000 | |
| December 1, 2029 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2030 | | | | | 12,384,000 | | | | | | 11,008,000 | | | | | | 11,008,000 | | | | | | 11,008,000 | | | | | | 11,008,000 | | | | | | 12,384,000 | | | | | | 68,800,000 | |
| December 1, 2030 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2031 | | | | | 9,369,000 | | | | | | 8,328,000 | | | | | | 8,328,000 | | | | | | 8,328,000 | | | | | | 8,328,000 | | | | | | 9,369,000 | | | | | | 52,050,000 | |
| December 1, 2031 | | | | | 3,204,000 | | | | | | 2,848,000 | | | | | | 2,848,000 | | | | | | 2,848,000 | | | | | | 2,848,000 | | | | | | 3,204,000 | | | | | | 17,800,000 | |
| June 1, 2032 | | | | | 4,788,000 | | | | | | 4,256,000 | | | | | | 4,256,000 | | | | | | 4,256,000 | | | | | | 4,256,000 | | | | | | 4,788,000 | | | | | | 26,600,000 | |
| December 1, 2032 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2033 | | | | | 11,763,000 | | | | | | 10,456,000 | | | | | | 10,456,000 | | | | | | 10,456,000 | | | | | | 10,456,000 | | | | | | 11,763,000 | | | | | | 65,350,000 | |
| December 1, 2033 | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| June 1, 2034 | | | | | 234,000 | | | | | | 208,000 | | | | | | 208,000 | | | | | | 208,000 | | | | | | 208,000 | | | | | | 234,000 | | | | | | 1,300,000 | |
Each Lessor has leased its Undivided Interest in the Facility and subleased its interest in the Facility Site to the Lessee. See ‘‘Description Of The Leases And Other Operative Documents—The Leases, the Site Leases, the Site Subleases and the Support Agreement’’. Basic Rent under a Lease is paid semiannually on each June 1 and December 1, commencing December 1, 2007. Payments under a Lease in excess of the amounts required to make payments on the related Lessor Notes will be paid without interest by the applicable Indenture Trustee to the applicable Lessor for distribution to the applicable Owner Participant and will not be available for distribution to the Certificateholders except in certain cases upon the occurrence of an Indenture Event of Default.
Security
The Lessor Notes issued by each Lessor are secured by an assignment and pledge by such Lessor to the applicable Indenture Trustee of the Collateral under the applicable Lease Indenture. This Collateral includes an assignment of: (i) such Lessor’s rights under the applicable Lease, including the right to receive payments of Periodic Rent and Supplemental Rent thereunder; (ii) such Lessor’s rights under the applicable Guaranty; (iii) such Lessor’s interest in the Facility and the Ground Interest granted to such Lessor pursuant to the applicable Site Lease; and (iv) such Lessor’s interest in certain of the other related Operative Documents described herein (excluding in all cases Excepted Payments).
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Table of ContentsLimitation of Liability
The Lessor Notes are not the obligations of or guaranteed by the Lessee, FES, the applicable Owner Participant or the applicable Lessor. None of the applicable Lessor, Owner Participant, Trust Company, Indenture Company and Indenture Trustee, nor any affiliates thereof, are personally liable to any holder of a Lessor Note or to the applicable Indenture Trustee for any amounts payable under such Lessor Note, for any performance to be rendered under any document assigned pursuant to the Lease Indenture or for any liability under any such document, or except as provided in the applicable Lease Indenture, for any liability under any Assigned Document. All payments of principal of, and Make-Whole Amount, if any, and interest on the applicable Lessor Notes (other than payments made in connection with any redemption or purchase by such Lessor) will be made only from the assets subject to the Lien of the applicable Lease Indenture.
Redemption of Lessor Notes
The Lessor Notes are subject to redemption under the circumstances described below. The Pass Through Trustee will make distributions to the Certificateholders of the Pass Through Trust related to the Lessor Notes being redeemed on the date and in the amount paid in respect of the redemption of those Lessor Notes.
Redemptions with Make-Whole Amount
Lessor Notes shall be redeemed, in whole but not in part, as provided below, at the redemption price equal to the principal amount thereof, together with accrued and unpaid interest thereon, if any, to the date of redemption, plus the Make-Whole Amount, on the earliest to occur of:
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| (1) | if the obligations represented by the Lessor Notes shall have been refinanced, in whole but not in part, on the date of such refinancing; |
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| (2) | if the applicable Lease is terminated as a result of a Burdensome Termination Event, the applicable Burdensome Termination Date provided in such Lease; and |
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| (3) | if the applicable Lease is terminated as a result of a breach by the applicable Lessor, the applicable Owner Breach Termination Date provided in such Lease. |
See ‘‘Description Of The Leases And Other Operative Documents—Burdensome Termination Option’’ and ‘‘Owner Breach Termination.’’
The Make-Whole Amount payable with respect to any Lessor Note to be redeemed will be determined by an investment banking institution of national standing in the United States selected by the Lessee or, if the applicable Lessor or the applicable Indenture Trustee does not receive notice of such selection at least 10 days prior to a scheduled prepayment date or if a Lease Event of Default under the applicable Lease shall have occurred and be continuing, selected by the applicable Lessor, provided that the same investment banking institution will also calculate the Special Event Amount payable concurrently therewith under the applicable Lease.
Make-Whole Amount means, with respect to any Lessor Note, an amount equal to the excess, if any, of (a) the present value of the remaining scheduled payments of principal and interest to maturity of such Lessor Note computed by discounting such payments on a semiannual basis on each payment date under the applicable Lease Indenture (assuming a 360-day year of twelve 30-day months) using a discount rate equal to the Treasury Yield plus 0.35% over (b) the outstanding principal amount of such Lessor Note plus accrued interest to the date of determination. The date of determination of a Make-Whole Amount shall be the third Business Day prior to the applicable payment or redemption date.
Treasury Yield means, at the date of determination with respect to any Lessor Note, the interest rate (expressed as a decimal and, in the case of United States Treasury bills, converted to a bond equivalent yield) determined to be the per annum rate equal to the semiannual yield to maturity for United States Treasury securities maturing on the Average Life Date of such Lessor Note and trading
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Table of Contentsin the public securities markets either as determined by interpolation between the most recent weekly average yield to maturity for two series of United States Treasury securities trading in the public securities markets, (A) one maturing as close as possible to, but earlier than, the Average Life Date of such Lessor Note and (B) the other maturing as close as possible to, but later than, the Average Life Date of such Lessor Note, in each case as published in the most recent H.15(519) or, if a weekly average yield to maturity for United States Treasury securities maturing on the Average Life Date of such Lessor Note is reported in the most recent H.15(519), such weekly average yield to maturity as published in such H.15(519).
Average Life Date for any Lessor Note shall be the date which follows the time of determination by a period equal to the Remaining Weighted Average Life of such Lessor Note.
Remaining Weighted Average Life on a given date with respect to any Lessor Note shall be the number of days equal to the quotient obtained by dividing (a) the sum of each of the products obtained by multiplying (i) the amount of each then remaining scheduled payment of principal of such Lessor Note by (ii) the number of days from and including such determination date to but excluding the date on which such payment of principal is scheduled to be made, by (b) the then outstanding principal amount of such Lessor Note.
H.15(519) means the weekly statistical release designated as such, or any successor publication, published by the Board of Governors of the Federal Reserve System and the ‘‘most recent H.15(519)’’ means the H.15(519) published prior to the close of business on the third Business Day prior to the applicable payment or redemption date.
Redemptions without Make-Whole Amount
Lessor Notes shall be redeemed, in whole but not in part, at a price equal to the principal amount thereof, together with accrued and unpaid interest thereon, if any, to the date of redemption, but without any Make-Whole Amount or other premium, on the applicable Termination Date if the applicable Lease is terminated as a result of the occurrence of an Event of Loss. See ‘‘Description Of The Leases And Other Operative Documents—Events of Loss.’’
Indenture Events of Default
An event of default under a Lease Indenture, or an Indenture Event of Default, shall mean any of the following:
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| 1. | a Lease Event of Default (other than (i) with respect to any Excepted Payments and (ii) in consequence of the Lessee’s failure to maintain required insurance if, and so long as, (x) such Lease Event of Default is waived by the applicable Lessor and Owner Participant and (y) the insurance maintained by the Lessee still constitutes Prudent Industry Practice; or |
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| 2. | the applicable Lessor shall fail to pay the principal of, or Make-Whole Amount, if any, or interest on, or any scheduled fees due and payable under or with respect to any Lessor Note within 10 days after the same shall have become due or any other amounts due and payable under or with respect to any Lessor Note within 30 days after the applicable Lessor receives notice that such amount is due and payable; or |
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| 3. | failure, in any material respect, by (a) the applicable Lessor to perform or observe any material covenant, obligation or agreement to be performed or observed by it under the related Lease Indenture, (b) applicable Lessor or Owner Participant to perform or observe any material covenant, obligation or agreement to be performed or observed by it under the related Participation Agreement, or (c) the OP Guarantor to perform or observe any material covenant, obligation or agreement to be performed by it under the OP Guaranty (provided the OP Guaranty shall not have been terminated or released), which failure shall continue unremedied for 30 days after receipt by such party of written notice; provided, however, that if such condition cannot be remedied within such 30-day period, then the period within which to remedy such condition shall be extended up to 180 days as long as such defaulting party diligently pursues such remedy and such condition may reasonably be remedied within the 180 days; or |
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| 4. | any representation or warranty made by the applicable Lessor or the applicable Owner Participant under the applicable Participation Agreement by the OP Guarantor (provided the OP Guaranty shall not have been terminated or released) under the OP Guaranty, or in the certificate delivered by such Lessor, Owner Participant or OP Guarantor under the applicable Participation Agreement shall prove to have been incorrect in any material respect as of the date made and continues to be material and unremedied for a period of 30 days after receipt by such party of written notice thereof; provided, however, that if such condition cannot be remedied within such 30-day period, then the period within which to remedy such condition shall be extended up to 180 days as lo ng as such defaulting party diligently pursues such remedy and such condition may reasonably by remedied within such extended period; or |
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| 5. | certain events of bankruptcy and insolvency, whether voluntary or involuntary, with respect to an Owner Participant, the OP Guarantor (provided the OP Guaranty shall not have been terminated or released) or a Lessor. |
Remedies
Upon the occurrence of an Indenture Event of Default under a particular Lease Indenture, the applicable Indenture Trustee, in its discretion may, or upon receipt of written instructions from a Majority in Interest of Noteholders under such Lease Indenture, shall declare, by written notice to the applicable Owner Participant and the applicable Lessor, the unpaid principal amount of all Lessor Notes issued thereunder, with accrued and unpaid interest thereon, but without any Make-Whole Amount to be immediately due and payable, upon which declaration such principal amount and such accrued and unpaid interest shall immediately become due and payable (except in the case of an Indenture Event of Default under certain events of bankruptcy and insolvency described above, such principal and interest shall automatically become due and payable immediately without any such declaration or notice) without further act or notice.
In addition, if an Indenture Event of Default shall have occurred and be continuing under a Lease Indenture, then the applicable Indenture Trustee may, and where required pursuant to the provisions of such Lease Indenture shall, upon written notice to the applicable Lessor and Owner Participant, exercise any or all of the rights and powers and pursue any or all of the remedies provided for in such Lease Indenture and, in the event such Indenture Event of Default shall be a Lease Event of Default, any and all of the remedies provided pursuant to the applicable provisions of such Lease Indenture and such Lease, may take possession of all or any part of such Lessor’s Undivided Interest in such Lease Indenture Estate and may exclude therefrom the applicable Owner Participant, such Lessor, and in the event such Indenture Event of Default shall be a Lease Event of Default, the Lessee and all persons claiming under them, and may exercise all remedies available to a secured party under the Uniform Commercial Code or any other provision of applicable law. Notwithstanding the foregoing, neither the applicable Indenture Trustee nor any Noteholder shall at any time, including at any time when an Indenture Event of Default shall have occurred and be continuing and there shall have occurred and be continuing a Lease Event of Default, be entitled to exercise any such remedy which could or would divest the applicable Lessor of title to, or its ownership interest in, any portion of the applicable Lease Indenture Estate unless the applicable Indenture Trustee shall have, to the extent it is then entitled to do so under the applicable Lease Indenture or under any other Operative Document and is not then stayed or otherwise prevented from doing so by operation of law, commenced and is diligently pursuing, in good faith, the exercise of one or more remedies under such Lease intending to dispossess the Lessee of its leasehold interest in the Undivided Interest; provided that durin g any period that such Indenture Trustee is stayed or otherwise prevented by operation of law from exercising such remedies, the applicable Indenture Trustee will not divest the applicable Lessor of title to, or its ownership interest in, any portion of such Lease Indenture Estate until the earliest of (a) the expiration of the 180-day period following the date of the commencement of a stay or other prevention provided that such 180-day period shall be extended through any period thereafter in which no Lease Event of Default shall have occurred and be continuing other than a Lease Event of Default as result of the bankruptcy or insolvency of the Lessee or the Lease Guarantor, (b) the date the applicable Lease is rejected in accordance with a final
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Table of Contentsand non-appealable order of the bankruptcy court or (c) the date of repossession of the Facility under the applicable Lease, provided that, in each case, the applicable Indenture Trustee shall have given at least 10 Business Days’ prior notice to the applicable Lessor and Owner Participant of such Indenture Trustee’s intention to exercise remedies which could or would divest the applicable Lessor of title to, or its ownership interest in, any portion of the applicable Lease Indenture Estate.
To the fullest extent permitted by applicable law, all rights of action and rights to assert claims under any Lease Indenture or under any of the Lessor Notes issued thereunder may be enforced by the applicable Indenture Trustee without the possession of the Lessor Notes at any trial or other proceedings instituted by such Indenture Trustee, and any such trial or other proceedings shall be brought in its own name as mortgagee of an express trust, and any recovery or judgment shall be for the ratable benefit of the applicable Noteholders. In any proceedings brought by an Indenture Trustee (and also any proceedings involving the interpretation of any provision of the applicable Lease Indenture), such Indenture Trustee shall be held to represent all the applicable Noteholders, and it shall not be necessary to make any such persons parties to such proceedings.
Right to Cure
If the Lessee shall fail to make any payment of Periodic Rent due on any Rent Payment Date, and if such failure of the Lessee to make such payment of Periodic Rent shall not constitute more than the third consecutive such failure or sixth cumulative failure of the Lessee, then the applicable Lessor or Owner Participant may cure any Lease Event of Default by making a payment of such Periodic Rent together with any interest due thereon on account of the delayed payment thereof at any time prior to the expiration of 10 Business Days after the applicable Lessor and Owner Participant would have received notice or have actual knowledge of the Lessee’s failure to make such Periodic Rent payments.
Certain Rights of the Lessor
Notwithstanding any other provision of the applicable Lease Indenture or any provision of any Operative Document to the contrary, and in addition to any rights conferred on each Lessor by the applicable Lease Indenture:
(a) Each Lessor shall at all times, to the exclusion of the applicable Indenture Trustee, (i) retain all rights to demand and receive payment of, and to commence an action for payment of, Excepted Payments owing to it but each Lessor shall have no remedy or right with respect to any such payment against the Lease Indenture Estate nor any right to collect any such payment by the exercise of any of its remedies under the applicable Lease in respect of a Lease Event of Default except as expressly provided in this paragraph (a) through paragraph (f) below; (ii) retain all rights with respect to insurance that the applicable Lease specifically confers upon such Lessor and to waive any failure by the Lessee to maintain such insurance before or after the fact so long as the insurance maintained by the Lessee still conforms to Prudent Industry Practice; (iii) retain all rights to adjust Periodic Rent and Termination Amounts as provided in the applicable Lease, the applicable Participation Agreement or the Tax Indemnity Agreement; provided, however, that after giving effect to any such adjustment, (x) the Basic Rent payable on any Rent Payment Date shall be in an amount at least sufficient to pay in full the scheduled payments required to be made in respect of principal of, and all accrued and unpaid interest on, the Lessor Notes due and payable on such Rent Payment Date and (y) Termination Amounts or PVRR Amounts payable on any date shall, together with all Basic Rent due and owing on such date, be in an amount at least sufficient to pay in full the principal of, and all accrued and unpaid interest on, the Lessor Notes due and payable on such date; (iv) except in connection with the exercise of remedies pursuant to the applicable Lease, retain all rights to exercise such Lessor’s rights relating to the Appraisal Procedure and to confer and agree with the Lessee on fair market rental value or fair market sales value, or any renewal term; an d (v) retain the right to declare the applicable Lease to be in default with respect to any Excepted Payment pursuant to the applicable Lease.
(b) Each Lessor shall have the right, together with or independently of the applicable Indenture Trustee, (i) to receive from the Lessee and the Lease Guarantor all notices, certificates,
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Table of Contentsreports, filings, opinions of counsel and other documents and all information that the Lessee or the Lease Guarantor is permitted or required to give or furnish to each Lessor or the applicable Owner Participant, as the case may be, pursuant to the applicable Lease or any other Operative Document; (ii) to inspect the Facility and the records relating thereto pursuant to the applicable Lease; (iii) to provide such insurance as may be permitted under the applicable Lease; (iv) to provide notices to the Lessee or the Lease Guarantor to the extent otherwise permitted by the Operative Documents; and (v) to perform for the Lessee as provided in the applicable Lease.
(c) So long as the Lessor Notes have not been accelerated (or, if accelerated, such acceleration has been rescinded) or the applicable Indenture Trustee shall not have exercised any of its rights under the applicable Lease Indenture to take possession of, foreclose, sell or otherwise take control of all or any part of the Lease Indenture Estate, each Lessor shall retain the right to the exclusion of the applicable Indenture Trustee to exercise the rights of such Lessor under the provisions of the applicable Lease relating to Events of Loss, Lease renewals, Burdensome Termination Events and other termination events (provided, however, that no such provision related to the due date and amount of the repayment of the Lessor Notes or to the due date and amount of the payment of Periodic Rent, Termination Amount, PVRR Amount or Special Event Amount may be waived or altered without the consent of the applicable Indenture Trustee), under the Supp ort Agreement and the operating agreement for the Mansfield Plant.
(d) Except as expressly provided in the applicable Lease Indenture, so long as the Lessor Notes have not been accelerated (or, if accelerated, such acceleration has been rescinded) or the applicable Indenture Trustee shall not have exercised any of its rights under the applicable Lease Indenture to take possession of, foreclose, sell or otherwise take control of all or any part of the Lease Indenture Estate, each Lessor shall have the right, to be exercised jointly with the applicable Indenture Trustee, (i) to exercise the rights with respect to the Lessee’s use and operation, modification or maintenance of the Undivided Interest, and (ii) to exercise such Lessor’s right under the applicable Participation Agreement to withhold or grant its consent to an assignment by the Lessee of its rights under the applicable Lease.
(e) So long as the Lessor Notes have not been accelerated or the applicable Indenture Trustee shall not have exercised any of its rights under the applicable Lease Indenture to take possession of, foreclose, sell or otherwise take control of all or any part of the Lease Indenture Estate, each Lessor shall have the right, together with the applicable Indenture Trustee and to the extent permitted by the Operative Documents and applicable law, to seek specific performance of the covenants of the Lessee and the Lease Guarantor under the applicable Operative Documents relating to the protection, insurance, maintenance, possession, use and return of the applicable Undivided Interest.
(f) Nothing in the applicable Lease Indenture shall give to, or create in, or otherwise provide the benefit of to, the applicable Indenture Trustee, any rights of the applicable Owner Participant under or pursuant to the Tax Indemnity Agreement, the operating agreement for the Mansfield Plant or any other Operative Document and nothing in the applicable Lease Indenture shall give to each Lessor the right to exercise any rights specifically given to the applicable Indenture Trustee pursuant to any Operative Document; and nothing in the applicable Lease Indenture shall give to, or create in, the applicable Indenture Trustee the right to, and the applicable Indenture Trustee shall not, release the Lease Guarantor of its obligations under the applicable Guaranty in respect of payment of the equity portion of Termination Amount, unpaid amounts of the equity portion of Periodic Rent (and all amounts of overdue interest relating to such amount) a nd other amounts constituting Excepted Payments, unless such release results in payment in full to the applicable Lessor of all such unpaid amounts as certified to the applicable Indenture Trustee by such Lessor, and all claims of the Noteholders; but nothing in paragraphs (a) through this (f) above shall deprive the applicable Indenture Trustee of the exclusive right, so long as the applicable Lease Indenture shall be in effect, to declare the applicable Lease to be in default and thereafter to exercise the remedies under the applicable Lease (except as expressly set forth in the proviso in paragraph (a) above).
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Table of ContentsLessors’ Right to Purchase the Lessor Notes
Each Noteholder and the applicable Indenture Trustee agrees, that if (i) (x) an Indenture Event of Default, which also constitutes a Lease Event of Default, shall have occurred and be continuing for a period of at least 180 days, (y) the Lessor Notes have been accelerated and such acceleration has not theretofore been rescinded, or (z) an Enforcement Notice has been given under the applicable Lease Indenture, (ii) no Indenture Event of Default of the nature described in any of clauses (b) through (f) under ‘‘—Indenture Events of Default’’ above shall have occurred and be continuing and (iii) the applicable Lessor shall give written notice to the applicable Indenture Trustee of such Lessor’s intention to purchase all of its Lessor Notes, then, upon receipt within 10 business days after such notice from such Lessor of an amount equal to the sum of (x) the aggregate unpaid principal amount of any unpaid Lessor Notes then hel d by the Noteholders, together with accrued but unpaid interest thereon to the date of such receipt (as well as any interest on overdue principal and, to the extent permitted by applicable law, overdue interest), plus (y) the aggregate amount, if any, of all sums which such Noteholder would be entitled to be paid before any payments were to be made to the applicable Lessor, but excluding any Make-Whole Amount, such Noteholder will forthwith (and upon its receipt of the payment referred to in clause (1) below, will be deemed to) sell, assign, transfer and convey to the applicable Lessor (without recourse or warranty of any kind other than of title to the Lessor Notes so conveyed) all of the right, title and interest of such Noteholder in and to the Lease Indenture Estate, the applicable Lease Indenture, all Lessor Notes held by such Noteholder and the Assigned Documents, and the applicable Lessor shall thereupon assume all such Noteholder’s rights and obligations in such documents; provided that no such holder shall be required to so convey unless (1) the applicable Lessor shall have simultaneously tendered payment on all other Lessor Notes issued by the applicable Lessor at the time outstanding pursuant to this paragraph and (2) such conveyance is not in violation of any applicable law. All charges and expenses required to be paid in connection with the issuance of any new Lessor Note or Lessor Notes in connection with this paragraph shall be borne by the applicable Lessor. Notwithstanding the foregoing, the applicable Lessor may exercise the right set forth in this paragraph prior to the end of the 180-day period set forth above but, in such case, the Make-Whole Amount, if any, shall also be payable. Following the receipt of a notice of the applicable Lessor’s intention to purchase all of the Lessor Notes, the applicable Indenture Trustee shall refrain from exercising any further remedies provided pursuant to the applicable Lease Indenture or Lease through the date of scheduled purchase. Any repurc hase of the Lessor Notes will result in a Special Distribution to Certificateholders. See ‘‘Description Of The Exchange Certificates—Distributions.’’ Enforcement Notice means the Indenture Trustee’s written notice to the applicable Lessee, each Lessor and Owner Participant not less than 10 Business Days prior to the date on or after which such Indenture Trustee intends to accelerate the applicable Lessor Notes and/or exercise remedies under the applicable Lease Indenture.
Modification of Operative Documents
Without the consent of any Noteholders and with the consent of the applicable Lessor, an Indenture Trustee under a Lease Indenture shall enter into any indenture or indentures supplemental thereto or execute any amendment, modification, supplement, waiver or consent with respect to any other related Operative Document (a) to evidence the succession of another Person as Lessor or the appointment of a co-Lessor in accordance with the terms of a trust agreement, or to evidence the succession of a successor as Indenture Trustee, the removal of an Indenture Trustee, the appointment of any separate or additional trustee or trustees, the succession of a successor Account Bank under the applicable Lease Indenture or the removal of the Account Bank, and to define the rights, powers, duties and obligations conferred upon any such separate trustee or trustees or co-trustee or co-trustees, (b) to correct, confirm or amplify the description of any property at any time subjec t to the Lien of the applicable Lease Indenture or to convey, transfer, assign, mortgage or pledge any property to or with the applicable Indenture Trustee, (c) to provide for any evidence of the creation and issuance of any Additional Lessor Notes and to establish the form and the terms of such Additional Lessor Notes, (d) to cure any ambiguity in, to correct or supplement any defective or inconsistent provision of, or to add to or modify any other provisions and agreements in, the applicable Lease Indenture or any other Operative Document in any manner that will not in the
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Table of Contentsjudgment of such Indenture Trustee materially adversely affect the interests of the Noteholders, (e) to grant or confer upon the applicable Indenture Trustee for the benefit of the Noteholders any additional rights, remedies, powers, authority or security which may be lawfully granted or conferred and which are not contrary or inconsistent with the applicable Lease Indenture, (f) to add to the covenants or agreements to be observed by the Lessee or the applicable Lessor and which are not contrary to the applicable Lease Indenture, to add Indenture Events of Defaults for the benefit of Noteholders or surrender any right or power of the applicable Lessor, provided it has consented thereto, (g) to comply with requirements of the SEC, any applicable law, rules or regulations of any exchange or quotation system on which the Original or Exchange Certificates are listed, or any regulatory body, (h) to modify, eliminate or add to the provisions of any Operative Documents to such extent as shall be necessary to qualify or continue the qualification of the applicable Lease Indenture or the Pass Through Trust Agreement (including any supplements thereto) under the Trust Indenture Act, or similar federal statute enacted after the Closing Date, and to add to such Lease Indenture such other provisions as may be expressly required or permitted by the Trust Indenture Act (if such qualification is required), and (i) to effect any indenture or indentures supplemental to such Lease Indenture or any amendment, modification, supplement, waiver or consent with respect to any other Operative Document, provided such supplemental indenture, amendment, modification, supplement, waiver or consent shall not reasonably be expected to materially and adversely affect the interest of the Noteholders; provided, however, that no such amendment, modification, supplement, waiver or consent contemplated above, shall without the consent of the holder of each then outstanding Lessor Note, (i) modify the definition of the term ‘‘Majo rity in Interest of Noteholders’’ or reduce the percentage of applicable Noteholders required to take or approve any action under the applicable Lease Indenture, (ii) change the amount or the time of payment of any amount owing or payable under any Lessor Note or change the rate or manner of calculation of interest payable on any Lessor Note, (iii) alter or modify the provisions of the applicable Lease Indenture with respect to the manner of payment or the order of priorities in which distributions under the applicable Lease Indenture shall be made as between the applicable Noteholders and the applicable Lessor, (iv) reduce the amount (except to any amount as shall be sufficient to pay the aggregate principal of, Make-Whole Amount, if any, and interest, including additional interest, if any, accruing under the circumstances and at the rate per annum set forth in each Lessor Note) on all outstanding Lessor Notes or extend the time of payment of Periodic Rent, PVRR Amount, Termination Amount or Spe cial Event Amount except as expressly provided in the applicable Lease, or change any of the circumstances under which Periodic Rent, PVRR Amount, Termination Amount or Special Event Amount is payable, (v) consent to any assignment of the applicable Lease if in connection therewith the Lessee will be released from its obligation to pay Periodic Rent, PVRR Amount, Termination Amount or Special Event Amount or release the Lessee of its obligation to pay Periodic Rent, PVRR Amount, Termination Amount or Special Event Amount, or change the absolute and unconditional character of such obligations as set forth in such Lease, (vi) consent to any release of the applicable Lease Guarantor under an applicable Guaranty or (vii) deprive the applicable Indenture Trustee of the relevant Lien on the Lease Indenture Estate or permit the creation of any Lien on the applicable Lease Indenture Estate ranking equally or prior to the Lien of such Indenture Trustee, except for Permitted Liens, and provided, further, that no such amendment, modification, supplement, waiver or consent contemplated in this paragraph shall, without the consent of the holder of a Majority in Interest of Noteholders, modify certain covenants and other rights and obligations of the Lessee and the applicable Owner Participant under the applicable Participation Agreement or the provisions of the applicable Lease, including assignments of any Operative Document, or modify in any material respect the provisions of the applicable Guaranty or the applicable Site Lease (other than, in each case, any amendment, modification, supplement, waiver or consent having no adverse affect on the interest of the Noteholders).
Discharge of Lien
Whenever a Component is replaced pursuant to a Lease, such Component shall automatically and without further act of any Person be released from the Lien of the applicable Lease Indenture and the applicable Indenture Trustee shall, upon the written request of the applicable Lessor or the Lessee,
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Table of Contentsexecute and deliver to, and as directed in writing by, the Lessee or the applicable Lessor an appropriate instrument (in due form for recording) releasing the replaced Component from the Lien of the applicable Lease Indenture.
Whenever the Lessee is entitled to acquire its Undivided Interest in the Facility or have its Undivided Interest in the Facility transferred to it pursuant to the express terms of a Lease, the applicable Indenture Trustee shall release the Lease Indenture Estate from the Lien of the applicable Lease Indenture and execute and deliver to, or as directed in writing by, the Lessee or the applicable Lessor an appropriate instrument (in due form for recording) releasing the Lease Indenture Estate from the Lien of the applicable Lease Indenture; provided that all sums secured by the applicable Lease Indenture have been paid to the Persons entitled to such sums.
Indenture Trustee
The Bank of New York Trust Company, N.A. is the Indenture Trustee under each Lease Indenture. Each Indenture Trustee shall pay, or cause to be paid, to the Pass Through Trustee all amounts then due on the applicable Lessor Notes, and the Pass Through Trustee will forward such amounts to the Certificateholders. The Bank of New York Trust Company, N.A. is also the Pass Through Trustee.
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Table of ContentsDESCRIPTION OF THE LEASES AND OTHER OPERATIVE DOCUMENTS
The following provides a summary of the material provisions of the Facility Lease Agreements, each referred to as a Lease, pertaining to the Undivided Interest. Leases were entered into between six separate Delaware statutory trusts, each held by an Owner Participant having a tangible net worth, or being guaranteed by an entity having a tangible net worth, of not less than $75 million, as Lessors, and FGCO, as Lessee, and have leased the Total Undivided Interest (as described more fully below) to the Lessee for an initial term of 32 years and 11 months. Each Lease contains substantially the same terms and provisions. The following provides only a summary description of the Leases and is subject to, and qualified by, reference to the Leases in their entirety, including the Participation Agreement and exhibit of defined terms used in the Leases.
The Leases, the Site Leases, the Site Subleases and the Support Agreement
On the Closing Date, each Lessor purchased, pursuant to a bill of sale, an Undivided Interest in the Facility, which it holds for the benefit of its related Owner Participant and provides as security for the Lessor Notes under a Lease Indenture. Each Lessor simultaneously leased its Undivided Interest to the Lessee under a net Lease for an initial term of 32 years and 11 months. In connection with the sale of each Undivided Interest to the applicable Lessor, the Lessee, as current co-owner of the Facility Site, leased the applicable Ground Interest to each Lessor for the full estimated useful life of the Facility pursuant to a separate Site Lease, and each Lessor subleased the Facility Site to the Lessee for the term of the Lease pursuant to the Site Sublease. The Lessee has also provided each Lessor with certain rights necessary for such Lessor to use the Facility upon the termination of the Lease, including with respect to the operation of the Facility, access to and use of the Facility and certain ancillary facilities common to the Mansfield Plant, pursuant to a separate Support Agreement. FES has entered into separate Guaranties in favor of each Lessor pursuant to which it unconditionally and irrevocably guarantees all of the Lessee’s obligations under the related Operative Documents. See ‘‘Description Of The Guaranties.’’
Undivided Interest
Each Undivided Interest subject to a Lease represents a proportionate interest in Unit 1 of the Mansfield Plant, a 830 MW coal-fired electric power generating unit located in Shippingport, Pennsylvania and more fully described in ‘‘Description Of The Facility.’’ The Total Undivided Interest to be acquired collectively by the Lessors is equal to 93.825% of the Facility. The remaining 6.175% undivided interest in the Facility is held by owner trusts pursuant to other sale and leaseback arrangements not related to this transaction. See ‘‘Description Of The Facility—1987 Sale and Leaseback.’’
Term and Rent
The term of each Lease commenced on July 13, 2007, the Closing Date, and will continue to and include June 13, 2040, subject to earlier termination upon the occurrence of certain events described below under ‘‘—Events of Loss,’’ ‘‘—Burdensome Termination Option,’’ ‘‘—Termination Due to Lessor Actions,’’ and ‘‘—Lease Events of Default.’’ Rent payable under each Lease consists of Basic Rent, which is payable in arrears on December 1, 2007, each June 1 and December 1 thereafter to the end of the Lease Term and on the last day of the Lease Term, each a Rent Payment Date, and Supplemental Rent, which includes all amounts, liabilities and obligations of the Lessee arising out of the Operative Documents, other than Basic Rent, including, without limitation, the Termination Amount and the PVRR Amount. Each term o f each Lease may be extended for one or more renewal terms.
Rights and Obligations of the Lessee
Maintenance and Repair
The Lessee is required by each Lease, at its own cost and expense, to maintain the Facility and the Ancillary Facilities such that the Facility and the Ancillary Facilities may be operated (a) in
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Table of Contentsaccordance with Prudent Industry Practice (as defined below), (b) in compliance with all applicable laws, rules and regulations, including environmental laws, subject to customary rights to contest the application of any such law, rule or regulation in good faith through appropriate proceedings and except to the extent any failure to comply would not reasonably be expected to result in a material adverse effect, (c) in accordance with the terms of all insurance policies required to be maintained under such Lease and the operating agreement for the Mansfield Plant, (d) without discriminating against the Facility solely because the Undivided Interest is leased to and not owned by the Lessee, and (e) in accordance with such operating standards as will be required to take advantage of and enforce all available warranties and consistent with manufacturer’s recommendations. The Lessee is also required to make all repairs, renewals, replacements, betterments and improvements to the Facility and the Ancillary Facilities as in the reasonable good faith judgment of the Lessee may be necessary or commercially advisable so that the Facility and the Ancillary Facilities may be operated in accordance with their intended purposes, and consistent with clauses (a) through (e) in the preceding sentence, the operating agreement and the estimated remaining economic useful life of the Facility as set forth in the independent engineer’s report and the appraisal delivered on the Closing Date pursuant to the applicable Operative Documents. The timing of such repairs, renewals, replacements, betterments and improvements are in the sole discretion of the Lessee. Subject to clauses (i) and (ii) above, the determination of the appropriate course of action in maintenance and all other matters pertaining to the Undivided Interest is also within the sole discretion of the Lessee, and the Lessee is not required to consult with the applicable Owner Participant or Lessor with regard thereto. Should the Lessee determine that any part s, components or portions of the Facility are obsolete, it may at its sole discretion and cost remove such parts, components or portions without replacing them, but only if doing so will not diminish the fair market value or residual value of the Undivided Interest or the remaining useful life of the Facility by more than a de minimis amount and will not cause the Facility to become ‘‘limited use property’’ for tax purposes.
Prudent Industry Practice means, at a particular time, (a) any of the practices, methods and acts engaged in or approved by a significant portion of the competitive coal-fired electric generating industry operating similarly situated facilities in the eastern United States at such time, or (b) with respect to any matter to which clause (a) does not apply, any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, would reasonably have been expected to (i) accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition and (ii) maintain the Facility in as good of condition as when delivered to the Lessee, ordinary wear and tear excepted. Prudent Industry Practice is not intended to be limited to the optimum practice, method or act to the exclusion of all others, but rather to be a spectrum of possible practices, m ethods or acts having due regard for, among other things, manufacturers’ warranties and the requirements of any governmental entity having jurisdiction.
Modifications
The Lessee is required by each Lease to make or cause to be made, at its own cost and expense, any modifications, alterations or improvements, or Modifications, to the Facility and the Ancillary Facilities as are required by applicable law or by any governmental entity having jurisdiction, any insurance policy required to be maintained under the Operative Documents, or the terms of any other Operative Document, each, a Required Modification, subject to customary rights to contest the validity or application of such requirements in good faith through appropriate proceedings. The Lessee may also make or cause to be made, at its own cost and expense, any Modifications as the Lessee considers desirable in the proper conduct of its business, or Optional Modifications, provided that such Optional Modifications will not decrease the fair market value, remaining useful life or utility of the Facility by more than a de minimis amount, or cause the Facility to be characte rized as limited use property for tax purposes.
The Lessee retains ownership and title to any Modification which is not a Required Modification and is a Severable Modification (other than Severable Modifications which are financed by the applicable Lessor). Upon a return of the Undivided Interest, the applicable Lessor has the right to
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Table of Contentspurchase the Severable Modifications at their then fair market value as of such return. If not so purchased, such Severable Modifications will become assets made available to such Lessor through the Support Agreement, if reasonably necessary or commercially advisable for the economic operation of the Undivided Interest. If such Lessor does not elect to purchase the Severable Modifications or the Lessee does not make the Severable Modifications available through the Support Agreement, the Lessee may remove such Modifications at the end of the Lease Term at the Lessee’s cost and expense.
The applicable Lessor has acquired title, at no cost, to an undivided interest equal to such Lessor’s percentage of the Total Undivided Interest in all non-Severable Modifications and Required Modifications, which interest is subject to the applicable Lease and the Lien of the applicable Lease Indenture securing the applicable Lessor Notes.
Subject to certain conditions, the cost of all non-Severable and Required Modifications may be financed through additional non-recourse borrowings.
Sublease
The Lessee has the right to sublease an Undivided Interest without the consent of the applicable Lessor, Owner Participant or Indenture Trustee or the Pass Through Trustee or any other person, if (a) the sublessee is a United States Person within the meaning of Section 7701(a)(30) of the Code (as defined below in ‘‘Certain U.S. Federal Income Tax Considerations’’) that (i) is a solvent corporation, partnership, business trust, limited liability company or any other entity (not an individual) not subject to bankruptcy proceedings, (ii) is not involved in any material litigation with the applicable Owner Participant, OP Guarantor or any of their respective affiliates and (iii) is, or its obligations under the sublease are guaranteed by, or contracted to be performed by, an experienced, reputable operator of United States-based, coal-fired electric generating facilities similar to the Facility, (b) all terms and conditions of the applicable Lease and the other related Operative Documents remain in effect and the Lessee remains fully and primarily liable for its obligations under such Lease and such other Operative Documents, and the Lease Guarantor remains fully liable for its obligations under the applicable Guaranty, (c) such sublease does not extend beyond the scheduled expiration of the Lease Term then in effect or any renewal term elected by the Lessee (and may be terminated upon early termination of the applicable Lease) and is expressly subject and subordinate to such Lease, (d) no Material Default (as defined below) or Lease Event of Default (as defined below under ‘‘—Lease Events of Default’’) under the applicable Lease will have occurred and be continuing, (e) such sublease prohibits further assignment or subletting, (f) the Lessee provides the applicable Lessor with 30 days’ written notice of the Lessee’s intent to enter into the sublease, (g) such sublease requires the sublessee to operate a nd maintain the Undivided Interest in a manner consistent with such Lease, (h) such sublease will not cause the property to become ‘‘tax-exempt use property’’ within the meaning of Section 168(h) of the Code during the period the applicable Owner Participant is claiming certain tax deductions (unless the Lessee compensates such Owner Participant for the resulting adverse tax consequences), (i) and the Lessee assigns its rights under such sublease to the applicable Lessor as security for the Lessee’s obligations under the applicable Operative Documents, (j) the applicable Lessor, Owner Participant, and so long as the Lessor Notes are outstanding, Indenture Trustee have received an opinion of counsel to the effect that all regulatory approvals required to enter into such sublease have been obtained and (k) the Lessee or sublessee has paid on an after-tax basis all reasonable and documented costs and expenses incurred by the applicable Owner Participant, Lessor, and Indenture Trustee and the Pass Through Trustee in connection with any such sublease.
Material Default means (a) a Lease Event of Default resulting from the Lessee’s failure to make payments under a Lease or any other Operative Documents or the bankruptcy of the Lessee or the Lease Guarantor or (b) the Lessee’s failure to comply in any material respect with its sublease obligations under such Lease, as summarized above.
Assignment
During the Lease Term, the Lessee may not assign the applicable Lease or any other applicable Operative Document, or any interest therein, without the prior written consent of the applicable
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Table of ContentsOwner Participant, such consent not to be unreasonably withheld, delayed or conditioned. However, the Lessee may assign all or any part of the applicable Lease, its leasehold interest therein, and any other applicable Operative Document to which it is a party, or any interest therein, to any of its affiliates without the consent of the applicable Lessor, Owner Participant, or Indenture Trustee or any other party to an Operative Document. Assignments are only permitted if the Lessee continues to remain liable under the applicable Lease and the related Operative Documents and the Lease Guarantor continues to remain liable under the applicable Guaranty after giving effect to such assignment, which assignment will be pursuant to an assignment and assumption agreement in form and substance reasonably satisfactory to the applicable Lessor, Owner Participant and Indenture Trustee and the Pass Through Trustee. In addition, these parties will be entitled to receive opinions of counsel regarding required regulatory ap provals and such assignment and assumption agreement and none of the following may have occurred or be caused by such assignment: (i) a Material Default or Lease Event of Default that has not been waived, (ii) the regulation of the applicable Owner Participant or Lessor as a public utility or public utility holding company, or (iii) a Regulatory Event of Loss (as defined below). The Lessee will pay, on an after-tax basis, all reasonable and documented out-of-pocket expenses of the applicable Lessor, Owner Participant and Indenture Trustee and the Pass Through Trustee in connection with any such assignment.
Liens
During the Lease Term, the Lessee will not, directly or indirectly, create, incur, assume or suffer to exist (and will promptly, at its own cost and expense, remove and indemnify the other parties to the related Operative Documents in respect of) any Lien on the Undivided Interest or any part thereof, or any of the applicable Lessor’s or the applicable Owner Participant’s rights, titles or interests in the Undivided Interest or any part thereof, except for Permitted Liens (as defined below).
Permitted Liens, with respect to the Lessee, means (a) Liens for taxes not yet due and payable or taxes being contested in good faith by appropriate proceedings so long as such proceedings do not involve a material risk of the sale, forfeiture, loss or restriction on use of the Undivided Interest, the Facility Site or any interest in or material part of either; (b) suppliers’, vendors’, workmen’s, repairmen’s, employee’s, mechanics’, materialmen’s or other like Liens arising in the ordinary course of business for amounts the payment of which is either not yet delinquent or is being contested in good faith by appropriate proceedings so long as such proceedings do not involve a material risk of the sale, forfeiture, loss or restriction on use of the Undivided Interest, the Facility Site or any interest in or material part of either; (c) pre-judgment Liens for claims against the Lessee or any sublessee permitted under a Lea se which are being contested in good faith and Liens arising out of judgments or awards against the Lessee or any such sublessee with respect to which an appeal or proceeding for review is being prosecuted in good faith and to which a stay of execution has been obtained pending such appeal or review; provided that during such proceedings, there is not, and such proceedings do not involve a material risk of the sale, forfeiture or loss of the Undivided Interest, the Facility Site or any interest in or material part of either; (d) easements, servitudes and land charges in respect of the Facility which do not have a material adverse effect on the current or residual value, useful life or utility of the Undivided Interest; (e) Liens arising by operation of law, to the extent not described above, and not including judgment Liens, that do not involve a material risk of the sale, forfeiture or loss of the Undivided Interest, the Facility Site or any interest in or material part of either; (f) Liens created or permi tted by any Operative Document; and (g) any Liens created, or permitted to be created by, the applicable Lessor or Indenture Trustee or the Pass Through Trustee.
Insurance
The Lessee will maintain, or cause to be maintained, property and liability insurance coverage customary for this type of Lease Transaction, as specified in the Lease.
Merger and Consolidation
During the Lease Term, the Lessee may not consolidate or merge with or into any other entity or sell, convey, transfer, lease or otherwise dispose of its properties and assets substantially as an entirety
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Table of Contentsto any other entity, and will not permit any entity to consolidate with or merge into it, unless (a) immediately prior to and immediately following such consolidation, merger, sale or lease, no Material Default or Lease Event of Default has occurred and is continuing that has not been waived, (b) the entity resulting from such consolidation, surviving such merger or succeeding to such assets will (i) be organized under the laws of the United States, any state thereof or the District of Columbia, (ii) expressly assume, pursuant to an agreement reasonably acceptable to the applicable Owner Participant and the Indenture Trustee, each obligation of the Lessee, under each Operative Document and (iii) provide customary certificates of officers and opinions of counsel, (c) the Lease Guarantor has affirmed its obligations under the applicable Guaranty and (d) all reasonable costs and expenses incurred in connection with such a consolidation, merger, sale or lease will be for the account of the Lessee.
Events of Loss
Event of Loss means any of the following events:
(a) the loss of the Undivided Interest or the use thereof due to destruction or damage that is beyond economic repair or that renders the Undivided Interest permanently unfit for normal use, as determined in good faith and in the reasonable opinion of the Lessee, or is not permanent but reasonably expected to last for at least 60 months;
(b) any damage to the Undivided Interest that results in an insurance settlement with respect thereto on the basis of a total loss or an actual, constructive or a compromised total loss of the Undivided Interest;
(c) a requisition following exhaustion of all permitted appeals, which in the case of a requisition of use would reasonably be foreseeable to exceed the Lease Term;
(d) assuming the Lessee is diligently attempting to do so, failure of the Lessee to complete the repair or restoration of the Undivided Interest following a material partial loss or damage to the Undivided Interest prior to the earlier of (at which point such material partial loss or damage should be deemed to be an Event of Loss for purposes of this definition) (i) 12 months prior to the expiration of the Lease Term (or, if there occurs a material partial loss or damage to the Undivided Interest after the date that is 36 months prior to the expiration of the Lease Term, as promptly as practicable thereafter and (unless the applicable Lessor shall agree otherwise) in no event later than the date of the expiration of the Lease Term) and (ii) the date which is 36 months after the occurrence of such partial loss or damage; or
(e) if elected by the applicable Owner Participant within six months after the date on which it has obtained knowledge of the event or circumstance described below through the receipt of notice by or actual knowledge of an officer or certain other employees, and only if the termination of the applicable Lease and the transfer of the Undivided Interest would remove the basis of the regulation described below, the applicable Owner Participant will reasonably determine (in consultation with counsel to the applicable Owner Participant having expertise with respect to such regulation), that the applicable Owner Participant’s or the applicable Lessor’s interest in the Undivided Interest, any Operative Document or the applicable Lease, or any part thereof, is or will become subject to any rate of return regulation of any governmental entity, or that the applicable Owner Participant, the applicable Lessor or the OP Guarantor is or will become subject to any other electric utility or holding company regulation of any governmental entity or any law which is materially burdensome, in either case by reason of the participation of the applicable Owner Participant or the applicable Lessor in the transactions contemplated by the Operative Documents, and not, in any event, as a result of (i) investments, loans or other business activities of the applicable Owner Participant or its affiliates or the nature of any of the properties or assets from time to time owned, leased, operated, managed or otherwise used or made available for use by the applicable Owner Participant or its affiliates or (ii) a failure of the applicable Owner Participant or any of its affiliates to perform routine, administrative or ministerial actions. The Lessee, the applicable Lessor and the applicable Owner Participant will agree to cooperate and to take reasonable measures to alleviate the source or consequence of any
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Table of Contentsregulation or law constituting an Event of Loss under this clause (e), or a Regulatory Event of Loss, at the cost and expense of the Lessee and so long as there will be no material adverse consequences to the applicable Owner Participant or the applicable Lessor (or any of their respective affiliates) as a result of such taking of such measures.
An Event of Loss described in clauses (a) or (b) above is referred to as a total loss, or a Total Loss.
Lessee’s Obligation to Repair or Restore
Upon the occurrence of a Total Loss, the Lessee must repair or restore the Facility and seek and obtain all necessary and advisable permits so that the Undivided Interest will have a current and residual value, remaining economic useful life and utility at least equal to that existing immediately prior to such Event of Loss, in accordance with certain conditions and procedures specified in the applicable Lease including, but not limited to: (a) the application for all necessary or advisable permits necessary to commence construction as soon as reasonably practicable after, but not later than 18 months after, the occurrence of such Event of Loss; (b) the delivery of a report of an independent engineer, or the EOL Report, selected by the applicable Owner Participant and reasonably satisfactory to the Lessee, such report to be reasonably satisfactory to such Owner Participant, as promptly as practicable after, but no later than 18 months after, the occurrence of a Total Loss and from time to time thereafter at the request of the applicable Lessor, to the effect that the repair or restoration of the Facility is technologically feasible and can reasonably be expected to be completed by the Long Stop Date; (c) the holding of any insurance proceeds received by the Lessee, the applicable Owner Participant, the applicable Lessor, or the applicable Indenture Trustee as a result of the occurrence of a Total Loss or other event described in clause (d) of the definition of Event of Loss, in either case pursuant to which the Lessee is obligated to repair or restore the Facility, to the extent such proceeds apply to or cover the Undivided Interest in an escrow account, subject to receipt by the applicable Lessor and the escrow agent of evidence of the cost of such repair or restoration covered by the applicable insurance policies, shall be disbursed to the Lessee to pay such costs and expenses or to reimburse the Lessee therefor with any remaining funds to be distributed to the a pplicable Lessor; and (d) the execution, delivery and recordation, if appropriate, of various documents on the completion date of the repair or restoration of the Facility.
Termination of the Lease
When a Total Loss has occurred and (i) the independent engineer has concluded in its EOL Report that the repair or restoration of the Facility is not technologically feasible or cannot be completed in accordance with the requirements described above under ‘‘—Lessee’s Obligation to Repair or Restore’’ by the Long Stop Date, then the Lessee shall pay to the applicable Lessor, on the next Termination Date occurring at least 120 days after the Lessee’s receipt of the EOL Report, (A) the Termination Amount as of such Termination Date, and (B) all accrued and unpaid rent due; provided, however, that if such Total Loss did not arise from a Lessee Loss Event, then the amount payable will instead be the PVRR Amount as of such Termination Date; or (ii) the Lessee fails to complete the repair or restoration of the Facility and to obtain all necessary and advisable permits by the Long Stop Date, the applicable Owner Participant may elect to terminate the applicable Lease or grant the Lessee additional time to complete the repair and restoration of the Facility. If the applicable Owner Participant elects to terminate the Lease, the Lessee’s obligation to repair or restore the Facility will cease and the Lessee will pay to the applicable Lessor (x) the scheduled Termination Amount, less any insurance proceeds received and not required to be paid into an escrow account (for purposes of rebuilding or restoring the Facility) by the applicable Lessor or Owner Participant in connection with the Total Loss, and (y) all accrued and unpaid rent due, provided, however, that if the Total Loss did not arise from a Lessee Loss Event, the amount payable will instead be the PVRR Amount determined as of such Termination Date and all accrued and unpaid rent due on such date. If the applicable Owner Participant elects to grant the Lessee additional time, the Lessee will use best efforts to satisfy the requirements of this paragraph within such extended time period. Such extended period may continue after the Lease Term, in which case the Lessee will continue to be obligated
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Table of Contentsunder all Operative Documents and the operating agreement for the Mansfield Plant, but Lessee will not be required to pay any rent for any period after the Lease Term by reason of such extension. Upon the Lessee’s payment of the amounts due, the applicable Lease will terminate. All insurance proceeds for such Total Loss to the extent such proceeds apply to or cover the Undivided Interest, shall be paid to, or retained by, the applicable Lessor.
PVRR Amount means the present value of all installments of Basic Rent from the date of an Event of Loss to the end of the Basic Term discounted at a discount rate equal to interest rate on the Lessor Notes plus 0.40%.
Notwithstanding anything to the contrary set forth above, so long as the Lien of the applicable Lease Indenture shall not have been terminated or discharged, no termination of the applicable Lease will be effective and the Lessee’s rights and obligations under the applicable Lease immediately prior to the termination of the Lease in respect of an Event of Loss will remain in full force and effect in all respects (regardless of whether the applicable Lessor elects to retain or sell such Lessor’s Interest in connection with such proposed termination) unless and until the applicable Lessor has paid all outstanding principal and accrued interest on the related Lessor Notes in respect of the Event of Loss and all other amounts due by such Lessor under the applicable Lease Indenture on such proposed date of termination.
Lessee Person means (i) the Lessee; (ii) the Lease Guarantor; (iii) any assignee or sublessee of the Lessee, each a lessee assignee; (iv) the operator under the operating agreement for the Mansfield Plant or any other operator of the Mansfield Plant, the Facility or the Ancillary Facilities or any portion or component thereof or interest therein (including, without limitation, the Undivided Interest), each a lessee operator; (v) (A) any Person under a contract with the Lessee, the Lease Guarantor, a lessee assignee or a lessee operator which contract, each a lessee contract, relates to, arises out of or was entered into in connection with (1) the Mansfield Plant, the Facility, the Facility Site, the Ancillary Facilities or any portion or component thereof or interest therein (including, without limitation, the Undivided Interest) or (2) the use thereof or (B) any contractor, subcontractor, consultant or agent under any Lessee Contract or any other Person supplyi ng or transporting goods or performing services under any Lessee Contract or otherwise in connection with the use of the Facility, the Facility Site, the Ancillary Facilities or any portion or component thereof or interest therein (including, without limitation, the Undivided Interest); (vi) any Person to whom the Lessee, the Lease Guarantor, a lessee assignee or a lessee operator shall have delegated duties or assigned rights (whether by contract or otherwise) relating to, arising out of or in connection with the Facility, the Facility Site, the Ancillary Facilities or any portion or component thereof or interest therein (including, without limitation, the Undivided Interest) or the use thereof; (vii) any other Person occupying, in possession or control of, engaging in or participating in the use of or otherwise present on or at, the Facility, the Facility Site or the Ancillary Facilities prior to or during the Lease Term with the knowledge or express or implied consent of (or as a result of the breach of c ontractual obligations (including, without limitation, the Operative Documents) of, or negligence of ) the Lessee, the Lease Guarantor, any lessee assignee or any lessee operator; (viii) any affiliate of any of the Persons described in the foregoing clause (i) through (vii) above and (ix) any officers, directors, employees or agents of any of the Persons described in clauses (i) through (viii) above; provided that the Persons described in clauses (ii), (v) and (vii) above do not, and shall not be deemed to, include the applicable Lessor, the applicable Owner Participant or any other Person in possession of all or any portion of the Facility that is claiming that right to possession through such Lessor or such Owner Participant, other than through the applicable Lease.
Long Stop Date means the date that is five years after the date of a Total Loss or, if less than five years remain prior to the expiration of the then-current Lease Term (including any renewal term that has been irrevocably elected by the Lessee), the earlier of (i) the expiration date of the then-current Lease Term (including any renewal term that has been irrevocably elected by the Lessee) and (ii) 48 months after such Total Loss.
Lessee Loss Event means a Lessee Person’s action, inaction, non-performance, breach or otherwise in the operation or maintenance of the Facility or any portion or component of the Facility that is not consistent with Best Utility Practice or not otherwise a Force Majeure Event.
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Table of ContentsBest Utility Practice means any best acts, practices, methods, equipment, specifications and standards of safety, performance and conduct (including all acts, practices, methods, equipment, specifications and standards of safety, performance and conduct which are intended to prevent events and conditions at the Facility or any portion or component thereof which could reasonably be expected to lead to a Lessee Loss Event), as (i) (x) engaged in or approved or utilized by that portion of the electric utility industry that is recognized by others as leaders in the industry at such time, or (y) viewed as advanced, optimum or state of the art at such time by one or more nationally recognized organizations, including, but not limited to, the Electric Power Research Institute, the American National Standards Institute, the Electric Utility Benchmarking Association, or a national professional engineering organization of national standing, and (ii) good, safe and best en gineering practices would dictate in connection with the operation, maintenance, repair and use of electric generating stations and facilities and improvements of such electrical generating stations.
Force Majeure Event means any event or condition that (i) is beyond the control of a Lessee Person, (ii) is not the result of any acts, omissions or delays of a Lessee Person, (iii) is not an event or condition, the risks or consequences of which the Lessee has expressly agreed to assume under any Lease, any other Operative Document or the operating agreement of the Mansfield Plant and (iv) cannot be cured, remedied, offset, negotiated or otherwise overcome by the prompt exercise of due diligence of any Lessee Person.
If an Event of Loss described in clause (c) of the definition of Event of Loss above occurs, the Lessee will pay to the applicable Lessor (i) the Termination Amount, provided, that such amount to be paid by the Lessee shall be less any proceeds received from a governmental entity applicable to such Event of Loss received by the applicable Lessor (or the applicable Owner Participant) and (ii) all accrued and unpaid rent due. However, if such Event of Loss did not arise from a Lessee Loss Event, the Lessee will instead pay to such Lessor (x) the PVRR Amount, and (y) all accrued and unpaid rent. Upon the Lessee’s payment of the amounts due, the applicable Lease will terminate and the Lessee will return the Undivided Interest to the applicable Lessor ‘‘as is’’ and ‘‘where is.’’
If an Event of Loss described in clause (d) of the definition of Event of Loss above has occurred, the applicable Owner Participant must provide prompt notice whether it (i) grants the Lessee additional time to complete the rebuilding or restoration of the Facility, (ii) retains the Undivided Interest, or (iii) sells the Undivided Interest. If the applicable Owner Participant grants the Lessee additional time to complete the rebuilding or restoration of the Facility, the Lessee will continue in good faith to rebuild or restore the Facility within such extended time period. Such extended time period may continue after the Lease Term and the Lessee will continue to be obligated under all Operative Documents and the operating agreement for the Mansfield Plant, but Lessee will not be required to pay any rent for any period after the Lease Term by reason of such extension. If the applicable Owner Participant does not grant the Lessee additional time to complete the r ebuilding or restoration of the Facility and elects to retain the Undivided Interest, it will provide notice to the Lessee, the applicable Indenture Trustee and the Pass Through Trustee electing to terminate the applicable Lease. Within 120 days after receipt of such notice, the Lessee will pay to the applicable Lessor all accrued and unpaid rent due and will return the Undivided Interest to the applicable Lessor ‘‘as is’’ and ‘‘where is.’’
If the applicable Owner Participant does not grant the Lessee additional time to complete the rebuilding or restoration of the Facility and elects to sell the Undivided Interest, such Owner Participant will use commercially reasonable efforts to solicit third party bids for the Undivided Interest or may elect to utilize an independent sales agent selected by the Lessee and reasonably satisfactory to such Owner Participant to solicit such bids for the Undivided Interest. The Lessee will have a right of first refusal with respect to the third party bid for the Undivided Interest that the applicable Owner Participant intends to accept. Upon the sale of the Undivided Interest (which must be concluded and closed as soon as practicable after such Owner Participant has made the election to sell the Undivided Interest), the applicable Lessor will be entitled to retain the net cash proceeds of the sale and the Lessee will pay, without duplication, the accrued and unpaid rent due and an amount, if any, equal to the excess of the Termination Amount at that date over the net cash proceeds of the sale, whereupon the applicable Lease will terminate. However, if (i) the cause of the material partial
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Table of Contentsloss or damage described in clause (d) of the definition of the Event of Loss did not arise from a Lessee Loss Event and the Lessee has failed to timely obtain all the permits required to repair, restore and operate the Facility or, having timely obtained such replacement permits has failed to complete the rebuilding or restoration of the Facility within 36 months thereafter, then the applicable Owner Participant may grant the Lessee additional time to complete the rebuilding or restoration of the Facility and the Lessee will continue to use commercially reasonable efforts to rebuild or restore the Facility within such extended time period. Such extended time period may continue after the Lease Term and the Lessee will continue to be obligated under all Operative Documents and the operating agreement for the Mansfield Plant, but the Lessee shall not be required to pay any Basic Rent for any period after the Lease Term by reason of such extension. If such Owner Participant does not grant the Lessee additional time to complete the rebuilding or restoration of the Facility and elects to sell the Undivided Interest, such Owner Participant will use commercially reasonable efforts to solicit Qualifying Cash Bids for the Undivided Interest or such Owner Participant may elect to utilize an independent sales agent selected by the Lessee and reasonably satisfactory to such Owner Participant to solicit Qualifying Cash Bids for the Undivided Interest. If such Owner Participant receives a Qualifying Cash Bid that is greater than or equal to the Termination Amount as of the date of such Event of Loss, the Lessee will have a right of first refusal with respect to any Qualifying Cash Bid for the Undivided Interest that such Owner Participant intends to accept. If such Owner Participant does not receive a Qualifying Cash Bid that is greater than or equal to the Termination Amount as of the date of such Event of Loss, the Lessee shall not have a right of first refusal with respect to any such Qualifying Cash Bid. Upon the sale o f the Undivided Interest to the Lessee or a third party (such sale to be concluded and closed as soon as practicable after such Owner Participant having made the election to sell the Undivided Interest), the applicable Lessor will be entitled to retain the net cash proceeds of the sale and the Lessee will pay to such Lessor the accrued and unpaid rent and, in the case of a sale of the Undivided Interest to a party other than the Lessee, the PVRR Amount, whereupon the applicable Lease will terminate. If such Owner Participant elects not to sell the Undivided Interest, the Lessee, within 120 days after receiving notice of such Owner Participant’s election to retain the Undivided Interest, will pay to such Lessor all accrued and unpaid rent and return the Undivided Interest to such Lessor ‘‘as is’’ and ‘‘where is.’’ For purposes of this paragraph, the replacement permits will not be considered to have been timely obtained if such replacement permits are not so obtained within the period of time beginning two years after the date of the occurrence of the material partial loss or damage to the Facility and if any of the following occurs: (i) any relevant governmental entity indicates that it will not grant a replacement permit on terms that will allow for the commercially feasible repair or reconstruction and operation of the Facility; (ii) the Lessee and any relevant governmental entity fail to reach agreement on the terms of a replacement permit necessary to allow for the commercially feasible repair or reconstruction and operation of the Facility; or (iii) at the request of the applicable Lessor, an independent third-party environmental attorney or environmental consultant, reasonably acceptable to Lessee, issues an opinion that any replacement permit is not reasonably likely to be issued in a manner that will allow for the commercially feasible repair or reconstruction construction and operation of the Facility.
If the applicable Owner Participant has provided notice to the Lessee of its election to treat an event described in clause (e) of the definition of Event of Loss above as an Event of Loss and such Event of Loss is due to a change in applicable law, the applicable Owner Participant will elect whether or not to sell the Undivided Interest. If the applicable Owner Participant elects not to sell the Undivided Interest, the Lessee, within 120 days after receiving notice of the applicable Owner Participant’s election to retain the Undivided Interest, will pay to the applicable Lessor all accrued and unpaid rent due and return the Undivided Interest to the applicable Lessor. If such Owner Participant elects to sell the Undivided Interest, such Owner Participant will use commercially reasonable efforts to solicit Qualified Cash Bids for the Undivided Interest, or may elect to utilize an independent sales agent selected by the Lessee and reasonably satisfactory to such Owner Participant to solicit such bids for the Undivided Interest. If the applicable Owner Participant receives a Qualifying Cash Bid that is greater than or equal to the Termination Amount as of the date of such Event of Loss, the Lessee will have a right of first refusal (on substantially the same terms and conditions as described in the definition thereof) with respect to the Qualified Cash Bid for the
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Table of ContentsUndivided Interest that such Owner Participant intends to accept. If the applicable Owner Participant does not receive a Qualifying Cash Bid that is greater than or equal to the Termination Amount as of the date of such Event of Loss, the Lessee will not have a right of first refusal with respect to any Qualified Cash Bid. Upon the sale of the Undivided Interest to the Lessee or a third party, the applicable Lessor will retain the net cash proceeds of the sale and the Lessee will pay to the applicable Lessor the accrued and unpaid rent due on such date and, in the case of a sale to a third party, the PVRR Amount. Upon the Lessee’s payment of the amounts due, the applicable Lease will terminate.
If the applicable Owner Participant has provided notice to the Lessee of its election to treat an event described in clause (e) of the definition of Event of Loss above, other than as described in the foregoing paragraph, as an Event of Loss, the applicable Owner Participant may elect to sell or retain the Undivided Interest. If the applicable Owner Participant elects not to sell the Undivided Interest, the Lessee, within 120 days after receiving notice of the applicable Owner Participant’s election to retain the Undivided Interest, will pay to the applicable Lessor all accrued and unpaid rent due and return the Undivided Interest to the applicable Lessor. If such Owner Participant elects to sell the Undivided Interest, such Owner Participant will use commercially reasonable efforts to solicit Qualifying Cash Bids for the Undivided Interest, or may elect to utilize an independent sales agent selected by the Lessee and reasonably satisfactory to such Owner Participant to solicit Qualifying Cash Bids for the Undivided Interest. The Lessee will have a right of first refusal (on substantially the same terms and conditions as described in the definition thereof) with respect to any Qualifying Cash Bid for the Undivided Interest that such Owner Participant intends to accept. Upon the sale of the Undivided Interest to the Lessee or a third party, the applicable Lessor may retain the net cash proceeds of the sale and the Lessee will pay to the applicable Lessor (i) the accrued and unpaid rent due on the date of the sale and (ii) an amount equal to the excess, if any, of the Termination Amount on such date over the net cash proceeds from the sale. Upon the Lessee’s payment of the amounts due, the applicable Lease will terminate.
Upon the applicable Owner Participant’s termination of the applicable Lease pursuant to the occurrence of a Total Loss, (i) rent will cease to accrue, (ii) the Lessee will cease to have any liability under the applicable Lease (it being understood and agreed that the Lessee shall continue to be obligated to pay Supplemental Rent and other obligations surviving pursuant to the express provisions of any Operative Document, and the obligations of the Lease Guarantor under the applicable Guaranty will continue with respect to such Supplemental Rent and other surviving obligations of the Lessee), (iii) the applicable Lessor will pay all amounts of principal and interest and other amounts owing by it under the applicable Lessor Notes to the applicable Indenture Trustee pursuant to the applicable Lease Indenture, (iv) the applicable Lease will terminate, (v) the applicable Lessor and Indenture Trustee will, at Lessee’s cost and expense, discharge the Lien o f the applicable Lease Indenture and execute and deliver appropriate releases and other documents or instruments necessary to effect the foregoing and (vi) if the Lessee purchased the Undivided Interest, the Site Lease with respect to the Facility Site and the Support Agreement with respect to the Ancillary Facilities will terminate and the applicable Lessor will, at the Lessee’s cost and expense, execute and deliver to the Lessee evidence of the release or termination of the Site Lease and the applicable Lessor will transfer (by an appropriate instrument of transfer in form and substance reasonably satisfactory to the applicable Lessor and prepared by and at the expense of the Lessee) all of its right, title and interest in and to the applicable Lessor’s Interests ‘‘as is’’, ‘‘where is’’ and ‘‘with all faults’’, without representations or warranties other than a warranty of the applicable Lessor as to the absence of Lessor&r squo;s Liens and of the applicable Owner Participant as to the absence of Owner Participant’s Liens.
Burdensome Termination Option
So long as no Material Default or Lease Event of Default has occurred and is then continuing, the Lessee will have the right to terminate all, but not less than all, of the Leases held by or for the benefit of the applicable Owner Participant, or the Burdensome Termination Option, upon not less than 180 days’ written notice or actual notice, if a Burdensome Termination Event (as defined below) will occur. If the Lessee elects to terminate the applicable Lease, the applicable Lessor must elect whether or not to sell the Undivided Interest.
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Table of ContentsIf an applicable Lessor elects to sell its Undivided Interest, the Lessee must appoint an independent sales agent reasonably satisfactory to the applicable Owner Participant to use commercially reasonable efforts to sell the Undivided Interest. The Lessee will have a right of first refusal to purchase such Undivided Interest on terms and conditions not materially less favorable than those set forth in a bid from a Person other than the Lessee or an affiliate of the Lessee meeting certain requirements specified in the applicable Participation Agreement, or a Qualifying Cash Bid, that the applicable Owner Participant intends to accept. If no Qualifying Cash Bids or Lessee bids are received by the date that is 90 days prior to the Burdensome Termination Date, the applicable Lessor will have been deemed to have accepted a Qualifying Cash Bid for zero dollars. The Lessee may exercise its right of first refusal by providing the applicable Owner Participant with notice of such exercise within 45 days after first receiving the relevant terms and conditions of such bid from such Owner Participant. If the Lessee fails or elects not to exercise its right of first refusal within such 45-day period, the applicable Owner Participant may proceed with such sale on the terms and conditions set forth in such bid. In the event that the terms or conditions of the bid are revised to be materially less favorable to such Owner Participant, the Lessee will have the right to purchase the Undivided Interest on the new terms and conditions. In addition, the Lessee and any affiliate thereof have the right to submit bids for the purchase of the Undivided Interest within 180 days after the applicable Lessor’s election to sell. Such bids are not subject to the Lessee’s right of first refusal. If any Qualifying Cash Bids or Lessee bids are received by the date that is 90 days prior to the Termination Date (provided that the sales agent has not failed to conduct the bid process diligen tly and in good faith), but the applicable Lessor has rejected all such bids, such Lessor will cause the sales agent to conduct a subsequent bid process to be concluded within 90 days. If the sales agent has failed to conduct the bid process diligently in good faith, then such Lessor shall appoint a new sales agent who shall conduct a subsequent bid process to be concluded within 120 days. After the conclusion of any subsequent bid process, the applicable Lessor will accept the highest, preferred or only Qualifying Cash Bid or Lessee Bid or, if no Qualifying Cash Bids or Lessee Bids are received, then such Lessor shall be deemed to have accepted a sale price of zero dollars.
If the Lessee exercises its Burdensome Termination Option, the Lessee will pay to the applicable Lessor (i) any Supplemental Rent (including all reasonable out-of-pocket costs and expenses of the applicable Lessor, Owner Participant and Indenture Trustee and the Pass Through Trustee associated with the exercise of the Burdensome Termination Option and all indemnity amounts not obviated by the termination) accrued and unpaid on or prior to such Burdensome Termination Date and (ii) any unpaid Basic Rent or renewal rent due and payable on or before such Burdensome Termination Date. Upon the sale of the Undivided Interest to a third party, (a) the applicable Lessor will pay all amounts of principal and interest and other amounts owing by it under the applicable Lessor Notes to the applicable Indenture Trustee pursuant to the applicable Lease Indenture, (b) rent shall cease to accrue, (c) the Lessee shall cease to have any liability under the applicable Lease (it bei ng understood and agreed that the Lessee shall continue to be obligated to pay Supplemental Rent and other obligations surviving pursuant to the express provisions of any Operative Document, and the obligations of the Lease Guarantor under the applicable Guaranty shall continue with respect to such Supplemental Rent and other surviving obligations of the Lessee), (d) the applicable Lease shall terminate, (e) the applicable Lessor shall, at the Lessee’s cost and expense, execute and deliver to the Lessee a release or termination of the applicable Lease, (f) in connection with the sale of the applicable Lessor’s Interest, such Lessor shall transfer all of its right, title and interest in and to such Lessor’s Interest to the purchaser on an ‘‘as is’’, ‘‘where is’’ and ‘‘with all faults’’ basis, without representations or warranties other than a warranty of such Lessor as to the absence of such Lessor’s Liens and a wa rranty of the applicable Owner Participant as to the absence of such Owner Participant’s Liens, (g) so long as the Lien of the applicable Lease Indenture has not been discharged or terminated, such Lessor shall use all reasonable efforts to cause the Indenture Trustee to discharge or terminate such Lien, (h) such Lessor shall execute and deliver, and shall use all reasonable efforts to cause the applicable Indenture Trustee to execute and deliver, appropriate releases and other documents or instruments necessary to effect the foregoing, all to be prepared, filed and recorded (as appropriate) by and at the cost and expense of the Lessee and (i) if the net cash proceeds of the sale are less than, or the Termination Amount, on the date of the sale, the Lessee shall pay the applicable
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Table of ContentsLessor an amount equal to the excess of the Termination Amount over the net cash proceeds of the sale. Upon the Lessee’s payment of the amounts due, the applicable Lease will terminate.
If the applicable Lessor elects to retain the Undivided Interest on the Burdensome Termination Date, the Lessee shall pay to such Lessor, without duplication, (i) any Supplemental Rent accrued and unpaid on or prior to on such Burdensome Termination Date and (ii) any unpaid Periodic Rent due and payable on or before such Burdensome Termination Date and due and payable on such Burdensome Termination Date, but shall not pay any Termination Amount. Concurrently with the payment of all sums required to be paid pursuant to this paragraph, (i) rent shall cease to accrue, (ii) the Lessee shall cease to have any liability under the applicable Lease (it being understood and agreed that the Lessee shall continue to be obligated to pay Supplemental Rent and other obligations surviving pursuant to the express provisions of any relevant Operative Document, and the obligations of the Lease Guarantor under the applicable Guaranty shall continue with respect to such Supple mental Rent and other surviving obligations of the Lessee), (iii) such Lessor will pay all amounts of principal and interest and other amounts owing by it under the Lessor Notes to the applicable Indenture Trustee pursuant to the applicable Lease Indenture, (iv) the Lessee shall return the Undivided Interest to such Lessor, and (v) such Lessor shall execute and deliver appropriate documents or instruments necessary to effect the foregoing, all to be prepared, filed and recorded (if appropriate) by and at the cost and expense of the Lessee.
Burdensome Termination Event means that, other than primarily as a result of events caused by the Lessee or any affiliate thereof, (a) it has become illegal for the Lessee to continue the Lease or for the Lessee to make any payments contemplated by the Lease or the other Operative Documents, or (b) one or more events outside the control of the Lessee and its affiliates has occurred which has given rise, give rise or will or can reasonably be expected to give rise to an indemnity obligation of the Lessee or the Lease Guarantor; provided, however, that (i) such indemnity (or the underlying cost or tax) can be avoided if the applicable Lease is terminated and (ii) the amount of such avoided payments would exceed two percent of the purchase price of the Undivided Interest, or the Purchase Price; and provided, further, that no such termination option exists if the applicable indemnitee waives its right to, or the applicable Owner Participant arranges, in its sole dis cretion, for payment (without reimbursement by the Lessee or any affiliate thereof) of amounts of indemnification payments in excess of such amount so as to cause such avoided payments not to exceed two percent of the Purchase Price.
So long as the Lien of the applicable Lease Indenture has not been terminated or discharged, no termination of the applicable Lease shall be effective and the Lessee’s rights and obligations under the applicable Lease immediately prior to the Lessee’s election to terminate the applicable Lease shall remain in full force and effect in all respects (regardless of whether the applicable Lessor elects to retain or sell the applicable Lessor’s Interest in connection with such proposed termination) unless and until such Lessor shall have paid all outstanding principal and accrued interest on the Lessor Notes and all other amounts due by such Lessor under the applicable Lease Indenture on such proposed date of termination.
The Lessee may, not less than 90 days prior to the proposed date on which the applicable Lease is scheduled to terminate pursuant to a Burdensome Termination Option, revoke its notice of termination. In that case, the applicable Lease will continue in effect and no Lease Event of Default will occur as a result of such revocation. The Lessee will reimburse, on an after-tax basis, the applicable Lessor, Owner Participant and Indenture Trustee and the Pass Through Trustee for all costs and expenses incurred and the Lessee will have the right to reinstitute such termination procedure.
Termination Due to Lessor Actions
So long as no Material Default shall have occurred and be continuing, the Lessee will have the right, within 180 days after the Lessee first receives notice or has actual knowledge of the occurrence of an event or condition described in (i) through (iv) below, to deliver notice of its decision to terminate the applicable Lease, or the Owner Breach Termination Notice, on a date not less than
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Table of Contents270 days after the date the Owner Breach Termination Notice is delivered to the applicable Lessor, or the Owner Breach Termination Date, if any of the following has occurred and is continuing on the Owner Breach Termination Date:
(i) there is a material continuing breach by either the applicable Lessor or applicable Owner Participant of its covenants with respect to Lessee’s quiet enjoyment of the use, operation and possession of its rights and interests in the Facility or the Undivided Interest, which breach remains unremedied for 10 days after notice to such Lessor and such Owner Participant;
(ii) the Trust Agreement creating the applicable Lessor has been terminated by the applicable Owner Participant or the trust created thereby is revoked by such Owner Participant;
(iii) the applicable Owner Participant has transferred any of the Trust Interest or the applicable Lessor has transferred any of the Undivided Interest in material violation of the transfer restrictions of the Operative Documents; or
(iv) the applicable Lessor, acting at the express direction of the applicable Owner Participant, or the applicable Owner Participant has breached any other material covenant of or representation made by it under the Operative Documents, which breach remains unremedied for 10 days after notice to such Lessor and such Owner Participant and which breach has (A) materially impaired the Lessee’s use, possession or enjoyment of the Undivided Interest or (B) given rise to a material risk of sale, loss or forfeiture of the Undivided Interest, the Facility or any material related property right (it being understood and agreed that the Lessee is not be entitled to exercise the option to terminate in respect of the matters referred to in clauses (i) through (iv) if, on or prior to the date the Lessee exercises the same, the applicable Owner Participant has fully cured the relevant breach and fully compensated the Lessee for all damage s incurred or reasonably likely to be incurred by the Lessee in connection therewith).
If the Lessee does not give an Owner Breach Termination Notice within 180 days of the date the Lessee receives notice or first has actual knowledge of an event or condition described above, the Lessee will lose its right to effect a termination as a result of such event or condition.
If the Lessee elects to terminate the applicable Lease, the applicable Lessor must elect whether or not to sell its Undivided Interest. If an applicable Lessor elects to sell its Undivided Interest, the Lessee must appoint an independent sales agent reasonably satisfactory to the applicable Owner Participant to use commercially reasonable efforts to sell the Undivided Interest and the provisions and procedures described in the second paragraph under ‘‘—Burdensome Termination Option’’ above shall apply, including with respect to the Lessee’s right of first refusal to purchase.
If such Lessor elects not to sell its Undivided Interest, on the Owner Breach Termination Date, the Lessee shall pay to such Lessor, without duplication (i) any Supplemental Rent accrued and unpaid on or prior to such Owner Breach Termination Date and (ii) any unpaid Periodic Rent due and payable on or before such Owner Breach Termination Date, but shall not pay any Termination Amount. Concurrently with the payment of all sums required to be paid pursuant to this paragraph, (i) rent shall cease to accrue, (ii) the Lessee shall cease to have any liability under the applicable Lease (it being understood and agreed that the Lessee shall continue to be obligated to pay Supplemental Rent and other obligations surviving pursuant to the express provisions of any relevant Operative Documents, and the obligations of the Lease Guarantor under the applicable Guaranty shall continue with respect to such Supplemental Rent and other surviving obligations of the Lessee), (iii) such Lessor will pay all amounts of principal and interest and other amounts owing by it under the applicable Lessor Notes to the applicable Indenture Trustee pursuant to the applicable Lease Indenture, (iv) the Lessee shall return the Undivided Interest to such Lessor, and (v) such Lessor shall execute and deliver appropriate documents or instruments necessary to effect the foregoing, all prepared, filed and recorded (if appropriate) by and at the cost and expense of the Lessee.
If the Lessee elects to terminate the applicable Lease, the Lessee will pay to the applicable Lessor (i) any Supplemental Rent (including all reasonable out-of-pocket costs and expenses of such Lessor, the applicable Owner Participant, the Indenture Trustee and the Pass Through Trustee associated with the exercise of the Burdensome Termination Option and all indemnity amounts not
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Table of Contentsobviated by the termination) accrued and unpaid on or prior to such Owner Breach Termination Date and (ii) any unpaid Basic Rent or renewal rent due and payable on or before such Owner Breach Termination Date. Upon the sale of the Undivided Interest to a third party, (i) the applicable Lessor will pay all amounts of principal and interest and other amounts owing in respect of the redemption of the Lessor Notes, (ii) rent shall cease to accrue, (iii) the Lessee shall cease to have any liability under the applicable Lease (it being understood and agreed that the Lessee shall continue to be obligated to pay Supplemental Rent and other obligations surviving pursuant to the express provisions of any Operative Document, and the obligations of the Lease Guarantor under the applicable Guaranty shall continue with respect to such Supplemental Rent and other surviving obligations of the Lessee), (iv) the applicable Lease shall terminate, (v) the applicable Lessor shall, at the Lessee’s cost and expense, exe cute and deliver to the Lessee a release or termination of the applicable Lease, (vi) in connection with the sale of the applicable Lessor’s Interest, such Lessor shall transfer all of its right, title and interest in and to such Lessor’s Interest to the purchaser on an ‘‘as is’’, ‘‘where is’’ and ‘‘with all faults’’ basis, without representations or warranties other than a warranty of such Lessor as to the absence of such Lessor’s Liens and a warranty of the applicable Owner Participant as to the absence of such Owner Participant’s Liens, (vii) so long as the Lien of the applicable Lease Indenture has not been discharged or terminated, such Lessor shall use all reasonable efforts to cause the applicable Indenture Trustee to discharge or terminate such Lien, (viii) such Lessor shall execute and deliver, and shall use all reasonable efforts to cause the applicable Indenture Trustee to execute and deliver, appropria te releases and other documents or instruments necessary to effect the foregoing, all to be prepared, filed and recorded (as appropriate) by and at the cost and expense of the Lessee and (ix) if the net cash proceeds of the sale are less than the scheduled Termination Amount on the date of the sale, the Lessee will pay the applicable Lessor an amount equal to the excess of the Termination Amount over the net cash proceeds of the sale. Upon the Lessee’s payment of the amounts due, the applicable Lease will terminate.
So long as the Lien of the applicable Lease Indenture has not been terminated or discharged, no termination of the applicable Lease shall be effective and the Lessee’s rights and obligations under the applicable Lease immediately prior to the Lessee’s election to terminate the applicable Lease shall remain in full force and effect in all respects (regardless of whether the applicable Lessor elects to retain or sell the applicable Lessor’s Interest in connection with such proposed termination) unless and until such Lessor shall have paid all outstanding principal and accrued interest on the Lessor Notes and all other amounts due by such Lessor under the applicable Lease Indenture on such proposed date of termination.
The Lessee may, not less than 90 days prior to the Owner Breach Termination Date, revoke its notice of termination. In that case, the applicable Lease will continue in effect and no Lease Event of Default will occur as a result of such revocation. The Lessee will reimburse, on an after-tax basis, the applicable Lessor, the applicable Owner Participant, the Indenture Trustee and the Pass Through Trustee for all costs and expenses incurred and the Lessee will have the right to reinstitute such termination procedure.
Lease Events of Default
Each of the following events will constitute a Lease Event of Default:
(a) the Lessee has failed to make any payment of Basic Rent, renewal rent, PVRR Amount, Termination Amount or any Special Event Amount within 10 days after such payment has become due;
(b) the Lessee has failed to make any payment due under any of the Operative Documents (other than payments referred to in clause (a) above and other specified exceptions) after such payment has become due and such failure has continued for a period of 30 days after the Lessee has received written notice of such failure from the Owner Participant, the Lessor, the Indenture Trustee or the Pass Through Trustee;
(c) the Lessee has failed to maintain the insurance coverage required under a Lease;
(d) any material representation or warranty made by the Lessee or the Lease Guarantor in the Operative Documents (other than a tax representation) or in any document or certificate
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Table of Contentsdelivered by the Lessee and the Lease Guarantor in connection with or pursuant to the Operative Documents has proven to have been incorrect or misleading in any material respect when made because of the omission to state a material fact and such incorrect or misleading representation is and continues to be material and unremedied for a period of 30 days after the Lessee or the Lease Guarantor has received written notice thereof from the applicable Owner Participant, the applicable Lessor, the Indenture Trustee or the Pass Through Trustee; provided, however, that if such condition cannot be remedied within a 30-day period, then the period within which to remedy the condition will be extended up to an additional 180 days, so long as the Lessee or the Lease Guarantor as applicable, diligently pursues a remedy and the condition is reasonably capable of being remedied within such additional 180 day period;
(e) the Lessee and the Lease Guarantor have failed to perform or observe in any material respect their obligations set forth in the Sammis NSR Litigation consent decree or their obligation to take certain actions in connection with the repair or restoration of the Facility in the event of Total Loss or the termination of the Facility and with respect to maintenance of existence, delivery of financial statements to the applicable Owner Participant, merger and consolidation, compliance with law, and assignment of rights under a Lease and other Operative Documents, as summarized above;
(f) the Lessee or the Lease Guarantor, if applicable, has failed to comply with any other material obligation under the Operative Documents or the operating agreement for the Mansfield Plant to be performed or observed by the Lessee or the Lease Guarantor and such failure has continued for a period of 30 days after notice by the applicable Lessor or the Indenture Trustee; provided, however, that if such condition cannot be remedied within 30 days, then the period within which to remedy the condition will be extended up to an additional 180 days (or 365 days once the Lessor Notes have been paid), so long as the Lessee diligently pursues a remedy and the condition is reasonably capable of being remedied within an additional 180-day or 365-day period, as applicable; and provided, further, that in the case of the Lessee’s obligations with respect to facility maintenance and Modifications, if a test, challenge, appeal or proceeding is pro secuted in good faith by the Lessee, the failure by the Lessee to comply with legal requirements will not constitute a Lease Event of Default if such test, challenge, appeal or proceeding does not involve (i) any material risk of foreclosure, sale, forfeiture or loss of, or imposition of a Lien on, any part of the Facility or the impairment of the use, operation or maintenance of the Facility in any material respect or any material adverse effect on the right, title and interest of the applicable Lessor, the applicable Owner Participant or the Indenture Trustee in or to the Undivided Interest or the coverage under the provisions of any insurance policy required to be carried pursuant to the Lease or the imposition of any sanction, or (ii) the risk of any criminal or unindemnified material civil liability being incurred by the applicable Owner Participant, the OP Guarantor, the applicable Lessor or the Indenture Trustee, or any material adverse effect, including, without limitation, subjecting the applicable Owner Participant, OP Guarantor, if any or Lessor to regulation as a public utility; and provided, further, in the case of the Lessee’s obligations with respect to facility maintenance and Modifications, if the noncompliance with legal requirements is not of a type that can be immediately remedied, the failure to comply will not be a Lease Event of Default if the Lessee is taking all reasonable action to remedy its noncompliance and such noncompliance does not create a material risk that the events described in the preceding clauses (i) or (ii) will occur; and provided, further, that such noncompliance, test, challenge, appeal or review will not extend beyond the scheduled expiration of the Lease Term then in effect or any renewal term irrevocably elected by the Lessee;
(g) the Lessee or the Lease Guarantor has (i) commenced a voluntary case or other proceeding seeking relief under Title 11 of the Bankruptcy Code or other similar relief, (ii) consented to, or fail to controvert in a timely manner, any such relief or the appointment of or taking possession by any such official in any involuntary case or other proceeding commenced against it, (iii) filed an answer admitting the material allegations of a petition filed against it in any such proceeding or (iv) made a general assignment for the benefit of creditors;
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Table of Contents(h) an involuntary case or other proceeding has commenced against the Lessee or the Lease Guarantor seeking (i) liquidation, reorganization or other relief with respect to it or its debts under Title 11 of the Bankruptcy Code or any bankruptcy, insolvency or other similar law, (ii) the appointment of a trustee, receiver, liquidator, custodian or other similar official with respect to it or any substantial part of its property or (iii) the winding-up or liquidation of such person, and such involuntary case or other proceeding has remained undismissed and unstayed for a period of 90 days;
(i) any of the Site Lease, Site Sublease, the Support Agreement the operating agreement for the Mansfield Plant or any other material Operative Document has been cancelled or terminated by any Lessee Person, or has otherwise ceased to be in full force and effect as a result of any Lessee Person’s action or inaction, unless, in any such case, alternative arrangements satisfactory to the applicable Lessor and the applicable Owner Participant have been made and such Lessor and such Owner Participant have so acknowledged in writing;
(j) upon the election of the applicable Owner Participant, a Lease Event of Default arising as a result of the Lessee’s action or failure to act under another Lease held by or for the benefit of the same Owner Participant or any of its affiliates; and
(k) the Guaranty has ceased to be a valid, binding and enforceable obligation of the Lease Guarantor as a result of one or more Lessee Person’s actions or failures to act.
Upon the occurrence of any Lease Event of Default and at any time thereafter, so long as such event is continuing, the applicable Lessor may, at its option, declare the applicable Lease to be in default by notice to the Lessee; provided that upon the occurrence of a Lease Event of Default described in paragraph (g) or (h) above with respect to the Lessee, the applicable Lease will automatically be deemed to be in default without the need for giving any notice. At any time after the occurrence of a Lease Event of Default, so long as the Lessee will not have remedied all outstanding Lease Events of Default, such Lessor may do one or more of the following, as such Lessor in its sole discretion will elect to:
(i) proceed by appropriate court action or actions, either at law or in equity, to enforce performance by the Lessee or the Lease Guarantor, at the Lessee’s sole expense, of the applicable covenants and terms of the applicable Lease or other Operative Documents or to recover damages for breach thereof;
(ii) terminate the applicable Lease;
(iii) sell such Lessor’s Interest at public or private sale in which case such Lessor may demand that the Lessee pay, as liquidated damages, all unpaid Periodic Rent accrued through the applicable sale date plus the amount, if any, by which the Termination Amount exceeds the net sale proceeds;
(iv) hold, keep idle or lease to others such Lessor’s Interest free and clear of any rights at the Lessee under the Lease; or
(v) demand that the Lessee pay all unpaid Periodic Rent certain amounts as liquidated damages. The liquidated damages payable under this paragraph (v) shall equal, in such Lessor’s sole discretion, one of the following amounts: (A) the excess, if any, of the Termination Amount over the fair market sales value of such Lessor’s Interest as of the payment date, (B) the excess, if any, of the Termination Amount over the present value of the fair market rental value of such Lessor’s Interest until the end of the Lease Term discounted to the payment date at a rate equal to the interest rate on the Lessor Notes; or (C) the Termination Amount; in the case, on a specified Termination Date not less than 10 days after written notice and together with any unpaid Periodic Rent due and payable on or prior to such date. In the case of (C) above, upon payment of such amount, such Lessor shall appoint an independent sales agent to ob tain Qualifying Cash Bids. If one or more Qualifying Cash Bids is received within 90 days of the appointment of the sales agent, such Lessor shall transfer its Lessor’s Interest to the highest bidder and shall pay the net sales proceeds to the Lessee. In addition, in the case of (A) and (B)
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Table of Contentsabove, fair market rental value and fair market sales value, as the case may be, of such Lessor’s Interest shall be deemed to equal $0 if such Lessor shall be unable to obtain constructive possession of the Undivided Interest sufficient to realize the economic benefit of such Lessor’s Interest. Upon payment of the amounts described in (A), (B) or (C) above, the applicable Lease, and the Lessee’s obligation to pay Periodic Rent or the Termination Amount for any subsequent period, shall terminate.
Notwithstanding the foregoing, the Lessee’s liability in connection with the exercise of any or all of the remedies described above shall be the Termination Amount computed as of the Termination Date occurring on or immediately prior to the date such Lessor declares the applicable Lease to be in default or it is otherwise deemed to be in default, except in the case of a Lease Event of Default resulting from a material breach of the Lessee’s ERISA compliance obligations, in which case the Lessee’s liability shall be the PVRR Amount.
Lessor’s Right to Perform
Subject to the terms of the Lease Indenture, each Lessor has the right, but not the obligation, to remedy, cure or otherwise perform or make payment with respect to any Material Default or Lease Event of Default that has occurred and is continuing within 10 Business Days after it has received written notice of such Material Default or Lease Event of Default. Each Lessor’s right to perform will in no event restrict any of such Lessor’s rights following the occurrence of a Lease Event of Default, and such Lessor will be entitled to exercise all of its remedies summarized above on the occurrence of any such event.
Inspection Rights
The Pass Through Trustee and each Owner Participant, OP Guarantor, Lessor and Indenture Trustee have the right, at its sole expense and upon adequate and reasonable prior notice, to inspect the Facility and the related operations and maintenance records during normal business hours and under conditions reasonably acceptable to the Lessee. These inspection rights are subject to confidentiality obligations and adherence to the Lessee’s safety and insurance procedures. Each inspecting entity shall endeavor to coordinate its inspection with itself and with the other Owner Participants. Notwithstanding the foregoing, so long as a Lease Event of Default is continuing, no more than one inspection in any 18-month period may be conducted by each of (x) an Owner Participant, the applicable OP Guarantor, if any, and the Lessor, and (y) an Indenture Trustee and the Pass Through Trustee.
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Table of ContentsDESCRIPTION OF THE GUARANTIES
The Lease Guarantor entered into each Guaranty as of July 1, 2007, pursuant to which it unconditionally and irrevocably guaranteed all of the Lessee’s obligations under the Operative Documents relating to the particular Lessor. Each Guaranty shall terminate pursuant to the terms thereof upon the payment and performance in full of all of the Lessee’s obligations thereunder.
Reports
The Lease Guarantor will furnish or otherwise make available to each Owner Participant (a) within 60 days after the end of each of its first three fiscal quarters, copies of quarterly unaudited consolidated financial statements; (b) within 120 days after the end of each of its fiscal years, copies of year-end audited consolidated financial statements in conformity with GAAP; and (c) to the extent reasonably requested, such other financial or operating information that is routinely made available to creditors of the Lease Guarantor.
Operation and Maintenance
The Lease Guarantor covenants that it will not take any actions intended to prevent the Lessee from maintaining and operating the Facility in accordance with its obligations under the Leases.
Merger and Consolidation
The Lease Guarantor covenants that it will not consolidate with or merge with or into any other entity or sell, convey, transfer, lease or otherwise dispose of its properties and assets substantially as an entirety to any other entity, and will not permit any entity to consolidate with or merge into it unless:
(a) the entity resulting from such consolidation, surviving such merger or succeeding to such properties and assets, or the Successor Guarantor, shall: (i) be organized under the laws of the United States, any state thereof or the District of Columbia, (ii) expressly assume, pursuant to an agreement reasonably acceptable to the applicable Owner Participant (and, so long as the Lessor Notes are outstanding, the applicable Indenture Trustee), each obligation of the Lease Guarantor under the applicable Guaranty and the other applicable Operative Documents to which the Lessee is a party and the operating agreement for the Mansfield Plant; (iii) provide the applicable Owner Participant (and so long as the Lessor Notes are outstanding, the applicable Indenture Trustee) a customary officer’s certificate and a customary legal opinion addressing certain matters in connection therewith, and (iv) have a net worth that is not less than that of t he Lease Guarantor, determined not more than seven days prior to the closing of such transaction;
(b) immediately prior to and immediately following such transaction, no Material Default or Lease Event of Default shall have occurred and be continuing that has not been waived; and
(c) the Successor Guarantor shall have affirmed its obligations under each Guaranty.
Upon any consolidation, merger, sale, conveyance, transfer, lease or other disposal in accordance with paragraphs (a) to (c) above, the Successor Guarantor shall succeed to, and be substituted for, and may exercise every right and power of, the Lease Guarantor under the applicable Guaranty and Participation Agreement with the same effect as if such Successor Guarantor had been named as the Lease Guarantor and the Lease Guarantor shall be relieved of and released from all obligations and covenants under a Guaranty.
Amendments
No term, covenant, agreement or condition of a Guaranty may be terminated or amended, or compliance therewith waived, except by an instrument or instruments in writing executed by the Lease Guarantor and consented to by the applicable Lessor, the applicable Owner Participant and, so long as certain liens relating to the Indenture Trustee shall not have been terminated or discharged, the applicable Indenture Trustee and the applicable Pass Through Trustee.
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Table of ContentsAssignment of a Guaranty
The Lease Guarantor shall not assign any Guaranty or any of its obligations thereunder to any Person; provided that when the applicable Lessor Notes have been paid in full and the Lien of the applicable Lease Indenture has been discharged, the Lease Guarantor may assign such Guaranty to another Person with the explicit written consent of the applicable Owner Participant, such consent not to be unreasonably withheld.
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Table of Contents Material U.S. FEDERAL INCOME TAX consequences
General
The following is a summary of certain material U.S. federal income tax consequences of the exchange of Original Certificates for Exchange Certificates pursuant to this exchange offer, but does not address any other aspects of U.S. federal income tax consequences to holders of Original Certificates or Exchange Certificates. This summary is based upon the Internal Revenue Code of 1986, as amended (the ‘‘Code’’), the Treasury Regulations promulgated or proposed thereunder, and administrative and judicial interpretations thereof, all as of the date hereof and all of which are subject to change, possibly on a retroactive basis. This summary is not binding on the Internal Revenue Service (the ‘‘Service’’) or on the courts, and no ruling will be sought from the Service with respect to the statements made and the conclusions reached in this summary. There can be no assurance that the Service will agree with such statements and conclusions.
This summary is limited to the material U.S. federal income tax consequences relevant to those persons who are the original beneficial owners of Original Certificates, who exchange Original Certificates for Exchange Certificates in this exchange offer and who hold Original Certificates as capital assets within the meaning of Section 1221 of the Code, which we refer to as ‘‘Holders.’’ This summary does not address specific tax consequences that may be relevant to particular persons (including banks, financial institutions, broker-dealers, insurance companies, real estate investment trusts, regulated investment companies, partnerships or other pass-through entities, expatriates, tax-exempt organizations and persons that have a functional currency other than the U.S. dollar or persons in special situations, such as those who have elected to mark securities to market or those who hold the certificates as part of a straddle, hedge, conversion transaction or other integrated investment). In addition, this summary does not address U.S. federal alternative minimum, estate and gift tax consequences, consequences under the tax laws of any state, local or foreign jurisdiction, or consequences under any U.S. federal tax laws other than income tax law.
If a partnership or other entity taxable as a partnership holds Original Certificates, the tax treatment of a partner in the partnership generally will depend upon the status of the partner and the activities of the partnership. If you are a partner of a partnership holding the certificates, you should consult your tax advisor regarding the tax consequences of the exchange of Original Certificates for Exchange Certificates pursuant to this exchange offer.
This summary is for general information only. Persons considering the exchange of Original Certificates for Exchange Certificates are urged to consult their own tax advisors concerning the U.S. federal income tax consequences to them of exchanging the certificates, as well as the application of state, local and foreign tax laws and U.S. federal tax laws other than income tax law.
Exchange of an Old Certificate for an Exchange Certificate Pursuant to this Exchange Offer
The exchange of Original Certificates for Exchange Certificates in the exchange offer described herein will not constitute a significant modification of the terms of the Original Certificates and thus will not constitute a taxable exchange for U.S. federal income tax purposes. Rather, the Exchange Certificates will be treated as a continuation of the Original Certificates. Consequently, a Holder will not recognize gain or loss upon receipt of the Exchange Certificates, the Holder’s basis in the Exchange Certificates will be the same as its basis in the Original Certificates immediately before the exchange, and the Holder’s holding period in the Exchange Certificates will include its holding period in the Original Certificates.
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Table of ContentsCERTAIN ERISA CONSIDERATIONS
Any person who intends to acquire Exchange Certificates or any interest therein with the assets of a Plan (as defined below) should consult with its counsel with respect to the potential consequences of such investment under the fiduciary responsibility provisions of the Employee Retirement Income Security Act of 1974, as amended (‘‘ERISA’’) and the prohibited transaction provisions of Section 406 of ERISA and the Internal Revenue Code of 1986 as amended (the ‘‘Code’’) Section 4975.
ERISA and the Code impose certain requirements on employee benefit plans, accounts and arrangements and any entity holding the assets of any such plan, account or arrangement (such as a bank common investment fund or an insurance company general or separate account) that is subject to Title I of ERISA or Section 4975 of the Code, collectively referred to as the ‘‘Plans’’. Generally, a person who exercises authority or control with respect to the assets of a Plan (‘‘Plan Assets’’) will be considered a fiduciary of the Plan under ERISA. Before acquiring an Exchange Certificate or any interest therein, a Plan fiduciary should determine whether such investment complies with ERISA’s fiduciary standards under the prevailing circumstances, including ERISA’s diversification and prudence requirements, taking into account the limited liquidity of the Exchange Certificates, and whether the investment is permitted by the Plan document and the instruments governing the Plan.
In addition, Section 406 of ERISA and Section 4975(c) of the Code prohibit a wide range of transactions, (‘‘Prohibited Transactions’’), involving the Plan assets and persons who have certain specified relationships to the Plan, (‘‘Parties in Interest’’ within the meaning of ERISA, or ‘‘Disqualified Persons’’ within the meaning of the Code). Thus, a Plan fiduciary considering an acquisition of an Exchange Certificate or any interest therein should also consider whether such investment might constitute or give rise to a Prohibited Transaction under ERISA or the Code for which no exemption (as discussed below) is available.
Further, acquisition of an Exchange Certificate or any interest therein by a Plan might result in the assets of the Pass Through Trust being deemed to constitute Plan Assets. If the assets of the Pass Through Trust are considered to be Plan Assets, the operation of the Pass Through Trust might give rise to a fiduciary breach or nonexempt Prohibited Transaction under ERISA or Section 4975 of the Code. In addition, the Plan fiduciary might be deemed to have engaged in an improper delegation to the Pass Through Trustee of its investment management responsibilities with respect to those assets of the Pass Through Trust deemed to be Plan Assets.
Section 2510.3-101 of the United States Department of Labor regulations, as amplified by Section 3(42) of ERISA, (the ‘‘Plan Asset Regulations’’), generally provides that, when a Plan acquires an Equity Interest (as defined below) in an entity that is neither a ‘‘publicly-offered security’’ or a security issued by an investment company registered under the Investment Company Act of 1940, as amended, the Plan’s assets, include both the ‘‘Equity Interest’’ and an undivided interest in each of the underlying assets of the entity, unless it is established that either the entity is an ‘‘operating company’’ or equity participation in the entity by ‘‘Benefit Plan Investors’’ is not ‘‘significant.’’ An ‘‘Equity Interest’’ is defined under the Plan Asset Regulations as any interest in an entity other than an instrument that is treated as indebtedness under applicable local law and that has no substantial equity features. Because it is anticipated that the Certificates will not be ‘‘publicly offered securities’’ for purposes of the Plan Asset Regulations, the Pass Through Trust will not be an investment company registered under the Investment Company Act of 1940 and the Pass Through Trust will not qualify as an operating company within the meaning of the Plan Asset Regulations, it is likely that the Exchange Certificates will be treated as Equity Interests in the Pass Through Trust under the Plan Asset Regulations.
Section 2510.3-101(b)(2) of the Plan Asset Regulations defines ‘‘publicly-offered security’’ as a security that is ‘‘freely transferable,’’ part of a class of securities that is ‘‘widely held’’ and either: (i) part of a class of securities registered under section 12(b) or 12(g) of the Securities Exchange Act of 1934, or (ii) sold to a plan as part of an offering of securities to the public pursuant to an effective registration statement under the Securities Act of 1933 and the class of securities of which such security is a part is registered under the Securities Act of 1934 within 120 days after the end of the
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Table of Contentsfiscal year of the issuer during which the offering of such securities to the public occurred. The Exchange Certificates will not be registered under the Securities Act of 1934, and will not be ‘‘publicly-offered securities.’’
Pursuant to the Plan Asset Regulations, therefore, if a Plan acquires an interest in an Exchange Certificate, the Plan’s assets may include (in addition to the Exchange Certificate or any interest therein) an undivided interest in the underlying assets of the Pass Through Trust, unless it is established that equity participation in the Pass Through Trust by Benefit Plan Investors is not ‘‘significant.’’
Participation by Benefit Plan Investors in the Pass Through Trust would not be ‘‘significant’’ if less than 25% of the value of any class of the equity interests in the Pass Through Trust is held by Benefit Plan Investors immediately after the most recent acquisition of an Equity Interest or any interest therein. The term ‘‘Benefit Plan Investors’’ includes any Plans and other entities whose underlying assets are deemed to include Plan Assets. Investment in and transfer of the Exchange Certificates or any interest therein will not be monitored with respect to this 25% limit. Accordingly, it is possible that, 25% or more of the Exchange Certificates will be held by Benefit Plan Investors so that, under the Plan Assets Regulations, an investment by a Plan in the Exchange Certificates or any interest therein would, in effect, be considered, for purposes of the fiduciary responsibility provisions of ERISA and the Prohi bited Transaction provisions of ERISA and Section 4975 of the Code, an investment in the corresponding Lessor Notes and an ongoing loan to each Lessor. If any of the assets of the Pass Through Trust are considered Plan Assets, investment by a Plan in the Exchange Certificates or any interest therein could result in a fiduciary breach, a non-exempt Prohibited Transaction or an impermissible delegation of authority.
Likewise, ownership of any Original Certificates or any interest therein remaining after the expiration of this Exchange Offer will not be monitored with respect to the 25% limit. Owners of any remaining Original Certificates or any interest therein, moreover, will remain subject to those representations and warranties deemed to have been made upon the acquisition of an Original Certificate or any interest therein.
The Initial Purchasers, the Pass Through Trustee, each Indenture Trustee, each Lessor and any of their affiliates may be a Party in Interest or a Disqualified Person with respect to the Plan acquiring, holding or disposing of the Exchange Certificates or any interest therein. If that is the case, such acquisition, holding or disposition could give rise to a direct or indirect non-exempt Prohibited Transaction regardless of whether the assets of the Pass Through Trust are considered Plan Assets. A Party in Interest or Disqualified Person, including a fiduciary, who engages in a Prohibited Transaction for which no statutory or administrative exemption is available may be subject to excise taxes and other penalties and liabilities under ERISA and the Code. The persons involved in the Prohibited Transaction may have to cancel the transaction and pay an amount to the Plan for any losses realized by the Plan or profits realized by these persons. Finally, an individual retirement account involved in the Prohibited Transaction may be disqualified which would result in adverse tax consequences to the owner of the account.
Certificates held by a Plan will be deemed to constitute Plan Assets, and the purchase, holding and disposition of the Exchange Certificates by a Plan may constitute or result in a direct or indirect Prohibited Transaction under Section 406 of ERISA, Section 4975 of the Code or both of those sections, if a party to the transaction is also a Party in Interest or Disqualified Person with respect to such Plan, unless an exemption is available. In this regard, the United States Department of Labor, or the DOL, has issued Prohibited Transaction Class Exemptions, or PTCEs, that may apply to these transactions. If you are a fiduciary of a Plan, before purchasing any Exchange Certificate or any interests therein you should consider the availability of one of these PTCEs, or one of the statutory exemptions provided by ERISA or Section 4975 of the Code which include:
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| • | PTCE 75-1, which exempts certain transactions between a Plan and certain broker-dealers, reporting dealers and banks; |
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| • | PTCE 84-14, which exempts certain transactions effected on behalf of a Plan by a ‘‘qualified professional asset manager’’; |
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| • | PTCE 90-1, which exempts certain transactions between insurance company pooled separate accounts and parties in interest; |
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| • | PTCE 91-38, which exempts certain transactions between bank collective investment funds and parties in interest; |
| | |
| • | PTCE 95-60, which exempts certain transactions between insurance company general accounts and parties in interest; |
| | |
| • | PTCE 96-23, which exempts certain transactions effected on behalf of a Plan by an ‘‘in-house asset manager’’; and |
| | |
| • | the statutory service provider exemption provided by Section 408(b)(17) of ERISA and Section 4975(d)(20) of the Code, which exempt certain transactions between Plans and certain service providers that are not fiduciaries with respect to the plan assets involved in the transaction. |
We cannot provide any assurance that any of these class exemptions or statutory exemptions will apply with respect to any particular investment in the Exchange Certificates by, or on behalf of, a Plan or, even if it were deemed to apply, that any exemption would apply to all transactions that may occur in connection with the investment.
Accordingly, by its purchase of the Exchange Certificates, each purchaser and any fiduciary acting in connection with the purchase on behalf of any Plan, will be deemed to have represented and warranted on each day from and including the date of its purchase of the Exchange Certificates through and including the date of disposition of any such Exchange Certificate that:
(a) no portion of the assets used by it for purchasing and holding an Exchange Certificate or any interest therein constitutes Plan Assets; or
(b) all or a portion of the assets used by it for purchasing or holding a Certificate or any interest therein constitute Plan Assets, provided,
(i) the Exchange Certificate Purchaser is a Benefit Plan Investor solely because its underlying assets include Plan Assets, and not because it is a Plan;
(ii) less than 25% of its assets are Plan Assets; and
(iii) either (A) the acquisition and holding of such Exchange Certificate or interest therein does not constitute a transaction that is prohibited by ERISA, the Code, or other applicable law; or (B) such acquisition or holding of such Exchange Certificate or interest therein constitutes or will constitute a transaction that is prohibited by ERISA, the Code, or other applicable law but an exemption is available with respect to such transactions and the conditions of such exemption have at all relevant times been satisfied.
The foregoing discussion is general in nature and is not intended to be all-inclusive. Due to the complexity of these rules and the penalties that may be imposed upon persons involved in non-exempt Prohibited Transactions, it is particularly important that each Plan fiduciary and each fiduciary of a governmental plan, non-U.S. pension plan or church plan subject to similar law that is considering the purchase of Certificates or any interest therein consult its tax and/or legal advisors regarding the circumstances under which the assets of the Pass Through Trust would be considered Plan Assets, the availability, if any, of exemptive relief from any potential Prohibited Transaction, and other fiduciary issues and their potential consequences.
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Table of ContentsPLAN OF DISTRIBUTION
As discussed under ‘‘The Exchange Offer’’ in this prospectus, based on interpretations by the staff of the SEC set forth in no-action letters issued to other companies, we believe that a holder, other than a person that is an affiliate of ours within the meaning of Rule 405 under the Securities Act or a broker-dealer registered under the Exchange Act that purchases Original Certificates or Exchange Certificates from us to resell pursuant to Rule 144A under the Securities Act or any other exemption, that acquires the Exchange Certificates in the ordinary course of business and that is not participating in, does not intend to participate in, and has no arrangement or understanding with any person to participate in, the distribution of the Original Certificates or Exchange Certificates will be allowed to resell the Exchange Certificates to the public without further registration under the Securities Act and without delivering to the purchase rs of the Exchange Certificates a prospectus that satisfies the requirements of Section 10 of the Securities Act. However, if any holder acquires Exchange Certificates in this exchange offer for the purpose of distributing or participating in a distribution of the Exchange Certificates, such holder cannot rely on the position of the staff enunciated in Morgan Stanley & Co., Inc. (available June 5, 1991) and Exxon Capital Holdings Corp. (available May 13, 1988), as interpreted in the SEC’s letter to Shearman & Sterling dated July 2, 1993, or similar no-action or interpretive letters and must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction, and such secondary resale transaction must be covered by an effective registration statement containing the selling security holder information required by Item 507 or 508, as applicable, of Regulation S-K if the resales are of Exchange Certi ficates obtained by such holder in exchange for Original Certificates acquired by such holder directly from us or an affiliate thereof, unless an exemption from registration is otherwise available.
As contemplated by the above no-action letters and the registration rights agreement, each holder accepting this exchange offer is required to represent to us in the letter of transmittal that:
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| (1) | any Exchange Certificates it receives will be acquired in the ordinary course of business; |
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| (2) | it has no arrangement or understanding with any person to participate in a distribution (within the meaning of the Securities Act) of the Exchange Certificates; |
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| (3) | it is not an ‘‘affiliate’’ of ours as defined in Rule 405 of the Securities Act; |
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| (4) | if it is not a broker-dealer, it is not engaged in, and does not intend to engage in, the distribution (within the meaning of the Securities Act) of the Exchange Certificates within the meaning of the Securities Act; and |
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| (5) | if it is a participating broker-dealer that it will receive Exchange Certificates for its own account in exchange for Original Certificates that were acquired as a result of market-making activities or other trading activities, and acknowledge that it will deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of such Exchange Certificates. |
This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Exchange Certificates received in exchange for Original Certificates where such Original Certificates were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period ending on the sooner of 90 days after the consummation of the exchange offer and the date on which all participating broker-dealers have sold all Exchange Certificates held by them, unless such period is extended pursuant to the registration rights agreement, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, dealers effecting transactions in Exchange Certificates may be required to deliver a prospectus.
We will not receive any proceeds from any sale of Exchange Certificates by broker-dealers. Exchange Certificates received by broker-dealers for their own account pursuant to this exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the Exchange Certificates or a combination
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Table of Contentsof such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such Exchange Certificates. Any broker-dealer that resells Exchange Certificates that were received by it for its own account pursuant to this exchange offer and any broker or dealer that participates in a distribution of such Exchange Certificates may be deemed to be an ‘‘underwriter’’ within the meaning of the Securities Act, and any profit on any such resale of Exchange Certificates and any commission or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a br oker-dealer will not be deemed to admit that it is an ‘‘underwriter’’ within the meaning of the Securities Act.
186
Table of ContentsLEGAL MATTERS
The validity of the Exchange Certificates offered by this prospectus and certain legal matters in connection with the exchange offer will be passed upon for the Lessee and FES by Gary Benz, Esq., Associate General Counsel of their parent, FirstEnergy, and Akin Gump Strauss Hauer & Feld LLP, New York, New York, their special counsel. As of August 1, 2007, Mr. Benz owned approximately 33,989 shares of our parent, FirstEnergy, which includes nonqualified options to acquire 26,750 shares (24,475 of which are presently exercisable), and 3,335 shares of unvested restricted stock units.
experts
The financial statements as of December 31, 2006 and 2005 and for each of the three years in the period ended December 31, 2006 included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.
187
INDEX TO FINANCIAL STATEMENTS
| | | | | | |
| Report of Independent Registered Public Accounting Firm | | | | | F-2 | |
| Consolidated Statements of Income for the years ended December 31, 2006, 2005 and 2004 | | | | | F-3 | |
| Consolidated Balance Sheets as of December 31, 2006 and 2005 | | | | | F-4 | |
| Consolidated Statements of Capitalization for the years ended December 31, 2006 and 2005 | | | | | F-5 | |
| Consolidated Statements of Common Stockholder’s Equity for the years ended December 31, 2006, 2005 and 2004 | | | | | F-6 | |
| Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004 | | | | | F-7 | |
| Notes to Consolidated Financial Statements | | | | | F-8 | |
| Consolidated Statements of Income and Comprehensive Income for the three and six months periods ended June 30, 2007 and 2006 (Unaudited) | | | | | F-45 | |
| Consolidated Balance Sheets as of June 30, 2007 (Unaudited) and December 31, 2006 | | | | | F-46 | |
| Consolidated Statements of Cash Flows for the six months period ended June 30, 2007 and 2006 (Unaudited) | | | | | F-47 | |
| Notes to Consolidated Financial Statements (Unaudited) | | | | | F-48 | |
F-1
Table of ContentsReport of Independent Registered Public Accounting Firm
To the Stockholder and Board of Directors of
FirstEnergy Solutions Corp.
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of FirstEnergy Solutions Corp. and its subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance a bout 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 3 to the consolidated financial statements, the Company changed the manner in which it accounts for defined benefit pension and other postretirement benefit plans as of December 31, 2006. As discussed in Note 2(H) and Note 8 to the consolidated financial statements, the Company changed its method of accounting for conditional asset retirement obligations as of December 31, 2005.
PricewaterhouseCoopers LLP
Cleveland, Ohio
April 11, 2007, except for Note 12, as to
which the date is August 6, 2007
F-2
Table of ContentsFIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME
| | | | | | | | | | | | | | | | | | |
| | | | For the Years Ended December 31, |
| | | | 2006 | | | 2005 | | | 2004 |
| | | | (in thousands) |
| REVENUES: | | | | | | | | | | | | | | | | | | |
| Electric sales to affiliates (Note 2(I)) | | | | $ | 2,609,299 | | | | | $ | 2,425,251 | | | | | $ | 2,634,594 | |
| Other | | | | | 1,402,054 | | | | | | 1,541,988 | | | | | | 2,571,567 | |
| Total revenues | | | | | 4,011,353 | | | | | | 3,967,239 | | | | | | 5,206,161 | |
| EXPENSES (Note 2(I)): | | | | | | | | | | | | | | | | | | |
| Fuel | | | | | 1,105,657 | | | | | | 1,005,877 | | | | | | 718,891 | |
| Purchased power from non-affiliates | | | | | 590,491 | | | | | | 957,570 | | | | | | 2,276,591 | |
| Purchased power from affiliates | | | | | 257,001 | | | | | | 308,602 | | | | | | 326,241 | |
| Other operating expenses | | | | | 1,027,564 | | | | | | 980,182 | | | | | | 954,469 | |
| Provision for depreciation | | | | | 179,163 | | | | | | 177,231 | | | | | | 198,503 | |
| General taxes | | | | | 73,332 | | | | | | 67,302 | | | | | | 66,350 | |
| Total expenses | | | | | 3,233,208 | | | | | | 3,496,764 | | | | | | 4,541,045 | |
| OPERATING INCOME | | | | | 778,145 | | | | | | 470,475 | | | | | | 665,116 | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | |
| Investment income | | | | | 45,937 | | | | | | 78,787 | | | | | | 61,175 | |
| Miscellaneous income (expense) | | | | | 8,565 | | | | | | (34,143 | ) | | | | | (9,771 | ) |
| Interest expense to affiliates (Note 2(I)) | | | | | (162,673 | ) | | | | | (184,317 | ) | | | | | (171,007 | ) |
| Interest expense – other | | | | | (26,468 | ) | | | | | (12,038 | ) | | | | | (10,613 | ) |
| Capitalized interest | | | | | 11,495 | | | | | | 14,295 | | | | | | 16,914 | |
| Total other expense | | | | | (123,144 | ) | | | | | (137,416 | ) | | | | | (113,302 | ) |
| INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | | | | | 655,001 | | | | | | 333,059 | | | | | | 551,814 | |
| INCOME TAXES | | | | | 236,348 | | | | | | 124,499 | | | | | | 229,575 | |
| INCOME FROM CONTINUING OPERATIONS | | | | | 418,653 | | | | | | 208,560 | | | | | | 322,239 | |
| Discontinued operations (net of income taxes of $3,761,000 and $3,038,000, respectively) (Note 2(G)) | | | | | — | | | | | | 5,410 | | | | | | 4,396 | |
| INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE | | | | | 418,653 | | | | | | 213,970 | | | | | | 326,635 | |
| Cumulative effect of a change in accounting principle (net of income tax benefit of $5,507,000) (Note 2(H)) | | | | | — | | | | | | (8,803 | ) | | | | | — | |
| NET INCOME | | | | $ | 418,653 | | | | | $ | 205,167 | | | | | $ | 326,635 | |
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
F-3
Table of ContentsFIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
| | | | | | | | | | | | |
| | | | As of December 31, |
| | | | 2006 | | | 2005 |
| | | | (in thousands) |
| ASSETS |
| CURRENT ASSETS: | | | | | | |
| Cash and cash equivalents | | | | $ | 2 | | | | | $ | 2 | |
| Receivables – | | | | | | | | | | | | |
| Customers (less accumulated provisions of $9,907,000 and $11,532,000, respectively, for uncollectible accounts) | | | | | 129,843 | | | | | | 99,315 | |
| Associated companies | | | | | 235,532 | | | | | | 236,651 | |
Other (less accumulated provisions of $5,593,000 and $5,599,000, respectively, for
uncollectible accounts) | | | | | 4,085 | | | | | | 14,880 | |
| Notes receivable from associated companies | | | | | 752,919 | | | | | | 291,626 | |
| Materials and supplies, at average cost | | | | | 460,239 | | | | | | 416,968 | |
| Prepayments and other | | | | | 57,546 | | | | | | 48,881 | |
| | | | | | 1,640,166 | | | | | | 1,108,323 | |
| PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | |
| In service | | | | | 8,355,344 | | | | | | 7,704,424 | |
| Less – Accumulated provision for depreciation | | | | | 3,818,268 | | | | | | 3,685,328 | |
| | | | | | 4,537,076 | | | | | | 4,019,096 | |
| Construction work in progress | | | | | 339,886 | | | | | | 512,467 | |
| | | | | | 4,876,962 | | | | | | 4,531,563 | |
| INVESTMENTS: | | | | | | | | | | | | |
| Nuclear plant decommissioning trusts | | | | | 1,238,272 | | | | | | 1,094,176 | |
| Long-term notes receivable from associated companies | | | | | 62,900 | | | | | | 62,900 | |
| Other | | | | | 72,509 | | | | | | 79,477 | |
| | | | | | 1,373,681 | | | | | | 1,236,553 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | |
| Goodwill | | | | | 24,248 | | | | | | 24,248 | |
| Property taxes | | | | | 44,111 | | | | | | 42,076 | |
| Prepaid pension costs (Note 3) | | | | | — | | | | | | 49,115 | |
| Accumulated deferred income taxes | | | | | — | | | | | | 16,464 | |
| Other | | | | | 39,839 | | | | | | 92,148 | |
| | | | | | 108,198 | | | | | | 224,051 | |
| | | | | $ | 7,999,007 | | | | | $ | 7,100,490 | |
| LIABILITIES AND CAPITALIZATION |
| CURRENT LIABILITIES: | | | | | | | | | | | | |
| Currently payable long-term debt | | | | $ | 1,469,660 | | | | | $ | 312,750 | |
| Notes payable to associated companies | | | | | 1,022,197 | | | | | | 975,795 | |
| Accounts payable – | | | | | | | | | | | | |
| Associated companies | | | | | 556,049 | | | | | | 469,621 | |
| Other | | | | | 136,631 | | | | | | 192,480 | |
| Accrued taxes | | | | | 113,231 | | | | | | 103,788 | |
| Other | | | | | 100,941 | | | | | | 76,000 | |
| | | | | | 3,398,709 | | | | | | 2,130,434 | |
| CAPITALIZATION: | | | | | | | | | | | | |
| Common stockholder’s equity | | | | | 1,859,363 | | | | | | 1,401,334 | |
| Long-term debt | | | | | 1,614,222 | | | | | | 2,615,247 | |
| | | | | | 3,473,585 | | | | | | 4,016,581 | |
| NONCURRENT LIABILITIES: | | | | | | | | | | | | |
| Accumulated deferred income taxes | | | | | 121,449 | | | | | | — | |
| Accumulated deferred investment tax credits | | | | | 65,751 | | | | | | 70,409 | |
| Asset retirement obligations | | | | | 760,228 | | | | | | 716,169 | |
| Retirement benefits | | | | | 103,027 | | | | | | 118,092 | |
| Property taxes | | | | | 44,433 | | | | | | 43,625 | |
| Other | | | | | 31,825 | | | | | | 5,180 | |
| | | | | | 1,126,713 | | | | | | 953,475 | |
| COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | | | | | |
| | | | | $ | 7,999,007 | | | | | $ | 7,100,490 | |
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
F-4
Table of ContentsFIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
| | | | | | | | | | | | |
| | | | As of December 31, |
| | | | 2006 | | | 2005 |
| | | | (dollars in thousands) |
| COMMON STOCKHOLDER’S EQUITY: | | | | | | |
| Common stock, without par value, authorized 750 shares – 8 shares outstanding | | | | $ | 1,050,302 | | | | | $ | 1,048,734 | |
| Accumulated other comprehensive income (Note 2(f)) | | | | | 111,723 | | | | | | 65,461 | |
| Retained earnings (Note 7(A)) | | | | | 697,338 | | | | | | 287,139 | |
| Total common stockholder’s equity | | | | | 1,859,363 | | | | | | 1,401,334 | |
| LONG-TERM DEBT (Note 7(B)): | | | | | | | | | | | | |
| Secured notes: | | | | | | | | | | | | |
| FE Generation Corp. | | | | | | | | | | | | |
| 3.980% due to associated companies 2025 (Note 1) | | | | | 770,912 | | | | | | 1,021,522 | |
| 4.380% due to associated companies 2025 (Note 1) | | | | | 35,952 | | | | | | 100,972 | |
| 5.390% due to associated companies 2025 (Note 1) | | | | | 13,967 | | | | | | 74,467 | |
| 5.990% due to associated companies 2025 (Note 1) | | | | | 221,485 | | | | | | 383,131 | |
| | | | | | 1,042,316 | | | | | | 1,580,092 | |
| FE Nuclear Generation Corp. | | | | | | | | | | | | |
| 4.380% due to associated companies 2025 (Note 1) | | | | | 55,100 | | | | | | 166,331 | |
| 5.990% due to associated companies 2025 (Note 1) | | | | | 265,150 | | | | | | 478,350 | |
| | | | | | 320,250 | | | | | | 644,681 | |
| Total secured notes | | | | | 1,362,566 | | | | | | 2,224,773 | |
| Unsecured notes: | | | | | | | | | | | | |
| FE Generation Corp. | | | | | | | | | | | | |
| *3.910% due 2017 | | | | | 28,525 | | | | | | — | |
| *4.000% due 2019 | | | | | 90,140 | | | | | | — | |
| *3.950% due 2023 | | | | | 234,520 | | | | | | — | |
| *4.350% due 2028 | | | | | 15,000 | | | | | | 15,000 | |
| *4.050% due 2040 | | | | | 43,000 | | | | | | 43,000 | |
| *3.940% due 2041 | | | | | 129,610 | | | | | | — | |
| *3.980% due 2041 | | | | | 56,600 | | | | | | — | |
| *4.050% due 2041 | | | | | 26,000 | | | | | | — | |
| | | | | | 623,395 | | | | | | 58,000 | |
| FE Nuclear Generation Corp. | | | | | | | | | | | | |
| *3.870% due 2033 | | | | | 15,500 | | | | | | — | |
| *3.870% due 2033 | | | | | 135,550 | | | | | | — | |
| *3.920% due 2033 | | | | | 62,500 | | | | | | — | |
| *3.930% due 2033 | | | | | 99,100 | | | | | | 99,100 | |
| *3.930% due 2033 | | | | | 8,000 | | | | | | 8,000 | |
| *3.950% due 2033 | | | | | 107,500 | | | | | | — | |
| *3.990% due 2033 | | | | | 46,500 | | | | | | — | |
| *3.940% due 2034 | | | | | 82,800 | | | | | | 82,800 | |
| *3.950% due 2034 | | | | | 7,200 | | | | | | 7,200 | |
| *3.870% due 2035 | | | | | 163,965 | | | | | | — | |
| *3.950% due 2035 | | | | | 72,650 | | | | | | 72,650 | |
| *3.970% due 2035 | | | | | 60,000 | | | | | | — | |
| 3.980% due to associated companies 2025 (Note 1) | | | | | 56,000 | | | | | | 194,821 | |
| 5.390% due to associated companies 2025 (Note 1) | | | | | 180,720 | | | | | | 180,720 | |
| | | | | | 1,097,985 | | | | | | 645,291 | |
| Total unsecured notes | | | | | 1,721,380 | | | | | | 703,291 | |
| Net unamortized discount on debt | | | | | (64 | ) | | | | | (67 | ) |
| Long-term debt due within one year | | | | | (1,469,660 | ) | | | | | (312,750 | ) |
| Total long-term debt | | | | | 1,614,222 | | | | | | 2,615,247 | |
| TOTAL CAPITALIZATION | | | | $ | 3,473,585 | | | | | $ | 4,016,581 | |
| * | Denotes variable rate issue with applicable year-end interest rate shown. |
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
F-5
Table of ContentsFIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Comprehensive
Income | | | Number of
Shares | | | Carrying
Value | | | Accumulated Other
Comprehensive
Income | | | Retained
Earnings
(Accumulated
Deficit) |
| | | | (dollar in thousands) |
| Balance, January 1, 2004 | | | | | | | | | | | 8 | | | | | $ | 783,685 | | | | | $ | 61,782 | | | | | $ | (245,504 | ) |
| Net income | | | | $ | 326,635 | | | | | | | | | | | | | | | | | | | | | | | | 326,635 | |
Net unrealized loss on derivative
instruments, net of $3,903,000 of income tax benefits | | | | | (5,561 | ) | | | | | | | | | | | | | | | | | (5,561 | ) | | | | | | |
Unrealized gain on investments,
net of $11,896,000 of income taxes | | | | | 16,270 | | | | | | | | | | | | | | | | | | 16,270 | | | | | | | |
Minimum liability for unfunded
retirement benefits, net of $660,000 of income taxes | | | | | 12,027 | | | | | | | | | | | | | | | | | | 12,027 | | | | | | | |
| Comprehensive income | | | | $ | 349,371 | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance, December 31, 2004 | | | | | | | | | | | 8 | | | | | | 783,685 | | | | | | 84,518 | | | | | | 81,131 | |
| Net income | | | | $ | 205,167 | | | | | | | | | | | | | | | | | | | | | | | | 205,167 | |
Net unrealized loss on derivative
instruments, net of $2,414,000 of income tax benefits | | | | | (3,595 | ) | | | | | | | | | | | | | | | | | (3,595 | ) | | | | | | |
Unrealized loss on investments,
net of $9,658,000 of income tax benefits | | | | | (15,462 | ) | | | | | | | | | | | | | | | | | (15,462 | ) | | | | | | |
| Comprehensive income | | | | $ | 186,110 | | | | | | | | | | | | | | | | | | | | | | | | | |
| Equity contribution from parent | | | | | | | | | | | | | | | | | 262,200 | | | | | | | | | | | | | |
Stock options exercised, restricted
stock units and other adjustments | | | | | | | | | | | | | | | | | 2,849 | | | | | | | | | | | | 841 | |
| Balance, December 31, 2005 | | | | | | | | | | | 8 | | | | | | 1,048,734 | | | | | | 65,461 | | | | | | 287,139 | |
| Net income | | | | $ | 418,653 | | | | | | | | | | | | | | | | | | | | | | | | 418,653 | |
Net unrealized loss on derivative
instruments, net of $5,082,000 of income tax benefits | | | | | (8,248 | ) | | | | | | | | | | | | | | | | | (8,248 | ) | | | | | | |
Unrealized gain on investments,
net of $33,698,000 of income taxes | | | | | 58,654 | | | | | | | | | | | | | | | | | | 58,654 | | | | | | | |
| Comprehensive income | | | | $ | 469,059 | | | | | | | | | | | | | | | | | | | | | | | | | |
Net liability for unfunded
retirement benefits due to the implementation of SFAS 158, net of $10,825,000 of income tax benefits | | | | | | | | | | | | | | | | | | | | | | | (4,144 | ) | | | | | | |
Stock options exercised, restricted
stock units and other adjustments | | | | | | | | | | | | | | | | | 1,568 | | | | | | | | | | | | | |
Cash dividends declared on
common stock | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (8,454 | ) |
| Balance, December 31, 2006 | | | | | | | | | | | 8 | | | | | $ | 1,050,302 | | | | | $ | 111,723 | | | | | $ | 697,338 | |
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
F-6
Table of ContentsFIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | | | | | | | | | | | | | | | |
| | | | For the Years Ended December 31, |
| | | | 2006 | | | 2005 | | | 2004 |
| | | | (in thousands) |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | $ | 418,653 | | | | | $ | 205,167 | | | | | $ | 326,635 | |
| Net Income | | | | | | | | | | | | | | | | | | |
Adjustments to reconcile net income to net cash from operating
activities – | | | | | | | | | | | | | | | | | | |
| Provision for depreciation | | | | | 179,163 | | | | | | 177,231 | | | | | | 198,503 | |
| Nuclear fuel amortization | | | | | 89,178 | | | | | | 86,748 | | | | | | 88,068 | |
| Deferred income taxes and investment tax credits, net | | | | | 115,878 | | | | | | 94,602 | | | | | | 155,417 | |
| Cumulative effect of a change in accounting principle | | | | | — | | | | | | 8,803 | | | | | | — | |
| Accrued compensation and retirement benefits | | | | | 25,052 | | | | | | 27,960 | | | | | | 35,699 | |
| Commodity derivative transactions, net | | | | | 24,144 | | | | | | (219 | ) | | | | | 11,353 | |
| Gain on asset sales | | | | | (37,663 | ) | | | | | (30,239 | ) | | | | | (5,097 | ) |
| Income from discontinued operations (Note 2(G)) | | | | | — | | | | | | (5,410 | ) | | | | | (4,396 | ) |
| Cash collateral, net | | | | | 40,680 | | | | | | 50,695 | | | | | | (66,384 | ) |
| Pension trust contribution | | | | | — | | | | | | (13,291 | ) | | | | | (61,502 | ) |
| Decrease (increase) in operating assets – | | | | | | | | | | | | | | | | | | |
| Receivables | | | | | (15,462 | ) | | | | | (17,076 | ) | | | | | 192,438 | |
| Materials and supplies | | | | | (1,637 | ) | | | | | (17,563 | ) | | | | | (3,708 | ) |
| Prepayments and other current assets | | | | | (5,237 | ) | | | | | (6,041 | ) | | | | | 2,202 | |
| Increase (decrease) in operating liabilities – | | | | | | | | | | | | | | | | | | |
| Accounts payable | | | | | 19,970 | | | | | | 44,792 | | | | | | (221,772 | ) |
| Accrued taxes | | | | | 12,235 | | | | | | 35,252 | | | | | | 54,444 | |
| Accrued interest | | | | | 4,101 | | | | | | 500 | | | | | | — | |
| Other | | | | | (10,214 | ) | | | | | 5,437 | | | | | | 12,269 | |
| Net cash provided from operating activities | | | | | 858,841 | | | | | | 647,348 | | | | | | 714,169 | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | |
| New Financing – | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | | | 1,156,841 | | | | | | — | | | | | | — | |
| Short-term borrowings, net | | | | | 46,402 | | | | | | — | | | | | | 19,739 | |
| Equity contribution from parent | | | | | — | | | | | | 262,200 | | | | | | — | |
| Redemptions and Repayments – | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | | | (1,137,740 | ) | | | | | — | | | | | | (325,332 | ) |
| Short-term borrowings, net | | | | | — | | | | | | (114,339 | ) | | | | | — | |
| Common stock dividend payments | | | | | (8,454 | ) | | | | | — | | | | | | — | |
| Net cash provided from (used for) financing activities | | | | | 57,049 | | | | | | 147,861 | | | | | | (305,593 | ) |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | |
| Property additions | | | | | (577,287 | ) | | | | | (411,560 | ) | | | | | (312,770 | ) |
| Proceeds from asset sales | | | | | 34,215 | | | | | | 58,087 | | | | | | 8,723 | |
| Proceeds from nuclear decommissioning trust fund sales | | | | | 1,067,216 | | | | | | 1,076,319 | | | | | | 861,691 | |
| Investments in nuclear decommissioning trust funds | | | | | (1,067,216 | ) | | | | | (1,165,424 | ) | | | | | (950,796 | ) |
| Loans to associated companies | | | | | (333,030 | ) | | | | | (291,626 | ) | | | | | — | |
| Other | | | | | (39,788 | ) | | | | | (61,033 | ) | | | | | (15,651 | ) |
| Net cash used for investing activities | | | | | (915,890 | ) | | | | | (795,237 | ) | | | | | (408,803 | ) |
| Net change in cash and cash equivalents | | | | | — | | | | | | (28 | ) | | | | | (227 | ) |
| Cash and cash equivalents at beginning of year | | | | | 2 | | | | | | 30 | | | | | | 257 | |
| Cash and cash equivalents at end of year | | | | $ | 2 | | | | | $ | 2 | | | | | $ | 30 | |
| SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | | | | | | | | | | | | | |
| Cash Paid During the Year – | | | | | | | | | | | | | | | | | | |
| Interest (net of amounts capitalized) | | | | $ | 173,337 | | | | | $ | 195,519 | | | | | $ | 177,213 | |
| Income taxes | | | | $ | 155,771 | | | | | $ | 20,274 | | | | | $ | 63,930 | |
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
F-7
Table of ContentsNOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| |
| 1. | ORGANIZATION AND BASIS OF PRESENTATION |
The consolidated financial statements include FES, or the Company, and its wholly owned subsidiaries, FGCO and NGC. The Company is a wholly owned subsidiary of FirstEnergy. FirstEnergy also holds directly, or indirectly, all of the issued and outstanding common shares of its eight principal electric utility operating subsidiaries: OE, Penn, CEI, TE, ATSI, JCP&L, Met-Ed and Penelec. Penn is a wholly owned subsidiary of OE.
On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies entered into certain agreements implementing a series of intra-system generation asset transfers, or GAT, that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively. The generating plant interests transferred do not include leasehold interests of CEI, TE and OE in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates. The GAT was accounted for as a transfer of assets under common control.
On October 24, 2005, the Ohio Companies and Penn completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO’s purchase option under the Master Facility Lease.
On December 16, 2005, the Ohio Companies and Penn completed the intra-system transfer of their respective ownership in the nuclear generation assets to NGC through, in the case of OE and Penn, an asset spin-off by way of dividend and, in the case of CEI and TE, a sale at net book value. FENOC continues to operate and maintain the nuclear generation assets.
These transactions were pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.
Prior to completion of the GAT in the fourth quarter of 2005, the Company, through its subsidiary, FGCO, operated FirstEnergy’s non-nuclear generation businesses. Its pre-GAT historical results reflected the related non-nuclear generation fuel and operating costs as well as certain transactions and relationships with its affiliates. These included PSAs to provide electricity to the Ohio Companies and Penn to meet their POLR obligations, lease arrangements for their non-nuclear generation assets and purchased power agreements for their nuclear generation. The Ohio Companies and Penn reflected the nuclear fuel and operating costs and depreciation and property tax expenses related to their nuclear and non-nuclear generation assets in their pre-GAT historical results.
The consolidated financial statements of the Company and its subsidiaries as of December 31, 2006 and 2005 and for the years ended December 31, 2006, 2005 and 2004 represent the financial position, results of operations and cash flows as if the GAT had occurred as of December 31, 2003. Certain financial results, net assets and net cash flows related to the ownership of OE, Penn, CEI and TE of the transferred generation assets prior to the GAT are reflected in these consolidated financial statements. The revisions in certain affiliated company transactions and relationships that had existed prior to the GAT, which are discussed above, have been reflected for the three years ended December 31, 2006, 2005 and 2004 as if the GAT had been effective as of December 31, 2003. Those changes in the Company’s historical results and cash flows that began in the fourth quarter of 2005 have been estimated on an annualized basis an d assumed to have begun at the end of 2003 and are reflected in the 2004 and 2005 financial statements. The Company’s results in 2006 reflect a full year of
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Table of Contentsthe GAT changes and therefore, no allocations or adjustments, except for those related to the NGC corporate restructuring discussed below, were reflected in the 2006 financial statements.
On December 28, 2006, the NRC approved the transfer of ownership in NGC from FirstEnergy to the Company. Effective December 31, 2006, NGC is a wholly owned subsidiary of the Company and a second tier subsidiary of FirstEnergy. FENOC continues to operate and maintain the nuclear generation assets. The consolidated financial statements assume that this corporate restructuring occurred at the end of 2003, with the Company’s and NGC’s financial position and results combined at the end of 2003 and associated company transactions and balances eliminated in consolidation.
Information in these consolidated financial statements was derived from historical and previously filed financial statements of FirstEnergy, OE, Penn, CEI and TE. Various allocation methodologies were employed to separate the results of operations and financial condition of the generation-related operations from the historical financial statements for the periods presented prior to the GAT. Certain assumptions used to reflect those various financial positions and transactions incorporated in the Company’s financial statements are described above.
Management believes that these assumptions and allocation methodologies are reasonable; however, had the GAT and FirstEnergy’s capital contribution of NGC to the Company actually occurred as of December 31, 2003, its results and financial position could have significantly differed from those presented herein. In addition, future results of operations, financial position and net cash flows could materially differ from the results presented in these consolidated financial statements.
The Company follows GAAP and complies with the regulations, orders, policies and practices prescribed by the SEC and the FERC. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period.
The Company operates in one business segment to generate and provide energy-related products and services to wholesale and retail customers in Ohio, Michigan, Pennsylvania, Maryland and New Jersey.
Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.
| |
| 2. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
(A) CASH AND SHORT-TERM FINANCIAL INSTRUMENTS–
All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value.
(B) REVENUES AND RECEIVABLES–
The Company’s principal business is providing energy related products and services primarily in Ohio, Pennsylvania, Michigan, Maryland and New Jersey. This includes providing electric power to affiliated regulated utility companies through PSAs in order that the utility affiliates meet all or a portion of their POLR requirements. The Company’s retail customers are metered on a cycle basis. Electric revenues are recorded based on energy delivered through the end of the calendar month. An estimate of unbilled revenues is calculated to recognize electric service provided between the last meter reading date and the end of the month. This estimate includes many factors including historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, the Company accrues the estimated unbilled amount receivable as revenue and reverses the related prior period estimate.
Receivables from customers include sales to residential, commercial and industrial customers and sales to non-affiliated wholesale customers. There was no material concentration of receivables as of
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Table of ContentsDecember 31, 2006 with respect to any particular segment of the Company’s customers. Total customer receivables were $128 million (billed—$102 million and unbilled—$26 million) and $99 million (billed—$75 million and unbilled—$24 million) as of December 31, 2006 and 2005, respectively.
(C) ACCOUNTING FOR CERTAIN WHOLESALE ENERGY TRANSACTIONS–
The Company engages in purchase and sale transactions in the PJM Market to support the supply of end-use customers, including POLR requirements in Pennsylvania. In conjunction with FirstEnergy’s dedication of the Beaver Valley Plant to PJM on January 1, 2005, the Company began accounting for purchase and sale transactions in the PJM Market based on its net hourly position – recording each hour as either an energy purchase or an energy sale in the Consolidated Statements of Income. Hourly energy positions are aggregated to recognize gross purchases and sales for the month. This revised method of accounting, which has no impact on net income, is consistent with the practice of other energy companies that have dedicated generating capacity in PJM and correlates with PJM’s scheduling and reporting of hourly energy transactions. The Company also applies the net hourly methodology to purchase and sale transactions in MISO’s energy mar ket, which became active on April 1, 2005 and continued through 2006.
For periods prior to January 1, 2005, FirstEnergy did not have substantial generating capacity in PJM and as such, the Company recognized purchases and sales in the PJM Market by recording each discrete transaction. Under those transactions, the Company would often buy a specific quantity of energy at a certain location in PJM and simultaneously sell a specific quantity of energy at a different location. Physical delivery occurred and the risks and rewards of ownership transferred with each transaction. The Company accounted for those transactions on a gross basis in accordance with EITF 99-19. The recognition of those transactions on a net basis in prior periods would have no impact on net income, but would have reduced both wholesale revenue and purchased power expense by $1.1 billion in 2004.
(D) PROPERTY, PLANT AND EQUIPMENT–
Property, plant and equipment reflects original cost for the nuclear generating assets (certain of which were adjusted to fair value in accordance with SFAS 144) and the purchase price of the non-nuclear generating assets (see Note 1 for further discussion), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred prior to placing the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. The Company’s accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred.
The Company provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annual composite rate for the Company’s electric plant was approximately 3.5%, 3.7% and 4.1% in 2006, 2005 and 2004, respectively.
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Table of ContentsJointly-Owned Generating Stations
The Company owns various power generating facilities, with OE, CEI and TE retaining interests in certain generating plants under sale and leaseback arrangements with non-affiliates that existed prior to the GAT. See Note 1 for further discussion. Each of the companies is obligated to pay a share of the costs associated with any jointly – owned facility in the same proportion as its interest. The Company’s portions of operating expenses associated with jointly – owned facilities are included in the corresponding operating expenses on the Consolidated Statements of Income. The amounts reflected on the Company’s Consolidated Balance Sheet under property, plant and equipment related to those jointly – owned facilities as of December 31, 2006 include the following:
| | | | | | | | | | | | | | | | | | | | | | | | |
| Generating Units | | | Utility Plant
in Service | | | Accumulated
Provision for
Depreciation | | | Construction
Work in
Progress | | | Company’s
Ownership
Interest |
| | | | (in millions) |
| Bruce Mansfield Units 1, 2 and 3 | | | | $ | 1,393 | | | | | $ | 592 | | | | | $ | 12 | | | | | | 67.89 | % |
| Beaver Valley Unit 2 | | | | | 137 | | | | | | 23 | | | | | | 18 | | | | | | 60.08 | % |
| Perry | | | | | 1,290 | | | | | | 488 | | | | | | 22 | | | | | | 87.42 | % |
| Total | | | | $ | 2,820 | | | | | $ | 1,103 | | | | | $ | 52 | | | | | | | |
Asset Retirement Obligations
The Company recognizes a liability for retirement obligations associated with tangible assets in accordance with SFAS 143 and FIN 47. These standards require recognition of the fair value of a liability for an ARO in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and depreciated over time, as described further in Note 8, ‘‘Asset Retirement Obligations.’’
Nuclear Fuel
Property, plant and equipment includes nuclear fuel recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. Nuclear fuel is amortized based on the units of production method.
(E) ASSET IMPAIRMENTS–
Long-Lived Assets
The Company evaluates the carrying value of its long-lived assets when events or circumstances indicate that the carrying amount may not be recoverable. In accordance with SFAS 144, the carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If an impairment exists, a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. Fair value is estimated by using available market valuations or the long-lived asset’s expected future net discounted cash flows. The calculation of expected cash flows is based on estimates and assumptions about future events.
Investments
At the end of each reporting period, the Company evaluates its investments for impairment. In accordance with SFAS 115 and FSP SFAS 115-1 and SFAS 124-1, investments classified as available-for-sale securities are evaluated to determine whether a decline in fair value below the cost basis is other-than-temporary. The Company first considers its intent and ability to hold the investment until recovery and then considers, among other factors, the duration and the extent to which the security’s fair value has been less than cost and the near-term financial prospects of the security issuer, when evaluating investments for impairment. If the decline in fair value is determined to be
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Table of Contentsother-than-temporary, the cost basis of the investment is written down to fair value. Upon adoption of FSP SFAS 115-1 and SFAS 124-1, the Company began recognizing in earnings the unrealized losses on available-for-sale securities held in the nuclear decommissioning trusts as the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of the other-than-temporary impairment. The fair value and unrealized gains and losses of the Company’s investments are disclosed in Note 4(B) and Note 4(C).
(F) COMPREHENSIVE INCOME–
Comprehensive income includes net income as reported on the Consolidated Statements of Income and certain changes in common stockholder’s equity, except those resulting from transactions with FirstEnergy. As of December 31, 2006, Accumulated Other Comprehensive Income, or AOCI, consisted of unrealized gains on investments in securities available for sale of $126 million, a net liability for unfunded retirement benefits due to the implementation of SFAS 158, net of income tax benefits of $4 million, and unrealized losses on derivative instrument hedges of $10 million. See Note 3 for further discussion. As of December 31, 2005, AOCI consisted of unrealized gains on investments in securities available for sale of $67 million and unrealized losses on derivative instrument hedges of $2 million.
(G) DIVESTITURES AND DISCONTINUED OPERATIONS–
In December 2004, the Company’s retail natural gas business qualified as assets held for sale in accordance with SFAS 144. As required by SFAS 142, goodwill associated with the natural gas business was tested for impairment as of December 31, 2004 with no impairment indicated. On March 31, 2005, the Company completed the sale of its retail natural gas business for an after-tax gain of $5 million.
Net results of $5 million (including the 2005 gain on the sale of assets discussed above) and $4 million associated with the divested retail gas business for 2005 and 2004, respectively, are reported as discontinued operations on the Consolidated Statements of Income. Pre-tax operating results were $1 million and $7 million in 2005 and 2004, respectively. Revenues associated with discontinued operations for 2005 and 2004 were $146 million and $496 million, respectively.
(H) CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE–
Results in 2005 included an after-tax charge of $9 million recorded upon the adoption of FIN 47 in December 2005. The Company identified applicable legal obligations as defined under FIN 47 at its active and retired generating units, identifying asbestos as the primary conditional ARO. The Company recorded a conditional ARO liability of $16 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $4 million (recorded as part of the carrying amount of the related long-lived asset), and accumulated depreciation of $1 million. The remaining cumulative effect adjustment for unrecognized depreciation and accretion of $14 million was charged to income ($9 million, net of tax) for the year ended December 31, 2005. See Note 8 for further discussion.
(I) TRANSACTIONS WITH AFFILIATED COMPANIES–
Operating revenues, operating expenses and interest expense include transactions with affiliated companies, primarily OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec and FESC. The Ohio transition plan resulted in the corporate separation of FirstEnergy’s regulated and unregulated operations in 2001. The Company operates the former generation businesses of OE, Penn, CEI and TE. As a result, OE, Penn, CEI and TE entered into a PSA with the Company to meet their POLR obligations. OE, Penn, CEI and TE have completed the intra-system transfers of their generation assets to FGCO and NGC excluding the leasehold interests of OE, CEI and TE in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliated entities. See Note 1 for further discussion. This resulted in the continuation of the sales arrangements with the Company for the
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Table of Contentsgeneration KWH related to those leasehold interests. The Company has a partial requirements wholesale PSA with Met-Ed and Penelec. See Note 6 for further discussion. The Company is incurring interest expense through FGCO and NGC associated companies’ notes payable provided to OE, Penn, CEI and TE in exchange for the transferred assets. OE, CEI and TE continue to purchase their power from the Company to meet their POLR obligations. Penn’s PSA expired in December 2006. See Note 6 for further discussion. The primary affiliated companies’ transactions are as follows:
| | | | | | | | | | | | | | | | | | |
| | | | 2006 | | | 2005 | | | 2004 |
| | | | (in millions) |
| Revenues: | | | | | | | | | | | | | | | | | | |
| Electric sales to affiliates | | | | $ | 2,609 | | | | | $ | 2,425 | | | | | $ | 2,635 | |
| Expenses: | | | | | | | | | | | | | | | | | | |
| Purchased power under PSA | | | | | 243 | | | | | | 275 | | | | | | 278 | |
| Purchased power from JCP&L | | | | | 14 | | | | | | 33 | | | | | | 48 | |
| FESC support services | | | | | 64 | | | | | | 48 | | | | | | 54 | |
| Net Interest Charges: | | | | | | | | | | | | | | | | | | |
| Interest expense to affiliated utilities | | | | | 109 | | | | | | 129 | | | | | | 145 | |
| Interest expense to FirstEnergy | | | | | 53 | | | | | | 55 | | | | | | 26 | |
FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from FESC, a subsidiary of FirstEnergy. The majority of costs are directly billed or assigned at no more than cost. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas developed by FESC. The current allocation or assignment formulas used and their bases include multiple factor formulas: each company’s proportionate amount of FirstEnergy’s aggregate direct payroll, number of employees, asset balances, revenues, number of customers, other factors and specific departmental charge ratios. Management believes that these allocation methods are reasonable. Intercompany transactions with FirstEnergy and its other subsidiaries are generally settled under commercial terms within thirty days.
(J) INCOME TAXES–
| | | | | | | | | | | | | | | | | | |
| For The Years Ended December 31, | | | 2006 | | | 2005 | | | 2004 |
| | | | (in thousands) |
| GENERAL TAXES: | | | | | | | | | | | | | | | | | | |
| Real and personal property | | | | $ | 48,773 | | | | | $ | 44,266 | | | | | $ | 48,085 | |
| Social security and unemployment | | | | | 12,854 | | | | | | 12,070 | | | | | | 11,216 | |
| State gross receipts* | | | | | 10,115 | | | | | | 9,305 | | | | | | 6,048 | |
| Other | | | | | 1,590 | | | | | | 1,661 | | | | | | 1,001 | |
| Total general taxes | | | | $ | 73,332 | | | | | $ | 67,302 | | | | | $ | 66,350 | |
| * | Collected from customers and included in revenue in the Consolidated Statements of Income. |
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Table of Contents
| | | | | | | | | | | | | | | | | | |
| For The Years Ended December 31, | | | 2006 | | | 2005 | | | 2004 |
| | | | (in thousands) |
| PROVISION FOR INCOME TAXES | | | | | | | | | | | | | | | | | | |
| Currently payable – | | | | | | | | | | | | | | | | | | |
| Federal | | | | $ | 102,633 | | | | | $ | 28,788 | | | | | $ | 57,066 | |
| State | | | | | 17,837 | | | | | | 1,109 | | | | | | 17,092 | |
| | | | | | 120,470 | | | | | | 29,897 | | | | | | 74,158 | |
| Deferred, net – | | | | | | | | | | | | | | | | | | |
| Federal | | | | | 110,052 | | | | | | 94,071 | | | | | | 123,291 | |
| State | | | | | 10,484 | | | | | | 5,223 | | | | | | 36,851 | |
| | | | | | 120,536 | | | | | | 99,294 | | | | | | 160,142 | |
| Investment tax credit amortization | | | | | (4,658 | ) | | | | | (4,692 | ) | | | | | (4,725 | ) |
| Total provision for income taxes | | | | $ | 236,348 | | | | | $ | 124,499 | | | | | $ | 229,575 | |
| RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES: | | | | | | | | | | | | | | | | | | |
| Book income before provision for income taxes | | | | $ | 655,001 | | | | | $ | 333,059 | | | | | $ | 551,814 | |
| Federal income tax expense at statutory rate | | | | $ | 229,251 | | | | | $ | 116,571 | | | | | $ | 193,135 | |
| Increases (reductions) in taxes resulting from – | | | | | | | | | | | | | | | | | | |
| State income taxes, net of federal income tax benefit | | | | | 18,409 | | | | | | 4,116 | | | | | | 35,063 | |
| Amortization of investment tax credits | | | | | (4,658 | ) | | | | | (4,692 | ) | | | | | (4,725 | ) |
| Penalties | | | | | — | | | | | | 9,800 | | | | | | — | |
| Other, net | | | | | (6,654 | ) | | | | | (1,296 | ) | | | | | 6,102 | |
| Total provision for income taxes | | | | $ | 236,348 | | | | | $ | 124,499 | | | | | $ | 229,575 | |
| | | | | | | | | | | | | | | | | | |
| ACCUMULATED DEFERRED INCOME TAXES AS OF DECEMBER 31: | | | | | | | | | |
| Property basis differences | | | | $ | 112,154 | | | | | $ | (736 | ) | | | | $ | 142,256 | |
| Unamortized investment tax credits | | | | | (23,983 | ) | | | | | (25,676 | ) | | | | | (31,129 | ) |
| Other comprehensive income | | | | | 60,173 | | | | | | 42,382 | | | | | | 54,454 | |
| Retirement benefits | | | | | (27,522 | ) | | | | | (42,529 | ) | | | | | (38,083 | ) |
| Asset retirement obligations | | | | | 29,273 | | | | | | 45,815 | | | | | | 6,671 | |
| Allowance for doubtful accounts | | | | | (5,803 | ) | | | | | (7,142 | ) | | | | | (8,167 | ) |
| State operating loss carryforwards | | | | | (3,461 | ) | | | | | (2,740 | ) | | | | | (10,796 | ) |
| Investment impairment | | | | | (14,037 | ) | | | | | (14,035 | ) | | | | | (12,578 | ) |
| All other | | | | | (5,345 | ) | | | | | (11,803 | ) | | | | | (4,776 | ) |
| Net deferred income tax liability (asset) | | | | $ | 121,449 | | | | | $ | (16,464 | ) | | | | $ | 97,852 | |
Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. The Company records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are ultimately settled. The Company is included in FirstEnergy’s consolidated federal income tax return. The consolidated tax liability is calculated on a
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Table of Contents‘‘stand-alone’’ company basis, with the Company recognizing any tax losses or credits it contributes to the consolidated return. See Note 5 for Ohio Tax Legislation discussion.
| |
| 3. | PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS |
FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees. Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy made a $300 million voluntary cash contribution to its qualified pension plan on January 2, 2007 (Company’s share was $64 million). Projections indicate that additional cash contributions will not be required before 2016.
FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. The Company recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. During 2006, FirstEnergy amended the OPEB plan effective in 2008 to cap the monthly contribution for many of the retirees and their spouses receiving subsidized healthcare coverage. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability related benefits.
Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans and earnings on plan assets. Such factors may be further affected by business combinations which impact employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. FirstEnergy uses a December 31 measurement date for its pension OPEB plans. The fair value of the plan assets represents the market value as of December 31, 2006.
In December 31, 2006, FirstEnergy adopted SFAS 158. This Statement requires an employer to recognize an asset or liability for the overfunded or underfunded status of its pension and other postretirement benefit plans. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. SFAS 158 required employers to recognize all unrecognized prior service costs and credits and unrecognized actuarial gains and losses in AOCI, net of income taxes. Such amounts will be adjusted as they are subsequently recognized as components of net periodic benefit cost or income pursuant to the current recognition and amortization provisions. The Company’s incremental impact of adopting SFAS 158 w as a decrease of $33 million in pension assets, a decrease of $18 million in pension liabilities and a decrease in AOCI of $4 million, net of income taxes.
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Table of ContentsWith the exception of the Company’s share of net pension (asset) liability at the end of the year and net period pension expense, the following tables detail the consolidated FirstEnergy pension plan and OPEB.
| | | | | | | | | | | | | | | | | | | | | | | | |
| Obligations and Funded Status As of December 31 | | | Pension Benefits | | | Other Benefits |
| 2006 | | | 2005 | | | 2006 | | | 2005 |
| | | | (in millions) |
| Change in benefit obligation | | | | | | | | | | | | | | | | | | | | | | | | |
| Benefit obligations as of January 1 | | | | $ | 4,750 | | | | | $ | 4,364 | | | | | $ | 1,884 | | | | | $ | 1,930 | |
| Service cost | | | | | 83 | | | | | | 77 | | | | | | 34 | | | | | | 40 | |
| Interest cost | | | | | 266 | | | | | | 254 | | | | | | 105 | | | | | | 111 | |
| Plan participants’ contributions | | | | | — | | | | | | — | | | | | | 20 | | | | | | 18 | |
| Plan amendments | | | | | 3 | | | | | | 15 | | | | | | (620 | ) | | | | | (312 | ) |
| Medicare retiree drug subsidy | | | | | — | | | | | | — | | | | | | 6 | | | | | | — | |
| Actuarial (gain) loss | | | | | 33 | | | | | | 310 | | | | | | (119 | ) | | | | | 197 | |
| Benefits paid | | | | | (274 | ) | | | | | (270 | ) | | | | | (109 | ) | | | | | (100 | ) |
| Benefit obligation as of December 31 | | | | $ | 4,861 | | | | | $ | 4,750 | | | | | $ | 1,201 | | | | | $ | 1,884 | |
| Change in fair value of plan assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of plan assets as of January 1 | | | | $ | 4,524 | | | | | $ | 3,969 | | | | | $ | 573 | | | | | $ | 564 | |
| Actual return on plan assets | | | | | 568 | | | | | | 325 | | | | | | 69 | | | | | | 33 | |
| Company contribution | | | | | — | | | | | | 500 | | | | | | 54 | | | | | | 58 | |
| Plan participants’ contribution | | | | | — | | | | | | — | | | | | | 20 | | | | | | 18 | |
| Benefits paid | | | | | (274 | ) | | | | | (270 | ) | | | | | (109 | ) | | | | | (100 | ) |
| Fair value of plan assets as of December 31 | | | | $ | 4,818 | | | | | $ | 4,524 | | | | | $ | 607 | | | | | $ | 573 | |
| Funded Status | | | | $ | (43 | ) | | | | $ | (226 | ) | | | | $ | (594 | ) | | | | $ | (1,311 | ) |
| Accumulated benefit obligations | | | | $ | 4,447 | | | | | $ | 4,327 | | | | | | | | | | | | | |
| Amounts Recognized in the Statement of Financial Position | | | | | | | | | | | | | | | | | | | | | | | | |
| Noncurrent assets | | | | $ | — | | | | | $ | 1,023 | | | | | $ | — | | | | | $ | — | |
| Current liabilities | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| Noncurrent liabilities | | | | | (43 | ) | | | | | — | | | | | | (594 | ) | | | | | (1,057 | ) |
| Net pension asset (liability) at end of year | | | | | (43 | ) | | | | | 1,023 | | | | | | (594 | ) | | | | | (1,057 | ) |
| Company’s share of net pension asset (liability) at end of year | | | | $ | (54 | ) | | | | $ | 49 | | | | | $ | (43 | ) | | | | $ | (112 | ) |
| Amounts Recognized in Accumulated Other Comprehensive Income | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior Service cost (credit) | | | | $ | 63 | | | | | $ | — | | | | | $ | (1,190 | ) | | | | $ | — | |
| Actuarial (gain) loss | | | | | 982 | | | | | | — | | | | | | 702 | | | | | | — | |
| Net amount recognized | | | | $ | 1,045 | | | | | $ | — | | | | | $ | (488 | ) | | | | $ | — | |
F-16
Table of Contents
| | | | | | | | | | | | | | | | | | | | | | | | |
| Obligations and Funded Status As of December 31 | | | Pension Benefits | | | Other Benefits |
| 2006 | | | 2005 | | | 2006 | | | 2005 |
| | | | (in millions) |
| Assumptions Used to Determine Benefit Obligations As of December 31 | | | | | | | | | | | | | | | | | | | | | | | | |
| Discount rate | | | | | 6.00 | % | | | | | 5.75 | % | | | | | 6.00 | % | | | | | 5.75 | % |
| Rate of compensation increase | | | | | 3.50 | % | | | | | 3.50 | % | | | | | | | | | | | | |
| Allocation of Plan Assets As of December 31 | | | | | | | | | | | | | | | | | | | | | | | | |
| Asset Category | | | | | | | | | | | | | | | | | | | | | | | | |
| Equity securities | | | | | 64 | % | | | | | 63 | % | | | | | 72 | % | | | | | 71 | % |
| Debt securities | | | | | 29 | | | | | | 33 | | | | | | 26 | | | | | | 27 | |
| Real estate | | | | | 5 | | | | | | 2 | | | | | | 1 | | | | | | — | |
| Private equities | | | | | 1 | | | | | | — | | | | | | — | | | | | | — | |
| Cash | | | | | 1 | | | | | | 2 | | | | | | 1 | | | | | | 2 | |
| Total | | | | | 100 | % | | | | | 100 | % | | | | | 100 | % | | | | | 100 | % |
| | | | | | | | | | | | |
| Estimated Items to Be Amortized in 2007 Net Periodic Pension Cost from Accumulated Other Comprehensive Income | | | Pension
Benefits | | | Other
Benefits |
| Prior service cost (credit) | | | | $ | 10 | | | | | $ | (149 | ) |
| Actuarial (gain) loss | | | | $ | 41 | | | | | $ | 45 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Components of Net Periodic Benefit Costs | | | Pension Benefits | | | Other Benefits |
| 2006 | | | 2005 | | | 2004 | | | 2006 | | | 2005 | | | 2004 |
| | | | (in millions) |
| Service cost | | | | $ | 83 | | | | | $ | 77 | | | | | $ | 77 | | | | | $ | 34 | | | | | $ | 40 | | | | | $ | 36 | |
| Interest cost | | | | | 266 | | | | | | 254 | | | | | | 252 | | | | | | 105 | | | | | | 111 | | | | | | 112 | |
| Expected return on plan assets | | | | | (396 | ) | | | | | (345 | ) | | | | | (286 | ) | | | | | (46 | ) | | | | | (45 | ) | | | | | (44 | ) |
| Amortization of prior service cost | | | | | 10 | | | | | | 8 | | | | | | 9 | | | | | | (76 | ) | | | | | (45 | ) | | | | | (40 | ) |
| Recognized net actuarial loss | | | | | 58 | | | | | | 36 | | | | | | 39 | | | | | | 56 | | | | | | 40 | | | | | | 39 | |
| Net periodic cost | | | | $ | 21 | | | | | $ | 30 | | | | | $ | 91 | | | | | $ | 73 | | | | | $ | 101 | | | | | $ | 103 | |
| Company’s share of net periodic cost | | | | $ | 16 | | | | | $ | 13 | | | | | $ | 20 | | | | | $ | 7 | | | | | $ | 14 | | | | | $ | 12 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Weighted-Average Assumptions Used to
Determine Net Periodic Benefit Cost for Years Ended December 31 | | | Pension Benefits | | | Other Benefits |
| 2006 | | | 2005 | | | 2004 | | | 2006 | | | 2005 | | | 2004 |
| Discount rate | | | | | 5.75 | % | | | | | 6.00 | % | | | | | 6.25 | % | | | | | 5.75 | % | | | | | 6.00 | % | | | | | 6.25 | % |
| Expected long-term return on plan assets | | | | | 9.00 | % | | | | | 9.00 | % | | | | | 9.00 | % | | | | | 9.00 | % | | | | | 9.00 | % | | | | | 9.00 | % |
| Rate of compensation increase | | | | | 3.50 | % | | | | | 3.50 | % | | | | | 3.50 | % | | | | | | | | | | | | | | | | | | |
In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. The assumed rates of return on pension plan assets consider historical market returns and economic forecasts for the types of investments held by the Company’s pension trusts. The long-term rate of return is developed considering the portfolio’s asset allocation strategy.
FirstEnergy employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return on plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalization funds. Other assets such as real
F-17
Table of Contentsestate are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.
| | | | | | |
| Assumed Health Case Cost Trend Rates As of December 31 | | | 2006 | | | 2005 |
Health care cost rend rate assumed for next year
(pre/post-Medicare) | | | 9-11% | | | 9-11% |
| Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) | | | 5% | | | 5% |
Year that the rate reaches the ultimate trend rate
(pre/post-Medicare) | | | 2001-2013 | | | 2010-2012 |
Assumed health care cost trend rates have a significant effect on the amounts reported for FirstEnergy’s health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
| | | | | | | | | | | | |
| | | | 1-Percentage-Point
Increase | | | 1-Percentage-Point
Increase |
| | | | (in millions) |
| Effect on total of service and interest cost | | | | $ | 6 | | | | | $ | (5 | ) |
| Effect on accumulated postretirement benefit obligations | | | | $ | 33 | | | | | $ | (29 | ) |
Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets:
| | | | | | | | | | | | |
| | | | Pension
Benefits | | | Other
Benefits |
| | | | (in millions) |
| 2007 | | | | $ | 247 | | | | | $ | 91 | |
| 2008 | | | | | 249 | | | | | | 91 | |
| 2009 | | | | | 256 | | | | | | 94 | |
| 2010 | | | | | 269 | | | | | | 98 | |
| 2011 | | | | | 280 | | | | | | 101 | |
| Years 2012 – 2016 | | | | | 1,606 | | | | | | 537 | |
| |
| 4. | FAIR VALUE OF FINANCIAL INSTRUMENTS |
(A) LONG-TERM DEBT–
All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost in the caption ‘‘short-term borrowings’’, which approximates their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt and long-term notes payable with affiliated companies as disclosed in the Consolidated Statements of Capitalization as of December 31:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 2006 | | | 2005 |
| | | | Carrying
Value | | | Fair
Value | | | Carrying
Value | | | Fair
Value |
| | | | (in millions) |
| Long-term debt | | | | $ | 1,485 | | | | | $ | 1,485 | | | | | $ | 328 | | | | | $ | 328 | |
| Long-term notes payable to affiliated companies | | | | | 1,599 | | | | | | 1,599 | | | | | | 2,600 | | | | | | 2,600 | |
| | | | | $ | 3,084 | | | | | $ | 3,084 | | | | | $ | 2,928 | | | | | $ | 2,928 | |
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Table of ContentsThe fair values of long-term debt and long-term notes payable with affiliated companies reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year.
(B) INVESTMENTS–
Investments other than cash and cash equivalents include held-to-maturity securities and available-for-sale securities. The Company periodically evaluates its investments for other-than-temporary impairment. They first consider their intent and ability to hold the investment until recovery and then consider, among other factors, the duration and the extent to which the security’s fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating investments for impairment. The following table provides the approximate fair value and related carrying amounts of investments excluding the nuclear decommissioning trust fund investments as of December 31:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 2006 | | | 2005 |
| | | | Carrying
Value | | | Fair
Value | | | Carrying
Value | | | Fair
Value |
| | | | (in millions) |
| Restricted funds | | | | $ | 8 | | | | | $ | 8 | | | | | $ | — | | | | | $ | — | |
| Notes receivable | | | | | 69 | | | | | | 66 | | | | | | 71 | | | | | | 68 | |
| Debt securities: | | | | | | | | | | | | | | | | | | | | | | | | |
| —Government obligations | | | | | 58 | | | | | | 58 | | | | | | 71 | | | | | | 71 | |
| | | | | $ | 135 | | | | | $ | 132 | | | | | $ | 142 | | | | | $ | 139 | |
The table above includes restricted funds, notes receivable, and other miscellaneous investments. The carrying value of the restricted funds is assumed to approximate market value. The fair value of notes receivable represents the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms and have maturities ranging from 2007 to 2040. The other miscellaneous investments are primarily government obligations with fair values equal to cost.
The following table provides the amortized cost basis, unrealized gains and losses, and fair values for the investments in debt and equity securities above excluding the restricted funds and notes receivable:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 2006 | | | 2005 |
| | | | Cost
Basis | | | Unrealized
Gains | | | Unrealized
Losses | | | Fair
Value | | | Cost
Basis | | | Unrealized
Gains | | | Unrealized
Losses | | | Fair
Value |
| | | | (in millions) |
| Debt Securities | | | | $ | 58 | | | | | $ | — | | | | | $ | — | | | | | $ | 58 | | | | | $ | 71 | | | | | $ | — | | | | | $ | — | | | | | $ | 71 | |
| | | | | $ | 58 | | | | | $ | — | | | | | $ | — | | | | | $ | 58 | | | | | $ | 71 | | | | | $ | — | | | | | $ | — | | | | | $ | 71 | |
There were no proceeds from the sale, realized gains and losses on those sales, or interest and dividend income for the three years ended December 31, 2006 for the investments detailed above.
(C) NUCLEAR DECOMMISSIONING TRUST FUND INVESTMENTS–
Nuclear decommissioning trust investments are classified as available-for-sale with the fair value representing quoted market prices. The Company has no securities held for trading purposes. Upon adoption of FSP SFAS 115-1 and SFAS 124-1, FirstEnergy began expensing unrealized losses on available-for-sale securities held in the nuclear decommissioning trusts since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of other-than-temporary impairment. Approximately $10 million of unrealized losses on these available-for-sale securities were reclassified from OCI to earnings upon adoption of this pronouncement. The following table provides the carrying value, which equals the fair value of the nuclear decommissioning trust funds as of December 31, 2006 and 2005, respectively. The fair value was determined using the specific identification method.
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Table of Contents
| | | | | | | | | | | | |
| | | | 2006 | | | 2005 |
| | | | (in millions) |
| Debt Securities: | | | | | | | | | | | | |
| —Government obligations | | | | $ | 237 | | | | | $ | 281 | |
| —Corporate debt securities | | | | | 123 | | | | | | 102 | |
| —Mortgage-backed securities | | | | | 5 | | | | | | — | |
| | | | | | 365 | | | | | | 383 | |
| Equity securities | | | | | 873 | | | | | | 711 | |
| | | | | $ | 1,238 | | | | | $ | 1,094 | |
The following table summarizes the amortized cost basis, unrealized gains and losses and fair values for decommissioning trust investments as of December 31:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 2006 | | | 2005 |
| | | | Cost
Basis | | | Unrealized
Gains | | | Unrealized
Losses | | | Fair
Value | | | Cost
Basis | | | Unrealized
Gains | | | Unrealized
Losses | | | Fair
Value |
| | | | (in millions) |
| Debt Securities | | | | $ | 360 | | | | | $ | 5 | | | | | $ | — | | | | | $ | 365 | | | | | $ | 381 | | | | | $ | 7 | | | | | $ | 5 | | | | | $ | 383 | |
| Equity Securities | | | | | 652 | | | | | | 221 | | | | | | — | | | | | | 873 | | | | | | 594 | | | | | | 132 | | | | | | 15 | | | | | | 711 | |
| | | | | $ | 1,012 | | | | | $ | 226 | | | | | $ | — | | | | | $ | 1,238 | | | | | $ | 975 | | | | | $ | 139 | | | | | $ | 20 | | | | | $ | 1,094 | |
Unrealized gains applicable to the Company’s decommissioning trust are recognized in OCI in accordance with SFAS 115, as fluctuations in fair value will eventually affect earnings.
Proceeds from the sale of decommissioning trust investments, realized gains and losses on those sales, and interest and dividend income for the three years ended December 31, 2006 were as follows:
| | | | | | | | | | | | | | | | | | |
| | | | 2006 | | | 2005 | | | 2004 |
| | | | (in millions) |
| Proceeds from sales | | | | $ | 1,067 | | | | | $ | 1,076 | | | | | $ | 862 | |
| Realized gains | | | | | 118 | | | | | | 109 | | | | | | 74 | |
| Realized losses | | | | | 90 | | | | | | 39 | | | | | | 39 | |
| Interest and dividend income | | | | | 36 | | | | | | 32 | | | | | | 30 | |
The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund’s custodian or managers and their parents or subsidiaries.
(D) DERIVATIVES–
The Company is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout the Company. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.
The Company accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchase and normal sales criteria. Derivatives that meet that criterion are accounted for on the accrual basis. The changes in the fair value of derivative instruments that do not meet the normal purchase and sales criteria are recorded in current earnings, in AOCI, or as part of the value of the hedged item, depending on whether or not it is designated as part of a hedge transaction, the nature of the hedge transaction and hedge effectiveness.
F-20
Table of ContentsThe Company’s primary ongoing hedging activities involve cash flow hedges of electricity and natural gas purchases. The effective portion of such hedges is initially recorded in equity as AOCI and is subsequently recorded in net income, as an operating expense, when the underlying hedged commodities are delivered. AOCI as of December 31, 2006 includes a net deferred loss of $10 million for derivative hedging activity. The $8 million increase from the December 31, 2005 balance of $2 million relates to current hedging activity. Approximately $10 million (after tax) of the current net deferred loss on derivative instruments in AOCI is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments will continue to fluctuate from period to period based on various market factors. Gains and losses from any ineffective portion of the cash flo w hedge are recorded directly to earnings. The impact of ineffectiveness on earnings during 2006 and 2005 was not material.
| |
| 5. | OHIO TAX LEGISLATION |
On June 30, 2005, tax legislation was enacted in the State of Ohio that created a new CAT tax, which is based on qualifying ‘‘taxable gross receipts’’ that does not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax was effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and the personal property tax is phased-out over a four-year period at a rate of approximately 25% annually, beginning with the year ended 2005. During the phase-out period, the Ohio income-based franchise tax will be computed consistent with the prior law, except that the tax liability as computed was or will be multiplie d by 80% in 2005; 60% in 2006; 40% in 2007 and 20% in 2008 to determine the actual liability, thereby eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred taxes that were not expected to reverse during the five-year phase-in period were written off as of June 30, 2005. Since the Company was in a deferred tax liability position, the adjustment to net deferred taxes resulted in a $7 million decrease to income taxes in 2005.
| |
| 6. | POWER SUPPLY AGREEMENTS WITH REGULATED AFFILIATES |
The Company’s revenues are primarily from the sale of electricity (provided from the Company’s generating facilities and through purchased power arrangements) to affiliated utility companies to meet all or a portion of their PLR requirements. These affiliated power sales include a full-requirements PSA with OE, CEI and TE to supply each of their PLR obligations through 2008, at prices that take into consideration their respective PUCO-authorized billing rates.
The Company has been supplying Met-Ed and Penelec with a portion of their PLR requirements through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, the Company retained the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec. The Company’s agreements have reduced Met-Ed’s and Penelec’s exposure to high wholesale power prices by providing power at a fixed price for their uncommitted POLR capacity and energy costs during the term of these agreements with the Company.
On April 7, 2006, the parties entered into a tolling agreement that arose from the Company’s notice to Met-Ed and Penelec that the Company elected to exercise its right to terminate the partial requirements agreement effective midnight December 31, 2006. On November 29, 2006, Met-Ed, Penelec and the Company agreed to suspend the April 7 Tolling Agreement pending resolution of the PPUC’s proceedings regarding the Met-Ed and Penelec Transition Rate Plan cases filed April 10, 2006. Separately, on September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their POLR obligations for the period December 1, 2006 through December 31, 2008. The Company was one of the successful bidders in that RFP process and on September 26, 2006, entered into a supplier master agreement to supply a certain portion of Met-Ed’s and Penelec’s POLR r equirements at market prices that substantially exceed the fixed price in the partial requirements agreements.
F-21
Table of ContentsBased on the outcome of the Transition Rate Plan filing, Met-Ed, Penelec and the Company agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by the Company as in the prior arrangements between the parties and automatically extends for successive one-year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of their NUG generation to the market and requires the Company to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their POLR obligations. The parties also have separately terminated the tolling, suspension and supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that woul d have been supplied under the supplier master agreement will now be provided under the restated partial requirements agreement.
On November 18, 2004, the FERC issued an order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECA mechanism to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and the Company participated in the FERC hearings held in May 2006 concerning the calculation and imposition of the SECA charges. The Presiding Judge issued an Initial Decision on August 10, 2006, rejecting the compliance filings made by the RTOs and transmission owners, ruling on various issues and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the Initial Decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in early 2007.
On November 1, 2005, the Company filed two PSAs for approval with the FERC. One PSA required the Company to provide the POLR requirements of the Ohio Companies at a price equal to the retail generation rates approved by the PUCO for a period of three years beginning January 1, 2006. The Ohio Companies will be relieved of their obligation to obtain POLR power requirements from the Company if the Ohio CBP results in a lower price for retail customers. A similar PSA between the Company and Penn permits Penn to obtain its POLR power requirements from the Company at a fixed price equal to the retail generation price during 2006.
On December 29, 2005, the FERC issued an order setting the two PSAs for hearing. The order criticized the Ohio CBP, and required the Company to submit additional evidence in support of the reasonableness of the prices charged in the power sales agreements. On July 14, 2006, the Chief Judge granted the joint motion of the Company and the Trial Staff to appoint a settlement judge in this proceeding and the procedural schedule was suspended pending settlement discussions among the parties. A settlement conference was held on September 5, 2006. The Company, the Ohio Companies, Penn, and the PUCO, along with other parties, reached an agreement to settle the case. The settlement was filed with the FERC on October 17, 2006, and was unopposed by the remaining parties, including the FERC Trial Staff. This settlement was accepted by the FERC on December 8, 2006.
The terms of the settlement provide for modification of both the Ohio and Penn PSAs with the Company. Under the Ohio PSA, separate rates are established for the Ohio Companies’ POLR requirements; special retail contract requirements, wholesale contract requirements, and interruptible buy-through retail load requirements. For their POLR and special retail contract requirements, the Ohio Companies will pay the Company no more than the lower of (i) the sum of the retail generation charge, the rate stabilization charge, the fuel recovery mechanism charge, and the Company’s actual incremental fuel costs for such sales; or (ii) the wholesale price cap. Different wholesale price caps are imposed for POLR sales, special retail contracts, and wholesale contracts. The wholesale price for interruptible buy-through retail load requirements is limited to the actual spot price of power obtained by the Company to provide this power. The Company billed the Ohio Comp anies for the additional amount payable to the Company for incremental fuel costs on power supplied during 2006. The total power supply cost billed by the Company was lower in each case than the wholesale price caps specified in the settlement accepted by the FERC. In addition, pursuant to the settlement, the
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Table of Contentswholesale rate charged by the Company under the Penn PSA can be no greater than the generation component of charges for retail POLR load in Pennsylvania. The modifications to the Ohio and Pennsylvania PSAs became effective January 1, 2006. The Penn PSA subject to the settlement expired at midnight on December 31, 2006.
As a result of Penn’s POLR competitive solicitation process approved by the PPUC for the period January 1, 2007 through May 31, 2008, the Company was selected as the winning bidder for a number of the tranches for individual customer classes. The balance of the tranches will be supplied by unaffiliated power suppliers. On October 2, 2006, the Company filed an application with the FERC under Section 205 of the Federal Power Act for authorization to make these affiliate sales to Penn. Interventions or protests were due on this filing on October 23, 2006. Penn was the only party to file an intervention in this proceeding. This filing was accepted by the FERC on November 15, 2006, and no request for rehearing was filed.
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| 7. | CAPITALIZATION |
(A) RETAINED EARNINGS–
There are no restrictions on retained earnings for payment of cash dividends on the Company’s common stock.
(B) LONG-TERM DEBT–
The Company has various debt covenants under its financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt and the maintenance of certain financial ratios. There also exist cross-default provisions among financing arrangements of FirstEnergy and the Company.
Sinking fund requirements for maturing long-term debt for the next five years are:
| | | | | | |
| | | | (in millions) |
| 2007 | | | | $ | 1,470 | |
| 2008 | | | | | — | |
| 2009 | | | | | — | |
| 2010 | | | | | 15 | |
| 2011 | | | | | — | |
Included in the table above are amounts for certain variable interest rate pollution control revenue bonds that have provisions by which individual debt holders may ‘‘put back’’ the respective debt to the Company for redemption prior to its maturity date. These amounts are $1.470 billion and $15 million in 2007 and 2010, respectively, representing the next time the debt holders may exercise this provision.
Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank LOCs of $1.484 billion as of December 31, 2006 to pay principal of, or interest on, the applicable pollution control revenue bonds. To the extent that drawings are made under the LOCs, FGCO and NGC are entitled to a credit against their obligation to repay those bonds. FGCO and NGC pay annual fees of 0.550% to 0.775% of the amounts of the LOCs to the issuing banks and are obligated to reimburse the banks for any drawings thereunder. These obligations are currently guaranteed by FirstEnergy.
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| 8. | ASSET RETIREMENT OBLIGATIONS |
The Company has recognized applicable legal obligations under SFAS 143 for nuclear power plant decommissioning, reclamation of a sludge disposal pond and closure of two coal ash disposal sites. In addition, the Company has recognized conditional retirement obligations (primarily for asbestos remediation) in accordance with FIN 47, which was implemented on December 31, 2005.
The ARO liability of $760.2 million as of December 31, 2006 primarily relates to the nuclear decommissioning of the Beaver Valley, Davis-Besse, and Perry nuclear generating facilities. The
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Table of Contentsobligation to decommission these units was developed based on site specific studies performed by an independent engineer. The Company uses an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.
In 2005, the Company revised the ARO associated with Beaver Valley Units 1 and 2, Davis-Besse and Perry, as a result of updated decommissioning studies. The present value of revisions in the estimated cash flows associated with projected decommissioning costs increased the ARO for Beaver Valley Unit 1 by $21 million and decreased the ARO for Beaver Valley Unit 2 by $22 million, resulting in a net decrease in the ARO liability and corresponding plant asset of $1 million. The present value of revisions in the estimated cash flows associated with projected decommissioning costs decreased the ARO and corresponding plant asset for Davis-Besse and Perry by $21 million and $57 million, respectively.
The Company identified applicable legal obligations as defined under the new standard at its active and retired generating units, identifying asbestos remediation as the primary conditional ARO. As a result of adopting FIN 47 in December 2005, the Company recorded a conditional ARO liability of $16 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $4 million (recorded as part of the carrying amount of the related long-lived asset) and accumulated depreciation of $1 million. The remaining cumulative effect adjustment for unrecognized depreciation and accretion of $14 million was charged to income ($9 million, net of tax) for the year ended December 31, 2005.
The following table describes the changes to the ARO balances during 2006 and 2005.
| | | | | | | | | | | | |
| ARO Reconciliation | | | 2006 | | | 2005 |
| | | | (in millions) |
| Balance at beginning of year | | | | $ | 716 | | | | | $ | 715 | |
| Accretion | | | | | 46 | | | | | | 64 | |
| Revisions in estimated cash flows | | | | | (2 | ) | | | | | (79 | ) |
| FIN 47 ARO upon adoption | | | | | — | | | | | | 16 | |
| Balance at end of year | | | | $ | 760 | | | | | $ | 716 | |
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| 9. | SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT |
The Company had approximately $1.0 billion of short-term indebtedness as of December 31, 2006, comprised of borrowings from affiliates.
On August 24, 2006, the Company, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec and ATSI, as borrowers, entered into a new $2.75 billion five-year revolving credit facility, which replaced FirstEnergy’s prior $2 billion credit facility. FirstEnergy may request an increase in the total commitments available under the new facility up to a maximum of $3.25 billion. Commitments under the new facility are available until August 24, 2011, unless the lenders agree, at the request of the borrowers, to two additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations. The Company is currently unable to borrow under the facility, but it will have the capacity to borrow up to $250 million when it is able to deliver notice to the administrative age nt that either the Company has senior unsecured debt ratings of at least BBB− by S&P and Baa3 by Moody’s or that FirstEnergy has guaranteed the Company’s obligations under the facility.
The weighted average interest rates on short-term borrowings outstanding as of December 31, 2006 and 2005 were 5.62% and 4.01% respectively.
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| 10. | COMMITMENTS AND CONTINGENCIES |
(A) NUCLEAR INSURANCE–
The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $10.8 billion. The amount is covered by a combination of private insurance and an industry
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Table of Contentsretrospective rating plan. Based on its owned interests in the Beaver Valley, Davis-Besse and Perry plants, the Company’s maximum potential assessment under the industry retrospective rating plan (assuming the other affiliates with leasehold interests in Beaver Valley Unit 2 and Perry contribute their proportionate shares of any assessments under the retrospective rating plan) would be $350 million per incident but not more than $52 million in any one year for each incident.
The Company is also insured under policies for each nuclear plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination costs. The Company has also obtained approximately $1.7 billion of insurance coverage for replacement power costs. Under these policies, the Company can be assessed a maximum of approximately $62 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses. On September 30, 2003, FirstEnergy tendered a Proof of Loss under NEIL policies for property damage and accidental outage losses associated with the extended outage at the Davis-Besse plant which began in February 2002. In December 2004, NEIL denied FirstEnergy’s claim. FirstEnergy requested binding arbitration under the policies and has submitted expert testimony to support its claim. Under NEIL’s policies, the arbitrators shall award reasonable attorney’s fees and costs to the prevailing party.
The Company intends to maintain insurance against nuclear risks, as described above, as long as it is available. To the extent that replacement power, property damage, decontamination, repair and replacement costs and other such costs arising from a nuclear incident at any of the Company’s plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Company’s insurance policies, or to the extent such insurance becomes unavailable in the future, the Company would remain at risk for such costs.
(B) ENVIRONMENTAL MATTERS–
Various federal, state and local authorities regulate FirstEnergy, the Company and their respective subsidiaries with regard to air and water quality and other environmental matters. The effects of compliance on the Company with regard to environmental matters could have a material adverse effect on its earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, the Company believes it is in compliance with existing regulations but is unable to predict future changes in regulatory policies and what, if any, the effects of such changes would be. The Company estimates additional capital expenditures for environmental compliance of approximately $1.8 billion for 2007 through 2011.
The Company accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in the Company’s determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.
Clean Air Act Compliance
The Company is required to meet federally approved SO2 emissions regulations. Violations of such regulations can result in shutdown of a generating unit involved and/or civil or criminal penalties of up to $32,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Company believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the Clean Air Act. The Company has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. Our affiliate, TE, owned the Bay Shore Power Plant at the time of the alleged violation and that we now own and operate.
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Table of ContentsThe Company complies with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants and/or using emission allowances. NOX reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOX reductions at the Company’s facilities. The EPA’s NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. The Company believes its facilities also are complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including SCR and SNCR systems, and/or using emission allowances.
National Ambient Air Quality Standards
In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter. In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the ‘‘8-hour’’ ozone NAAQS in other states. The CAIR provided each affected state until 2006 to develop implementing regulations to achieve additional reductions of NOX and SO2 emissions in two phases (Phase I i n 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2). The Company’s Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to caps on SO2 and NOX emissions, whereas its New Jersey fossil-fired generation facility will be subject to only a cap on NOX emissions. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOX emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOX cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which the Company and its subsidiaries operate affected facilities.
Mercury Emissions
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 (as a ‘‘co-benefit’’ from implementation of SO2 and NOX emission caps under the EPA’s CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the CAMR have been challenged in the United States Court of Appeals for the District of Columbia. The Company’s future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which the Company and its subsidiaries operate affected facilities.
The model rules for both the CAIR and the CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. The Company would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, the Company will be disadvantaged if these model rules were implemented as proposed because the Company’s substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.
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Table of ContentsPennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap and trade approach as in the CAMR, but rather follows a command and control approach imposing emission limits on individual sources. Pennsylvania’s mercury regulation would deprive the Company of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving the Company’s system-wide compliance. The future cost of compliance with these regulations, if approved and implemented, may be substantial.
W. H. Sammis Plant
In 1999 and 2000, the EPA issued NOV or compliance orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn, and is now owned by FGCO. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as the NSR cases and the case involving the Sammis Plant is referred to as the Sammis NSR Litigation.
On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the New Source Review litigation. This settlement agreement, which is in the form of a consent decree, was approved by the Court on July 11, 2005, and requires reductions of NOX and SO2 emissions at the W. H. Sammis Plant and other Company coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if First Energy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FGCO and its affiliates, OE and Penn, could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation are currently estimated to be $1.5 billion ($400 million of which is expected to be spent in 2007, with the largest portion of the remaining $1.1 billion expected to be spent in 2008 and 2009).
The Sammis NSR Litigation consent decree also requires FGCO and its affiliates, OE and Penn, to spend up to $25 million toward environmentally beneficial projects, $14 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.
On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. On May 8, 2007, the EPA proposed to change the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.
Climate Change
In December 1997, delegates to the United Nations’ climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.
The Company cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO2 emissions could require significant capital and other expenditures.
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Table of ContentsThe CO2 emissions per KWH of electricity generated by the Company is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
On April 2, 2007, the United States Supreme Court found that EPA has the authority to regulate CO2 emissions from automobiles as ‘‘air pollutants’’ under the Clear Air Act. Although this decision did not address CO2 emissions from electric generating plants, EPA has similar authority under the Clan Air Act to regulate ‘‘air pollutants’’ from those and other facilities. FirstEnergy cannot estimate the financial impact of possible EPA regulation of CO2 emissions, al though potential restrictions on CO2 emissions could require significant capital and other expenditures.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to the Company’s plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to the Company’s operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system, and entrainment, which occurs when aquatic life is drawn into a facility’s cooling water system. On January 26, 2007, the federal Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to EPA for further rulemaking and eliminated the restoration option from EPA’s regulations. The Company is conducting comprehensive demonstration studies, due in 2008, to determine the operational measures or equipment, if any, necessary for compliance by its facilities with the performance standards. The Company is unable to predict the outcome of such studies or changes in these requirements from the remand to EPA. Depending on the outcome of such studies and EPA’s further rulemaking, the future cost of compliance with these standards may require material capital expenditures.
Regulation of Hazardous Waste
As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste.
Under NRC regulations, the Company and its affiliates, OE and TE, must ensure that adequate funds will be available to decommission their nuclear facilities in proportion to their respective ownership or leased interest in the nuclear units. As of December 31, 2006, FirstEnergy had approximately $1.4 billion (NGC—$1.2 billion and other affiliates—$0.2 billion) invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley and Perry. As part of the application to the NRC to transfer the ownership of these nuclear facilities to NGC, FirstEnergy agreed to contribute another $80 million to these trusts by 2010; $63 million has been recognized as a notes receivable on the Consolidated Balance Sheet. Consistent with NRC guidance, utilizing a ‘‘real’’ rate of return on these funds of approximately 2% over inflation, these trusts are expecte d to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy plans to seek for these facilities.
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Table of ContentsOTHER LEGAL PROCEEDINGS–
Nuclear Plant Matters
On January 20, 2006, FENOC announced that it had entered into a deferred prosecution agreement with the U.S. Attorney’s Office for the Northern District of Ohio and the Environmental Crimes Section of the Environment and Natural Resources Division of the DOJ related to FENOC’s communications with the NRC during the fall of 2001 in connection with the reactor head issue at the Davis-Besse Nuclear Power Station. Under the agreement, the United States acknowledged FENOC’s extensive corrective actions at Davis-Besse, FENOC’s cooperation during investigations by the DOJ and the NRC, FENOC’s pledge of continued cooperation in any related criminal and administrative investigations and proceedings, FENOC’s acknowledgement of responsibility for the behavior of its employees, and its agreement to pay a monetary penalty. The DOJ agreed to refrain from seeking an indictment or otherwise initiating criminal prosecution of FENOC f or all conduct related to the statement of facts attached to the deferred prosecution agreement, as long as FENOC remained in compliance with the agreement, which FENOC has done. A monetary penalty of $28 million (not deductible for income tax purposes) was reflected in NGC’s fourth quarter of 2005 results. The deferred prosecution agreement expired on December 31, 2006.
On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee’s failure to take prompt and corrective action. On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC’s annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Nuclear Power Plant operated ‘‘in a manner that preserved public health and safety’’ even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performan ce to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the NRC Action Matrix.
On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Nuclear Power Plant and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC’s Reactor Oversight Process. In the NRC’s 2005 annual assessment letter dated March 2, 2006 and associated meetings to discuss the performance of the Perry Nuclear Power Plant on March 14, 2006, the NRC again stated that the Perry Nuclear Power Plant continued to operate in a manner that ‘‘preserved public health and safety.’’ However, the NRC also stated that increased levels of regulatory oversight would continue until sustained improvement in the performance of the facility was realized. By two letters dated March 2, 2007, the NRC closed the Confirmatory Action Letter commitments for Perry, the two outs tanding white findings and crosscutting issues. Moreover, the NRC removed Perry from the Multiple Degraded Cornerstone Column of the NRC Action Matrix and placed the plant in the Licensee Response Column (regular agency oversight).
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to the Company’s normal business operations pending against the Company and its subsidiaries, the most significant of which are described above.
If it were ultimately determined that the Company or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the above matters, it could have a material adverse effect on the Company’s or its subsidiaries’ financial condition, results of operations and cash flows.
(D) FERC MATTERS–
The EPACT provides for the creation of the ERO to establish and enforce reliability standards for the bulk power system, subject to FERC’s review. On February 3, 2006, the FERC adopted a rule
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Table of Contentsestablishing certification requirements for the ERO, as well as regional entities envisioned to assume compliance monitoring and enforcement responsibility for the new reliability standards. The FERC issued an order on rehearing on March 30, 2006, providing certain clarifications and essentially affirming the rule.
The NERC has been preparing the implementation aspects of reorganizing its structure to meet the FERC’s certification requirements for the ERO. The NERC made a filing with the FERC on April 4, 2006 to obtain certification as the ERO and to obtain FERC approval of pro forma delegation agreements with regional reliability organizations (regional entities). The new FERC rule referred to above, further provides for reorganizing regional entities that would replace the current regional councils and for rearranging their relationship with the ERO. The ‘‘regional entity’’ may be delegated authority by the ERO, subject to FERC approval, for compliance and enforcement of reliability standards adopted by the ERO and approved by the FERC. The ERO filing was noticed on April 7, 2006, and comments and reply comments were filed in May, June and July 2006. On July 20, 2006, the FERC certified the NERC as the ERO to implement the provisions of Section 215 of the Federal Power Act and directed the NERC to make compliance filings addressing governance and non-governance issues and the regional delegation agreements. On September 18, 2006 and October 18, 2006, the NERC submitted compliance filings addressing the governance and non-governance issues identified in the FERC ERO Certification Order, dated July 20, 2006. On October 30, 2006, the FERC issued an order accepting most of the NERC’s governance filings. On January 18, 2007, the FERC issued an order largely accepting the NERC’s compliance filings addressing non-governance issues, subject to an additional compliance filing requirement.
On April 4, 2006, the NERC also submitted a filing with the FERC seeking approval of mandatory reliability standards, as well as for approval with the relevant Canadian authorities. These reliability standards are based, with some modifications and additions, on the current NERC Version 0 reliability standards. The reliability standards filing was subsequently evaluated by the FERC on May 11, 2006, leading to the FERC staff’s release of a preliminary assessment that cited many deficiencies in the proposed reliability standards. The NERC and industry participants filed comments in response to the Staff’s preliminary assessment. The FERC held a technical conference on the proposed reliability standards on July 6, 2006. The FERC issued a NOPR on the proposed reliability standards on October 20, 2006. In the NOPR, the FERC proposed to approve 83 of the 107 reliability standards and directed the NERC to make technic al improvements to 62 of the 83 standards approved. The 24 standards that were not approved remain pending at the FERC awaiting further clarification and filings by the NERC and regional entities. The FERC also provided additional clarification within the NOPR regarding the proposed application of final standards and guidance with regard to technical improvements of the standards. On November 15, 2006, the NERC submitted several revised reliability standards and three new proposed reliability standards. Interested parties were provided the opportunity to comment on the NOPR (including the revised standards submitted by the NERC in November) by January 3, 2007. Numerous parties, including FirstEnergy, filed comments on the NOPR on January 3, 2007. Mandatory reliability standards enforceable with penalties are expected to be in place by the summer of 2007. In a separate order issued October 24, 2006, the FERC approved the NERC’s 2007 budget and business plan subject to certain compliance filings.
On November 29, 2006, NERC submitted an additional compliance filing with the FERC regarding the CMEP along with the proposed Delegation Agreements between the ERO and the regional reliability entities. The FERC provided opportunity for interested parties to comment on the CMEP by January 10, 2007. FirstEnergy, as well as other parties, moved to intervene and submitted responsive comments on January 10, 2007. This filing is pending before the FERC.
The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils completed the consolidation of these regions into a single new regional reliability organization known as ReliabilityFirst Corporation. ReliabilityFirst began operations as a regional reliability council under NERC on January 1, 2006 and on November 29, 2006 filed a proposed Delegation Agreement with the NERC to obtain certification consistent with the final rule as a ‘‘regional entity’’ under the ERO. All of FirstEnergy’s facilities are located within the ReliabilityFirst
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Table of Contentsregion and, as a result, ReliabilityFirst is charged with administering the reliability standards as such standards apply to the Company’s facilities. The Company believes it is in compliance with all current NERC reliability standards.
On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security standards that replaced interim standards put in place in the wake of the September 11, 2001 terrorist attacks, and 13 additional reliability standards. The security standards became effective on June 1, 2006, and the remaining standards will become effective throughout 2006 and 2007. The NERC filed these proposed standards with the FERC and relevant Canadian authorities for approval. The cyber security standards were not included in the October 20, 2006 NOPR and are being addressed in a separate FERC docket. On December 11, 2006, the FERC Staff provided its preliminary assessment of these proposed mandatory reliability standards and again cited various deficiencies in the proposed standards, providing interested parties with the opportunity to comment on the assessment by February 12, 2007.
Based upon a review of the October 20, 2006 NOPR, it appears that the FERC will adopt more strict reliability standards than those contained in the current NERC standards. The financial impact of complying with the new standards cannot be determined at this time. However, the EPACT required that all prudent costs incurred to comply with the new reliability standards be recovered in rates by the Company’s regulated affiliates. If the Company is unable to meet the reliability standards for its facilities in the future, the Company would be required to move into compliance, which, could have a material adverse effect on the Company’s and its subsidiaries’ financial condition, results of operations and cash flows. In addition, failure to comply with the reliability standards approved by the FERC can result in the imposition of fines and civil penalties.
On March 16, 2007, the FERC issued a final rule approving the 83 mandatory reliability standards. The final rule will take effect on June 4, 2007. The FERC also directed the NERC to improve 56 reliability standards. The final rule has not yet been fully evaluated to assess its impact on our operations.
On February 15, 2007, MISO filed documents with the FERC to establish a market-based, competitive ancillary services market. MISO contends that the filing will integrate operating reserves into MISO’s existing day-ahead and real-time settlements process, incorporate opportunity costs into these markets, address scarcity pricing through the implementation of a demand curve methodology, foster demand response in the provision of operating reserves, and provide for various efficiencies and optimization with regard to generation dispatch. The filing also proposes amendments to existing documents to provide for the transfer of balancing functions from existing local balancing authorities to MISO. MISO will then carry out this reliability function as the NERC-certified balancing authority for the MISO region. MISO is targeting implementation for the second or third quarter of 2008. The FERC established March 30, 2007, as the date for interest ed parties to submit comments addressing the filing. FESC filed comments on behalf of FES on March 30, 2007. Although there are certain features of the proposal that will need to be refined and/or more fully developed before the Ancillary Services Market will be fully operational, FirstEnergy supports MISO’s proposal to establish a competitive Ancillary Services Market.
On February 16, 2007, the FERC issued a final rule that revises its decade-old open access transmission regulations and policies. The FERC explained that the final rule is intended to strengthen non-discriminatory access to the transmission grid, facilitate FERC enforcement, and provide for a more open and coordinated transmission planning process. The final rule will become effective on May 14, 2007. The final rule has not yet been fully evaluated to assess its impact on FirstEnergy’s operations.
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| 11. | NEW ACCOUNTING STANDARDS AND INTERPRETATIONS |
SFAS 159—‘‘The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115’’
In February 2007, the FASB issued SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value. The Statement requires companies to provide
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Table of Contentsadditional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. The Statement also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157, Fair Value Measurements, and SFAS 107, Disclosures about Fair Value of Financial Instruments. This statement is effective for financial statements issued for fiscal yea rs beginning after November 15, 2007. The Company is currently evaluating the impact of this Statement on its financial statements.
SFAS 157—‘‘Fair Value Measurements’’
In September 2006, the FASB issued SFAS 157, that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value which focuses on an exit price rather than entry price; (2) the methods used to measure fair value such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. The Company is cu rrently evaluating the impact of this Statement on its financial statements.
FIN 48—‘‘Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109’’
In June 2006, the FASB issued FIN 48 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, ‘‘Accounting for Income Taxes.’’ This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken on a tax return. This interpretation also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation will be a two-step process. The first step will determine if it is more likely than not that a tax position will be sustained upon examination and should therefore be recognized. The second step will measure a tax position that meets the more likely than not recognition threshold to determine the amount of benefit to recognize in the financial statements. This interpretation is effective for fiscal years beginning after December 15, 2006. The Company does not expect this Statement to have a material impact on its financial statements.
F-32
Table of Contents12. SUPPLEMENTAL GUARANTOR INFORMATION
On July 13, 2007, FGCO, a wholly-owned subsidiary of FES, completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Plant Unit 1. The purchase price of approximately $1.329 billion for the undivided interest was funded through a combination of equity investments in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034. A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases that secures the secured notes.
The following supplemental consolidating financial statements present the condensed consolidating statements of income for the years ended December 31, 2006, 2005 and 2004, consolidating balance sheets as of December 31, 2006 and 2005 and condensed consolidating statements of cash flows for the years ended December 31, 2006, 2005 and 2004.
Investments in subsidiaries are accounted for by FES using the equity method for purposes of this presentation. Results of operations of FGCO and NGC are therefore reflected in FES’ investment accounts and earnings. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions.
F-33
Table of Contentsfirstenergy solutions corp.
condensed consolidating statements of income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2006 | | | FirstEnergy
Solutions Corp. | | | FGCO | | | NGC | | | Eliminations | | | Consolidated |
| | | | (in thousands) |
| REVENUES | | | | $ | 4,023,752 | | | | | $ | 1,767,549 | | | | | $ | 1,028,159 | | | | | $ | (2,808,107 | ) | | | | $ | 4,011,353 | |
| EXPENSES: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | | | 18,265 | | | | | | 983,492 | | | | | | 103,900 | | | | | | — | | | | | | 1,105,657 | |
| Purchased power from non-affiliates | | | | | 590,491 | | | | | | — | | | | | | — | | | | | | — | | | | | | 590,491 | |
| Purchased power from affiliates | | | | | 2,804,110 | | | | | | 180,759 | | | | | | 80,239 | | | | | | (2,808,107 | ) | | | | | 257,001 | |
| Other operating expenses | | | | | 202,369 | | | | | | 271,718 | | | | | | 553,477 | | | | | | — | | | | | | 1,027,564 | |
| Provision for depreciation | | | | | 1,779 | | | | | | 93,728 | | | | | | 83,656 | | | | | | — | | | | | | 179,163 | |
| General taxes | | | | | 12,459 | | | | | | 38,781 | | | | | | 22,092 | | | | | | — | | | | | | 73,332 | |
| Total expenses | | | | | 3,629,473 | | | | | | 1,568,478 | | | | | | 843,364 | | | | | | (2,808,107 | ) | | | | | 3,233,208 | |
| OPERATING INCOME | | | | | 394,279 | | | | | | 199,071 | | | | | | 184,795 | | | | | | — | | | | | | 778,145 | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Investment income | | | | | 12,100 | | | | | | 352 | | | | | | 33,485 | | | | | | — | | | | | | 45,937 | |
| Miscellaneous income (expense), including net income from equity investees | | | | | 172,167 | | | | | | (948 | ) | | | | | 2,086 | | | | | | (164,740 | ) | | | | | 8,565 | |
| Interest expense to affiliates | | | | | (241 | ) | | | | | (117,639 | ) | | | | | (44,793 | ) | | | | | — | | | | | | (162,673 | ) |
| Interest expense – other | | | | | (720 | ) | | | | | (9,125 | ) | | | | | (16,623 | ) | | | | | — | | | | | | (26,468 | ) |
| Capitalized interest | | | | | 1 | | | | | | 4,941 | | | | | | 6,553 | | | | | | — | | | | | | 11,495 | |
| Total other income (expense) | | | | | 183,307 | | | | | | (122,419 | ) | | | | | (19,292 | ) | | | | | (164,740 | ) | | | | | (123,144 | ) |
| INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | | | | | 577,586 | | | | | | 76,652 | | | | | | 165,503 | | | | | | (164,740 | ) | | | | | 655,001 | |
| INCOME TAXES | | | | | 158,933 | | | | | | 17,605 | | | | | | 59,810 | | | | | | — | | | | | | 236,348 | |
| NET INCOME | | | | $ | 418,653 | | | | | $ | 59,047 | | | | | $ | 105,693 | | | | | $ | (164,740 | ) | | | | $ | 418,653 | |
F-34
Table of Contentsfirstenergy solutions corp.
condensed consolidating statements of income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2005 | | | FirstEnergy
Solutions Corp. | | | FGCO | | | NGC | | | Eliminations | | | Consolidated |
| | | | (in thousands) |
| REVENUES | | | | $ | 3,998,410 | | | | | $ | 1,567,597 | | | | | $ | 671,729 | | | | | $ | (2,270,497 | ) | | | | $ | 3,967,239 | |
| EXPENSES: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | | | 37,955 | | | | | | 866,583 | | | | | | 101,339 | | | | | | — | | | | | | 1,005,877 | |
| Purchased power from non-affiliates | | | | | 957,570 | | | | | | — | | | | | | — | | | | | | — | | | | | | 957,570 | |
| Purchased power from affiliates | | | | | 2,516,399 | | | | | | 60,207 | | | | | | 2,493 | | | | | | (2,270,497 | ) | | | | | 308,602 | |
| Other operating expenses | | | | | 276,896 | | | | | | 261,646 | | | | | | 441,640 | | | | | | — | | | | | | 980,182 | |
| Provision for depreciation | | | | | 1,597 | | | | | | 95,237 | | | | | | 80,397 | | | | | | — | | | | | | 177,231 | |
| General taxes | | | | | 11,640 | | | | | | 37,594 | | | | | | 18,068 | | | | | | — | | | | | | 67,302 | |
| Total expenses | | | | | 3,802,057 | | | | | | 1,321,267 | | | | | | 643,937 | | | | | | (2,270,497 | ) | | | | | 3,496,764 | |
| OPERATING INCOME | | | | | 196,353 | | | | | | 246,330 | | | | | | 27,792 | | | | | | — | | | | | | 470,475 | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Investment income | | | | | 4,462 | | | | | | 6,964 | | | | | | 67,361 | | | | | | — | | | | | | 78,787 | |
| Miscellaneous income (expense), including net income from equity investees | | | | | 79,371 | | | | | | (2,658 | ) | | | | | (28,000 | ) | | | | | (82,856 | ) | | | | | (34,143 | ) |
| Interest expense to affiliates | | | | | (4,677 | ) | | | | | (102,580 | ) | | | | | (77,060 | ) | | | | | — | | | | | | (184,317 | ) |
| Interest expense – other | | | | | (204 | ) | | | | | (2,220 | ) | | | | | (9,614 | ) | | | | | — | | | | | | (12,038 | ) |
| Capitalized interest | | | | | 82 | | | | | | 3,180 | | | | | | 11,033 | | | | | | — | | | | | | 14,295 | |
| Total other income (expense) | | | | | 79,034 | | | | | | (97,314 | ) | | | | | (36,280 | ) | | | | | (82,856 | ) | | | | | (137,416 | ) |
| INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | | | | | 275,387 | | | | | | 149,016 | | | | | | (8,488 | ) | | | | | (82,856 | ) | | | | | 333,059 | |
| INCOME TAXES (BENEFIT) | | | | | 75,630 | | | | | | 50,739 | | | | | | (1,870 | ) | | | | | — | | | | | | 124,499 | |
| INCOME (LOSS) FROM CONTINUING OPERATIONS | | | | | 199,757 | | | | | | 98,277 | | | | | | (6,618 | ) | | | | | (82,856 | ) | | | | | 208,560 | |
| Discontinued operations (net of income taxes of $3,761,000) | | | | | 5,410 | | | | | | — | | | | | | — | | | | | | — | | | | | | 5,410 | |
| Income (Loss) Before Cumulative Effect of a Change in Accounting Principle | | | | | 205,167 | | | | | | 98,277 | | | | | | (6,618 | ) | | | | | (82,856 | ) | | | | | 213,970 | |
| Cumulative effect of a change in accounting principle (net of income tax benefit of $5,507,000) | | | | | — | | | | | | (8,803 | ) | | | | | — | | | | | | — | | | | | | (8,803 | ) |
| Net Income (Loss) | | | | $ | 205,167 | | | | | $ | 89,474 | | | | | $ | (6,618 | ) | | | | $ | (82,856 | ) | | | | $ | 205,167 | |
F-35
Table of Contentsfirstenergy solutions corp.
condensed consolidating statements of income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2004 | | | FirstEnergy
Solutions Corp. | | | FGCO | | | NGC | | | Eliminations | | | Consolidated |
| | | | (in thousands) |
| REVENUES | | | | $ | 5,217,494 | | | | | $ | 1,395,460 | | | | | $ | 729,250 | | | | | $ | (2,136,043 | ) | | | | $ | 5,206,161 | |
| EXPENSES: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | | | 17,365 | | | | | | 599,727 | | | | | | 101,799 | | | | | | — | | | | | | 718,891 | |
| Purchased power from non-affiliates | | | | | 2,276,591 | | | | | | — | | | | | | — | | | | | | — | | | | | | 2,276,591 | |
| Purchased power from affiliates | | | | | 2,444,919 | | | | | | 17,365 | | | | | | — | | | | | | (2,136,043 | ) | | | | | 326,241 | |
| Other operating expenses | | | | | 225,404 | | | | | | 297,673 | | | | | | 431,392 | | | | | | — | | | | | | 954,469 | |
| Provision for depreciation | | | | | 2,492 | | | | | | 121,309 | | | | | | 74,702 | | | | | | — | | | | | | 198,503 | |
| General taxes | | | | | 8,784 | | | | | | 36,290 | | | | | | 21,276 | | | | | | — | | | | | | 66,350 | |
| Total expenses | | | | | 4,975,555 | | | | | | 1,072,364 | | | | | | 629,169 | | | | | | (2,136,043 | ) | | | | | 4,541,045 | |
| OPERATING INCOME | | | | | 241,939 | | | | | | 323,096 | | | | | | 100,081 | | | | | | — | | | | | | 665,116 | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Investment income | | | | | 1,918 | | | | | | 6,886 | | | | | | 52,371 | | | | | | — | | | | | | 61,175 | |
| Miscellaneous income (expense), including net income from equity investees | | | | | 179,610 | | | | | | (6,213 | ) | | | | | — | | | | | | (183,168 | ) | | | | | (9,771 | ) |
| Interest expense to affiliates | | | | | (4,007 | ) | | | | | (101,615 | ) | | | | | (65,385 | ) | | | | | — | | | | | | (171,007 | ) |
| Interest expense – other | | | | | (226 | ) | | | | | (1,955 | ) | | | | | (8,432 | ) | | | | | — | | | | | | (10,613 | ) |
| Capitalized interest | | | | | 2 | | | | | | 2,733 | | | | | | 14,179 | | | | | | — | | | | | | 16,914 | |
| Total other income (expense) | | | | | 177,297 | | | | | | (100,164 | ) | | | | | (7,267 | ) | | | | | (183,168 | ) | | | | | (113,302 | ) |
| INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | | | | | 419,236 | | | | | | 222,932 | | | | | | 92,814 | | | | | | (183,168 | ) | | | | | 551,814 | |
| INCOME TAXES | | | | | 96,997 | | | | | | 95,539 | | | | | | 37,039 | | | | | | — | | | | | | 229,575 | |
| INCOME FROM CONTINUING OPERATIONS | | | | | 322,239 | | | | | | 127,393 | | | | | | 55,775 | | | | | | (183,168 | ) | | | | | 322,239 | |
| Discontinued operations (net of income taxes of $3,038,000) | | | | | 4,396 | | | | | | — | | | | | | — | | | | | | — | | | | | | 4,396 | |
| NET INCOME | | | | $ | 326,635 | | | | | $ | 127,393 | | | | | $ | 55,775 | | | | | $ | (183,168 | ) | | | | $ | 326,635 | |
F-36
Table of Contentsfirstenergy solutions corp.
consolidating balance sheets
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2006 | | | FirstEnergy
Solutions Corp. | | | FGCO | | | NGC | | | Eliminations | | | Consolidated |
| | | | (in thousands) |
| ASSETS | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| CURRENT ASSETS: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | | | $ | 2 | | | | | $ | — | | | | | $ | — | | | | | $ | — | | | | | $ | 2 | |
| Receivables– | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Customers | | | | | 129,843 | | | | | | — | | | | | | — | | | | | | — | | | | | | 129,843 | |
| Associated companies | | | | | 201,281 | | | | | | 160,965 | | | | | | 69,751 | | | | | | (196,465 | ) | | | | | 235,532 | |
| Other | | | | | 2,383 | | | | | | 1,702 | | | | | | — | | | | | | — | | | | | | 4,085 | |
| Notes receivable from associated companies | | | | | 460,023 | | | | | | — | | | | | | 292,896 | | | | | | — | | | | | | 752,919 | |
| Materials and supplies, at average cost | | | | | 195 | | | | | | 238,936 | | | | | | 221,108 | | | | | | — | | | | | | 460,239 | |
| Prepayments and other | | | | | 45,314 | | | | | | 10,389 | | | | | | 1,843 | | | | | | — | | | | | | 57,546 | |
| | | | | | 839,041 | | | | | | 411,992 | | | | | | 585,598 | | | | | | (196,465 | ) | | | | | 1,640,166 | |
| Property, Plant and Equipment | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| In service | | | | | 16,261 | | | | | | 4,960,453 | | | | | | 3,378,630 | | | | | | — | | | | | | 8,355,344 | |
| Less − Accumulated provision for depreciation | | | | | 5,738 | | | | | | 2,477,004 | | | | | | 1,335,526 | | | | | | — | | | | | | 3,818,268 | |
| | | | | | 10,523 | | | | | | 2,483,449 | | | | | | 2,043,104 | | | | | | — | | | | | | 4,537,076 | |
| Construction work in progress | | | | | 345 | | | | | | 170,063 | | | | | | 169,478 | | | | | | — | | | | | | 339,886 | |
| | | | | | 10,868 | | | | | | 2,653,512 | | | | | | 2,212,582 | | | | | | — | | | | | | 4,876,962 | |
| Investments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nuclear plant decommissioning trusts | | | | | — | | | | | | — | | | | | | 1,238,272 | | | | | | — | | | | | | 1,238,272 | |
| Long-term notes receivable from associated companies | | | | | — | | | | | | — | | | | | | 62,900 | | | | | | — | | | | | | 62,900 | |
| Investment in associated companies | | | | | 1,471,184 | | | | | | — | | | | | | — | | | | | | (1,471,184 | ) | | | | | — | |
| Other | | | | | 6,474 | | | | | | 65,833 | | | | | | 202 | | | | | | — | | | | | | 72,509 | |
| | | | | | 1,477,658 | | | | | | 65,833 | | | | | | 1,301,374 | | | | | | (1,471,184 | ) | | | | | 1,373,681 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Goodwill | | | | | 24,248 | | | | | | — | | | | | | — | | | | | | — | | | | | | 24,248 | |
| Property taxes | | | | | — | | | | | | 20,946 | | | | | | 23,165 | | | | | | — | | | | | | 44,111 | |
| Accumulated deferred income taxes | | | | | 32,939 | | | | | | — | | | | | | — | | | | | | (32,939 | ) | | | | | — | |
| Other | | | | | 23,544 | | | | | | 11,542 | | | | | | 4,753 | | | | | | — | | | | | | 39,839 | |
| | | | | | 80,731 | | | | | | 32,488 | | | | | | 27,918 | | | | | | (32,939 | ) | | | | | 108,198 | |
| Total Assets | | | | $ | 2,408,298 | | | | | $ | 3,163,825 | | | | | $ | 4,127,472 | | | | | $ | (1,700,588 | ) | | | | $ | 7,999,007 | |
F-37
Table of Contentsfirstenergy solutions corp.
consolidating balance sheets, Continued
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2006 | | | FirstEnergy
Solutions Corp. | | | FGCO | | | NGC | | | Eliminations | | | Consolidated |
| | | | (in thousands) |
| LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Current Liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Currently payable long-term debt | | | | $ | — | | | | | $ | 608,395 | | | | | $ | 861,265 | | | | | $ | — | | | | | $ | 1,469,660 | |
| Notes payable to associated companies | | | | | — | | | | | | 1,022,197 | | | | | | — | | | | | | — | | | | | | 1,022,197 | |
| Accounts payable– | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | | | 375,328 | | | | | | 11,964 | | | | | | 365,222 | | | | | | (196,465 | ) | | | | | 556,049 | |
| Other | | | | | 32,864 | | | | | | 103,767 | | | | | | — | | | | | | — | | | | | | 136,631 | |
| Accrued taxes | | | | | 54,537 | | | | | | 32,028 | | | | | | 26,666 | | | | | | — | | | | | | 113,231 | |
| Other | | | | | 49,906 | | | | | | 41,401 | | | | | | 9,634 | | | | | | — | | | | | | 100,941 | |
| | | | | | 512,635 | | | | | | 1,819,752 | | | | | | 1,262,787 | | | | | | (196,465 | ) | | | | | 3,398,709 | |
| Capitalization: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Common stockholder’s equity | | | | | 1,859,363 | | | | | | 78,542 | | | | | | 1,392,642 | | | | | | (1,471,184 | ) | | | | | 1,859,363 | |
| Long-term debt | | | | | — | | | | | | 1,057,252 | | | | | | 556,970 | | | | | | — | | | | | | 1,614,222 | |
| | | | | | 1,859,363 | | | | | | 1,135,794 | | | | | | 1,949,612 | | | | | | (1,471,184 | ) | | | | | 3,473,585 | |
| NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Accumulated deferred income taxes | | | | | — | | | | | | 25,293 | | | | | | 129,095 | | | | | | (32,939 | ) | | | | | 121,449 | |
| Accumulated deferred investment tax credits | | | | | — | | | | | | 38,894 | | | | | | 26,857 | | | | | | — | | | | | | 65,751 | |
| Asset retirement obligations | | | | | — | | | | | | 24,272 | | | | | | 735,956 | | | | | | — | | | | | | 760,228 | |
| Other postretirement benefits | | | | | 10,255 | | | | | | 92,772 | | | | | | — | | | | | | — | | | | | | 103,027 | |
| Property taxes | | | | | — | | | | | | 21,268 | | | | | | 23,165 | | | | | | — | | | | | | 44,433 | |
| Other | | | | | 26,045 | | | | | | 5,780 | | | | | | — | | | | | | — | | | | | | 31,825 | |
| | | | | | 36,300 | | | | | | 208,279 | | | | | | 915,073 | | | | | | (32,939 | ) | | | | | 1,126,713 | |
| Total Liabilities and Capitalization | | | | $ | 2,408,298 | | | | | $ | 3,163,825 | | | | | $ | 4,127,472 | | | | | $ | (1,700,588 | ) | | | | $ | 7,999,007 | |
F-38
Table of Contentsfirstenergy solutions corp.
consolidating BALANCE SHEETS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2005 | | | FirstEnergy
Solutions Corp. | | | FGCO | | | NGC | | | Eliminations | | | Consolidated |
| | | | (in thousands) |
| ASSETS | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| CURRENT ASSETS: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | | | $ | 2 | | | | | $ | — | | | | | $ | — | | | | | $ | — | | | | | $ | 2 | |
| Receivables– | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Customers | | | | | 99,315 | | | | | | — | | | | | | — | | | | | | — | | | | | | 99,315 | |
| Associated companies | | | | | 204,992 | | | | | | 166,572 | | | | | | 33,121 | | | | | | (168,034 | ) | | | | | 236,651 | |
| Other | | | | | 4,923 | | | | | | 9,957 | | | | | | — | | | | | | — | | | | | | 14,880 | |
| Notes receivable from associated companies | | | | | 217,426 | | | | | | — | | | | | | 74,200 | | | | | | — | | | | | | 291,626 | |
| Materials and supplies, at average cost | | | | | 2,714 | | | | | | 212,357 | | | | | | 201,897 | | | | | | — | | | | | | 416,968 | |
| Prepayments and other | | | | | 40,046 | | | | | | 8,835 | | | | | | — | | | | | | — | | | | | | 48,881 | |
| | | | | | 569,418 | | | | | | 397,721 | | | | | | 309,218 | | | | | | (168,034 | ) | | | | | 1,108,323 | |
| Property, Plant and Equipment | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| In service | | | | | 15,364 | | | | | | 4,832,228 | | | | | | 2,856,832 | | | | | | — | | | | | | 7,704,424 | |
| Less − Accumulated provision for depreciation | | | | | 5,769 | | | | | | 2,436,939 | | | | | | 1,242,620 | | | | | | — | | | | | | 3,685,328 | |
| | | | | | 9,595 | | | | | | 2,395,289 | | | | | | 1,614,212 | | | | | | — | | | | | | 4,019,096 | |
| Construction work in progress | | | | | 1,720 | | | | | | 143,435 | | | | | | 367,312 | | | | | | — | | | | | | 512,467 | |
| | | | | | 11,315 | | | | | | 2,538,724 | | | | | | 1,981,524 | | | | | | — | | | | | | 4,531,563 | |
| Investments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nuclear plant decommissioning trusts | | | | | — | | | | | | — | | | | | | 1,094,176 | | | | | | — | | | | | | 1,094,176 | |
| Long-term notes receivable from associated companies | | | | | — | | | | | | — | | | | | | 62,900 | | | | | | — | | | | | | 62,900 | |
| Investment in associated companies | | | | | 1,265,368 | | | | | | — | | | | | | — | | | | | | (1,265,368 | ) | | | | | — | |
| Other | | | | | 8,484 | | | | | | 70,491 | | | | | | 502 | | | | | | — | | | | | | 79,477 | |
| | | | | | 1,273,852 | | | | | | 70,491 | | | | | | 1,157,578 | | | | | | (1,265,368 | ) | | | | | 1,236,553 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Goodwill | | | | | 24,248 | | | | | | — | | | | | | — | | | | | | — | | | | | | 24,248 | |
| Property taxes | | | | | — | | | | | | 23,771 | | | | | | 18,305 | | | | | | — | | | | | | 42,076 | |
| Prepaid pension costs | | | | | 3,624 | | | | | | 45,491 | | | | | | — | | | | | | — | | | | | | 49,115 | |
| Accumulated deferred income taxes | | | | | 33,495 | | | | | | 42,943 | | | | | | — | | | | | | (59,974 | ) | | | | | 16,464 | |
| Other | | | | | 76,786 | | | | | | 13,766 | | | | | | 1,596 | | | | | | — | | | | | | 92,148 | |
| | | | | | 138,153 | | | | | | 125,971 | | | | | | 19,901 | | | | | | (59,974 | ) | | | | | 224,051 | |
| Total Assets | | | | $ | 1,992,738 | | | | | $ | 3,132,907 | | | | | $ | 3,468,221 | | | | | $ | (1,493,376 | ) | | | | $ | 7,100,490 | |
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Table of Contentsfirstenergy solutions corp.
consolidating BALANCE SHEETS, Continued
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2005 | | | FirstEnergy
Solutions Corp. | | | FGCO | | | NGC | | | Eliminations | | | Consolidated |
| | | | (in thousands) |
| LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Current Liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Currently payable long-term debt | | | | $ | — | | | | | $ | 43,000 | | | | | $ | 269,750 | | | | | $ | — | | | | | $ | 312,750 | |
| Notes payable to associated companies | | | | | — | | | | | | 975,795 | | | | | | — | | | | | | — | | | | | | 975,795 | |
| Accounts payable– | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | | | 418,847 | | | | | | 80,592 | | | | | | 138,216 | | | | | | (168,034 | ) | | | | | 469,621 | |
| Other | | | | | 79,562 | | | | | | 112,918 | | | | | | — | | | | | | — | | | | | | 192,480 | |
| Accrued taxes | | | | | 39,373 | | | | | | 61,535 | | | | | | 2,880 | | | | | | — | | | | | | 103,788 | |
| Other | | | | | 33,727 | | | | | | 40,270 | | | | | | 2,003 | | | | | | — | | | | | | 76,000 | |
| | | | | | 571,509 | | | | | | 1,314,110 | | | | | | 412,849 | | | | | | (168,034 | ) | | | | | 2,130,434 | |
| Capitalization: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Common stockholder’s equity | | | | | 1,401,334 | | | | | | 24,309 | | | | | | 1,241,059 | | | | | | (1,265,368 | ) | | | | | 1,401,334 | |
| Long-term debt | | | | | — | | | | | | 1,595,025 | | | | | | 1,020,222 | | | | | | — | | | | | | 2,615,247 | |
| | | | | | 1,401,334 | | | | | | 1,619,334 | | | | | | 2,261,281 | | | | | | (1,265,368 | ) | | | | | 4,016,581 | |
| NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Accumulated deferred income taxes | | | | | — | | | | | | — | | | | | | 59,974 | | | | | | (59,974 | ) | | | | | — | |
| Accumulated deferred investment tax credits | | | | | — | | | | | | 41,736 | | | | | | 28,673 | | | | | | — | | | | | | 70,409 | |
| Asset retirement obligations | | | | | — | | | | | | 30,225 | | | | | | 685,944 | | | | | | — | | | | | | 716,169 | |
| Other postretirement benefits | | | | | 15,257 | | | | | | 102,835 | | | | | | — | | | | | | — | | | | | | 118,092 | |
| Property taxes | | | | | — | | | | | | 24,125 | | | | | | 19,500 | | | | | | — | | | | | | 43,625 | |
| Other | | | | | 4,638 | | | | | | 542 | | | | | | — | | | | | | — | | | | | | 5,180 | |
| | | | | | 19,895 | | | | | | 199,463 | | | | | | 794,091 | | | | | | (59,974 | ) | | | | | 953,475 | |
| Total Liabilities and Capitalization | | | | $ | 1,992,738 | | | | | $ | 3,132,907 | | | | | $ | 3,468,221 | | | | | $ | (1,493,376 | ) | | | | $ | 7,100,490 | |
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Table of Contentsfirstenergy solutions corp.
condenseD consolidating statements of cash flows
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2006 | | | FirstEnergy
Solutions Corp. | | | FGCO | | | NGC | | | Eliminations | | | Consolidated |
| | | | (in thousands) |
| Net Cash Provided From Operating Activities | | | | $ | 250,518 | | | | | $ | 150,510 | | | | | $ | 470,578 | | | | | $ | (12,765 | ) | | | | $ | 858,841 | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| New financing— | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | | | — | | | | | | 565,326 | | | | | | 591,515 | | | | | | — | | | | | | 1,156,841 | |
| Short-term borrowings, net | | | | | — | | | | | | 46,402 | | | | | | — | | | | | | — | | | | | | 46,402 | |
| Redemptions and repayments— | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | | | — | | | | | | (543,064 | ) | | | | | (594,676 | ) | | | | | — | | | | | | (1,137,740 | ) |
Dividend payments
Common stock | | | | | (8,454 | ) | | | | | — | | | | | | (12,765 | ) | | | | | 12,765 | | | | | | (8,454 | ) |
| Net cash provided from (used for) financing activitities | | | | | (8,454 | ) | | | | | 68,664 | | | | | | (15,926 | ) | | | | | 12,765 | | | | | | 57,049 | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Property additions | | | | | (948 | ) | | | | | (212,867 | ) | | | | | (363,472 | ) | | | | | — | | | | | | (577,287 | ) |
| Proceeds from asset sales | | | | | — | | | | | | 34,215 | | | | | | — | | | | | | — | | | | | | 34,215 | |
| Proceeds from nuclear decommissioning trust funds sales | | | | | — | | | | | | — | | | | | | 1,067,216 | | | | | | — | | | | | | 1,067,216 | |
| Contributions to nuclear decommissioning trust fund | | | | | — | | | | | | — | | | | | | (1,067,216 | ) | | | | | — | | | | | | (1,067,216 | ) |
| Loans to associated companies | | | | | (242,597 | ) | | | | | — | | | | | | (90,433 | ) | | | | | — | | | | | | (333,030 | ) |
| Other | | | | | 1,481 | | | | | | (40,522 | ) | | | | | (747 | ) | | | | | — | | | | | | (39,788 | ) |
| Net cash used for investing activities | | | | | (242,064 | ) | | | | | (219,174 | ) | | | | | (454,652 | ) | | | | | — | | | | | | (915,890 | ) |
| Net change in cash and cash equivalents | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | |
| Cash and cash equivalents at beginning of year | | | | | 2 | | | | | | — | | | | | | — | | | | | | — | | | | | | 2 | |
| Cash and cash equivalents at end of year | | | | $ | 2 | | | | | $ | — | | | | | $ | — | | | | | $ | — | | | | | $ | 2 | |
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Table of Contentsfirstenergy solutions corp.
condenseD consolidating statements of cash flows
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2005 | | | FirstEnergy
Solutions Corp. | | | FGCO | | | NGC | | | Eliminations | | | Consolidated |
| | | | (in thousands) |
| Net cash provided from (used for) operating activities | | | | $ | 475,191 | | | | | $ | 243,683 | | | | | $ | (71,526 | ) | | | | $ | — | | | | | $ | 647,348 | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| New financing— | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Short-term borrowings, net | | | | | — | | | | | | 130,876 | | | | | | — | | | | | | (130,876 | ) | | | | | — | |
| Equity contribution from parent | | | | | 262,200 | | | | | | — | | | | | | 459,498 | | | | | | (459,498 | ) | | | | | 262,200 | |
| Redemptions and repayments— | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Short-term borrowings, net | | | | | (245,215 | ) | | | | | — | | | | | | — | | | | | | 130,876 | | | | | | (114,339 | ) |
| Return of capital to parent | | | | | — | | | | | | (197,298 | ) | | | | | — | | | | | | 197,298 | | | | | | — | |
| Net cash provided from (used for) financing activitities | | | | | 16,985 | | | | | | (66,422 | ) | | | | | 459,498 | | | | | | (262,200 | ) | | | | | 147,861 | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Property additions | | | | | (1,340 | ) | | | | | (186,176 | ) | | | | | (224,044 | ) | | | | | — | | | | | | (411,560 | ) |
| Proceeds from asset sales | | | | | 15,000 | | | | | | 43,087 | | | | | | — | | | | | | — | | | | | | 58,087 | |
| Proceeds from nuclear decommissioning trusts | | | | | — | | | | | | — | | | | | | 1,076,319 | | | | | | — | | | | | | 1,076,319 | |
| Contributions to nuclear decommissioning trust fund | | | | | — | | | | | | — | | | | | | (1,165,424 | ) | | | | | — | | | | | | (1,165,424 | ) |
| Loans to associated companies | | | | | (217,426 | ) | | | | | — | | | | | | (74,200 | ) | | | | | — | | | | | | (291,626 | ) |
| Return of capital from subsidiary | | | | | 197,298 | | | | | | — | | | | | | — | | | | | | (197,298 | ) | | | | | — | |
| Investment in subsidiary | | | | | (459,498 | ) | | | | | — | | | | | | — | | | | | | 459,498 | | | | | | — | |
| Other | | | | | (26,211 | ) | | | | | (34,199 | ) | | | | | (623 | ) | | | | | — | | | | | | (61,033 | ) |
| Net cash used for investing activities | | | | | (492,177 | ) | | | | | (177,288 | ) | | | | | (387,972 | ) | | | | | 262,200 | | | | | | (795,237 | ) |
| Net change in cash and cash equivalents | | | | | (1 | ) | | | | | (27 | ) | | | | | — | | | | | | — | | | | | | (28 | ) |
| Cash and cash equivalents at beginning of year | | | | | 3 | | | | | | 27 | | | | | | — | | | | | | — | | | | | | 30 | |
| Cash and cash equivalents at end of year | | | | $ | 2 | | | | | $ | — | | | | | $ | — | | | | | $ | — | | | | | $ | 2 | |
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Table of Contentsfirstenergy solutions corp.
condenseD consolidating statements of cash flows
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2004 | | | FirstEnergy
Solutions Corp. | | | FGCO | | | NGC | | | Eliminations | | | Consolidated |
| | | | (in thousands) |
| Net cash provided from operating activities | | | | $ | 176,021 | | | | | $ | 231,889 | | | | | $ | 306,259 | | | | | $ | — | | | | | $ | 714,169 | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| New financing— | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Short-term borrowings, net | | | | | (182,761 | ) | | | | | 202,500 | | | | | | — | | | | | | — | | | | | | 19,739 | |
| Redemptions and repayments— | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | | | — | | | | | | (325,332 | ) | | | | | — | | | | | | — | | | | | | (325,332 | ) |
| Net cash used for financing activities | | | | | (182,761 | ) | | | | | (122,832 | ) | | | | | — | | | | | | — | | | | | | (305,593 | ) |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Property additions | | | | | (297 | ) | | | | | (91,814 | ) | | | | | (220,659 | ) | | | | | — | | | | | | (312,770 | ) |
| Proceeds from asset sales | | | | | — | | | | | | 8,723 | | | | | | — | | | | | | — | | | | | | 8,723 | |
| Proceeds from nuclear decommissioning trusts | | | | | — | | | | | | — | | | | | | 861,691 | | | | | | — | | | | | | 861,691 | |
| Contributions to nuclear decommissioning trust fund | | | | | — | | | | | | — | | | | | | (950,796 | ) | | | | | — | | | | | | (950,796 | ) |
| Other | | | | | 6,810 | | | | | | (25,966 | ) | | | | | 3,505 | | | | | | — | | | | | | (15,651 | ) |
| Net cash provided from (used for) investing activities | | | | | 6,513 | | | | | | (109,057 | ) | | | | | (306,259 | ) | | | | | — | | | | | | (408,803 | ) |
| Net change in cash and cash equivalents | | | | | (227 | ) | | | | | — | | | | | | — | | | | | | — | | | | | | (227 | ) |
| Cash and cash equivalents at beginning of year | | | | | 230 | | | | | | 27 | | | | | | — | | | | | | — | | | | | | 257 | |
| Cash and cash equivalents at end of year | | | | $ | 3 | | | | | $ | 27 | | | | | $ | — | | | | | $ | — | | | | | $ | 30 | |
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Table of Contents13. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED)
The following summarizes certain consolidated operating results by quarter for 2006 and 2005.
| | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended | | | March 31,
2006 | | | June 30,
2006 | | | September 30,
2006 | | | December 31,
2006 |
| | | | (in millions) |
| Revenues | | | | $ | 956.5 | | | | | $ | 994.0 | | | | | $ | 1,109.6 | | | | | $ | 951.2 | |
| Expenses | | | | | 866.8 | | | | | | 801.8 | | | | | | 808.0 | | | | | | 756.6 | |
| Operating Income | | | | | 89.7 | | | | | | 192.2 | | | | | | 301.6 | | | | | | 194.6 | |
| Other Expense, net | | | | | 33.1 | | | | | | 34.6 | | | | | | 19.2 | | | | | | 36.2 | |
Income From Continuing Operations Before
Income Taxes | | | | | 56.6 | | | | | | 157.6 | | | | | | 282.4 | | | | | | 158.4 | |
| Income Taxes | | | | | 19.4 | | | | | | 59.0 | | | | | | 106.2 | | | | | | 51.7 | |
| Net Income | | | | $ | 37.2 | | | | | $ | 98.6 | | | | | $ | 176.2 | | | | | $ | 106.7 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended | | | March 31,
2005 | | | June 30,
2005 | | | September 30,
2005 | | | December 31,
2005 |
| | | | (in millions) |
| Revenues | | | | $ | 960.0 | | | | | $ | 936.0 | | | | | $ | 1,059.4 | | | | | $ | 1,011.9 | |
| Expenses | | | | | 865.4 | | | | | | 830.8 | | | | | | 926.1 | | | | | | 874.5 | |
| Operating Income | | | | | 94.6 | | | | | | 105.2 | | | | | | 133.3 | | | | | | 137.4 | |
| Other Expense (Income), net | | | | | 40.0 | | | | | | 28.6 | | | | | | (1.5 | ) | | | | | 70.3 | |
Income From Continuing Operations Before
Income Taxes | | | | | 54.6 | | | | | | 76.6 | | | | | | 134.8 | | | | | | 67.1 | |
| Income Taxes | | | | | 20.3 | | | | | | 19.9 | | | | | | 49.2 | | | | | | 35.1 | |
| Income From Continuing Operations | | | | | 34.3 | | | | | | 56.7 | | | | | | 85.6 | | | | | | 32.0 | |
Discontinued Operations (Net of Income
Taxes) | | | | | 6.1 | | | | | | (1.0 | ) | | | | | 0.5 | | | | | | (0.2 | ) |
| Cumulative Effect of a Change in Accounting Principle (Net of Income Taxes) | | | | | — | | | | | | — | | | | | | — | | | | | | (8.8 | ) |
| Net Income | | | | $ | 40.4 | | | | | $ | 55.7 | | | | | $ | 86.1 | | | | | $ | 23.0 | |
14. SUBSEQUENT EVENTS (UNAUDITED)
On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Plant Unit 1, representing 779 MW of net demonstrated capacity. The purchase price of approximately $1.329 billion (net after-tax proceeds of approximately $1.2 billion) for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034. A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates. The lessor trusts leased the undivided interest back to FGCO for a term approximately 33 years under substantially identical leases. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under eac h of the leases. The notes and certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor’s undivided interest in Unit 1 and interests in the applicable lease and other related transaction documents. The transaction will be classified as a financing under GAAP until FGCO’s and FES’ registration obligations under the registration rights agreement applicable to the $1.135 billion principal amount of pass through certificates issued in connection with the transaction are satisfied, at which time it is expected to be classified as an operating lease under GAAP. This transaction generated tax capital gains of approximately $830 million, a substantial portion of which will be offset by existing tax capital loss carryforwards. FirstEnergy will reduce its tax loss carryforward valuation allowances in the third quarter of 2007 and anticipates an immaterial impact to net income as the majority of the unrecognized tax benefits will reduce goodwill.
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Table of ContentsFIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Three Months Ended
June 30, | | | Six Months Ended
June 30, |
| | | | 2007 | | | 2006 | | | 2007 | | | 2006 |
| | | | (In thousands) |
| REVENUES: | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric sales to affiliates | | | | $ | 690,697 | | | | | $ | 623,425 | | | | | $ | 1,404,371 | | | | | $ | 1,234,990 | |
| Other | | | | | 378,034 | | | | | | 370,606 | | | | | | 682,653 | | | | | | 715,552 | |
| Total revenues | | | | | 1,068,731 | | | | | | 994,031 | | | | | | 2,087,024 | | | | | | 1,950,542 | |
| EXPENSES: | | | | | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | | | 268,880 | | | | | | 275,979 | | | | | | 502,415 | | | | | | 529,392 | |
| Purchased power from non-affiliates | | | | | 162,873 | | | | | | 125,382 | | | | | | 349,076 | | | | | | 303,629 | |
| Purchased power from affiliates | | | | | 70,585 | | | | | | 69,576 | | | | | | 147,068 | | | | | | 133,051 | |
| Other operating expenses | | | | | 233,145 | | | | | | 267,051 | | | | | | 496,741 | | | | | | 576,051 | |
| Provision for depreciation | | | | | 48,520 | | | | | | 45,898 | | | | | | 96,530 | | | | | | 88,520 | |
| General taxes | | | | | 20,910 | | | | | | 17,894 | | | | | | 42,628 | | | | | | 37,941 | |
| Total expenses | | | | | 804,913 | | | | | | 801,780 | | | | | | 1,634,458 | | | | | | 1,668,584 | |
| OPERATING INCOME | | | | | 263,818 | | | | | | 192,251 | | | | | | 452,566 | | | | | | 281,958 | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | | | | | |
| Miscellaneous income | | | | | 15,369 | | | | | | 9,819 | | | | | | 35,101 | | | | | | 17,181 | |
| Interest expense—affiliates | | | | | (22,817 | ) | | | | | (40,473 | ) | | | | | (52,263 | ) | | | | | (81,248 | ) |
| Interest expense—other | | | | | (21,693 | ) | | | | | (6,418 | ) | | | | | (39,051 | ) | | | | | (9,966 | ) |
| Capitalized interest | | | | | 4,423 | | | | | | 2,476 | | | | | | 7,632 | | | | | | 6,309 | |
| Total other expense | | | | | (24,718 | ) | | | | | (34,596 | ) | | | | | (48,581 | ) | | | | | (67,724 | ) |
| INCOME BEFORE INCOME TAXES | | | | | 239,100 | | | | | | 157,655 | | | | | | 403,985 | | | | | | 214,234 | |
| INCOME TAXES | | | | | 87,684 | | | | | | 59,019 | | | | | | 150,065 | | | | | | 78,397 | |
| NET INCOME | | | | | 151,416 | | | | | | 98,636 | | | | | | 253,920 | | | | | | 135,837 | |
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension and other postretirement benefits | | | | | (1,360 | ) | | | | | — | | | | | | (2,720 | ) | | | | | — | |
| Unrealized gain (loss) on derivative hedges | | | | | (13,170 | ) | | | | | 1,677 | | | | | | 4,588 | | | | | | (119 | ) |
| Change in unrealized gain on available for sale securities | | | | | 41,340 | | | | | | (19,896 | ) | | | | | 58,790 | | | | | | 8,321 | |
| Other comprehensive income (loss) | | | | | 26,810 | | | | | | (18,219 | ) | | | | | 60,658 | | | | | | 8,202 | |
Income tax expense (benefit) related to other
comprehensive income | | | | | 9,226 | | | | | | (6,773 | ) | | | | | 21,559 | | | | | | 3,095 | |
| Other comprehensive income (loss), net of tax | | | | | 17,584 | | | | | | (11,446 | ) | | | | | 39,099 | | | | | | 5,107 | |
| TOTAL COMPREHENSIVE INCOME | | | | $ | 169,000 | | | | | $ | 87,190 | | | | | $ | 293,019 | | | | | $ | 140,944 | |
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
F-45
Table of ContentsFIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | | |
| | | | June 30,
2007 | | | December 31,
2006 |
| | | | (In thousands) |
| ASSETS | | | | | | | | | | | | |
| CURRENT ASSETS: | | | | | | | | | | | | |
| Cash and cash equivalents | | | | $ | 2 | | | | | $ | 2 | |
| Receivables— | | | | | | | | | | | | |
| Customers (less accumulated provisions of $8,682,000 and $7,938,000, respectively, for uncollectible accounts) | | | | | 152,397 | | | | | | 129,843 | |
| Associated companies | | | | | 289,102 | | | | | | 235,532 | |
| Other (less accumulated provisions of $9,000 and $5,593,000, respectively, for uncollectible accounts) | | | | | 6,551 | | | | | | 4,085 | |
| Notes receivable from associated companies | | | | | 937,095 | | | | | | 752,919 | |
| Materials and supplies, at average cost | | | | | 474,697 | | | | | | 460,239 | |
| Prepayments and other | | | | | 82,440 | | | | | | 57,546 | |
| | | | | | 1,942,284 | | | | | | 1,640,166 | |
| PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | |
| In service | | | | | 8,545,851 | | | | | | 8,355,344 | |
| Less—Accumulated provision for depreciation | | | | | 3,972,113 | | | | | | 3,818,268 | |
| | | | | | 4,573,738 | | | | | | 4,537,076 | |
| Construction work in progress | | | | | 464,404 | | | | | | 339,886 | |
| | | | | | 5,038,142 | | | | | | 4,876,962 | |
| OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | |
| Nuclear plant decommissioning trusts | | | | | 1,314,508 | | | | | | 1,238,272 | |
| Long-term notes receivable from associated companies | | | | | 62,900 | | | | | | 62,900 | |
| Other | | | | | 40,385 | | | | | | 72,509 | |
| | | | | | 1,417,793 | | | | | | 1,373,681 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | |
| Goodwill | | | | | 24,248 | | | | | | 24,248 | |
| Property taxes | | | | | 44,111 | | | | | | 44,111 | |
| Pension assets | | | | | 9,703 | | | | | | — | |
| Other | | | | | 45,981 | | | | | | 39,839 | |
| | | | | | 124,043 | | | | | | 108,198 | |
| | | | | $ | 8,522,262 | | | | | $ | 7,999,007 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | | | | | |
| Currently payable long-term debt | | | | $ | 1,469,721 | | | | | $ | 1,469,660 | |
| Short-term borrowings— | | | | | | | | | | | | |
| Associated companies | | | | | 887,044 | | | | | | 1,022,197 | |
| Other | | | | | 500,000 | | | | | | — | |
| Accounts payable— | | | | | | | | | | | | |
| Associated companies | | | | | 389,474 | | | | | | 556,049 | |
| Other | | | | | 179,200 | | | | | | 136,631 | |
| Accrued taxes | | | | | 117,804 | | | | | | 113,231 | |
| Other | | | | | 118,850 | | | | | | 100,941 | |
| | | | | | 3,662,093 | | | | | | 3,398,709 | |
| CAPITALIZATION: | | | | | | | | | | | | |
| Common stockholder’s equity— | | | | | | | | | | | | |
| Common stock, without par value, authorized 750 shares—8 shares outstanding | | | | | 1,751,870 | | | | | | 1,050,302 | |
| Accumulated other comprehensive income | | | | | 150,822 | | | | | | 111,723 | |
| Retained earnings | | | | | 913,648 | | | | | | 697,338 | |
| Total common stockholder’s equity | | | | | 2,816,340 | | | | | | 1,859,363 | |
| Long-term debt | | | | | 869,607 | | | | | | 1,614,222 | |
| | | | | | 3,685,947 | | | | | | 3,473,585 | |
| NONCURRENT LIABILITIES: | | | | | | | | | | | | |
| Accumulated deferred income taxes | | | | | 178,813 | | | | | | 121,449 | |
| Accumulated deferred investment tax credits | | | | | 63,434 | | | | | | 65,751 | |
| Asset retirement obligation | | | | | 784,495 | | | | | | 760,228 | |
| Retirement benefits | | | | | 52,476 | | | | | | 103,027 | |
| Property taxes | | | | | 44,433 | | | | | | 44,433 | |
| Other | | | | | 50,571 | | | | | | 31,825 | |
| | | | | | 1,174,222 | | | | | | 1,126,713 | |
| COMMITMENTS AND CONTINGENCIES (Note 7) | | | | | | | | | | | | |
| | | | | $ | 8,522,262 | | | | | $ | 7,999,007 | |
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
F-46
Table of ContentsFIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | | | | |
| | | | Six Months Ended
June 30, |
| | | | 2007 | | | 2006 |
| | | | (In thousands) |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | | | |
| Net income | | | | $ | 253,920 | | | | | $ | 135,837 | |
| Adjustments to reconcile net income to net cash from operating activities— | | | | | | | | | | | | |
| Provision for depreciation | | | | | 96,530 | | | | | | 88,520 | |
| Nuclear lease amortization | | | | | 49,406 | | | | | | 41,111 | |
| Deferred income taxes and investment tax credits, net | | | | | 48,026 | | | | | | 1,779 | |
| Investment impairment | | | | | 10,856 | | | | | | — | |
| Accrued compensation and retirement benefits | | | | | (2,597 | ) | | | | | 4,437 | |
| Commodity derivative transactions, net | | | | | 2,727 | | | | | | 43,846 | |
| Gain on asset sales | | | | | (12,105 | ) | | | | | (3,765 | ) |
| Cash collateral, net | | | | | (3,120 | ) | | | | | 43,795 | |
| Pension trust contribution | | | | | (64,020 | ) | | | | | — | |
| Decrease (increase) in operating assets: | | | | | | | | | | | | |
| Receivables | | | | | (42,901 | ) | | | | | 39,472 | |
| Materials and supplies | | | | | 14,492 | | | | | | (39,606 | ) |
| Prepayments and other current assets | | | | | (8,270 | ) | | | | | (3,730 | ) |
| Increase (decrease) in operating liabilities: | | | | | | | | | | | | |
| Accounts payable | | | | | (148,755 | ) | | | | | (184,158 | ) |
| Accrued taxes | | | | | 4,452 | | | | | | 14,306 | |
| Accrued interest | | | | | 387 | | | | | | 885 | |
| Other | | | | | (9,185 | ) | | | | | (22,541 | ) |
| Net cash provided from operating activities | | | | | 189,843 | | | | | | 160,188 | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | |
| New Financing— | | | | | | | | | | | | |
| Long-term debt | | | | | — | | | | | | 251,978 | |
| Equity contribution from parent | | | | | 700,000 | | | | | | — | |
| Short-term borrowings, net | | | | | 364,847 | | | | | | 119,484 | |
| Redemptions and Repayments— | | | | | | | | | | | | |
| Long-term debt | | | | | (745,536 | ) | | | | | — | |
| Common stock dividend payments | | | | | (37,000 | ) | | | | | — | |
| Net cash provided from financing activities | | | | | 282,311 | | | | | | 371,462 | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | |
| Property additions | | | | | (302,424 | ) | | | | | (327,496 | ) |
| Proceeds from asset sales | | | | | 12,120 | | | | | | 3,765 | |
| Sales of investment securities held in trusts | | | | | 367,924 | | | | | | 593,732 | |
| Purchases of investment securities held in trusts | | | | | (367,924 | ) | | | | | (593,732 | ) |
| Loans to associated companies, net | | | | | (184,176 | ) | | | | | (184,971 | ) |
| Other | | | | | 2,326 | | | | | | (22,948 | ) |
| Net cash used for investing activities | | | | | (472,154 | ) | | | | | (531,650 | ) |
| Net change in cash and cash equivalents | | | | | — | | | | | | — | |
| Cash and cash equivalents at beginning of period | | | | | 2 | | | | | | 2 | |
| Cash and cash equivalents at end of period | | | | $ | 2 | | | | | $ | 2 | |
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
F-47
Table of ContentsNOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. ORGANIZATION AND BASIS OF PRESENTATION
The consolidated financial statements include FES and its wholly owned subsidiaries, FGCO and NGC. FES is a wholly owned subsidiary of FirstEnergy. FirstEnergy also holds directly, or indirectly, all of the issued and outstanding common shares of its eight principal electric utility operating subsidiaries: OE, Penn, CEI, TE, ATSI, JCP&L, Met-Ed and Penelec. Penn is a wholly owned subsidiary of OE.
On December 28, 2006, the NRC approved the transfer of ownership in NGC from FirstEnergy to FES. Effective December 31, 2006, NGC is a wholly owned subsidiary of FES and a second tier subsidiary of FirstEnergy. FENOC continues to operate and maintain the nuclear generation assets. FES’ results in 2006 reflect all of the GAT changes and therefore, no allocations or adjustments, except for those related to the NGC corporate restructuring were reflected in the 2006 financial statements.
FES follows GAAP and complies with the regulations, orders, policies and practices prescribed by the SEC and the FERC. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period.
These statements should be read in conjunction with the financial statements and notes included in FES’ 2006 Annual Report, which was furnished on FirstEnergy’s Form 8-K dated April, 20, 2007. The consolidated unaudited financial statements of FES reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods.
FES operates in one business segment that provides energy-related products and services to wholesale and retail customers in Ohio, Pennsylvania, Michigan and Maryland. The segment also generates and sells power to meet all or a portion of the PLR requirements for FirstEnergy’s Ohio and Pennsylvania utility subsidiaries.
Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.
2. DERIVATIVE INSTRUMENTS
FES is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FES uses a variety of derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout the Company. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.
FES accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchase and normal sales criteria. Derivatives that meet those criteria are accounted for on the accrual basis. The changes in the fair value of derivative instruments that do not meet the normal purchase and normal sales criteria are recorded as other expense, as AOCI, or as part of the value of the hedged item, depending on whether or not it is designated as part of a hedge transaction, the nature of the hedge transaction and hedge effectiveness.
The net deferred losses of $7 million included in AOCI as of June 30, 2007, for derivative hedging activity, as compared to the December 31, 2006 balance of $10 million for net deferred losses,
F-48
Table of Contentsresulted from a net $3 million increase related to current hedging activity and a $6 million decrease due to net hedge losses reclassified into earnings during the six months ended June 30, 2007. Based on current estimates, approximately $9 million (after tax) of the net deferred gains on derivative instruments in AOCI as of June 30, 2007 is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.
3. ASSET RETIREMENT OBLIGATIONS
FES has recognized applicable legal obligations under SFAS 143 for nuclear power plant decommissioning, reclamation of a sludge disposal pond and closure of two coal ash disposal sites. In addition, FES has recognized conditional retirement obligations (primarily for asbestos remediation) in accordance with FIN 47.
The ARO liability of $784 million as of June 30, 2007 primarily related to the nuclear decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities. FES utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.
FES maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of June 30, 2007, the fair value of the decommissioning trust assets was approximately $1.3 billion.
The following table analyzes changes to the ARO balance during the first six months of 2007 and 2006, respectively.
| | | | | | | | | | | | |
| ARO Reconciliation | | | 2007 | | | 2006 |
| (In millions) |
| Balance, January 1 | | | | $ | 760 | | | | | $ | 716 | |
| Accretion | | | | | 25 | | | | | | 24 | |
| Revisions in estimated cash flows | | | | | (1 | ) | | | | | 3 | |
| Balance, June 30 | | | | $ | 784 | | | | | $ | 743 | |
| | | | | | | | | | | | | |
4. PENSION AND OTHER POSTRETIREMENT BENEFITS
FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy uses a December 31 measurement date for its pension and other postretirement benefit plans. The fair value of the plan assets represents the actual market value as of December 31, 2006. On January 2, 2007, FirstEnergy made a $300 million (FES’ share was $64 million) voluntary cash contribution to its qualified pension plan. Projections indicate that additional cash contributions are not expected to be required before 2016. FirstEnergy also provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain em ployee contributions, deductibles and co-payments, are available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension benefits and other postretirement benefits from the time employees are hired until they become eligible to receive those benefits. During 2006, FirstEnergy amended the health care plan effective in 2008 to cap the monthly contribution for many of the retirees and their spouses receiving subsidized health care coverage. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
F-49
Table of ContentsThe components of FirstEnergy’s net periodic pension and other postretirement benefit costs (including amounts capitalized) for the three months and six months ended June 30, 2007 and 2006 consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Three Months Ended
June 30, | | | Six Months Ended
June 30, | | | | | | | | | |
| Pension Benefits | | | 2007 | | | 2006 | | | 2007 | | | 2006 | | | | | | | | | |
| | | | (In millions) | | | | | | | | | |
| Service cost | | | | $ | 21 | | | | | $ | 21 | | | | | $ | 42 | | | | | $ | 41 | | | | | | | | | | |
| Interest cost | | | | | 71 | | | | | | 66 | | | | | | 142 | | | | | | 133 | | | | | | | | | | |
| Expected return on plan assets | | | | | (113 | ) | | | | | (99 | ) | | | | | (225 | ) | | | | | (198 | ) | | | | | | | | | |
| Amortization of prior service cost | | | | | 3 | | | | | | 2 | | | | | | 5 | | | | | | 5 | | | | | | | | | | |
| Recognized net actuarial loss | | | | | 11 | | | | | | 15 | | | | | | 21 | | | | | | 29 | | | | | | | | | | |
| Net periodic cost (credit) | | | | $ | (7 | ) | | | | $ | 5 | | | | | $ | (15 | ) | | | | $ | 10 | | | | | | | | | | |
| FES’ share of net periodic cost (credit) | | | | $ | 2 | | | | | $ | 4 | | | | | $ | 3 | | | | | $ | 8 | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Three Months Ended
June 30, | | | Six Months Ended
June 30, | | | | | | | | | |
| Other Postretirement Benefits | | | 2007 | | | 2006 | | | 2007 | | | 2006 | | | | | | | | | |
| | | | (In millions) | | | | | | | | | |
| Service cost | | | | $ | 5 | | | | | $ | 9 | | | | | $ | 10 | | | | | $ | 17 | | | | | | | | | | |
| Interest cost | | | | | 17 | | | | | | 26 | | | | | | 34 | | | | | | 52 | | | | | | | | | | |
| Expected return on plan assets | | | | | (12 | ) | | | | | (12 | ) | | | | | (25 | ) | | | | | (23 | ) | | | | | | | | | |
| Amortization of prior service cost | | | | | (37 | ) | | | | | (19 | ) | | | | | (74 | ) | | | | | (37 | ) | | | | | | | | | |
| Recognized net actuarial loss | | | | | 11 | | | | | | 14 | | | | | | 23 | | | | | | 27 | | | | | | | | | | |
| Net periodic cost (credit) | | | | $ | (16 | ) | | | | $ | 18 | | | | | $ | (32 | ) | | | | $ | 36 | | | | | | | | | | |
| FES’ share of net periodic cost (credit) | | | | $ | (2 | ) | | | | $ | 1 | | | | | $ | (3 | ) | | | | $ | 3 | | | | | | | | | | |
5. INCOME TAXES
FES is included in FirstEnergy’s consolidated federal income tax return. The consolidated tax liability is calculated on a ‘‘stand-alone’’ company basis, with FES recognizing any tax losses or credits it contributes to the consolidated return. On January 1, 2007, FirstEnergy adopted FIN 48, which provides guidance for accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. This interpretation prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. FIN 48 also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation is a two-step process. The first step is to determine if it is more likel y than not that a tax position will be sustained upon examination, based on the merits of the position, and should therefore be recognized. The second step is to measure a tax position that meets the more likely than not recognition threshold to determine the amount of income tax benefit to recognize in the financial statements.
As of January 1, 2007, the total amount of FirstEnergy’s unrecognized tax benefits calculated for FES was $14 million. FES recorded a $0.6 million cumulative effect adjustment to the January 1, 2007 balance of retained earnings to increase reserves for uncertain tax positions. Of the total amount of unrecognized income tax benefits, $6 million would favorably affect FES’ effective tax rate upon recognition. During the first six months of 2007, there were no material changes to FES’ unrecognized tax benefits. As of June 30, 2007, the entire liability for uncertain tax positions is included in other non-current liabilities and changes to FES’ tax contingencies that are reasonably possible in the next 12 months are not material.
FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or
F-50
Table of Contentsexpected to be taken on the tax return. FES includes net interest and penalties in the provision for income taxes, consistent with its policy prior to implementing FIN 48. As of January 1, 2007, FES’ net amount of interest accrued was $2.7 million. During the first six months of 2007, there were no material changes to the amount of interest accrued.
FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2006. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audit for years 2004 and 2005 began in June 2006 and is not expected to close before December 2007. The IRS began auditing the year 2006 in April 2006 under its Compliance Assurance Process experimental program, and is not expected to close before December 2007. Management believes that adequate reserves have been recognized, and final settlement of these audits is not expected to have a material adverse effect on FES’ financial condition or results of operations.
6. POWER SUPPLY AGREEMENTS WITH REGULATED AFFILIATES
FES’ revenues are primarily from the sale of electricity (provided from FES’ generating facilities and through purchased power arrangements) to affiliated utility companies to meet all or a portion of their PLR requirements. These affiliated power sales include a full-requirements PSA with OE, CEI and TE to supply each of their PLR obligations through 2008, at prices that take into consideration their respective PUCO-authorized billing rates.
FES has been supplying Met-Ed and Penelec with a portion of their PLR requirements through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, FES retained the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec. The FES agreements have reduced Met-Ed’s and Penelec’s exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR capacity and energy costs during the term of these agreements with FES.
On April 7, 2006, the parties entered into a tolling agreement that arose from FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the partial requirements agreement effective midnight December 31, 2006. On November 29, 2006, Met-Ed, Penelec and FES agreed to suspend the April 7 tolling agreement pending resolution of the PPUC’s proceedings regarding the Met-Ed and Penelec comprehensive transition rate cases filed April 10, 2006. Separately, on September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligation for the period December 1, 2006 through December 31, 2008. FES was one of the successful bidders in that RFP process and on September 26, 2006 entered into a supplier master agreement to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market prices that substantially exceed the fixed price in the partial requirements agreements.
Based on the outcome of the 2006 comprehensive transition rate filing, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR obligations. The parties also have separately terminated the tolling, suspension and supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied unde r the supplier master agreement will now be provided under the restated partial requirements agreement. The fixed price under the restated agreement is expected to remain below wholesale market prices during the term of the agreement.
As a result of Penn’s PLR competitive solicitation process approved by the PPUC for the period January 1, 2007 through May 31, 2008, FES was selected as the winning bidder for a number of the tranches for individual customer classes. The balance of the tranches is supplied by unaffiliated power
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Table of Contentssuppliers. On October 2, 2006, FES filed an application with the FERC under Section 205 of the Federal Power Act for authorization to make these affiliate sales to Penn. This filing was accepted by the FERC on November 15, 2006, and no request for rehearing was filed.
7. COMMITMENTS, GUARANTEES AND CONTINGENCIES
(A) GUARANTEES AND OTHER ASSURANCES
On March 26, 2007, S&P assigned FES a corporate credit rating of BBB. On March 27, 2007, Moody’s assigned FES an issuer rating of Baa2. In support of these credit ratings, on March 26, 2007, FES entered into guarantees in favor of present and future holders of FGCO and NGC indebtedness. FGCO and NGC also entered into guarantees in favor of present and future holders of FES’ indebtedness. Accordingly, guaranteed parties will have claims against FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC. In addition, as previously disclosed, under provisions included in applicable FGCO and NGC 2005 and 2006 debt transactions, FES may elect to replace FirstEnergy as guarantor so long as FES maintains senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s.
On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in the Bruce Mansfield Plant Unit 1, representing 779 MW of net demonstrated capacity. The purchase price of approximately $1.329 billion for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034. A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates. The lessor trusts leased the undivided interest back to FGCO for a term of approximately 33 years under substantially identical leases. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The notes and certificate s are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements. The transaction will be classified as a financing under GAAP until FGCO’s and FES’ registration obligations under the registration rights agreement applicable to the $1.135 billion principal amount of pass through certificates issued in connection with the transaction are satisfied, at which time it is expected to be classified as an operating lease under GAAP. FGCO continues to operate the plant and is entitled to 779 MW of the unit’s net demonstrated capacity. CEI has an existing sale and leaseback arrangement for the remaining 51 MW portion of Bruce Mansfield Unit 1. Net after-tax proceeds of approximately $1.2 billion to FGCO from the transaction were used to repay short-term borrowings from, and to invest in, the FirstEnergy unregulated money pool. FGCO’s basic rent expense is expected to be approximately $44 million for 2007 and $81 million on an average annual basis for subsequent years during the lease term. There will be no material gain from this transaction reflected in earnings during the third quarter of 2007.
(B) FERC MATTERS
On August 1, 2007, a number of filings were made with the FERC by transmission owning utilities in the MISO and PJM footprint that could affect the transmission rates paid by FirstEnergy’s operating companies and FES.
FirstEnergy joined in a filing made by the MISO transmission owners that would maintain the existing ‘‘license plate’’ rates for transmission service within MISO provided over existing transmission facilities. FirstEnergy also joined in a filing made by both the MISO and PJM transmission owners proposing to continue the elimination of transmission rates associated with service over existing transmission facilities between MISO and PJM. If approved by the FERC, these filings would not affect the rates charged to load-serving FirstEnergy affiliates for transmission service over existing transmission facilities. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and
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Table of Contentshigher transmission facilities across the entire MISO footprint be maintained (known as the RECB Process). Each of these filings was supported by the majority of transmission owners in either MISO or PJM, as applicable.
The Midwest Stand-Alone Transmission Companies made a filing under Section 205 of the Federal Power Act requesting that 100% of the cost of new qualifying 345 kV and higher transmission facilities be spread throughout the entire MISO footprint. Further, Indianapolis Power and Light Company separately moved the FERC to reopen the record to address the cost allocation for the RECB Process. If either proposal is adopted by the FERC, it could shift a greater portion of the cost of new 345 kV and higher transmission facilities to the FirstEnergy footprint, and increase the transmission rates paid by load-serving FirstEnergy affiliates.
AEP filed a letter with the FERC Commissioners stating its intent to file a complaint under Section 206 of the Federal Power Act challenging the justness and reasonableness of the rate designs underlying the MISO and PJM transmission tariffs. AEP stated that it will propose the adoption of a regional rate design that is expected to reallocate the cost of both existing and new high voltage transmission facilities across the combined MISO and PJM footprint. Based upon the position advocated by AEP in a related proceeding, the AEP proposal is expected to result in a greater allocation of costs to FirstEnergy transmission zones in MISO and PJM. If approved by the FERC, AEP’s proposal would increase the transmission rates paid by load-serving FirstEnergy affiliates.
Any increase in rates charged for transmission service to FirstEnergy affiliates is dependent upon the outcome of these proceedings at FERC. All or some of these proceedings may be consolidated by the FERC and set for hearing. The outcome of these cases cannot be predicted. Any material adverse impact on FirstEnergy would depend upon the ability of the load-serving FirstEnergy affiliates to recover increased transmission costs in their retail rates. FirstEnergy believes that current retail rate mechanisms in place for PLR service for the Ohio Companies and for Met-Ed and Penelec would permit them to pass through increased transmission charges in their retail rates. Increased transmission charges in the JCP&L and Penn transmission zones would be the responsibility of competitive electric retail suppliers, including FES.
(C) ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy, FES and their respective subsidiaries with regard to air and water quality and other environmental matters. The effects of compliance on FES with regard to environmental matters could have a material adverse effect on its earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FES estimates capital expenditures for environmental compliance of approximately $1.8 billion for 2007 through 2011.
FES accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FES’ determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.
Clean Air Act Compliance
FES is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. FES believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006 alleging violations to various sections of the Clean Air Act. FES has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided at
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Table of Contentsan August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss ‘‘an appropriate compliance program’’ and a disagreement regarding the opacity limit applicable to the common stack for Bay Shore Units 2, 3 and 4. TE, an affiliated company, owned the Bay Shore Power Plant at the time of the alleged violation. FES owns and operates the plant.
FES complies with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants and/or using emission allowances. NOX reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOX reductions at FES’ facilities. The EPA’s NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. FES believes its facilities are also complying with the NO X budgets established under SIPs through combustion controls and post-combustion controls, including SCR and SNCR systems, and/or using emission allowances.
On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal Clean Air Act, alleging violations of air pollution laws at the Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Mansfield Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On July 25, 2007, FirstEnergy and PennFuture entered into a Tolling and Confidentiality Agreement that provides for a 60-day negotiation period during which the parties have agreed to not file a lawsuit.
National Ambient Air Quality Standards
In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter. In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the ‘‘8-hour’’ ozone NAAQS in other states. CAIR allowed each affected state until 2006 to develop implementing regulations to achieve additional reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2). FES’ Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to caps on SO2 and NOX emissions. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOX emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOX cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FES operates affected facilities.
Mercury Emissions
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 (as a ‘‘co-benefit’’ from
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Table of Contentsimplementation of SO2 and NOX emission caps under the EPA’s CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the CAMR have been challenged in the United States Court of Appeals for the District of Columbia. FES’ future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FES operates affected facilities.
The model rules for both CAIR and CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. FES would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, FES will be disadvantaged if these model rules were implemented as proposed because FES’ substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap and trade approach as in the CAMR, but rather follows a command and control approach imposing emission limits on individual sources. Pennsylvania’s mercury regulation would deprive FES of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving FES system-wide compliance. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Mansfield Plant, FES’ only coal-fired Pennsylvania power plant, until 2015, if at all.
W. H. Sammis Plant
In 1999 and 2000, the EPA issued NOV or compliance orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn, and is now owned by FGCO. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as the NSR cases and the case involving the Sammis Plant is referred to as the Sammis NSR Litigation.
On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR Litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install s uch pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FGCO and its affiliates, OE and Penn, could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation settlement agreement are currently estimated to be $1.7 billion ($400 million of which is expected to be spent during 2007, with the largest portion of the remaining $1.3 billion expected to be spent in 2008 and 2009).
The Sammis NSR Litigation consent decree also requires FGCO and its affiliates, OE and Penn, to spend up to $25 million toward environmentally beneficial projects, $14 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.
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Table of ContentsOn April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. On May 8, 2007, the EPA proposed to change the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.
Climate Change
In December 1997, delegates to the United Nations’ climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. At the international level, efforts have begun to develop climate change agreements for post-2012 GHG reductions. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.
At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as ‘‘air pollutants’’ under the Clean Air Act. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the Clean Air Act to regulate ‘‘air pollutants’’ from those and other facilities.
FES cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions could require significant capital and other expenditures. The CO2 emissions per KWH of electricity generated by FES is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FES’ plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FES’ operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system, and entrainment, which occurs when aquatic life is drawn into a facility’s cooling water system. On January 26, 2007, the federal Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to EPA for further rulemaking and eliminated the restoration option from EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment ( BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. FES is evaluating various control options and their costs and effectiveness. Depending on the outcome of such studies, the EPA’s further rulemaking and any action taken by the states exercising BPJ, the future cost of compliance with these standards may require material capital expenditures.
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Table of ContentsRegulation of Hazardous Waste
As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste.
Under NRC regulations, FES and its affiliates, OE and TE, must ensure that adequate funds will be available to decommission their nuclear facilities in proportion to their respective ownership or leased interest in the nuclear units. As of June 30, 2007, NGC had approximately $1.3 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley and Perry. As part of the application to the NRC to transfer the ownership of these nuclear facilities to NGC, FirstEnergy agreed to contribute another $80 million to these trusts by 2010; $63 million of which has been recognized as a note receivable from Penn on FES’ Consolidated Balance Sheet. Consistent with NRC guidance, utilizing a ‘‘real’’ rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Con servatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy plans to seek for these facilities.
(D) OTHER LEGAL PROCEEDINGS
Nuclear Plant Matters
On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee’s failure to take prompt and corrective action. On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC’s annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Nuclear Power Plant operated ‘‘in a manner that preserved public health and safety’’ even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections would continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the NRC Action Matrix.
On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Nuclear Power Plant and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC’s Reactor Oversight Process. By two letters dated March 2, 2007, the NRC closed the CAL commitments for Perry, the two outstanding white findings and crosscutting issues. Moreover, the NRC removed Perry from the Multiple Degraded Cornerstone Column of the NRC Action Matrix and placed the plant in the Licensee Response Column (regular agency oversight).
On April 30, 2007, the UCS filed a petition with the NRC under Section 2.206 of the NRC’s regulations based on a report prepared at FENOC’s request by expert witnesses for an insurance arbitration. In December 2006, the expert witnesses for FENOC completed a report that analyzed the crack growth rates in control rod drive mechanism penetrations and wastage of the former reactor pressure vessel head at Davis-Besse. Citing the findings in the expert witness’ report, the Section 2.206 petition requested that: (1) Davis-Besse be immediately shut down; (2) the NRC conduct an independent review of the consultant’s report and that all pressurized water reactors be shut down until remedial actions can be implemented; and (3) Davis-Besse’s operating license be revoked.
In a letter dated May 18, 2007, the NRC stated that the ‘‘current reactor pressure vessel (RPV) head inspection requirements are adequate to detect RPV degradation issues before they result in
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