~~Regulatory Matters - Ohio~~

Recent Market Developments

~~Legislative Process~~

In response to the recent unprecedented volatility in the capital and credit markets, FirstEnergy continues to assess its exposure to counterparty credit risk, its access to funds in the capital and credit markets, and market-related changes in the value of its postretirement benefit trusts, nuclear decommissioning trusts and other investments. FirstEnergy has taken several steps to strengthen its liquidity position and provide additional flexibility to meet its anticipated obligations and those of its subsidiaries. While FirstEnergy believes its existing sources of liquidity will continue to be available to meet its anticipated obligations, management is reviewing its 2009 plans to determine what adjustments should be made to operating and capital budgets in response to the economic climate to reduce the need for external sources of capital. Although this process is not yet complete, management expects that FirstEnergy's capital expenditures will be reduced from the levels previously anticipated; however, it expects to continue to meet commitments for required capital projects and necessary operational expenditures.

Liquidity

~~On April 22, 2008, an amended version~~

FirstEnergy has access to more than $4 billion of ~~Substitute Senate Bill 221 (Substitute SB221)~~liquidity, of which approximately $1.9 billion was ~~passed by~~available as of October 31, 2008. FirstEnergy and its subsidiaries have approximately $404 million available under a $2.75 billion revolving credit facility, with no one financial institution having more than 7.3% of the ~~Ohio House~~total commitment. An additional $1.1 billion was available through other commitments including: bank credit facilities totaling $420 million; a $300 million term loan with Credit Suisse, discussed below; and $550 million of ~~Representatives~~accounts receivable financing facilities. FirstEnergy had $456 million of cash and ~~sent back~~cash equivalents as of October 31, 2008.

FirstEnergy’s currently payable long-term debt includes approximately $2.1 billion of variable-rate PCRBs. The interest rates on these PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory repurchase prior to the Ohio Senate for concurrence. On April 23, 2008, the Ohio Senate approved the House's amendments to Substitute SB221 and forwarded the bill to the Governor for signature, which he signed on May 1, 2008. Amended Substitute SB221 requires all electric distribution utilities to file an RSP, now called an ESP,their maturity with the ~~PUCO. An ESP is required~~purchase price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings under irrevocable direct pay LOCs. Prior to ~~contain a proposal for the supply and pricing~~September 18, 2008, FirstEnergy had not experienced any unsuccessful remarketings of retail generation. A utility could also simultaneously file an MRO in which it would have to demonstrate the following objective market criteria: The utility or its transmission service affiliate belongs to a FERC-approved RTO having a market-monitor function and the ability to mitigate market power, and a published source exists that identifies information for traded electricity and energy products that are contracted for delivery two years into the future. The PUCO would test the ESP and its pricing and all other terms and conditions against the MRO and may only approve the ESP if it is found to be more favorable to customers. As part of an ESP with a plan period longer than three years, the PUCO shall prospectively determine every fourth year of the plan whether it is substantially likely the plan will provide the electric distribution utility a return on common equity significantly in excess of the return likely to be earned by publicly traded companies, including utilities, that face comparable business and financial risk (comparable companies). If so, the PUCO may terminate the ESP. Annually under an ESP, the PUCO shall determine whether an electric distribution utility's earned return on common equity is significantly in excess of returns earned on common equity during the same period by comparable companies, and if so, shall require the utility to return such excess to customers by prospective adjustments. Amended Substitute SB221 also includes provisions dealing with advanced and renewable energy standards and energy efficiency, including requirements to meet annual benchmarks. FirstEnergy is currently evaluating this legislation and expects to file an ESP in the second or third quarter of 2008.these variable-rate PCRBs.

·	Depreciation expense decreased $3 million due to a change in estimate for the asset retirement obligation for OE’s retired Toronto and Gorge plants.

~~A utility~~

Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement 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 sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The fixed price under the agreement is expected to remain below wholesale market prices during the term of the agreement. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for their fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC. See FERC Matters below for a description of the Third Restated Partial Requirements Agreement, executed by the parties on October 31, 2008, that limits the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the event of a third party supplier default, the increased costs to Met-Ed and Penelec could be material.

Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.

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The PPUC entered its opinion and order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes to NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million).

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the ~~court~~Court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. ~~Oral arguments are scheduled to take place~~The Commonwealth Court issued its decision on November 7, 2008, which affirmed the PPUC's January 11, 2007 order in ~~September 2008. If Met-Ed~~all respects, including the deferral and ~~Penelec do not prevail on the issue~~recovery of transmission and congestion ~~it could have a material adverse effect on the results of operations of Met-Ed, Penelec and FirstEnergy.~~

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related costs.

On ~~April 14,~~May 22, 2008, the PPUC approved the Met-Ed and Penelec ~~filed~~ annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. Various intervenors filed complaints against Met-Ed’s and Penelec’s TSC filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing the company to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted with hearings for both companies scheduled to begin in January 2009. The ~~proposed~~ TSCs include a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed ~~has proposed~~received approval from the PPUC of a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.

On March 13, 2008, the PPUC approved the residential procurement process in Penn’s Joint Petition for Settlement. This RFP process calls for load-following, full-requirements contracts for default service procurement for residential customers for the period covering June 1, 2008 through May 31, 2011. The PPUC had previously approved the default service procurement processes for commercial and industrial customers. The default service procurement for small commercial customers was conducted through multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the two RFPs for small commercial load were approved by the PPUC on February 22, 2008, and March 20, 2008. On March 28, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for small commercial customers which the PPUC then certified on April 4, 2008. On April 14, 2008, the first RFP for residential customers’ load was held consisting of tranches for both 12 and 24-month supply. The PPUC approved the bids on April 16, 2008. The second RFP is scheduled to be held on May 14, 2008, after which time the PPUC is expected to approve the new rates to go into effect June 1, 2008.

On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. ~~Neither chamber has formally considered~~As part of the ~~other’s bill.~~2008 state budget negotiations, the Alternative Energy Investment Act was enacted creating a $650 million alternative energy fund to increase the development and use of alternative and renewable energy, improve energy efficiency and reduce energy consumption. On ~~February 12,~~October 8, 2008, ~~the Pennsylvania House passed~~ House Bill 2200 as amended, was voted out of the full Senate and adopted by the House. On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which ~~provides for~~becomes effective on November 14, 2008 as Act 129 of 2008. The bill addresses issues such as: energy efficiency and ~~demand management programs and targets as well as the installation of~~peak load reduction; generation procurement; time-of-use rates; smart meters ~~within ten years. Other~~and alternative energy. Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009 and a smart meter procurement and installation plan by August 14, 2009.

Major provisions of the legislation ~~has been introduced to address generation~~include:

·	power acquired by utilities to serve customers after rate caps expire will be procured through a competitive procurement process that must include a mix of long-term and short-term contracts and spot market purchases;

·	the competitive procurement process must be approved by the PPUC and may include auctions, request for proposals, and/or bilateral agreements;

·	utilities must provide for the installation of smart meter technology within 15 years;

·	a minimum reduction in peak demand of 4.5% by May 31, 2013;

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·	minimum reductions in energy consumption of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and

·	an expanded definition of alternative energy to include additional types of hydroelectric and biomass facilities.

The current legislative session ends on November 30, 2008, and any pending legislation addressing rate mitigation and the expiration of rate caps ~~conservation~~not enacted by that time must be re-introduced in order to be considered in the next legislative session which begins in January 2009. While the form and ~~renewable energy. The final form~~impact of ~~this pending~~such legislation is ~~uncertain. Consequently, FirstEnergy is unable~~uncertain, several legislators and the Governor have indicated their intent to ~~predict what impact, if any, such legislation may have on its operations.~~address these issues next year.

On September 25, 2008, Met-Ed and Penelec filed for Commission approval of a Voluntary Prepayment Plan that would provide an opportunity for residential and small commercial customers to pre-pay an amount, which would earn interest at 7.5%, on their monthly electric bills in 2009 and 2010, to be used to reduce electric rates in 2011 and 2012. Met-Ed and Penelec also intend to file a generation procurement plan for 2011 and beyond with the PPUC later this year or early next year. Met-Ed and Penelec requested that the PPUC approve the Plan by mid-December 2008 and are currently awaiting a decision.

New Jersey

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of ~~March 31,~~September 30, 2008, the accumulated deferred cost balance totaled approximately ~~$264~~$210 million.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set.

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. A public hearing on these proposed rules was held on April 23, 2008 ~~with~~and comments from interested parties ~~due on~~were submitted by May ~~16,~~19, 2008.

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New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in 2006, 2007 and the ~~fall~~first half of ~~2006 and in early 2007.~~2008.

On April 17, 2008, a draft EMP was released for public comment. The ~~draft~~final EMP was issued on October 22, 2008 and establishes ~~four~~five major goals:

·	maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020;

·	reduce peak demand for electricity by 5,700 MW by ~~2020 (amounting to about a 22% reduction in projected demand);~~2020;

·	meet ~~22.5%~~30% of the state’s electricity needs with renewable energy by 2020;

·	examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and

·	~~develop low carbon emitting, efficient power plants~~invest in innovative clean energy technologies and ~~close~~businesses to stimulate the ~~gap between the supply and demand for electricity.~~industry’s growth in New Jersey.

~~Following the public comment period which is expected to extend into July 2008, a~~

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The final EMP will ~~be issued to~~ be followed by appropriate legislation and regulation as necessary. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations or those of JCP&L.

On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments that were submitted in September and October 2007. Final regulations (effective upon publication) were published in the New Jersey Register March 17, 2008. Upon preliminary review of the new regulations, FirstEnergy does not expect a material impact on its operations or those of JCP&L.

FERC Matters

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate ~~so-called “pancaking” of~~multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered ~~the~~ MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, 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 by year-end 2008. In the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the ~~second quarter~~docket to mitigate the risk of ~~2008.~~lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision.

PJM Transmission Rate Design

On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.

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On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce the costs of future transmission ~~revenue recovery~~to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding ~~Judge. The FERC’s action on~~Judge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement ~~agreement is pending.~~subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. The remaining merchant transmission cost allocation issues ~~will proceed to~~were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions are due on November 10, 2008. On February ~~13,~~11, 2008, AEP appealed the FERC’s April 19, 2007 and January 31, 2008 orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit.

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Post Transition Period Rate Design

The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within MISO, and between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of the FERC’s approval, the rates charged to FirstEnergy’s load-serving affiliates for transmission service over existing transmission facilities in MISO and PJM are unchanged. 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 higher transmission facilities across the entire MISO footprint (known as the RECB methodology) be retained.

On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP is pending before the FERC.

~~Distribution of MISO Network Service Revenues~~

Effective February 1, 2008, the MISO Transmission Owners Agreement provides for a change in the method of distributing transmission revenues among the transmission owners. MISO and a majority of the MISO transmission owners filed on December 3, 2007 to change the MISO tariff to clarify, for purposes of distributing network transmission revenue to the transmission owners, that all network transmission service revenues, whether collected by MISO or directly by the transmission owner, are included in the revenue distribution calculation. This clarification was necessary because some network transmission service revenues are collected and retained by transmission owners in states where retail choice does not exist, and their “unbundled” retail load is currently exempt from MISO network service charges. The tariff changes filed with the FERC ensure that revenues collected by transmission owners from bundled load are taken into account in the revenue distribution calculation, and that transmission owners with bundled load do not collect more than their revenue requirements. Absent the changes, transmission owners, and ultimately their customers, with unbundled load or in retail choice states, such as ATSI, would subsidize transmission owners with bundled load, who would collect their revenue requirement from bundled load, plus share in revenues collected by MISO from unbundled customers. This would result in a large revenue shortfall for ATSI, which would eventually be passed on to customers in the form of higher transmission rates as calculated pursuant to ATSI’s Attachment O formula under the MISO tariff.

Numerous parties filed in support of the tariff changes, including the public service commissions of Michigan, Ohio and Wisconsin. Ameren filed a protest on December 26, 2007, arguing that the December 3, 2007 filing violates the MISO Transmission Owners’ Agreement as well as an agreement among Ameren (Union Electric), MISO, and the Missouri Public Service Commission, which provides that Union Electric’s bundled load cannot be charged by MISO for network service. On February 2, 2008, the FERC issued an order conditionally accepting the tariff amendment subject to a minor compliance filing, which was made on March 3, 2008. This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement. A rehearing request by Ameren is pending before the FERC.

On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of the MISO Transmission Owners’ Agreement. This request was accepted by the FERC on March 13, 2008. On that same day, MISO and the MISO transmission owners made a filing to amend the Transmission Owners’ Agreement to effectively continue the distribution of transmission revenues that was in effect prior to February 1, 2008. This matter is currently pending before the FERC.

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MISO Ancillary Services Market and Balancing Area Consolidation

MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. ~~This filing~~These markets would permit ~~load serving~~generators to sell, and load-serving entities to purchase, their operating reserve requirements in a competitive market. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. ~~MISO has since notified~~Numerous parties filed requests for rehearing on March 26, 2008. On June 23, 2008, the FERC issued an order granting in part and denying in part rehearing.

On February 29, 2008, MISO submitted a compliance filing setting forth MISO’s Readiness Advisor ASM and Consolidated Balancing Authority Initiative Verification plan and status and Real-Time Operations ASM Reversion plan. FERC action on this compliance filing remains pending. On March 26, 2008, MISO submitted a tariff filing in compliance with the FERC’s 30-day directives in the February 25 order. Numerous parties submitted comments and protests on April 16, 2008. The FERC issued an order accepting the revisions pending further compliance on June 23, 2008. On April 25, 2008, MISO submitted a tariff filing in compliance with the FERC’s 60-day directives in the February 25 order. FERC action on this compliance filing remains pending. On May 23, 2008, MISO submitted its amended Balancing Authority Agreement. On July 21, 2008, the FERC issued an order conditionally accepting the amended Balancing Authority Agreement and requiring a further compliance filing. On August 19, 2008, MISO submitted its compliance filing to the FERC. On July 25, 2008, MISO submitted another Readiness Certification. The FERC has not yet acted on this submission. MISO announced on August 26, 2008 that the ~~start~~startup of its ~~ASM~~market is ~~delayed until September~~postponed indefinitely. MISO commits to make a filing giving at least sixty days notice of the new effective date. The latest announced effective date for market startup is January 6, 2009.

Interconnection Agreement with AMP-Ohio

On May 29, 2008, TE filed with the FERC a proposed Notice of Cancellation effective midnight December 31, 2008, of the Interconnection Agreement with AMP-Ohio. AMP-Ohio protested this filing. TE also filed a Petition for Declaratory Order seeking a FERC ruling, in the alternative if cancellation is not accepted, of TE's right to file for an increase in rates effective January 1, 2009, for power provided to AMP-Ohio under the Interconnection Agreement. AMP-Ohio filed a pleading agreeing that TE may seek an increase in rates, but arguing that any increase is limited to the cost of generation owned by TE affiliates. On August 18, 2008, the FERC issued an order that suspended the cancellation of the Agreement for five months, to become effective on June 1, 2009, and established expedited hearing procedures on issues raised in the filing and TE’s Petition for Declaratory Order. On October 14, 2008, the parties filed a settlement agreement and mutual notice of cancellation of the Interconnection Agreement effective midnight December 31, 2008. Upon acceptance by the FERC, this filing will terminate the litigation and the Interconnection Agreement, among other effects.

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Duquesne’s Request to Withdraw from PJM

On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join ~~the~~ MISO. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. FirstEnergy believes that Duquesne’s filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesne’s proposal. Consequently, FirstEnergy submitted responsive filings that, while conceding Duquesne’s rights to exit PJM, contested various aspects of Duquesne’s proposal. FirstEnergy particularly focused on Duquesne’s proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne’s failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use the Beaver Valley Plant to meet existing commitments in the PJM capacity markets and to serve native load. Other market participants also submitted filings contesting Duquesne’s plans.

On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne zone load-serving entities to pay ~~the~~their PJM capacity obligations through May 31, 2011. The FERC’s order took notice of the numerous transmission and other issues raised by FirstEnergy and other parties to the proceeding, but did not provide any responsive rulings or other guidance. Rather, the FERC ordered Duquesne to make a compliance filing in forty-five days detailing how Duquesne will satisfy its obligations under the PJM Transmission Owners’ Agreement. The FERC likewise directed the MISO to submit detailed plans to integrate Duquesne into the MISO. Finally, the FERC directed MISO and PJM to work together to resolve the substantive and procedural issues implicated by Duquesne’s transition into the MISO. These issues remain unresolved. If Duquesne satisfies all of the obligations set by the FERC, its planned transition date is October 9, 2008.

~~On March 18, 2008, the PJM Power Providers Group filed a request for emergency clarification regarding whether Duquesne-zone generators (including the Beaver Valley Plant) could participate~~FirstEnergy desires to continue to use its Duquesne zone generation resources to serve load in ~~PJM’s May 2008 auction for the 2011-2012 RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings.~~PJM. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification ~~wherein~~on whether Duquesne-zone generators could participate in PJM’s May 2008 auction for the 2011-2012 planning year. In the order, the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators ~~can~~could contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with the FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy ~~satisfies~~satisfied the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction. ~~Notwithstanding these events, on April~~

The FERC also directed MISO and PJM to resolve the substantive and procedural issues associated with Duquesne’s transition into MISO. As directed, PJM filed thirteen load-serving entity Capacity Payment Agreements and a Capacity Portability Agreement with the FERC. The Capacity Payment Agreements addressed Duquesne Zone load-serving entity obligations through May 31, 2011 with regards to RPM Capacity while the Capacity Portability Agreement addressed operational issues associated with the portability of such capacity. On September 30, 2008, the FERC approved both agreements, subject to conditions, taking notice of many operational and procedural issues brought forth by FirstEnergy and other market participants.

Several issues surrounding Duquesne’s transition into MISO continue to be contested at the FERC. Specifically, Duquesne’s obligation to pay for transmission expansion costs allocated to the Duquesne zone when they were a member of PJM, and other issues in which market participants wish to be held harmless by Duquesne’s transition. FirstEnergy filed for rehearing on these issues on October 3, 2008. Duquesne’s transition into MISO is also contingent upon the start of MISO’s ancillary services market and consolidation of its balancing authorities, currently scheduled for January 6, 2009.

Complaint against PJM RPM Auction

On May 1,30, 2008, ~~certain members~~a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. Most of the parties comprising the RPM Buyers group were parties to the settlement approved by the FERC that established the RPM. In the complaint, the RPM Buyers request that the total projected payments to RPM sellers for the three auctions at issue be materially reduced. On July 11, 2008, PJM ~~Power Providers Group~~ filed ~~further pleadings~~its answer to the complaint, in which it denied the allegation that the rates are unjust and unreasonable. Also on ~~these issues. On May 2, 2008,~~that date, FirstEnergy filed a ~~responsive pleading. FirstEnergy is participating~~motion to intervene.

On September 19, 2008, the FERC denied the RPM Buyers complaint. However, the FERC did grant the RPM Buyers request for a technical conference to review aspects of the RPM. The FERC also ordered PJM to file on or before December 15, 2008, a report on its progress on contemplating adjustments to the RPM as suggested by the Brattle Group in its report reviewing the ~~May~~RPM. The technical conference will take place in February, 2009. On October 20, 2008, the RPM ~~auction~~Buyers filed a request for rehearing of the ~~2011-2012 RPM delivery year.~~FERC’s September 19, 2008 order.

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MISO Resource Adequacy Proposal

MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for ~~load serving~~load-serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for ~~load serving~~load-serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for ~~load serving~~load-serving entities in its state. FirstEnergy ~~generally supports~~believes the proposal ~~as it~~ promotes a mechanism that will result in ~~long-term~~ commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were filed on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, ~~2008.~~2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. AOn May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing. On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchase power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. Issuance of these orders is ~~due on or before~~not expected to delay the June ~~25, 2008.~~

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1, 2009 start date for MISO Resource Adequacy.

Organized Wholesale Power Markets

~~On February 21, 2008, the~~The FERC issued a ~~NOPR through which it proposes~~final rule on October 17, 2008, amending its regulations to ~~adopt new rules that it states will~~ “improve ~~operations in~~the operation of organized wholesale electric markets ~~boost competition and bring additional benefits to consumers.” The proposed rule addresses~~in the areas of: (1) demand response and market pricing during periods of operating reserve ~~shortages,~~shortage; (2) long-term power ~~contracting,~~contracting; (3) market-monitoring ~~policies,~~policies; and (4) the responsiveness of RTOs and ISOs to their customers and other stakeholders.” The RTOs and ISOs were directed to submit amendments to their respective tariffs to address these market operation improvements. The final rule directs RTOs to adopt market rules permitting prices to increase during periods of supply shortages and to permit enhanced participation by demand response resources. It also codifies and defines for the first time the roles and duties of independent market monitors within RTOs. Finally, it adopts requirements for enhanced access by stakeholders to RTO boards of directors. RTOs are directed to make compliance filings six months from the effective date of the final rule. The final rule is not expected to have any material effect on FirstEnergy's operations within MISO and ~~customers. FirstEnergy does not believe that the proposed rule will have a significant impact~~PJM.

FES Sales to Affiliates

On October 24, 2008, FES, on its ~~operations. Comments~~own behalf and on behalf of its generation-controlling subsidiaries, filed an application with the ~~NOPR were~~FERC seeking a waiver of the affiliate sales restrictions between FES and the Ohio Companies. The purpose of the waiver is to ensure that FES will be able to continue supplying a material portion of the electric load requirements of the Ohio Companies in January 2009 pursuant to either an ESP or MRO as filed ~~on April 18,~~with the PUCO. FES previously obtained a similar waiver for electricity sales to its affiliates in New Jersey, New York, and Pennsylvania. A ruling by the FERC is expected the week of December 15, 2008.

On October 31, 2008, FES executed a Third Restated Partial Requirements Agreement with Met-Ed, Penelec, and The Waverly Power and Light Company (Waverly) effective November 1, 2008. The Third Restated Partial Requirements Agreement limits the amount of capacity and energy required to be supplied by FES in 2009 and 2010 to roughly two-thirds of these affiliates’ power supply requirements. Met-Ed, Penelec, and Waverly have committed resources in place for the balance of their expected power supply during 2009 and 2010. Under the Third Restated Partial Requirements Agreement, Met-Ed, Penelec, and Waverly are responsible for obtaining additional power supply requirements created by the default or failure of supply of their committed resources. Prices for the power provided by FES were not changed in the Third Restated Partial Requirements Agreement.

Environmental Matters

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on FirstEnergy's 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. FirstEnergy estimates capital expenditures for environmental compliance of approximately $1.4 billion for the period 2008-2012.

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FirstEnergy 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 FirstEnergy’s determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.

Clean Air Act Compliance

FirstEnergy is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the 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. FirstEnergy 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 CAA. FirstEnergy has disputed those alleged violations based on its CAA permit, the Ohio SIP and other information provided to the EPA 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. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding ~~the opacity limit~~emission limits applicable to the common stack for Bay Shore Units 2, 3 and 4.

FirstEnergy 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 FirstEnergy'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. FirstEnergy believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case, along with seven other similar cases, is referred to as the NSR cases. OE’s and Penn’s 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 was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, 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. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree are currently estimated to be $1.3 billion for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above. On September 8, 2008, the Environmental Enforcement Section of the DOJ sent a letter to OE regarding its view that the company was not in compliance with the Sammis NSR Litigation consent decree because the installation of an SNCR at Eastlake Unit 5 was not completed by December 31, 2006. However, the DOJ acknowledged that stipulated penalties could not apply under the terms of the Sammis NSR Litigation consent decree because Eastlake Unit 5 was idled on December 31, 2006 pending installation of the SNCR and advised that it had exercised its discretion not to seek any other penalties for this alleged non-compliance. OE disputed the DOJ's interpretation of the consent decree in a letter dated September 22, 2008. Although the Eastlake Unit 5 issue is no longer active, OE filed a dispute resolution petition on October 23, 2008, with the United States District Court for the Southern District of Ohio, due to potential impacts on its compliance decisions with respect to Burger Units 4 and 5. Under the Sammis NSR Litigation consent decree, an election to repower by December 31, 2012, install flue gas desulfurization (FGD) by December 31, 2010, or permanently shut down those units by December 31, 2010, is due no later than December 31, 2008. Although FirstEnergy will meet the December 31, 2008 deadline for making an election, one potential compliance option, should FGD be elected, would be to idle Burger Units 4 and 5 on December 31, 2010 pending completion of the FGD installation. Thus, OE is seeking a determination by the Court whether this approach is indeed in compliance with the terms of the Sammis NSR Litigation consent decree. The Court has scheduled a hearing on OE’s dispute resolution petition for November 17, 2008. The outcome of this dispute resolution process could have an impact on the option FirstEnergy ultimately elects with respect to Burger Units 4 and 5.

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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. Subsequently, on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR. The EPA has not yet issued a final regulation. FGCO’s future cost of compliance with those regulations may be substantial and will depend on how they are ultimately implemented.

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 CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the 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 October 18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim.

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In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.

On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the United States District Court. ~~Although it remains liable for civil~~The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. By letter dated October 1, 2008, New Jersey informed the Court of its intent to file an amended complaint. Met-Ed is unable to predict the outcome of this matter.

On June 11, 2008, the EPA issued a Notice and Finding of Violation to MEW alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or ~~criminal penalties~~permitting under the CAA's prevention of significant deterioration program. MEW is seeking indemnification from Penelec, the co-owner (along with New York State Electric and ~~fines that may be assessed relating to events~~Gas Company) and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from MEW is disputed. Penelec is unable to predict the ~~sale~~outcome of this matter.

On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the ~~Portland Station in 1999, Met-Ed~~CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an ACO modifying that request and setting forth a schedule for FGCO’s response. FGCO complied with the modified schedule and otherwise intends to fully comply with the ACO, but, at this time, is ~~indemnified by Sithe Energy against any other liability arising under~~unable to predict the outcome of this matter.

On August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether ~~it arises out~~these generating sources are complying with the NSR provisions of ~~pre-1999 or post-1999 events.~~the CAA. FirstEnergy intends to fully comply with the EPA’s information request, but, at this time, is unable to predict the outcome of this matter.

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National Ambient Air Quality Standards

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 ~~requires~~would have required 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)~~. FirstEnergy's Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO~~2 ~~and NO~~X ~~emissions, whereas its New Jersey fossil generation facility will be subject to only a cap on NO~~X ~~emissions. According to the EPA, SO~~2 ~~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,~~, ultimately capping SO2 emissions in affected states to just 2.5 million tons ~~annually.~~annually and 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 NO~~X ~~cap of~~to just 1.3 million tons annually. CAIR ~~has been~~was challenged in the United States Court of Appeals for the District of ~~Columbia.~~Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” The Court ruling also vacated the CAIR regional cap and trade requirements for SO2 and NOX, which is currently not expected to, but may, materially impair the value of emissions allowances obtained for future compliance. On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On October 21, 2008, the Court ordered the parties who appealed CAIR to file responses to the rehearing petitions by November 5, 2008 and directed them to address (1) whether any party is seeking vacatur of CAIR and (2) whether the Court should stay its vacatur of CAIR until EPA promulgates a revised rule. The future cost of compliance with these regulations may be substantial and ~~may~~will depend on the ~~outcome of this litigation and how CAIR is ultimately implemented.~~Court’s ruling on rehearing, as well as the action taken by the EPA or Congress in response to the Court’s ruling.

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, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the ~~court~~Court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a ~~cap and trade~~cap-and-trade program. The EPA ~~must now seek further judicial~~petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of ~~that~~the Court’s ruling vacating CAMR. The Supreme Court could grant the EPA’s petition and alter some or all of the lower Court’s decision, or the EPA could take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.

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. 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 Bruce Mansfield Plant, FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at all.

~~W. H. Sammis Plant~~

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W.H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case, along with seven other similar cases, are referred to as the NSR cases.

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 SO~~2 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 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, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree are currently estimated to be $1.3 billion for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.

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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. Subsequently, on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR. The EPA has not yet issued a final regulation. FGCO’s future cost of compliance with those regulations may be substantial and will depend on how they are ultimately implemented.

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 2012. The United States signed the Kyoto Protocol in 1998 but it ~~failed to receive the two-thirds vote required~~was never submitted 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. Also, in an April 16, 2008 speech, President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, 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.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the Senate ~~Environmental~~Environment and Public Works ~~Committees have~~Committee has passed one such bill. 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 CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On July 11, 2008, the EPA released an Advance Notice of Proposed Rulemaking, soliciting input from the public on the effects of climate change and the potential ramifications of regulation of CO2 under the CAA.

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FirstEnergy 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 FirstEnergy 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 FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy'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 United States 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 and eliminated the restoration option from the 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. On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review ~~certain aspects~~one significant aspect of the Second ~~Circuit’s decision.~~Circuit Court’s opinion which is whether Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. Oral argument before the Supreme Court is scheduled for December 2, 2008. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising ~~BPJ,~~best professional judgment, the future ~~cost~~costs of compliance with these standards may require material capital expenditures.

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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 non-hazardous waste.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of ~~March 31,~~September 30, 2008, FirstEnergy had approximately ~~$2.0~~$1.9 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $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 FirstEnergy (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.

The ~~Companies~~Utilities have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site may be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of ~~March 31,~~September 30, 2008, based on estimates of the total costs of cleanup, the ~~Companies'~~Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately ~~$92~~$94 million (JCP&L - ~~$65~~$68 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - ~~$25~~$24 million) have been accrued through ~~March 31,~~September 30, 2008. Included in the total for JCP&L are accrued liabilities of approximately ~~$56~~$57 million for environmental remediation of former manufactured gas plants in New ~~Jersey;~~Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

43

Other Legal Proceedings

Power Outages and Related Litigation

In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.

In August 2002, the trial ~~court~~Court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial ~~court~~Court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings are continuing in the Superior Court and a case management conference with the presiding Judge ~~is scheduled for~~was held on June 13, 2008. ~~FirstEnergy~~At that conference, the plaintiffs stated their intent to drop their efforts to create a class-wide damage model and, instead of dismissing the class action, expressed their desire for a bifurcated trial on liability and damages. The judge directed the plaintiffs to indicate, on or before August 22, 2008, how they intend to proceed under this scenario. Thereafter, the judge expects to hold another pretrial conference to address plaintiffs' proposed procedure. JCP&L has received the plaintiffs’ proposed plan of action, and intends to file its objection to the proposed plan, and also file a renewed motion to decertify the class. JCP&L is defending this ~~class~~ action but is unable to predict the ~~outcome of this matter.~~outcome. No liability has been accrued as of ~~March 31,~~September 30, 2008.

30

Nuclear Plant Matters

On May 14, 2007, the Office of Enforcement of the NRC issued a DFI to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was 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 DFI 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 FirstEnergy’s other nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the DFI response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC has conducted the employee training required by the confirmatory order and a consultant has performed follow-up reviews to ensure the effectiveness of that training. The NRC continues to monitor FENOC’s compliance with ~~these~~all the commitments made in the confirmatory order.

In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The NRC is ~~subject~~required by statute to ~~future~~provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. On September 24, 2008, the NRC ~~review.~~issued a draft supplemental Environmental Impact Statement for Beaver Valley. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively.

44

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and 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 W.H. Sammis Plant 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 April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint, which OE opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their ~~complaint.~~complaint and oral argument was held on November 5, 2008.

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district ~~court~~Court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. A final order identifying the individual damage amounts was issued on October 31, 2007. The award appeal process was initiated. The union filed a motion with the federal ~~court~~Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. The ~~court held a scheduling conference in April 2008 where it set a briefing schedule with all briefs~~Court has yet to ~~be concluded by July 2008.~~render its decision. JCP&L recognized a liability for the potential $16 million award in 2005.

The union employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. The parties are continuing to bargain with the assistance of a federal mediator. FirstEnergy has a strike mitigation plan ready in the event of a strike.

FirstEnergy accrues legal 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. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

31

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 141(R) – “Business Combinations”

In December 2007, the FASB issued SFAS 141(R), ~~which~~which: (i) requires the acquiring entity in a business combination to recognize all ~~the~~ assets acquired and liabilities assumed in the transaction; (ii) establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and (iii) requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. ~~SFAS 141(R) attempts to reduce the complexity of existing GAAP related to business combinations.~~ The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FirstEnergy that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in deferred tax valuation allowances and income tax uncertainties made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. ~~FirstEnergy is currently evaluating~~Under SFAS 141(R), adjustments to the acquired entity’s deferred tax assets and uncertain tax position balances occurring outside the measurement period will be recorded as a component of income tax expense, rather than goodwill. The impact of ~~adopting~~FirstEnergy’s application of this Standard ~~on its financial statements.~~in periods after implementation will be dependent upon acquisitions at that time.

45

SFAS 160 - ~~“Noncontrolling~~“Non-controlling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”

In December 2007, the FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statement is not expected to have a material impact on FirstEnergy’s financial statements.

SFAS 161 - “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133”

In March 2008, the FASB issued SFAS 161 ~~which~~that enhances the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. ~~This disclosure better conveys the purpose of derivative use in terms of the risks that the entity is intending to manage.~~ The FASB believes ~~disclosing~~that additional required disclosure of the fair values of derivative instruments and their gains and losses in a tabular format ~~is designed to~~will provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide information on the potential effect on an entity’s liquidity from using derivatives. ~~Finally, this~~This Statement also requires cross-referencing within the footnotes ~~which is intended~~ to help users of financial statements locate important information about derivative instruments. The Statement is effective for reporting periods beginning after November 15, 2008. FirstEnergy ~~is currently evaluating the impact of adopting~~expects this Standard onto increase its ~~financial statements.~~disclosure requirements for derivative instruments and hedging activities.

3246

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of FirstEnergy Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of ~~March 31,~~September 30, 2008 and the related consolidated statements of income and comprehensive income ~~and cash flows~~ for each of the three-month and nine-month periods ended ~~March 31,~~September 30, 2008 and 2007 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 9, Note 3, Note 2(G) and Note 12 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

~~May 7,~~November 6, 2008

33

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

Three Months Ended
March 31,
2008 2007
(In millions except,
per share amounts)
REVENUES:
Electric utilities $ 2,913 $ 2,659
Unregulated businesses 364 314
Total revenues* 3,277 2,973

EXPENSES:
Fuel and purchased power 1,328 1,121
Other operating expenses 800 749
Provision for depreciation 164 156
Amortization of regulatory assets 258 251
Deferral of new regulatory assets (105 ) (144 )
General taxes 215 203
Total expenses 2,660 2,336

OPERATING INCOME 617 637

OTHER INCOME (EXPENSE):
Investment income 17 33
Interest expense (179 ) (185 )
Capitalized interest 8 5
Total other expense (154 ) (147 )

INCOME BEFORE INCOME TAXES 463 490

INCOME TAXES 187 200

NET INCOME $ 276 $ 290

BASIC EARNINGS PER SHARE OF COMMON STOCK $ 0.91 $ 0.92

WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING 304 314

DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 0.90 $ 0.92

WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING 307 316

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $ 0.55 $ 0.50

* Includes $114 million and $108 million of excise tax collections in the first quarter of 2008 and 2007, respectively.

The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral
part of these statements.

3447

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Three Months Ended
March 31,
2008 2007

(In millions)

NET INCOME $ 276 $ 290

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (20 ) (11 )
Unrealized gain (loss) on derivative hedges (13 ) 21
Change in unrealized gain on available-for-sale securities (58 ) 17
Other comprehensive income (loss) (91 ) 27
Income tax expense (benefit) related to other comprehensive income (33 ) 9
Other comprehensive income (loss), net of tax (58 ) 18

COMPREHENSIVE INCOME $ 218 $ 308

The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral
part of these statements.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months						Nine Months
	Ended September 30						Ended September 30
	2008			2007			2008			2007
	(In millions, except per share amounts)
REVENUES:
Electric utilities	$	3,469		$	3,242		$	9,247		$	8,619
Unregulated businesses		435			399			1,179			1,104
Total revenues *		3,904			3,641			10,426			9,723

EXPENSES:
Fuel		356			327			1,000			887
Purchased power		1,306			1,168			3,376			2,914
Other operating expenses		794			756			2,375			2,255
Provision for depreciation		168			162			500			477
Amortization of regulatory assets		291			288			795			785
Deferral of new regulatory assets		(58	)		(107	)		(261	)		(399	)
General taxes		201			197			596			589
Total expenses		3,058			2,791			8,381			7,508

OPERATING INCOME		846			850			2,045			2,215

OTHER INCOME (EXPENSE):
Investment income		40			30			73			93
Interest expense		(192	)		(203	)		(559	)		(593	)
Capitalized interest		15			9			36			21
Total other expense		(137	)		(164	)		(450	)		(479	)

INCOME BEFORE INCOME TAXES		709			686			1,595			1,736

INCOME TAXES		238			273			585			695

NET INCOME	$	471		$	413		$	1,010		$	1,041


BASIC EARNINGS PER SHARE OF COMMON STOCK	$	1.55		$	1.36		$	3.32		$	3.39

WEIGHTED AVERAGE NUMBER OF
BASIC SHARES OUTSTANDING		304			304			304			307


DILUTED EARNINGS PER SHARE OF COMMON STOCK	$	1.54		$	1.34		$	3.29		$	3.35

WEIGHTED AVERAGE NUMBER OF
DILUTED SHARES OUTSTANDING		307			307			307			311


DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	1.10		$	1.00		$	1.65		$	1.50


* Includes excise tax collections of $115 million and $113 million in the three months ended September 30, 2008 and 2007,
respectively, and $329 million and $322 million in the nine months ended September 2008 and 2007, respectively.

The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.

3548

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

	Three Months						Nine Months
	Ended September 30						Ended September 30
	2008			2007			2008			2007
	(In millions)

NET INCOME	$	471		$	413		$	1,010		$	1,041

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(20	)		(12	)		(60	)		(34	)
Unrealized gain (loss) on derivative hedges		26			(10	)		21			10
Change in unrealized gain on available for sale securities		(100	)		26			(181	)		89
Other comprehensive income (loss)		(94	)		4			(220	)		65
Income tax expense (benefit) related to other
comprehensive income		(34	)		-			(81	)		19
Other comprehensive income (loss), net of tax		(60	)		4			(139	)		46

COMPREHENSIVE INCOME	$	411		$	417		$	871		$	1,087


The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2008
2007

(In millions)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents $ 70 $ 129
Receivables-
Customers (less accumulated provisions of $34 million and
$36 million, respectively, for uncollectible accounts) 1,264 1,256
Other (less accumulated provisions of $24 million and
$22 million, respectively, for uncollectible accounts) 159 165
Materials and supplies, at average cost 570 521
Prepayments and other 307 159
2,370 2,230
PROPERTY, PLANT AND EQUIPMENT:
In service 24,894 24,619
Less - Accumulated provision for depreciation 10,454 10,348
14,440 14,271
Construction work in progress 1,465 1,112
15,905 15,383
INVESTMENTS:
Nuclear plant decommissioning trusts 2,025 2,127
Investments in lease obligation bonds 679 717
Other 714 754
3,418 3,598
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill 5,606 5,607
Regulatory assets 3,797 3,945
Pension assets 723 700
Other 596 605
10,722 10,857
$ 32,415 $ 32,068
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt $ 2,183 $ 2,014
Short-term borrowings 1,649 903
Accounts payable 754 777
Accrued taxes 416 408
Other 1,167 1,046
6,169 5,148
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $.10 par value, authorized 375,000,000 shares-
304,835,407 shares outstanding. 31 31
Other paid-in capital 5,472 5,509
Accumulated other comprehensive loss (108 ) (50 )
Retained earnings 3,596 3,487
Total common stockholders' equity 8,991 8,977
Long-term debt and other long-term obligations 8,332 8,869
17,323 17,846
NONCURRENT LIABILITIES:
Accumulated deferred income taxes 2,717 2,671
Asset retirement obligations 1,287 1,267
Deferred gain on sale and leaseback transaction 1,052 1,060
Power purchase contract loss liability 682 750
Retirement benefits 911 894
Lease market valuation liability 643 663
Other 1,631 1,769
8,923 9,074
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
$ 32,415 $ 32,068

The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
balance sheets.

3649

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2008			2007
	(In millions)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	181		$	129
Receivables-
Customers (less accumulated provisions of $31 million and
$36 million, respectively, for uncollectible accounts)		1,383			1,256
Other (less accumulated provisions of $9 million and
$22 million, respectively, for uncollectible accounts)		148			165
Materials and supplies, at average cost		587			521
Prepayments and other		505			159
		2,804			2,230
PROPERTY, PLANT AND EQUIPMENT:
In service		26,141			24,619
Less - Accumulated provision for depreciation		10,714			10,348
		15,427			14,271
Construction work in progress		1,730			1,112
		17,157			15,383
INVESTMENTS:
Nuclear plant decommissioning trusts		1,873			2,127
Investments in lease obligation bonds		674			717
Other		720			754
		3,267			3,598
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		5,583			5,607
Regulatory assets		3,433			3,945
Pension assets		768			700
Other		550			605
		10,334			10,857
	$	33,562		$	32,068
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	2,509		$	2,014
Short-term borrowings		2,392			903
Accounts payable		744			777
Accrued taxes		253			408
Other		1,149			1,046
		7,047			5,148
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 375,000,000 shares-
304,835,407 outstanding		31			31
Other paid-in capital		5,465			5,509
Accumulated other comprehensive loss		(189	)		(50	)
Retained earnings		3,994			3,487
Total common stockholders' equity		9,301			8,977
Long-term debt and other long-term obligations		8,674			8,869
		17,975			17,846
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,793			2,671
Asset retirement obligations		1,314			1,267
Deferred gain on sale and leaseback transaction		1,035			1,060
Power purchase contract loss liability		603			750
Retirement benefits		914			894
Lease market valuation liability		319			663
Other		1,562			1,769
		8,540			9,074
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 11)
	$	33,562		$	32,068

The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
balance sheets.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Three Months Ended
March 31,
2008 2007
(In millions)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 276 $ 290
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 164 156
Amortization of regulatory assets 258 251
Deferral of new regulatory assets (105 ) (144 )
Nuclear fuel and lease amortization 26 26
Deferred purchased power and other costs (59 ) (116 )
Deferred income taxes and investment tax credits, net 89 53
Investment impairment 16 5
Deferred rents and lease market valuation liability 4 (25 )
Accrued compensation and retirement benefits (142 ) (65 )
Commodity derivative transactions, net 8 1
Gain on asset sales (37 ) -
Cash collateral received 8 6
Pension trust contribution - (300 )
Decrease (increase) in operating assets-
Receivables (6 ) (155 )
Materials and supplies (17 ) 15
Prepayments and other current assets (115 ) (74 )
Increase (decrease) in operating liabilities-
Accounts payable (23 ) (108 )
Accrued taxes (5 ) 73
Accrued interest 91 86
Electric service prepayment programs (19 ) (17 )
Other (56 ) (15 )
Net cash provided from (used for) operating activities 356 (57 )

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt - 250
Short-term borrowings, net 746 1,139
Redemptions and Repayments-
Common stock - (891 )
Long-term debt (368 ) (13 )
Net controlled disbursement activity 6 12
Stock-based compensation tax benefit 11 8
Common stock dividend payments (168 ) (159 )
Net cash provided from financing activities 227 346

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (711 ) (296 )
Proceeds from asset sales 50 -
Sales of investment securities held in trusts 361 273
Purchases of investment securities held in trusts (384 ) (294 )
Cash investments 58 25
Other (16 ) 2
Net cash used for investing activities (642 ) (290 )

Net decrease in cash and cash equivalents (59 ) (1 )
Cash and cash equivalents at beginning of period 129 90
Cash and cash equivalents at end of period $ 70 $ 89

The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.

3750

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Nine Months
	Ended September 30
	2008			2007
	(In millions)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,010		$	1,041
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		500			477
Amortization of regulatory assets		795			785
Deferral of new regulatory assets		(261	)		(399	)
Nuclear fuel and lease amortization		82			75
Deferred purchased power and other costs		(163	)		(265	)
Deferred income taxes and investment tax credits, net		278			(158	)
Investment impairment		63			16
Deferred rents and lease market valuation liability		(62	)		(41	)
Accrued compensation and retirement benefits		(127	)		(50	)
Stock-based compensation		(74	)		(32	)
Commodity derivative transactions, net		4			5
Gain on asset sales		(43	)		(35	)
Cash collateral		21			(50	)
Pension trust contribution		-			(300	)
Decrease (increase) in operating assets-
Receivables		(117	)		(329	)
Materials and supplies		(34	)		62
Prepayments and other current assets		(264	)		(39	)
Increase (decrease) in operating liabilities-
Accounts payable		(34	)		(15	)
Accrued taxes		(166	)		355
Accrued interest		107			104
Electric service prepayment programs		(58	)		(52	)
Other		(29	)		55
Net cash provided from operating activities		1,428			1,210

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		631			1,100
Short-term borrowings, net		1,489			-
Redemptions and Repayments-
Common stock		-			(918	)
Long-term debt		(733	)		(647	)
Short-term borrowings, net		-			(535	)
Net controlled disbursement activity		6			6
Stock-based compensation tax benefit		24			16
Common stock dividend payments		(503	)		(464	)
Net cash provided from (used for) financing activities		914			(1,442	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(2,177	)		(1,127	)
Proceeds from asset sales		64			37
Proceeds from sale and leaseback transaction		-			1,329
Sales of investment securities held in trusts		1,144			1,010
Purchases of investment securities held in trusts		(1,215	)		(1,126	)
Cash investments		72			48
Restricted funds for debt redemption		(82	)		-
Other		(96	)		1
Net cash provided from (used for) investing activities		(2,290	)		172

Net change in cash and cash equivalents		52			(60	)
Cash and cash equivalents at beginning of period		129			90
Cash and cash equivalents at end of period	$	181		$	30

The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an
integral part of these statements.

51

FIRSTENERGY SOLUTIONS CORP.

~~MANAGEMENT’S NARRATIVE~~

MANAGEMENT’S NARRATIVE

~~ANALYSIS OF RESULTS OF OPERATIONS~~

ANALYSIS OF RESULTS OF OPERATIONS

FES is a wholly owned subsidiary of FirstEnergy. FES provides energy-related products and services primarily in Ohio, Pennsylvania, Michigan and Maryland, and through its subsidiaries, FGCO and NGC, owns or leases and operates FirstEnergy’s fossil and hydroelectric generation facilities and owns FirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.

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 and default service requirements. These affiliated power sales include a full-requirements PSA with OE, CEI and TE to supply each of their ~~PLR~~default service obligations through 2008, at prices that take into consideration their respective PUCO-authorized billing rates. FES also has a partial requirements wholesale power sales agreement with its affiliates, Met-Ed and Penelec, to supply a portion of each of their respective ~~PLR~~default service obligations at fixed prices through 2010. The fixed prices under the partial requirements agreement are expected to remain below wholesale market prices during the term of the agreement. FES also supplies ~~the majority~~a portion of ~~the PLR~~Penn’s default service requirements ~~of Penn~~ at market-based rates as a result of aPenn’s 2008 competitive ~~solicitation conducted by Penn.~~solicitations. FES’ existing contractual obligations to Penn expire on May 31, ~~2008,~~2009, but could continue if FES successfully bids in future competitive solicitations. FES’ revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, Maryland and Michigan.

Results of Operations

In the first ~~three~~nine months of 2008, net income decreased to ~~$90~~$344 million from ~~$103~~$409 million in the same period in 2007. The decrease in net income was primarily due to higher fuel and other operating expenses, partially offset by lower purchased power costs and higher revenues.

Revenues

Revenues increased by ~~$81~~$154 million in the first ~~three~~nine months of 2008 compared to the same period inof 2007 due to increases in revenues from non-affiliated and affiliated wholesale sales, partially offset by lower retail generation sales. Non-affiliated wholesale revenues increased as a result of higher capacity prices and sales volumes in the PJM market, partially offset by decreased sales volumes in the MISO market. Retail generation sales revenues decreased as a result of decreased sales in the PJM market partially offset by increased sales in the MISO market. Lower sales in the PJM market were primarily due to lower contract renewals for commercial and industrial customers. ~~Greater~~Increased sales in the MISO market were primarily due to ~~FES’~~FES capturing more shopping customers in Penn’s service territory, partially offset by lower customer usage. ~~Non-affiliated wholesale revenues increased as a result of more generation available for wholesale sales to non-affiliates.~~

The increase in affiliated company wholesale sales was due to ~~greater~~higher unit prices for the Ohio Companies partially offset by lower unit prices for the Pennsylvania Companies and decreased sales volumes to all affiliates. Higher unit prices on sales to the Ohio ~~and Pennsylvania~~ Companies ~~to meet their higher retail generation sales requirements. Higher unit prices~~ resulted from the PSA provision, ~~of the full-requirements PSA under which~~whereby PSA rates reflect the increase in the Ohio Companies’ retail generation rates. While unit prices for each of the Pennsylvania Companies did not change, the mix of sales among the companies caused the composite price to decline. The ~~higher~~lower PSA sales volumes to the Ohio and Pennsylvania Companies were due to ~~increased Met-Ed~~milder weather and ~~Penelec generation sales requirements. These increases were partially offset by lower sales to Penn due to~~decreased default service requirements in Penn’s service territory as a ~~45% increase in customer shopping in the first quarter~~result of ~~2008 compared to the first quarter of 2007.~~

Transmission revenue increased $10 million due to increased retail load in the MISO market and higher transmission prices ($12 million), partially offset by reduced FTR auction revenues ($2 million).its RFP process.

Changes in revenues in the first ~~three~~nine months of 2008 from the same period of 2007 are summarized below:

	Three Months Ended							Nine Months Ended
	March 31,				Increase			September 30,				Increase
Revenues by Type of Service	2008		2007		(Decrease)			2008		2007		(Decrease)
	(In millions)							(In millions)
Non-Affiliated Generation Sales:
Retail	$	160	$	174	$	(14	)	$	485	$	547	$	(62	)
Wholesale		129		103		26			509		426		83
Total Non-Affiliated Generation Sales		289		277		12			994		973		21
Affiliated Generation Sales		776		714		62			2,266		2,210		56
Transmission		33		23		10			113		71		42
Other		1		4		(3	)		39		4		35
Total Revenues	$	1,099	$	1,018	$	81		$	3,412	$	3,258	$	154

3852

The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated generation sales in the first ~~three~~nine months of 2008 compared to the same period last year:

	Increase			Increase
Source of Change in Non-Affiliated Generation Revenues	(Decrease)			(Decrease)
	(In millions)			(In millions)
Retail:
Effect of 9.0% decrease in sales volumes	$	(16	)
Effect of 13.2% decrease in sales volumes				$	(73	)
Change in prices		2			11
		(14	)		(62	)
Wholesale:
Effect of 3.5% increase in sales volumes		4
Effect of 4.6% increase in sales volumes					19
Change in prices		22			64
		26			83
Net Increase in Non-Affiliated Generation Revenues	$	12		$	21

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months						Nine Months
	Ended September 30						Ended September 30
	2008			2007			2008			2007
	(In thousands)

REVENUES:
Electric sales to affiliates	$	785,681		$	805,372		$	2,266,271		$	2,209,743
Electric sales to non-affiliates		381,483			337,561			994,100			972,591
Other		74,440			27,975			151,627			75,598
Total revenues		1,241,604			1,170,908			3,411,998			3,257,932

EXPENSES:
Fuel		349,946			301,786			982,185			804,201
Purchased power from non-affiliates		221,493			228,755			648,556			577,831
Purchased power from affiliates		15,821			62,508			75,834			209,576
Other operating expenses		279,184			235,033			863,468			731,774
Provision for depreciation		64,633			48,500			170,535			145,030
General taxes		21,736			22,242			64,728			64,870
Total expenses		952,813			898,824			2,805,306			2,533,282

OPERATING INCOME		288,791			272,084			606,692			724,650

OTHER INCOME (EXPENSE):
Miscellaneous income		18,427			12,655			13,449			47,756
Interest expense - affiliates		(8,015	)		(9,641	)		(25,953	)		(61,904	)
Interest expense - other		(32,769	)		(31,794	)		(81,809	)		(70,845	)
Capitalized interest		12,395			5,131			29,599			12,763
Total other expense		(9,962	)		(23,649	)		(64,714	)		(72,230	)

INCOME BEFORE INCOME TAXES		278,829			248,435			541,978			652,420

INCOME TAXES		93,174			93,671			198,245			243,736

NET INCOME		185,655			154,764			343,733			408,684

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(1,821	)		(1,360	)		(5,462	)		(4,080	)
Unrealized gain on derivative hedges		27,277			4,863			15,075			9,451
Change in unrealized gain on available-for-sale securities		(90,198	)		21,263			(159,759	)		80,053
Other comprehensive income (loss)		(64,742	)		24,766			(150,146	)		85,424
Income tax expense (benefit) related to other
comprehensive income		(24,781	)		8,915			(55,497	)		30,474
Other comprehensive income (loss), net of tax		(39,961	)		15,851			(94,649	)		54,950

TOTAL COMPREHENSIVE INCOME	$	145,694		$	170,615		$	249,084		$	463,634

The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an integral part of
these balance sheets.

56

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,		December 31,
	2008		2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	2
Receivables-
Customers (less accumulated provisions of $5,840,000 and $8,072,000,
respectively, for uncollectible accounts)		137,126		133,846
Associated companies		263,779		376,499
Other (less accumulated provisions of $6,798,000 and $9,000
respectively, for uncollectible accounts)		22,924		3,823
Notes receivable from associated companies		156,926		92,784
Materials and supplies, at average cost		497,276		427,015
Prepayments and other		179,530		92,340
		1,257,563		1,126,309
PROPERTY, PLANT AND EQUIPMENT:
In service		9,834,662		8,294,768
Less - Accumulated provision for depreciation		4,211,717		3,892,013
		5,622,945		4,402,755
Construction work in progress		1,385,652		761,701
		7,008,597		5,164,456
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		1,145,384		1,332,913
Long-term notes receivable from associated companies		62,900		62,900
Other		40,573		40,004
		1,248,857		1,435,817
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		230,341		276,923
Lease assignment receivable from associated companies		71,356		215,258
Goodwill		24,248		24,248
Property taxes		47,774		47,774
Pension assets		14,764		16,723
Unamortized sale and leaseback costs		57,365		70,803
Other		49,702		43,953
		495,550		695,682
	$	10,010,567	$	8,422,264
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,938,215	$	1,441,196
Short-term borrowings-
Associated companies		311,750		264,064
Other		1,000,000		300,000
Accounts payable-	��
Associated companies		361,447		445,264
Other		163,173		177,121
Accrued taxes		80,719		171,451
Other		217,914		237,806
		4,073,218		3,036,902
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 750 shares-
7 shares outstanding		1,461,541		1,164,922
Accumulated other comprehensive income		46,005		140,654
Retained earnings		1,409,388		1,108,655
Total common stockholder's equity		2,916,934		2,414,231
Long-term debt and other long-term obligations		558,923		533,712
		3,475,857		2,947,943
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		1,035,013		1,060,119
Accumulated deferred investment tax credits		63,968		61,116
Asset retirement obligations		849,475		810,114
Retirement benefits		67,567		63,136
Property taxes		48,095		48,095
Lease market valuation liability		319,129		353,210
Other		78,245		41,629
		2,461,492		2,437,419
COMMITMENTS AND CONTINGENCIES (Note 11)
	$	10,010,567	$	8,422,264

The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an integral
part of these balance sheets.

57

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Nine Months
	Ended September 30
	2008			2007
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	343,733		$	408,684
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		170,535			145,030
Nuclear fuel and lease amortization		81,950			75,102
Deferred rents and lease market valuation liability		(36,702	)		-
Deferred income taxes and investment tax credits, net		91,082			(381,042	)
Investment impairment		58,173			14,296
Accrued compensation and retirement benefits		(2,110	)		3,414
Commodity derivative transactions, net		3,634			4,913
Gain on asset sales		(11,319	)		(12,105	)
Cash collateral, net		(8,827	)		(19,798	)
Pension trust contribution		-			(64,020	)
Decrease (increase) in operating assets:
Receivables		106,574			(30,172	)
Materials and supplies		(35,498	)		48,123
Prepayments and other current assets		(10,762	)		(5,118	)
Increase (decrease) in operating liabilities:
Accounts payable		(61,035	)		(108,949	)
Accrued taxes		(90,767	)		434,568
Accrued interest		15,420			14,355
Other		(59,948	)		(5,254	)
Net cash provided from operating activities		554,133			522,027

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		537,375			-
Equity contribution from parent		280,000			700,000
Short-term borrowings, net		747,686			-
Redemptions and Repayments-
Common stock		-			(600,000	)
Long-term debt		(460,902	)		(1,110,174	)
Short-term borrowings, net		-			(785,127	)
Common stock dividend payments		(43,000	)		(67,000	)
Net cash provided from (used for) financing activities		1,061,159			(1,862,301	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(1,417,205	)		(482,907	)
Proceeds from asset sales		15,218			12,990
Proceeds from sale and leaseback transaction		-			1,328,919
Sales of investment securities held in trusts		596,291			521,535
Purchases of investment securities held in trusts		(624,899	)		(552,779	)
Loan repayments from (loans to) associated companies, net		(64,142	)		510,307
Restricted funds for debt redemption		(81,640	)		-
Other		(38,915	)		2,209
Net cash provided from (used for) investing activities		(1,615,292	)		1,340,274

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 as they related to FirstEnergy Solutions Corp. are
an integral part of these balance sheets.

.

~~A utility~~

Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement 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 sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The fixed price under the agreement is expected to remain below wholesale market prices during the term of the agreement. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for their fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC. See FERC Matters below for a description of the Third Restated Partial Requirements Agreement, executed by the parties on October 31, 2008, that limits the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the event of a third party supplier default, the increased costs to Met-Ed and Penelec could be material.

83

Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.

The PPUC entered its opinion and order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes to NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million).

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the ~~court~~Court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. ~~Oral arguments are scheduled to take place~~The Commonwealth Court issued its decision on November 7, 2008, which affirmed the PPUC's January 11, 2007 order in ~~September 2008. If Met-Ed~~all respects, including the deferral and ~~Penelec do not prevail on the issue~~recovery of transmission and congestion ~~it could have a material adverse effect on the results of operations of Met-Ed, Penelec and FirstEnergy.~~related costs.

On ~~April 14,~~May 22, 2008, the PPUC approved the Met-Ed and Penelec ~~filed~~ annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. Various intervenors filed complaints against Met-Ed’s and Penelec’s TSC filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing the company to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted with hearings for both companies scheduled to begin in January 2009. The ~~proposed~~ TSCs include a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed ~~has proposed~~received approval from the PPUC of a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.

On March 13, 2008, the PPUC approved the residential procurement process in Penn’s Joint Petition for Settlement. This RFP process calls for load-following, full-requirements contracts for default service procurement for residential customers for the period covering June 1, 2008 through May 31, 2011. The PPUC had previously approved the default service procurement processes for commercial and industrial customers. The default service procurement for small commercial customers was conducted through multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the two RFPs for small commercial load were approved by the PPUC on February 22, 2008, and March 20, 2008. On March 28, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for small commercial customers which the PPUC then certified on April 4, 2008. On April 14, 2008, the first RFP for residential customers’ load was held consisting of tranches for both 12 and 24-month supply. The PPUC approved the bids on April 16, 2008. The second RFP is scheduled to be held on May 14, 2008, after which time the PPUC is expected to approve the new rates to go into effect June 1, 2008.

8499

On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. ~~Neither chamber has formally considered~~As part of the ~~other’s bill.~~2008 state budget negotiations, the Alternative Energy Investment Act was enacted creating a $650 million alternative energy fund to increase the development and use of alternative and renewable energy, improve energy efficiency and reduce energy consumption. On ~~February 12,~~October 8, 2008, ~~the Pennsylvania House passed~~ House Bill 2200 as amended, was voted out of the full Senate and adopted by the House. On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which ~~provides for~~becomes effective on November 14, 2008 as Act 129 of 2008. The bill addresses issues such as: energy efficiency and ~~demand management programs and targets as well as the installation of~~peak load reduction; generation procurement; time-of-use rates; smart meters ~~within ten years. Other~~and alternative energy. Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009 and a smart meter procurement and installation plan by August 14, 2009.

Major provisions of the legislation ~~has been introduced to address generation~~include:

·	power acquired by utilities to serve customers after rate caps expire will be procured through a competitive procurement process that must include a mix of long-term and short-term contracts and spot market purchases;

·	the competitive procurement process must be approved by the PPUC and may include auctions, request for proposals, and/or bilateral agreements;

·	utilities must provide for the installation of smart meter technology within 15 years;

·	a minimum reduction in peak demand of 4.5% by May 31, 2013;

·	minimum reductions in energy consumption of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and

·	an expanded definition of alternative energy to include additional types of hydroelectric and biomass facilities.

The current legislative session ends on November 30, 2008, and any pending legislation addressing rate mitigation and the expiration of rate caps ~~conservation~~not enacted by that time must be re-introduced in order to be considered in the next legislative session which begins in January 2009. While the form and ~~renewable energy. The final form~~impact of ~~this pending~~such legislation is ~~uncertain. Consequently,~~uncertain, several legislators and the Governor have indicated their intent to address these issues next year.

On September 25, 2008, Met-Ed and Penelec OEfiled for Commission approval of a Voluntary Prepayment Plan that would provide an opportunity for residential and ~~Penn are unable~~small commercial customers to ~~predict what impact, if any, such legislation may have~~pre-pay an amount, which would earn interest at 7.5%, on their ~~operations.~~monthly electric bills in 2009 and 2010, to be used to reduce electric rates in 2011 and 2012. Met-Ed and Penelec also intend to file a generation procurement plan for 2011 and beyond with the PPUC later this year or early next year. Met-Ed and Penelec requested that the PPUC approve the Plan by mid-December 2008 and are currently awaiting a decision.

New Jersey (Applicable to JCP&L)

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of ~~March 31,~~September 30, 2008, the accumulated deferred cost balance totaled approximately ~~$264~~$210 million.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set.

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On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. A public hearing on these proposed rules was held on April 23, 2008 ~~with~~and comments from interested parties ~~due on~~were submitted by May ~~16,~~19, 2008.

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in 2006, 2007 and the ~~fall~~first half of ~~2006 and in early 2007.~~

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2008.

On April 17, 2008, a draft EMP was released for public comment. The ~~draft~~final EMP was issued on October 22, 2008 and establishes ~~four~~five major goals:

·	maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020;

·	reduce peak demand for electricity by 5,700 MW by ~~2020 (amounting to about a 22% reduction in projected demand);~~2020;

·	meet ~~22.5%~~30% of the state’s electricity needs with renewable energy by 2020;

·	examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and

·	~~develop low carbon emitting, efficient power plants~~invest in innovative clean energy technologies and ~~close~~businesses to stimulate the ~~gap between the supply and demand for electricity.~~industry’s growth in New Jersey.

~~Following the public comment period which is expected to extend into July 2008, a~~The final EMP will ~~be issued to~~ be followed by appropriate legislation and regulation as necessary. At this time, JCP&L cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations.

On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments that were submitted in September and October 2007. Final regulations (effective upon publication) were published in the New Jersey Register March 17, 2008. Upon preliminary review of the new regulations, JCP&L does not expect a material impact on its operations.

FERC Matters (Applicable to FES and each of the ~~Companies)~~Utilities)

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate ~~so-called “pancaking” of~~multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered ~~the~~ MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, 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 by year-end 2008. In the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the ~~second quarter~~docket to mitigate the risk of ~~2008.~~lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision.

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PJM Transmission Rate Design

On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.

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On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce the costs of future transmission ~~revenue recovery~~to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding ~~Judge. The FERC’s action on~~Judge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement ~~agreement is pending.~~subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. The remaining merchant transmission cost allocation issues ~~will proceed to~~were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions are due on November 10, 2008. On February ~~13,~~11, 2008, AEP appealed the FERC’s April 19, 2007 and January 31, 2008 orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit.

Post Transition Period Rate Design

The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within ~~the~~ MISO, and between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of the FERC’s approval, the rates charged to FirstEnergy’s load-serving affiliates for transmission service over existing transmission facilities in MISO and PJM are unchanged. 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 higher transmission facilities across the entire MISO footprint (known as the RECB methodology) be retained.

On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP is pending before the FERC.

~~Distribution of MISO Network Service Revenues~~

Effective February 1, 2008, the MISO Transmission Owners Agreement provides for a change in the method of distributing transmission revenues among the transmission owners. MISO and a majority of the MISO transmission owners filed on December 3, 2007 to change the MISO tariff to clarify, for purposes of distributing network transmission revenue to the transmission owners, that all network transmission service revenues, whether collected by MISO or directly by the transmission owner, are included in the revenue distribution calculation. This clarification was necessary because some network transmission service revenues are collected and retained by transmission owners in states where retail choice does not exist, and their “unbundled” retail load is currently exempt from MISO network service charges. The tariff changes filed with the FERC ensure that revenues collected by transmission owners from bundled load are taken into account in the revenue distribution calculation, and that transmission owners with bundled load do not collect more than their revenue requirements. Absent the changes, transmission owners, and ultimately their customers, with unbundled load or in retail choice states, such as ATSI, would subsidize transmission owners with bundled load, who would collect their revenue requirement from bundled load, plus share in revenues collected by MISO from unbundled customers. This would result in a large revenue shortfall for ATSI, which would eventually be passed on to customers in the form of higher transmission rates as calculated pursuant to ATSI’s Attachment O formula under the MISO tariff.

Numerous parties filed in support of the tariff changes, including the public service commissions of Michigan, Ohio and Wisconsin. Ameren filed a protest on December 26, 2007, arguing that the December 3, 2007 filing violates the MISO Transmission Owners’ Agreement as well as an agreement among Ameren (Union Electric), MISO, and the Missouri Public Service Commission, which provides that Union Electric’s bundled load cannot be charged by MISO for network service. On February 2, 2008, the FERC issued an order conditionally accepting the tariff amendment subject to a minor compliance filing, which was made on March 3, 2008. This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement. A rehearing request by Ameren is pending before the FERC.

On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of the MISO Transmission Owners’ Agreement. This request was accepted by the FERC on March 13, 2008. On that same day, MISO and the MISO transmission owners made a filing to amend the Transmission Owners’ Agreement to effectively continue the distribution of transmission revenues that was in effect prior to February 1, 2008. This matter is currently pending before the FERC.

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MISO Ancillary Services Market and Balancing Area Consolidation

MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. ~~This filing~~These markets would permit ~~load serving~~generators to sell, and load-serving entities to purchase, their operating reserve requirements in a competitive market. ~~FES, CEI, OE, Penn and TE support~~FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. ~~MISO has since notified~~Numerous parties filed requests for rehearing on March 26, 2008. On June 23, 2008, the FERC issued an order granting in part and denying in part rehearing.

On February 29, 2008, MISO submitted a compliance filing setting forth MISO’s Readiness Advisor ASM and Consolidated Balancing Authority Initiative Verification plan and status and Real-Time Operations ASM Reversion plan. FERC action on this compliance filing remains pending. On March 26, 2008, MISO submitted a tariff filing in compliance with the FERC’s 30-day directives in the February 25 order. Numerous parties submitted comments and protests on April 16, 2008. The FERC issued an order accepting the revisions pending further compliance on June 23, 2008. On April 25, 2008, MISO submitted a tariff filing in compliance with the FERC’s 60-day directives in the February 25 order. FERC action on this compliance filing remains pending. On May 23, 2008, MISO submitted its amended Balancing Authority Agreement. On July 21, 2008, the FERC issued an order conditionally accepting the amended Balancing Authority Agreement and requiring a further compliance filing. On August 19, 2008, MISO submitted its compliance filing to the FERC. On July 25, 2008, MISO submitted another Readiness Certification. The FERC has not yet acted on this submission. MISO announced on August 26, 2008 that the ~~start~~startup of its ~~ASM~~market is ~~delayed until September~~postponed indefinitely. MISO commits to make a filing giving at least sixty days notice of the new effective date. The latest announced effective date for market startup is January 6, 2009.

Interconnection Agreement with AMP-Ohio

On May 29, 2008, TE filed with the FERC a proposed Notice of Cancellation effective midnight December 31, 2008, of the Interconnection Agreement with AMP-Ohio. AMP-Ohio protested this filing. TE also filed a Petition for Declaratory Order seeking a FERC ruling, in the alternative if cancellation is not accepted, of TE's right to file for an increase in rates effective January 1, 2009, for power provided to AMP-Ohio under the Interconnection Agreement. AMP-Ohio filed a pleading agreeing that TE may seek an increase in rates, but arguing that any increase is limited to the cost of generation owned by TE affiliates. On August 18, 2008, the FERC issued an order that suspended the cancellation of the Agreement for five months, to become effective on June 1, 2009, and established expedited hearing procedures on issues raised in the filing and TE’s Petition for Declaratory Order. On October 14, 2008, the parties filed a settlement agreement and mutual notice of cancellation of the Interconnection Agreement effective midnight December 31, 2008. Upon acceptance by the FERC, this filing will terminate the litigation and the Interconnection Agreement, among other effects.

Duquesne’s Request to Withdraw from PJM

On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join ~~the~~ MISO. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. FirstEnergy believes that Duquesne’s filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesne’s proposal. Consequently, FirstEnergy submitted responsive filings that, while conceding Duquesne’s rights to exit PJM, contested various aspects of Duquesne’s proposal. FirstEnergy particularly focused on Duquesne’s proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne’s failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use the Beaver Valley Plant to meet existing commitments in the PJM capacity markets and to serve native load. Other market participants also submitted filings contesting Duquesne’s plans.

On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne zone load-serving entities to pay ~~the~~their PJM capacity obligations through May 31, 2011. The FERC’s order took notice of the numerous transmission and other issues raised by FES and the Companies and other parties to the proceeding, but did not provide any responsive rulings or other guidance. Rather, the FERC ordered Duquesne to make a compliance filing in forty-five days detailing how Duquesne will satisfy its obligations under the PJM Transmission Owners’ Agreement. The FERC likewise directed the MISO to submit detailed plans to integrate Duquesne into the MISO. Finally, the FERC directed MISO and PJM to work together to resolve the substantive and procedural issues implicated by Duquesne’s transition into the MISO. These issues remain unresolved. If Duquesne satisfies all of the obligations set by the FERC, its planned transition date is October 9, 2008.

~~On March 18, 2008, the PJM Power Providers Group filed a request for emergency clarification regarding whether Duquesne-zone generators (including the Beaver Valley Plant) could participate~~FirstEnergy desires to continue to use its Duquesne zone generation resources to serve load in ~~PJM’s May 2008 auction for the 2011-2012 RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings.~~PJM. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification ~~wherein~~on whether Duquesne-zone generators could participate in PJM’s May 2008 auction for the 2011-2012 planning year. In the order, the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators ~~can~~could contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with the FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy ~~satisfies~~satisfied the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction. ~~Notwithstanding these events, on April~~

The FERC also directed MISO and PJM to resolve the substantive and procedural issues associated with Duquesne’s transition into MISO. As directed, PJM filed thirteen load-serving entity Capacity Payment Agreements and a Capacity Portability Agreement with the FERC. The Capacity Payment Agreements addressed Duquesne Zone load-serving entity obligations through May 31, 2011 with regards to RPM Capacity while the Capacity Portability Agreement addressed operational issues associated with the portability of such capacity. On September 30, 2008, the FERC approved both agreements, subject to conditions, taking notice of many operational and procedural issues brought forth by FirstEnergy and other market participants.

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Several issues surrounding Duquesne’s transition into MISO continue to be contested at the FERC. Specifically, Duquesne’s obligation to pay for transmission expansion costs allocated to the Duquesne zone when they were a member of PJM, and other issues in which market participants wish to be held harmless by Duquesne’s transition. FirstEnergy filed for rehearing on these issues on October 3, 2008. Duquesne’s transition into MISO is also contingent upon the start of MISO’s ancillary services market and consolidation of its balancing authorities, currently scheduled for January 6, 2009.

Complaint against PJM RPM Auction

On May 1,30, 2008, ~~certain members~~a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. Most of the parties comprising the RPM Buyers group were parties to the settlement approved by the FERC that established the RPM. In the complaint, the RPM Buyers request that the total projected payments to RPM sellers for the three auctions at issue be materially reduced. On July 11, 2008, PJM ~~Power Providers Group~~ filed ~~further pleadings~~its answer to the complaint, in which it denied the allegation that the rates are unjust and unreasonable. Also on ~~these issues. On May 2, 2008,~~that date, FirstEnergy filed a ~~responsive pleading. FirstEnergy is participating~~motion to intervene.

On September 19, 2008, the FERC denied the RPM Buyers complaint. However, the FERC did grant the RPM Buyers request for a technical conference to review aspects of the RPM. The FERC also ordered PJM to file on or before December 15, 2008, a report on its progress on contemplating adjustments to the RPM as suggested by the Brattle Group in its report reviewing the ~~May~~RPM. The technical conference will take place in February, 2009. On October 20, 2008, the RPM ~~auction~~Buyers filed a request for rehearing of the ~~2011-2012 RPM delivery year.~~FERC’s September 19, 2008 order.

MISO Resource Adequacy Proposal

MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for ~~load serving~~load-serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for ~~load serving~~load-serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for ~~load serving~~load-serving entities in its state. FirstEnergy ~~generally supports~~believes the proposal ~~as it~~ promotes a mechanism that will result in ~~long-term~~ commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were filed on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, ~~2008.~~2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. AOn May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing. On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchase power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. Issuance of these orders is ~~due on or before~~not expected to delay the June ~~25, 2008.~~

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1, 2009 start date for MISO Resource Adequacy.

Organized Wholesale Power Markets

~~On February 21, 2008, the~~The FERC issued a ~~NOPR through which it proposes~~final rule on October 17, 2008, amending its regulations to ~~adopt new rules that it states will~~ “improve ~~operations in~~the operation of organized wholesale electric markets ~~boost competition and bring additional benefits to consumers.” The proposed rule addresses~~in the areas of: (1) demand response and market pricing during periods of operating reserve ~~shortages,~~shortage; (2) long-term power ~~contracting,~~contracting; (3) market-monitoring ~~policies,~~policies; and (4) the responsiveness of RTOs and ISOs to their customers and other stakeholders.” The RTOs and ISOs were directed to submit amendments to their respective tariffs to address these market operation improvements. The final rule directs RTOs to adopt market rules permitting prices to increase during periods of supply shortages and to permit enhanced participation by demand response resources. It also codifies and defines for the first time the roles and duties of independent market monitors within RTOs. Finally, it adopts requirements for enhanced access by stakeholders to RTO boards of directors. RTOs are directed to make compliance filings six months from the effective date of the final rule. The final rule is not expected to have any material effect on FirstEnergy's operations within MISO and ~~customers.~~PJM.

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FES Sales to Affiliates

On October 24, 2008, FES, on its own behalf and on behalf of its generation-controlling subsidiaries, filed an application with the FERC seeking a waiver of the affiliate sales restrictions between FES and the Ohio Companies. The purpose of the waiver is to ensure that FES will be able to continue supplying a material portion of the electric load requirements of the Ohio Companies ~~do not believe that~~in January 2009 pursuant to either an ESP or MRO as filed with the ~~proposed rule will have~~PUCO. FES previously obtained a ~~significant impact on their operations. Comments on~~similar waiver for electricity sales to its affiliates in New Jersey, New York, and Pennsylvania. A ruling by the ~~NOPR were filed on April 18,~~FERC is expected the week of December 15, 2008.

On October 31, 2008, FES executed a Third Restated Partial Requirements Agreement with Met-Ed, Penelec, and The Waverly Power and Light Company (Waverly) effective November 1, 2008. The Third Restated Partial Requirements Agreement limits the amount of capacity and energy required to be supplied by FES in 2009 and 2010 to roughly two-thirds of these affiliates’ power supply requirements. Met-Ed, Penelec, and Waverly have committed resources in place for the balance of their expected power supply during 2009 and 2010. Under the Third Restated Partial Requirements Agreement, Met-Ed, Penelec, and Waverly are responsible for obtaining additional power supply requirements created by the default or failure of supply of their committed resources. Prices for the power provided by FES were not changed in the Third Restated Partial Requirements Agreement.

Environmental Matters

Various federal, state and local authorities regulate FES and the Companies with regard to air and water quality and other environmental matters. The effects of compliance on FES and the Companies with regard to environmental matters could have a material adverse effect on their earnings and competitive position to the extent that they compete 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 ~~and the Companies estimate~~estimates capital expenditures for environmental compliance of approximately $1.4 billion for the period 2008-2012.

FES and the Companies accrue environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FES’ and the Companies’ determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.

Clean Air Act Compliance (Applicable to FES)

FES is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the 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 CAA. FES has disputed those alleged violations based on its CAA permit, the Ohio SIP and other information provided to the EPA 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. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding ~~the opacity limit~~emission limits applicable to the common stack for Bay Shore Units 2, 3 and 4.

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 NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.

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In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case, along with seven other similar cases, is referred to as the NSR cases. OE’s and Penn’s 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 was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, 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. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree are currently estimated to be $1.3 billion for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above. On September 8, 2008, the Environmental Enforcement Section of the DOJ sent a letter to OE regarding its view that the company was not in compliance with the Sammis NSR Litigation consent decree because the installation of an SNCR at Eastlake Unit 5 was not completed by December 31, 2006. However, the DOJ acknowledged that stipulated penalties could not apply under the terms of the Sammis NSR Litigation consent decree because Eastlake Unit 5 was idled on December 31, 2006 pending installation of the SNCR and advised that it had exercised its discretion not to seek any other penalties for this alleged non-compliance. OE disputed the DOJ's interpretation of the consent decree in a letter dated September 22, 2008. Although the Eastlake Unit 5 issue is no longer active, OE filed a dispute resolution petition on October 23, 2008, with the United States District Court for the Southern District of Ohio, due to potential impacts on its compliance decisions with respect to Burger Units 4 and 5. Under the Sammis NSR Litigation consent decree, an election to repower by December 31, 2012, install flue gas desulfurization (FGD) by December 31, 2010, or permanently shut down those units by December 31, 2010, is due no later than December 31, 2008. Although FirstEnergy will meet the December 31, 2008 deadline for making an election, one potential compliance option, should FGD be elected, would be to idle Burger Units 4 and 5 on December 31, 2010 pending completion of the FGD installation. Thus, OE is seeking a determination by the Court whether this approach is indeed in compliance with the terms of the Sammis NSR Litigation consent decree. The Court has scheduled a hearing on OE’s dispute resolution petition for November 17, 2008. The outcome of this dispute resolution process could have an impact on the option FirstEnergy ultimately elects with respect to Burger Units 4 and 5.

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. Subsequently, on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR. The EPA has not yet issued a final regulation. FGCO’s future cost of compliance with those regulations may be substantial and will depend on how they are ultimately implemented.

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 CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the 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 October 18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim.

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In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.

On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the United States District Court. ~~Although it remains liable for civil~~The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. By letter dated October 1, 2008, New Jersey informed the Court of its intent to file an amended complaint. Met-Ed is unable to predict the outcome of this matter.

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On June 11, 2008, the EPA issued a Notice and Finding of Violation to MEW alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or ~~criminal penalties~~permitting under the CAA's prevention of significant deterioration program. MEW is seeking indemnification from Penelec, the co-owner (along with New York State Electric and ~~fines that may be assessed relating to events~~Gas Company) and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from MEW is disputed. Penelec is unable to predict the ~~sale~~outcome of this matter.

On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the ~~Portland Station in 1999, Met-Ed~~CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an ACO modifying that request and setting forth a schedule for FGCO’s response. FGCO complied with the modified schedule and otherwise intends to fully comply with the ACO, but, at this time, is ~~indemnified by Sithe Energy against any other liability arising under~~unable to predict the outcome of this matter.

On August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether ~~it arises out~~these generating sources are complying with the NSR provisions of ~~pre-1999 or post-1999 events.~~the CAA. FirstEnergy intends to fully comply with the EPA’s information request, but, at this time, is unable to predict the outcome of this matter.

National Ambient Air Quality Standards (Applicable to FES)

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 ~~requires~~would have required 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 generation facilities will be subject to caps on SO~~2 ~~and NO~~X ~~emissions. According to the EPA, SO~~2 ~~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,~~, ultimately capping SO2 emissions in affected states to just 2.5 million tons ~~annually.~~annually and 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 NO~~X ~~cap of~~to just 1.3 million tons annually. CAIR ~~has been~~was challenged in the United States Court of Appeals for the District of ~~Columbia.~~Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” The Court ruling also vacated the CAIR regional cap and trade requirements for SO2 and NOX, which is currently not expected to, but may, materially impair the value of emissions allowances obtained for future compliance. On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On October 21, 2008, the Court ordered the parties who appealed CAIR to file responses to the rehearing petitions by November 5, 2008 and directed them to address (1) whether any party is seeking vacatur of CAIR and (2) whether the Court should stay its vacatur of CAIR until EPA promulgates a revised rule. The future cost of compliance with these regulations may be substantial and ~~may~~will depend on the ~~outcome of this litigation and how CAIR is ultimately implemented.~~Court’s ruling on rehearing, as well as the action taken by the EPA or Congress in response to the Court’s ruling.

Mercury Emissions (Applicable to FES)

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, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the ~~court~~Court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a ~~cap and trade~~cap-and-trade program. The EPA ~~must now seek further judicial~~petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of ~~that~~the Court’s ruling vacating CAMR. The Supreme Court could grant the EPA’s petition and alter some or all of the lower Court’s decision, or the EPA could take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.

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. 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 Bruce Mansfield Plant, FES’ only Pennsylvania coal-fired power plant, until 2015, if at all.

~~W. H. Sammis Plant~~ ~~(Applicable to FES, OE and Penn)~~

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W.H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case, along with seven other similar cases, are referred to as the NSR cases.

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 SO~~2 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 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, 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 consent decree are currently estimated to be $1.3 billion for FGCO for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.

90107

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. Subsequently, on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR. The EPA has not yet issued a final regulation. FGCO’s future cost of compliance with those regulations may be substantial and will depend on how they are ultimately implemented.

Climate Change (Applicable to FES)

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 2012. The United States signed the Kyoto Protocol in 1998 but it ~~failed to receive the two-thirds vote required~~was never submitted 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. Also, in an April 16, 2008 speech, President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, 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.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the Senate ~~Environmental~~Environment and Public Works ~~Committees have~~Committee has passed one such bill. 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 CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On July 11, 2008, the EPA released an Advance Notice of Proposed Rulemaking, soliciting input from the public on the effects of climate change and the potential ramifications of regulation of CO2 under the CAA.

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 (Applicable to FES)

Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to ~~FES’~~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 United States 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 and eliminated the restoration option from the 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. On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review ~~certain aspects~~one significant aspect of the Second ~~Circuit’s decision. FirstEnergy~~Circuit Court’s opinion which is whether Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. Oral argument before the Supreme Court is scheduled for December 2, 2008. FES is studying various control options and their costs and effectiveness. Depending on the results of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising ~~BPJ,~~best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

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Regulation of Hazardous Waste (Applicable to FES and each of the ~~Companies)~~Utilities)

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 non-hazardous waste.

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Under NRC regulations, ~~FES and the Companies~~FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of ~~March 31,~~September 30, 2008, ~~FES and the Companies~~FirstEnergy had approximately ~~$2.0~~$1.9 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $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 FirstEnergy ~~and FES~~ (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.

The ~~Companies~~Utilities have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site may be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of ~~March 31,~~September 30, 2008, based on estimates of the total costs of cleanup, the ~~Companies'~~Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately ~~$92~~$94 million (JCP&L - ~~$65~~$68 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - ~~$25~~$24 million) have been accrued through ~~March 31,~~September 30, 2008. Included in the total for JCP&L are accrued liabilities of approximately ~~$56~~$57 million for environmental remediation of former manufactured gas plants in New ~~Jersey;~~Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

Other Legal Proceedings

Power Outages and Related Litigation (Applicable to JCP&L)

In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.

In August 2002, the trial ~~court~~Court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial ~~court~~Court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings are continuing in the Superior Court and a case management conference with the presiding Judge ~~is scheduled for~~was held on June 13, 2008. At that conference, the plaintiffs stated their intent to drop their efforts to create a class-wide damage model and, instead of dismissing the class action, expressed their desire for a bifurcated trial on liability and damages. The judge directed the plaintiffs to indicate, on or before August 22, 2008, how they intend to proceed under this scenario. Thereafter, the judge expects to hold another pretrial conference to address plaintiffs' proposed procedure. JCP&L has received the plaintiffs’ proposed plan of action, and intends to file its objection to the proposed plan, and also file a renewed motion to decertify the class. JCP&L is defending this ~~class~~ action but is unable to predict the ~~outcome of this matter.~~outcome. No liability has been accrued as of ~~March 31,~~September 30, 2008.

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Nuclear Plant Matters (Applicable to FES)

On May 14, 2007, the Office of Enforcement of the NRC issued a DFI to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was 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 DFI 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 FirstEnergy’s other nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the DFI response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC has conducted the employee training required by the confirmatory order and a consultant has performed follow-up reviews to ensure the effectiveness of that training. The NRC continues to monitor FENOC’s compliance with ~~these~~all the commitments made in the confirmatory order.

In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The NRC is ~~subject~~required by statute to ~~future~~provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. On September 24, 2008, the NRC ~~review.~~issued a draft supplemental Environmental Impact Statement for Beaver Valley. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively.

Other Legal Matters (Applicable to OE, JCP&L and FES)

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to ~~FirstEnergy's~~ normal business operations pending against ~~FirstEnergy~~FES and ~~its subsidiaries.~~the Utilities. 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 W.H. Sammis Plant 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 April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint, which OE opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their ~~complaint.~~complaint and oral argument was held on November 5, 2008.

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district ~~court~~Court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. A final order identifying the individual damage amounts was issued on October 31, 2007. The award appeal process was initiated. The union filed a motion with the federal ~~court~~Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. The ~~court held a scheduling conference in April 2008 where it set a briefing schedule with all briefs~~Court has yet to ~~be concluded by July 2008.~~render its decision. JCP&L recognized a liability for the potential $16 million award in 2005.

The union employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. The parties are continuing to bargain with the assistance of a federal mediator. ~~FirstEnergy~~FES has a strike mitigation plan ready in the event of a strike.

~~FirstEnergy accrues~~FES and the Utilities accrue legal liabilities only when ~~it concludes~~they conclude that it is probable that ~~it has~~they have an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that ~~FirstEnergy or its subsidiaries~~FES and the Utilities have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect ~~on FirstEnergy's or its subsidiaries'~~their financial condition, results of operations and cash flows.

93110

New Accounting Standards and Interpretations (Applicable to FES and each of the ~~Companies)~~Utilities)

SFAS 141(R) – “Business Combinations”

In December 2007, the FASB issued SFAS 141(R), ~~which~~which: (i) requires the acquiring entity in a business combination to recognize all ~~the~~ assets acquired and liabilities assumed in the transaction; (ii) establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and (iii) requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. ~~SFAS 141(R) attempts to reduce the complexity of existing GAAP related to business combinations.~~ The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by ~~FES or any of the Companies~~FirstEnergy that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in deferred tax valuation allowances and income tax uncertainties made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. ~~FES~~Under SFAS 141(R), adjustments to the acquired entity’s deferred tax assets and uncertain tax position balances occurring outside the ~~Companies are currently evaluating the~~measurement period will be recorded as a component of income tax expense, rather than goodwill. The impact of ~~adopting~~FirstEnergy’s application of this Standard ~~on their financial statements.~~in periods after implementation will be dependent upon acquisitions at that time.

SFAS 160 - ~~“Noncontrolling~~“Non-controlling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”

In December 2007, the FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statement is not expected to have a material impact on FES’ or the ~~Companies’~~Utilities’ financial statements.

SFAS 161 - “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133”

In March 2008, the FASB issued SFAS 161 ~~which~~that enhances the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. ~~This disclosure better conveys the purpose of derivative use in terms of the risks that the entity is intending to manage.~~ The FASB believes ~~disclosing~~that additional required disclosure of the fair values of derivative instruments and their gains and losses in a tabular format ~~is designed to~~will provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide information on the potential effect on an entity’s liquidity from using derivatives. ~~Finally, this~~This Statement also requires cross-referencing within the footnotes ~~which is intended~~ to help users of financial statements locate important information about derivative instruments. The Statement is effective for reporting periods beginning after November 15, 2008. FES ~~and the Companies are currently evaluating the impact of adopting~~expects this Standard ~~on their financial statements.~~to increase its disclosure requirements for derivative instruments and hedging activities.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. ORGANIZATION AND BASIS OF PRESENTATION

FirstEnergy is a diversified energy company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and its subsidiaries FGCO and NGC, and FESC.

FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, the FERC and, as applicable, the PUCO, the PPUC and the NJBPU. 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 the combined Annual Report on Form 10-K for the year ended December 31, 2007 for FirstEnergy, FES and the ~~Companies.~~Utilities. The consolidated unaudited financial statements of FirstEnergy, FES and each of the ~~Companies~~Utilities reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 8)9) when it is determined to be the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income.

The consolidated financial statements as of ~~March 31,~~September 30, 2008 and for the three-month and nine-month periods ended ~~March 31,~~September 30, 2008 and 2007, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated ~~May 7,~~November 6, 2008) is included herein. The report of PricewaterhouseCoopers LLP states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act of 1933.

2. EARNINGS PER SHARE

Basic earnings per share of common stock is computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. ~~The pool of stock-based compensation tax benefits is calculated in accordance with SFAS 123(R).~~ On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock through an accelerated share repurchase program at an initial price of approximately $900 million. A final purchase price adjustment of $51 million was settled in cash on December 13, 2007. The following table reconciles basic and diluted earnings per share of common stock:

Reconciliation of Basic and Diluted
Three Months Ended
March 31,

Earnings per Share of Common Stock 2008 2007

(In millions, except
per share amounts)
Net income $ 276 $ 290

Average shares of common stock outstanding – Basic 304 314
Assumed exercise of dilutive stock options and awards 3 2
Average shares of common stock outstanding – Dilutive 307 316

Basic earnings per share of common stock $ 0.91 $ 0.92
Diluted earnings per share of common stock $ 0.90 $ 0.92

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	Three Months				Nine Months
	Ended September 30				Ended September 30
Reconciliation of Basic and Diluted Earnings per Share	2008		2007		2008		2007
	(In millions, except per share amounts)

Net income	$	471	$	413	$	1,010	$	1,041

Average shares of common stock outstanding – Basic		304		304		304		307
Assumed exercise of dilutive stock options and awards		3		3		3		4
Average shares of common stock outstanding – Dilutive		307		307		307		311

Basic earnings per share	$	1.55	$	1.36	$	3.32	$	3.39
Diluted earnings per share	$	1.54	$	1.34	$	3.29	$	3.35

3. GOODWILL

In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment at least annually and more frequently as indicators of impairment arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment is indicated, FirstEnergy recognizes a loss – calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill.

FirstEnergy's 2008 annual review was completed in the third quarter of 2008 with no impairment indicated. As discussed in Note 12(B), the Ohio Companies filed a comprehensive ESP and MRO with the PUCO on July 31, 2008. The annual goodwill impairment analysis assumed management's best estimate of the outcome of those filings. There was no impairment indicated for FirstEnergy and the Ohio Companies based on a probability-weighted outcome of the ESP and MRO proceedings. If the PUCO’s final decision authorizes less revenue recovery than the amounts assumed, an additional impairment analysis would be performed at that time that could result in future goodwill impairment.

FirstEnergy's goodwill primarily relates to its energy delivery services segment. In the first and third quarters of 2008, FirstEnergy adjusted goodwill by $1 million and $23 million, respectively, of the former GPU companies due to the realization of tax benefits that had been reserved under purchase accounting. The following tables reconcile changes to goodwill for the three months and nine months ended September 30, 2008.

Three Months Ended	FirstEnergy			FES		CEI		TE		JCP&L			Met-Ed			Penelec
	(In millions)
Balance as of July 1, 2008	$	5,606		$	24	$	1,689	$	501	$	1,826		$	424		$	778
Adjustments related to GPU acquisition		(23	)		-		-		-		(11	)		(5	)		(7	)
Balance as of September 30, 2008	$	5,583		$	24	$	1,689	$	501	$	1,815		$	419		$	771

Nine Months Ended	FirstEnergy			FES		CEI		TE		JCP&L			Met-Ed			Penelec
	(In millions)
Balance as of January 1, 2008	$	5,607		$	24	$	1,689	$	501	$	1,826		$	425		$	778
Adjustments related to GPU acquisition		(24	)		-		-		-		(11	)		(6	)		(7	)
Balance as of September 30, 2008	$	5,583		$	24	$	1,689	$	501	$	1,815		$	419		$	771

4. DIVESTITURES AND DISCONTINUED OPERATIONS

On March 7, 2008, FirstEnergy sold certain telecommunication assets, resulting in a net after-tax gain of $19.3 million. ~~As a result of the sale, FirstEnergy adjusted goodwill by $1 million for the former GPU companies due to the realization of tax benefits that had been reserved in purchase accounting.~~ The sale of assets did not meet the criteria for classification as discontinued operations as of ~~March 31,~~September 30, 2008.

4.5. FAIR VALUE MEASURES

Effective January 1, 2008, FirstEnergy adopted SFAS 157, which provides a framework for measuring fair value under GAAP and, among other things, requires enhanced disclosures about assets and liabilities recognized at fair value. FirstEnergy also adopted SFAS 159 on January 1, 2008, which provides the option to measure certain financial assets and financial liabilities at fair value. FirstEnergy has analyzed its financial assets and financial liabilities within the scope of SFAS 159 and, as of ~~March 31,~~September 30, 2008, has elected not to record eligible assets and liabilities at fair value.

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As defined in SFAS 157, fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between willing market participants on the measurement date. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those where transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. FirstEnergy’s Level 1 assets and liabilities primarily consist of exchange-traded derivatives and equity securities listed on active exchanges that are held in various trusts.

Level 2 – Pricing inputs are either directly or indirectly observable in the market as of the reporting date, other than quoted prices in active markets included in Level 1. FirstEnergy’s Level 2 ~~consists~~assets and liabilities consist primarily of investments in debt securities held in various trusts and commodity forwards. Additionally, Level 2 includes those financial instruments that are valued using models or other valuation methodologies based on assumptions that are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Instruments in this category include non-exchange-traded derivatives such as forwards and certain interest rate swaps.

Level 3 – Pricing inputs include inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. FirstEnergy develops its view of the future market price of key commodities through a combination of market observation and assessment (generally for the short term) and fundamental modeling (generally for the longer term). Key fundamental electricity model inputs are generally directly observable in the market or derived from publicly available historic and forecast data. Some key inputs reflect forecasts published by industry leading consultants who generally employ similar fundamental modeling approaches. Fundamental model inputs and results, as well as the selection of consultants, reflect the consensus of appropriate FirstEnergy management. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. FirstEnergy’s Level 3 instruments consist of NUG contracts.

FirstEnergy utilizes market data and assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs.

The following table sets forth FirstEnergy’s financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of ~~March 31,~~September 30, 2008. As required by SFAS 157, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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	March 31, 2008								September 30, 2008
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In millions)								(In millions)
Assets:
Derivatives	$	4	$	98	$	-	$	102	$	-	$	45	$	-	$	45
Nuclear decommissioning trusts~~(1)~~		1,070		953		-		2,023		761		1,112		-		1,873
Other investments~~(2)~~		21		303		-		324		19		312		-		331
Total	$	1,095	$	1,354	$	-	$	2,449	$	780	$	1,469	$	-	$	2,249

Liabilities:
Derivatives	$	-	$	98	$	-	$	98	$	8	$	19	$	-	$	27
NUG contracts~~(3)~~(1)		-		-		682		682		-		-		603		603
Total	$	-	$	98	$	682	$	780	$	8	$	19	$	603	$	630

FES, through potential participation in utility sponsored competitive power procurement processes (including those of affiliates) or through forward hedging transactions and as a consequence of future power price movements, could be required to post significantly higher collateral to support its power transactions.

~~A utility~~

Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement 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 sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The fixed price under the agreement is expected to remain below wholesale market prices during the term of the agreement. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for their fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC. See FERC Matters below for a description of the Third Restated Partial Requirements Agreement, executed by the parties on October 31, 2008, that limits the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the event of a third party supplier default, the increased costs to Met-Ed and Penelec could be material.

~~110~~

Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.

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The PPUC entered its opinion and order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes to NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million).

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the ~~court~~Court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. ~~Oral arguments are scheduled to take place~~The Commonwealth Court issued its decision on November 7, 2008, which affirmed the PPUC's January 11, 2007 order in ~~September 2008. If Met-Ed~~all respects, including the deferral and ~~Penelec do not prevail on the issue~~recovery of transmission and congestion ~~it could have a material adverse effect on the results of operations of Met-Ed, Penelec and FirstEnergy.~~related costs.

On ~~April 14,~~May 22, 2008, the PPUC approved the Met-Ed and Penelec ~~filed~~ annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. Various intervenors filed complaints against Met-Ed’s and Penelec’s TSC filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing the company to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted with hearings for both companies scheduled to begin in January 2009. The ~~proposed~~ TSCs include a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed ~~has proposed~~received approval from the PPUC of a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.

On March 13, 2008, the PPUC approved the residential procurement process in Penn’s Joint Petition for Settlement. This RFP process calls for load-following, full-requirements contracts for default service procurement for residential customers for the period covering June 1, 2008 through May 31, 2011. The PPUC had previously approved the default service procurement processes for commercial and industrial customers. The default service procurement for small commercial customers was conducted through multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the two RFPs for small commercial load were approved by the PPUC on February 22, 2008, and March 20, 2008. On March 28, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for small commercial customers which the PPUC then certified on April 4, 2008. On April 14, 2008, the first RFP for residential customers’ load was held consisting of tranches for both 12 and 24-month supply. The PPUC approved the bids on April 16, 2008. The second RFP is scheduled to be held on May 14, 2008, after which time the PPUC is expected to approve the new rates to go into effect June 1, 2008.

~~111~~

On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. ~~Neither chamber has formally considered~~As part of the ~~other’s bill.~~2008 state budget negotiations, the Alternative Energy Investment Act was enacted creating a $650 million alternative energy fund to increase the development and use of alternative and renewable energy, improve energy efficiency and reduce energy consumption. On ~~February 12,~~October 8, 2008, ~~the Pennsylvania House passed~~ House Bill 2200 as amended, was voted out of the full Senate and adopted by the House. On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which ~~provides for~~becomes effective on November 14, 2008 as Act 129 of 2008. The bill addresses issues such as: energy efficiency and ~~demand management programs and targets as well as the installation of~~peak load reduction; generation procurement; time-of-use rates; smart meters ~~within ten years. Other~~and alternative energy. Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009 and a smart meter procurement and installation plan by August 14, 2009.

Major provisions of the legislation ~~has been introduced to address generation~~include:

·	power acquired by utilities to serve customers after rate caps expire will be procured through a competitive procurement process that must include a mix of long-term and short-term contracts and spot market purchases;

·	the competitive procurement process must be approved by the PPUC and may include auctions, request for proposals, and/or bilateral agreements;

·	utilities must provide for the installation of smart meter technology within 15 years;

·	a minimum reduction in peak demand of 4.5% by May 31, 2013;

131

·	minimum reductions in energy consumption of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and

·	an expanded definition of alternative energy to include additional types of hydroelectric and biomass facilities.

The current legislative session ends on November 30, 2008, and any pending legislation addressing rate mitigation and the expiration of rate caps ~~conservation~~not enacted by that time must be re-introduced in order to be considered in the next legislative session which begins in January 2009. While the form and ~~renewable energy. The final form~~impact of ~~this pending~~such legislation is ~~uncertain. Consequently, FirstEnergy is unable~~uncertain, several legislators and the Governor have indicated their intent to ~~predict what impact, if any, such legislation may have~~address these issues next year.

On September 25, 2008, Met-Ed and Penelec filed for Commission approval of a Voluntary Prepayment Plan that would provide an opportunity for residential and small commercial customers to pre-pay an amount, which would earn interest at 7.5%, on ~~its operations.~~their monthly electric bills in 2009 and 2010, to be used to reduce electric rates in 2011 and 2012. Met-Ed and Penelec also intend to file a generation procurement plan for 2011 and beyond with the PPUC later this year or early next year. Met-Ed and Penelec requested that the PPUC approve the Plan by mid-December 2008 and are currently awaiting a decision.

(D) NEW JERSEY

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of ~~March 31,~~September 30, 2008, the accumulated deferred cost balance totaled approximately ~~$264~~$210 million.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set.

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. A public hearing on these proposed rules was held on April 23, 2008 ~~with~~and comments from interested parties ~~due on~~were submitted by May ~~16,~~19, 2008.

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in 2006, 2007 and the ~~fall~~first half of ~~2006 and in early 2007.~~2008.

On April 17, 2008, a draft EMP was released for public comment. The ~~draft~~final EMP was issued on October 22, 2008 and establishes ~~four~~five major goals:

·	maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020;

·	reduce peak demand for electricity by 5,700 MW by ~~2020 (amounting to about a 22% reduction in projected demand);~~2020;

·	meet 30% of the state’s electricity needs with renewable energy by 2020;

~~112~~132

·	~~meet 22.5% of~~examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s ~~electricity needs with renewable energy by 2020;~~greenhouse gas targets; and

·	~~develop low carbon emitting, efficient power plants~~invest in innovative clean energy technologies and ~~close~~businesses to stimulate the ~~gap between the supply and demand for electricity.~~industry’s growth in New Jersey.

~~Following the public comment period which is expected to extend into July 2008, a~~The final EMP will ~~be issued to~~ be followed by appropriate legislation and regulation as necessary. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations or those of JCP&L.

On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments that were submitted in September and October 2007. Final regulations (effective upon publication) were published in the New Jersey Register March 17, 2008. Upon preliminary review of the new regulations, FirstEnergy does not expect a material impact on its operations or those of JCP&L.

(E) FERC MATTERS

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate ~~so-called “pancaking” of~~multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered ~~the~~ MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, 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 by year-end 2008. In the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the ~~second quarter~~docket to mitigate the risk of ~~2008.~~lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision.

PJM Transmission Rate Design

On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.

On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce the costs of future transmission ~~revenue recovery~~to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding ~~Judge. The FERC’s action on~~Judge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement ~~agreement is pending.~~subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. The remaining merchant transmission cost allocation issues ~~will proceed to~~were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions are due on November 10, 2008. On February ~~13,~~11, 2008, AEP appealed the FERC’s April 19, 2007 and January 31, 2008 orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit.

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Post Transition Period Rate Design

The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within MISO, and between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of the FERC’s approval, the rates charged to FirstEnergy’s load-serving affiliates for transmission service over existing transmission facilities in MISO and PJM are unchanged. 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 higher transmission facilities across the entire MISO footprint (known as the RECB methodology) be retained.

On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP is ~~pending before the FERC.~~

~~Distribution of MISO Network Service Revenues~~

Effective February 1, 2008, the MISO Transmission Owners Agreement provides for a change in the method of distributing transmission revenues among the transmission owners. MISO and a majority of the MISO transmission owners filed on December 3, 2007 to change the MISO tariff to clarify, for purposes of distributing network transmission revenue to the transmission owners, that all network transmission service revenues, whether collected by MISO or directly by the transmission owner, are included in the revenue distribution calculation. This clarification was necessary because some network transmission service revenues are collected and retained by transmission owners in states where retail choice does not exist, and their “unbundled” retail load is currently exempt from MISO network service charges. The tariff changes filed with the FERC ensure that revenues collected by transmission owners from bundled load are taken into account in the revenue distribution calculation, and that transmission owners with bundled load do not collect more than their revenue requirements. Absent the changes, transmission owners, and ultimately their customers, with unbundled load or in retail choice states, such as ATSI, would subsidize transmission owners with bundled load, who would collect their revenue requirement from bundled load, plus share in revenues collected by MISO from unbundled customers. This would result in a large revenue shortfall for ATSI, which would eventually be passed on to customers in the form of higher transmission rates as calculated pursuant to ATSI’s Attachment O formula under the MISO tariff.

Numerous parties filed in support of the tariff changes, including the public service commissions of Michigan, Ohio and Wisconsin. Ameren filed a protest on December 26, 2007, arguing that the December 3, 2007 filing violates the MISO Transmission Owners’ Agreement as well as an agreement among Ameren (Union Electric), MISO, and the Missouri Public Service Commission, which provides that Union Electric’s bundled load cannot be charged by MISO for network service. On February 2, 2008, the FERC issued an order conditionally accepting the tariff amendment subject to a minor compliance filing, which was made on March 3, 2008. This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement. A rehearing request by Ameren is pending before the FERC.

On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of the MISO Transmission Owners’ Agreement. This request was accepted by the FERC on March 13, 2008. On that same day, MISO and the MISO transmission owners made a filing to amend the Transmission Owners’ Agreement to effectively continue the distribution of transmission revenues that was in effect prior to February 1, 2008. This matter is currently pending before the FERC.

MISO Ancillary Services Market and Balancing Area Consolidation

MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. ~~This filing~~These markets would permit ~~load serving~~generators to sell, and load-serving entities to purchase, their operating reserve requirements in a competitive market. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. ~~MISO has since notified~~Numerous parties filed requests for rehearing on March 26, 2008. On June 23, 2008, the FERC ~~that the start of its ASM is delayed until September of 2008.~~issued an order granting in part and denying in part rehearing.

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On February 29, 2008, MISO submitted a compliance filing setting forth MISO’s Readiness Advisor ASM and Consolidated Balancing Authority Initiative Verification plan and status and Real-Time Operations ASM Reversion plan. FERC action on this compliance filing remains pending. On March 26, 2008, MISO submitted a tariff filing in compliance with the FERC’s 30-day directives in the February 25 order. Numerous parties submitted comments and protests on April 16, 2008. The FERC issued an order accepting the revisions pending further compliance on June 23, 2008. On April 25, 2008, MISO submitted a tariff filing in compliance with the FERC’s 60-day directives in the February 25 order. FERC action on this compliance filing remains pending. On May 23, 2008, MISO submitted its amended Balancing Authority Agreement. On July 21, 2008, the FERC issued an order conditionally accepting the amended Balancing Authority Agreement and requiring a further compliance filing. On August 19, 2008, MISO submitted its compliance filing to the FERC. On July 25, 2008, MISO submitted another Readiness Certification. The FERC has not yet acted on this submission. MISO announced on August 26, 2008 that the startup of its market is postponed indefinitely. MISO commits to make a filing giving at least sixty days notice of the new effective date. The latest announced effective date for market startup is January 6, 2009.

Interconnection Agreement with AMP-Ohio

On May 29, 2008, TE filed with the FERC a proposed Notice of Cancellation effective midnight December 31, 2008, of the Interconnection Agreement with AMP-Ohio. AMP-Ohio protested this filing. TE also filed a Petition for Declaratory Order seeking a FERC ruling, in the alternative if cancellation is not accepted, of TE's right to file for an increase in rates effective January 1, 2009, for power provided to AMP-Ohio under the Interconnection Agreement. AMP-Ohio filed a pleading agreeing that TE may seek an increase in rates, but arguing that any increase is limited to the cost of generation owned by TE affiliates. On August 18, 2008, the FERC issued an order that suspended the cancellation of the Agreement for five months, to become effective on June 1, 2009, and established expedited hearing procedures on issues raised in the filing and TE’s Petition for Declaratory Order. On October 14, 2008, the parties filed a settlement agreement and mutual notice of cancellation of the Interconnection Agreement effective midnight December 31, 2008. Upon acceptance by the FERC, this filing will terminate the litigation and the Interconnection Agreement, among other effects.

Duquesne’s Request to Withdraw from PJM

On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join ~~the~~ MISO. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. FirstEnergy believes that Duquesne’s filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesne’s proposal. Consequently, FirstEnergy submitted responsive filings that, while conceding Duquesne’s rights to exit PJM, contested various aspects of Duquesne’s proposal. FirstEnergy particularly focused on Duquesne’s proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne’s failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use the Beaver Valley Plant to meet existing commitments in the PJM capacity markets and to serve native load. Other market participants also submitted filings contesting Duquesne’s plans.

On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne zone load-serving entities to pay ~~the~~their PJM capacity obligations through May 31, 2011. The FERC’s order took notice of the numerous transmission and other issues raised by FirstEnergy and other parties to the proceeding, but did not provide any responsive rulings or other guidance. Rather, the FERC ordered Duquesne to make a compliance filing in forty-five days detailing how Duquesne will satisfy its obligations under the PJM Transmission Owners’ Agreement. The FERC likewise directed the MISO to submit detailed plans to integrate Duquesne into the MISO. Finally, the FERC directed MISO and PJM to work together to resolve the substantive and procedural issues implicated by Duquesne’s transition into the MISO. These issues remain unresolved. If Duquesne satisfies all of the obligations set by the FERC, its planned transition date is October 9, 2008.

~~On March 18, 2008, the PJM Power Providers Group filed a request for emergency clarification regarding whether Duquesne-zone generators (including the Beaver Valley Plant) could participate~~

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FirstEnergy desires to continue to use its Duquesne zone generation resources to serve load in ~~PJM’s May 2008 auction for the 2011-2012 RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings.~~PJM. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification ~~wherein~~on whether Duquesne-zone generators could participate in PJM’s May 2008 auction for the 2011-2012 planning year. In the order, the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators ~~can~~could contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with the FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy ~~satisfies~~satisfied the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction. ~~Notwithstanding these events, on April~~

The FERC also directed MISO and PJM to resolve the substantive and procedural issues associated with Duquesne’s transition into MISO. As directed, PJM filed thirteen load-serving entity Capacity Payment Agreements and a Capacity Portability Agreement with the FERC. The Capacity Payment Agreements addressed Duquesne Zone load-serving entity obligations through May 31, 2011 with regards to RPM Capacity while the Capacity Portability Agreement addressed operational issues associated with the portability of such capacity. On September 30, 2008, the FERC approved both agreements, subject to conditions, taking notice of many operational and procedural issues brought forth by FirstEnergy and other market participants.

Several issues surrounding Duquesne’s transition into MISO continue to be contested at the FERC. Specifically, Duquesne’s obligation to pay for transmission expansion costs allocated to the Duquesne zone when they were a member of PJM, and other issues in which market participants wish to be held harmless by Duquesne’s transition. FirstEnergy filed for rehearing on these issues on October 3, 2008. Duquesne’s transition into MISO is also contingent upon the start of MISO’s ancillary services market and consolidation of its balancing authorities, currently scheduled for January 6, 2009.

Complaint against PJM RPM Auction

On May 1,30, 2008, ~~certain members~~a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. Most of the parties comprising the RPM Buyers group were parties to the settlement approved by the FERC that established the RPM. In the complaint, the RPM Buyers request that the total projected payments to RPM sellers for the three auctions at issue be materially reduced. On July 11, 2008, PJM ~~Power Providers Group~~ filed ~~further pleadings~~its answer to the complaint, in which it denied the allegation that the rates are unjust and unreasonable. Also on ~~these issues. On May 2, 2008,~~that date, FirstEnergy filed a ~~responsive pleading. FirstEnergy is participating~~motion to intervene.

On September 19, 2008, the FERC denied the RPM Buyers complaint. However, the FERC did grant the RPM Buyers request for a technical conference to review aspects of the RPM. The FERC also ordered PJM to file on or before December 15, 2008, a report on its progress on contemplating adjustments to the RPM as suggested by the Brattle Group in its report reviewing the ~~May~~RPM. The technical conference will take place in February, 2009. On October 20, 2008, the RPM ~~auction~~Buyers filed a request for rehearing of the ~~2011-2012 RPM delivery year.~~FERC’s September 19, 2008 order.

MISO Resource Adequacy Proposal

MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for ~~load serving~~load-serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for ~~load serving~~load-serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for ~~load serving~~load-serving entities in its state. FirstEnergy ~~generally supports~~believes the proposal ~~as it~~ promotes a mechanism that will result in ~~long-term~~ commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were filed on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, ~~2008.~~2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. AOn May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement ~~is due on or before June 25, 2008.~~

~~Organized Wholesale Power Markets~~

which establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing. On ~~February 21,~~October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a ~~NOPR through which it proposes to adopt~~compliance filing modifying the cost of new rules that it states will “improve operations in organized electric markets, boost competition and bring additional benefits to consumers.” The proposed rule addresses demand response and market pricing during reserve shortages, long-term power contracting, market-monitoring policies, and responsiveness of RTOs and ISOs to stakeholders and customers. FirstEnergy does not believe thatentry penalty. Second, the ~~proposed rule will have a significant impact on its operations. Comments~~FERC conditionally accepted MISO's compliance filing on the ~~NOPR~~qualifications for purchase power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were ~~filed~~directed on ~~April 18, 2008.~~accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. Issuance of these orders is not expected to delay the June 1, 2009 start date for MISO Resource Adequacy.

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~~12.~~Organized Wholesale Power Markets

The FERC issued a final rule on October 17, 2008, amending its regulations to “improve the operation of organized wholesale electric markets in the areas of: (1) demand response and market pricing during periods of operating reserve shortage; (2) long-term power contracting; (3) market-monitoring policies; and (4) the responsiveness of RTOs and ISOs to their customers and other stakeholders.” The RTOs and ISOs were directed to submit amendments to their respective tariffs to address these market operation improvements. The final rule directs RTOs to adopt market rules permitting prices to increase during periods of supply shortages and to permit enhanced participation by demand response resources. It also codifies and defines for the first time the roles and duties of independent market monitors within RTOs. Finally, it adopts requirements for enhanced access by stakeholders to RTO boards of directors. RTOs are directed to make compliance filings six months from the effective date of the final rule. The final rule is not expected to have any material effect on FirstEnergy's operations within MISO and PJM.

FES Sales to Affiliates

On October 24, 2008, FES, on its own behalf and on behalf of its generation-controlling subsidiaries, filed an application with the FERC seeking a waiver of the affiliate sales restrictions between FES and the Ohio Companies. The purpose of the waiver is to ensure that FES will be able to continue supplying a material portion of the electric load requirements of the Ohio Companies in January 2009 pursuant to either an ESP or MRO as filed with the PUCO. FES previously obtained a similar waiver for electricity sales to its affiliates in New Jersey, New York, and Pennsylvania. A ruling by the FERC is expected the week of December 15, 2008.

On October 31, 2008, FES executed a Third Restated Partial Requirements Agreement with Met-Ed, Penelec, and The Waverly Power and Light Company (Waverly) effective November 1, 2008. The Third Restated Partial Requirements Agreement limits the amount of capacity and energy required to be supplied by FES in 2009 and 2010 to roughly two-thirds of these affiliates’ power supply requirements. Met-Ed, Penelec, and Waverly have committed resources in place for the balance of their expected power supply during 2009 and 2010. Under the Third Restated Partial Requirements Agreement, Met-Ed, Penelec, and Waverly are responsible for obtaining additional power supply requirements created by the default or failure of supply of their committed resources. Prices for the power provided by FES were not changed in the Third Restated Partial Requirements Agreement.

13. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 141(R) – “Business Combinations”

In December 2007, the FASB issued SFAS 141(R), ~~which~~which: (i) requires the acquiring entity in a business combination to recognize all ~~the~~ assets acquired and liabilities assumed in the transaction; (ii) establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and (iii) requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. ~~SFAS 141(R) attempts to reduce the complexity of existing GAAP related to business combinations.~~ The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FirstEnergy that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in deferred tax valuation allowances and income tax uncertainties made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. ~~FirstEnergy is currently evaluating~~Under SFAS 141(R), adjustments to the acquired entity’s deferred tax assets and uncertain tax position balances occurring outside the measurement period will be recorded as a component of income tax expense, rather than goodwill. The impact of ~~adopting~~FirstEnergy’s application of this Standard ~~on its financial statements.~~in periods after implementation will be dependent upon acquisitions at that time.

SFAS 160 - ~~“Noncontrolling~~“Non-controlling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”

In December 2007, the FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statement is not expected to have a material impact on FirstEnergy’s financial statements.

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SFAS 161 - “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133”

In March 2008, the FASB issued SFAS 161 ~~which requires~~ ~~enhancements to~~ that enhances the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. ~~This disclosure is intended to better convey the purpose of derivatives use in terms of the risks that the entity is intending to manage.~~ The FASB believes ~~disclosing~~that additional required disclosure of the fair values of derivative instruments and their gains and losses in a tabular format ~~is designed to~~will provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide ~~financial statement users~~ information on the potential effect on an entity’s liquidity from using derivatives. ~~Finally, this~~This Statement also requires cross-referencing within the footnotes ~~which is intended~~ to help users of financial statements locate important information about derivative instruments. The Statement is effective for reporting periods beginning after November 15, 2008. FirstEnergy ~~is currently evaluating the impact of adopting~~expects this Standard onto increase its ~~financial statements.~~disclosure requirements for derivative instruments and hedging activities.

~~13.~~14. SEGMENT INFORMATION

FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The ~~“Other” segment primarily consists of telecommunications services. The~~ assets and revenues for ~~the~~all other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable operating segments.”

The energy delivery services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems and is responsible for the regulated generation commodity operations of FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. Its revenues are primarily derived from the delivery of electricity, cost recovery of regulatory assets, and default service electric generation sales to non-shopping customers in its Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES under partial requirements purchased power agreements and from non-affiliated power suppliers as well as the net PJM transmission expenses related to the delivery of that generation load.

The competitive energy services segment supplies electric power to its electric utility affiliates, provides competitive ~~electric~~electricity sales primarily in Ohio, Pennsylvania, Maryland and Michigan, owns or leases and operates FirstEnergy’s generating facilities and purchases electricity to meet its sales obligations. The segment's net income is primarily derived from the affiliated company PSA sales and the non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver electricity to the segment’s customers. The segment’s internal revenues represent the affiliated company PSA sales.

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The Ohio transitional generation services segment represents the regulated generation commodity operations of FirstEnergy’s Ohio electric utility subsidiaries. Its revenues are primarily derived from electric generation sales to non-shopping customers under the PLR obligations of the Ohio Companies. Its results reflect the purchase of electricity from the competitive energy services segment through full-requirements PSA arrangements, the deferral and amortization of certain fuel costs authorized for recovery by the energy delivery services segment and the net MISO transmission revenues and expenses related to the delivery of generation load. This segment’s total assets consist of accounts receivable for generation revenues from retail customers.

Segment Financial Information
Ohio
Energy Competitive Transitional
Delivery Energy Generation Reconciling
Three Months Ended Services Services Services Other Adjustments Consolidated
(In millions)
March 31, 2008
External revenues $ 2,212 $ 329 $ 707 $ 40 $ (11 ) $ 3,277
Internal revenues - 776 - - (776 ) -
Total revenues 2,212 1,105 707 40 (787 ) 3,277
Depreciation and amortization 255 53 4 - 5 317
Investment income 45 (6 ) 1 - (23 ) 17
Net interest charges 103 27 - - 41 171
Income taxes 119 58 15 14 (19 ) 187
Net income 179 87 23 22 (35 ) 276
Total assets 23,211 8,108 257 281 558 32,415
Total goodwill 5,582 24 - - - 5,606
Property additions 255 462 - 12 (18 ) 711

March 31, 2007
External revenues $ 2,040 $ 321 $ 619 $ 12 $ (19 ) $ 2,973
Internal revenues - 714 - - (714 ) -
Total revenues 2,040 1,035 619 12 (733 ) 2,973
Depreciation and amortization 220 51 (15 ) 1 6 263
Investment income 70 3 1 - (41 ) 33
Net interest charges 107 49 1 2 21 180
Income taxes 148 65 15 5 (33 ) 200
Net income 218 98 24 1 (51 ) 290
Total assets 23,526 7,089 246 254 675 31,790
Total goodwill 5,874 24 - - - 5,898
Property additions 155 124 - 1 16 296
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Segment Financial Information
						Ohio
	Energy		Competitive			Transitional
	Delivery		Energy			Generation						Reconciling
Three Months Ended	Services		Services			Services			Other			Adjustments			Consolidated
	(In millions)
September 30, 2008
External revenues	$	2,657	$	460		$	813		$	5		$	(31	)	$	3,904
Internal revenues		-		786			-			-			(786	)		-
Total revenues		2,657		1,246			813			5			(817	)		3,904
Depreciation and amortization		286		67			46			1			1			401
Investment income		48		13			1			-			(22	)		40
Net interest charges		101		31			1			-			44			177
Income taxes		188		109			14			(46	)		(27	)		238
Net income		283		164			19			48			(43	)		471
Total assets		23,088		9,360			270			457			387			33,562
Total goodwill		5,559		24			-			-			-			5,583
Property additions		170		285			-			85			20			560

September 30, 2007
External revenues	$	2,520	$	370		$	723		$	9		$	19		$	3,641
Internal revenues		-		806			-			-			(806	)		-
Total revenues		2,520		1,176			723			9			(787	)		3,641
Depreciation and amortization		299		51			(16	)		1			8			343
Investment income		58		5			-			1			(34	)		30
Net interest charges		117		39			-			1			37			194
Income taxes		175		99			11			(2	)		(10	)		273
Net income		269		148			16			6			(26	)		413
Total assets		23,308		7,182			268			232			663			31,653
Total goodwill		5,585		24			-			-			-			5,609
Property additions		209		199			-			3			19			430

Nine Months Ended

September 30, 2008
External revenues	$	7,051	$	1,164		$	2,203		$	65		$	(57	)	$	10,426
Internal revenues		-		2,266			-			-			(2,266	)		-
Total revenues		7,051		3,430			2,203			65			(2,323	)		10,426
Depreciation and amortization		782		179			61			2			10			1,034
Investment income		133		(1	)		1			6			(66	)		73
Net interest charges		303		86			1			-			133			523
Income taxes		436		212			42			(33	)		(72	)		585
Net income		655		317			62			96			(120	)		1,010
Total assets		23,088		9,360			270			457			387			33,562
Total goodwill		5,559		24			-			-			-			5,583
Property additions		621		1,430			-			106			20			2,177

September 30, 2007
External revenues	$	6,655	$	1,089		$	1,968		$	29		$	(18	)	$	9,723
Internal revenues		-		2,210			-			-			(2,210	)		-
Total revenues		6,655		3,299			1,968			29			(2,228	)		9,723
Depreciation and amortization		767		153			(80	)		3			20			863
Investment income		190		13			1			1			(112	)		93
Net interest charges		340		131			1			3			97			572
Income taxes		464		259			46			-			(74	)		695
Net income		695		388			69			13			(124	)		1,041
Total assets		23,308		7,182			268			232			663			31,653
Total goodwill		5,585		24			-			-			-			5,609
Property additions		609		462			-			6			50			1,127

Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consist of interest expense related to holding company debt, corporate support services revenues and expenses and elimination of intersegment transactions.

~~14. SUPPLEMENTAL GUARANTOR INFORMATION~~

138

15. SUPPLEMENTAL GUARANTOR INFORMATION

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates 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, including FES’ lease guaranty. This transaction is classified as an operating lease under GAAP for FES and FirstEnergy and a financing for FGCO.

The consolidating statements of income for the ~~three months~~three-month and nine-month periods ended ~~March 31,~~September 30, 2008 and 2007, consolidating balance sheets as of ~~March 31,~~September 30, 2008 and December 31, 2007 and condensed consolidating statements of cash flows for the ~~three~~nine months ended ~~March 31,~~September 30, 2008 and 2007 for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES’ investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.

~~117~~139

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended September 30, 2008	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)

REVENUES	$	1,222,783		$	574,394		$	267,017		$	(822,590	)	$	1,241,604

EXPENSES:
Fuel		8,177			307,646			34,123			-			349,946
Purchased power from non-affiliates		221,493			-			-			-			221,493
Purchased power from affiliates		815,243			7,347			15,821			(822,590	)		15,821
Other operating expenses		35,596			110,701			120,697			12,190			279,184
Provision for depreciation		1,978			33,432			30,559			(1,336	)		64,633
General taxes		4,829			10,768			6,139			-			21,736
Total expenses		1,087,316			469,894			207,339			(811,736	)		952,813
		-			-			-			-
OPERATING INCOME		135,467			104,500			59,678			(10,854	)		288,791

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		102,777			(515	)		13,287			(97,122	)		18,427
Interest expense - affiliates		(120	)		(4,963	)		(2,932	)		-			(8,015	)
Interest expense - other		(8,464	)		(23,447	)		(17,183	)		16,325			(32,769	)
Capitalized interest		41			11,376			978			-			12,395
Total other income (expense)		94,234			(17,549	)		(5,850	)		(80,797	)		(9,962	)

INCOME BEFORE INCOME TAXES		229,701			86,951			53,828			(91,651	)		278,829

INCOME TAXES		44,046			31,863			14,995			2,270			93,174

NET INCOME	$	185,655		$	55,088		$	38,833		$	(93,921	)	$	185,655

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended March 31, 2008 FES FGCO NGC Eliminations Consolidated
(In thousands)

REVENUES $ 1,099,848 $ 567,701 $ 325,684 $ (894,117 ) $ 1,099,116

EXPENSES:
Fuel 2,138 291,239 28,312 - 321,689
Purchased power from non-affiliates 206,724 - - - 206,724
Purchased power from affiliates 891,979 2,138 25,485 (894,117 ) 25,485
Other operating expenses 37,596 107,167 139,595 12,188 296,546
Provision for depreciation 307 26,599 24,194 (1,358 ) 49,742
General taxes 5,415 11,570 6,212 - 23,197
Total expenses 1,144,159 438,713 223,798 (883,287 ) 923,383

OPERATING INCOME (LOSS) (44,311 ) 128,988 101,886 (10,830 ) 175,733

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees 121,725 (1,208 ) (6,537 ) (116,884 ) (2,904 )
Interest expense to affiliates (82 ) (5,289 ) (1,839 ) - (7,210 )
Interest expense - other (3,978 ) (25,968 ) (11,018 ) 16,429 (24,535 )
Capitalized interest 21 6,228 414 - 6,663
Total other income (expense) 117,686 (26,237 ) (18,980 ) (100,455 ) (27,986 )

INCOME BEFORE INCOME TAXES 73,375 102,751 82,906 (111,285 ) 147,747

INCOME TAXES (BENEFIT) (16,609 ) 39,285 32,764 2,323 57,763

NET INCOME $ 89,984 $ 63,466 $ 50,142 $ (113,608 ) $ 89,984

~~118~~140

FIRSTENERGY SOLUTIONS CORP.	FIRSTENERGY SOLUTIONS CORP.																FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME	CONSOLIDATING STATEMENTS OF INCOME																CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)	(Unaudited)																(Unaudited)

For the Three Months Ended March 31, 2007		FES			FGCO			NGC			Eliminations			Consolidated
For the Three Months Ended September 30, 2007																		FES			FGCO			NGC			Eliminations			Consolidated
		(In thousands)																(In thousands)

REVENUES		$	1,019,387		$	551,355		$	234,091		$	(786,540	)	$	1,018,293			$	1,180,449		$	496,204		$	280,072		$	(785,817	)	$	1,170,908

EXPENSES:
Fuel			2,367			201,231			29,937			-			233,535				10,944			261,759			29,083			-			301,786
Purchased power from non-affiliates			186,203			2,367			-			(2,367	)		186,203				228,755			-			-			-			228,755
Purchased power from affiliates			784,172			59,069			17,415			(784,173	)		76,483				774,873			57,927			15,525			(785,817	)		62,508
Other operating expenses			51,249			99,095			113,252			-			263,596				41,828			75,985			117,220			-			235,033
Provision for depreciation			453			24,936			22,621			-			48,010				650			24,669			23,181			-			48,500
General taxes			4,934			10,568			6,216			-			21,718				5,406			11,788			5,048			-			22,242
Total expenses			1,029,378			397,266			189,441			(786,540	)		829,545				1,062,456			432,128			190,057			(785,817	)		898,824

OPERATING INCOME (LOSS)			(9,991	)		154,089			44,650			-			188,748
OPERATING INCOME																			117,993			64,076			90,015			-			272,084

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
Miscellaneous income, including
net income from equity investees			113,948			916			5,200			(100,332	)		19,732				82,870			2,375			3,935			(76,525	)		12,655
Interest expense to affiliates			-			(24,331	)		(5,115	)		-			(29,446	)
Interest expense - affiliates																			(676	)		(4,769	)		(4,196	)		-			(9,641	)
Interest expense - other			(1,385	)		(6,760	)		(9,213	)		-			(17,358	)			(808	)		(21,274	)		(9,712	)		-			(31,794	)
Capitalized interest			5			2,099			1,105			-			3,209				9			3,889			1,233			-			5,131
Total other income (expense)			112,568			(28,076	)		(8,023	)		(100,332	)		(23,863	)			81,395			(19,779	)		(8,740	)		(76,525	)		(23,649	)

INCOME BEFORE INCOME TAXES			102,577			126,013			36,627			(100,332	)		164,885				199,388			44,297			81,275			(76,525	)		248,435

INCOME TAXES			73			49,289			13,019			-			62,381				44,624			19,850			29,197			-			93,671

NET INCOME		$	102,504		$	76,724		$	23,608		$	(100,332	)	$	102,504			$	154,764		$	24,447		$	52,078		$	(76,525	)	$	154,764

~~119~~141

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of March 31, 2008 FES FGCO NGC Eliminations Consolidated
(In thousands)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents $ 2 $ - $ - $ - $ 2
Receivables-
Customers 125,116 - - - 125,116
Associated companies 285,350 231,049 96,852 (295,511 ) 317,740
Other 1,174 1,050 - 2,224
Notes receivable from associated companies 668,376 - 69,011 - 737,387
Materials and supplies, at average cost 2,849 264,501 207,275 - 474,625
Prepayments and other 107,798 26,208 1,728 - 135,734
1,190,665 522,808 374,866 (295,511 ) 1,792,828

PROPERTY, PLANT AND EQUIPMENT:
In service 35,302 5,359,381 3,700,973 (391,896 ) 8,703,760
Less - Accumulated provision for depreciation 7,810 2,655,103 1,537,747 (168,115 ) 4,032,545
27,492 2,704,278 2,163,226 (223,781 ) 4,671,215
Construction work in progress 10,792 881,899 165,389 - 1,058,080
38,284 3,586,177 2,328,615 (223,781 ) 5,729,295

OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts - - 1,263,338 - 1,263,338
Long-term notes receivable from associated companies - - 62,900 - 62,900
Investment in associated companies 2,598,022 - - (2,598,022 ) -
Other 2,529 21,657 202 - 24,388
2,600,551 21,657 1,326,440 (2,598,022 ) 1,350,626

DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes 10,518 495,131 - (248,666 ) 256,983
Lease assignment receivable from associated companies - 67,256 - - 67,256
Goodwill 24,248 - - 24,248
Property taxes - 25,007 22,767 - 47,774
Pension assets 3,214 12,856 - - 16,070
Unamortized sale and leaseback costs - 38,120 - 47,575 85,695
Other 18,177 49,393 5,188 (37,939 ) 34,819
56,157 687,763 27,955 (239,030 ) 532,845
$ 3,885,657 $ 4,818,405 $ 4,057,876 $ (3,356,344 ) $ 9,405,594

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt $ - $ 738,087 $ 887,265 $ (16,896 ) $ 1,608,456
Notes payable-
Associated companies - 885,760 260,199 - 1,145,959
Other 700,000 - - - 700,000
Accounts payable-
Associated companies 554,844 1,419 119,773 (270,368 ) 405,668
Other 55,614 130,090 - - 185,704
Accrued taxes 3,378 116,383 47,292 (24,219 ) 142,834
Other 85,100 107,791 9,731 45,484 248,106
1,398,936 1,979,530 1,324,260 (265,999 ) 4,436,727

CAPITALIZATION:
Common stockholder's equity 2,460,215 1,011,907 1,579,614 (2,591,521 ) 2,460,215
Long-term debt and other long-term obligations - 1,320,773 62,900 (1,305,717 ) 77,956
2,460,215 2,332,680 1,642,514 (3,897,238 ) 2,538,171

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction - - - 1,051,871 1,051,871
Accumulated deferred income taxes - - 244,978 (244,978 ) -
Accumulated deferred investment tax credits - 35,350 24,619 - 59,969
Asset retirement obligations - 24,947 798,739 - 823,686
Retirement benefits 9,332 56,016 - - 65,348
Property taxes - 25,329 22,766 - 48,095
Lease market valuation liability - 341,881 - - 341,881
Other 17,174 22,672 - - 39,846
26,506 506,195 1,091,102 806,893 2,430,696
$ 3,885,657 $ 4,818,405 $ 4,057,876 $ (3,356,344 ) $ 9,405,594

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Nine Months Ended September 30, 2008	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)

REVENUES	$	3,387,258		$	1,707,320		$	879,729		$	(2,562,309	)	$	3,411,998

EXPENSES:
Fuel		13,920			876,077			92,188			-			982,185
Purchased power from non-affiliates		648,556			-			-			-			648,556
Purchased power from affiliates		2,549,892			12,417			75,834			(2,562,309	)		75,834
Other operating expenses		103,034			342,041			381,826			36,567			863,468
Provision for depreciation		3,885			90,058			80,646			(4,054	)		170,535
General taxes		14,971			33,842			15,915			-			64,728
Total expenses		3,334,258			1,354,435			646,409			(2,529,796	)		2,805,306

OPERATING INCOME		53,000			352,885			233,320			(32,513	)		606,692

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		323,092			(1,234	)		(2,699	)		(305,710	)		13,449
Interest expense - affiliates		(252	)		(18,172	)		(7,529	)		-			(25,953	)
Interest expense - other		(19,105	)		(73,112	)		(38,833	)		49,241			(81,809	)
Capitalized interest		90			27,460			2,049			-			29,599
Total other income (expense)		303,825			(65,058	)		(47,012	)		(256,469	)		(64,714	)

INCOME BEFORE INCOME TAXES		356,825			287,827			186,308			(288,982	)		541,978

INCOME TAXES		13,092			109,615			68,597			6,941			198,245

NET INCOME	$	343,733		$	178,212		$	117,711		$	(295,923	)	$	343,733

~~120~~142

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Nine Months Ended September 30, 2007	FES		��	FGCO			NGC			Eliminations			Consolidated
	(In thousands)

REVENUES	$	3,274,694		$	1,501,112		$	793,255		$	(2,311,129	)	$	3,257,932

EXPENSES:
Fuel		20,824			698,643			84,734			-			804,201
Purchased power from non-affiliates		577,831			-			-			-			577,831
Purchased power from affiliates		2,290,305			176,654			53,746			(2,311,129	)		209,576
Other operating expenses		123,596			240,774			367,404			-			731,774
Provision for depreciation		1,572			74,844			68,614			-			145,030
General taxes		15,942			31,406			17,522			-			64,870
Total expenses		3,030,070			1,222,321			592,020			(2,311,129	)		2,533,282

OPERATING INCOME		244,624			278,791			201,235			-			724,650

OTHER INCOME (EXPENSE):
Miscellaneous income, including
net income from equity investees		271,599			2,669			13,350			(239,862	)		47,756
Interest expense - affiliates		(676	)		(47,090	)		(14,138	)		-			(61,904	)
Interest expense - other		(7,966	)		(34,150	)		(28,729	)		-			(70,845	)
Capitalized interest		20			9,044			3,699			-			12,763
Total other income (expense)		262,977			(69,527	)		(25,818	)		(239,862	)		(72,230	)

INCOME BEFORE INCOME TAXES		507,601			209,264			175,417			(239,862	)		652,420

INCOME TAXES		98,917			82,031			62,788			-			243,736

NET INCOME	$	408,684		$	127,233		$	112,629		$	(239,862	)	$	408,684

143

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of September 30, 2008	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	-	$	-	$	-		$	2
Receivables-
Customers		137,126		-		-		-			137,126
Associated companies		267,777		195,005		100,481		(299,484	)		263,779
Other		910		1,595		20,419		-			22,924
Notes receivable from associated companies		118,526		38,400		-		-			156,926
Materials and supplies, at average cost		3,519		288,623		205,134		-			497,276
Prepayments and other		64,585		84,138		30,807		-			179,530
		592,445		607,761		356,841		(299,484	)		1,257,563

PROPERTY, PLANT AND EQUIPMENT:
In service		108,733		5,413,310		4,704,478		(391,859	)		9,834,662
Less - Accumulated provision for depreciation		10,990		2,712,638		1,658,863		(170,774	)		4,211,717
		97,743		2,700,672		3,045,615		(221,085	)		5,622,945
Construction work in progress		2,827		1,225,381		157,444		-			1,385,652
		100,570		3,926,053		3,203,059		(221,085	)		7,008,597
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,145,384		-			1,145,384
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		3,581,979		-		-		(3,581,979	)		-
Other		2,124		38,247		202		-			40,573
		3,584,103		38,247		1,208,486		(3,581,979	)		1,248,857
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		9,655		471,718		-		(251,032	)		230,341
Lease assignment receivable from associated companies		-		71,356		-		-			71,356
Goodwill		24,248		-		-		-			24,248
Property taxes		-		25,007		22,767		-			47,774
Pension assets		3,208		11,556		-		-			14,764
Unamortized sale and leaseback costs		-		8,445		-		48,920			57,365
Other		18,343		59,511		18,717		(46,869	)		49,702
		55,454		647,593		41,484		(248,981	)		495,550
	$	4,332,572	$	5,219,654	$	4,809,870	$	(4,351,529	)	$	10,010,567
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	4,679	$	873,562	$	1,077,289	$	(17,315	)	$	1,938,215
Short-term borrowings-
Associated companies		-		147,108		164,642		-			311,750
Other		1,000,000		-		-		-			1,000,000
Accounts payable-
Associated companies		276,155		202,678		158,215		(275,601	)		361,447
Other		36,724		126,449		-		-			163,173
Accrued taxes		4,109		88,826		17,661		(29,877	)		80,719
Other		36,491		116,637		26,777		38,009			217,914
		1,358,158		1,555,260		1,444,584		(284,784	)		4,073,218
CAPITALIZATION:
Common stockholder's equity		2,916,934		1,813,911		1,755,054		(3,568,965	)		2,916,934
Long-term debt and other long-term obligations		40,333		1,364,207		451,365		(1,296,982	)		558,923
		2,957,267		3,178,118		2,206,419		(4,865,947	)		3,475,857
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,035,013			1,035,013
Accumulated deferred income taxes		-		-		235,811		(235,811	)		-
Accumulated deferred investment tax credits		-		40,209		23,759		-			63,968
Asset retirement obligations		-		24,148		825,327		-			849,475
Retirement benefits		9,745		57,822		-		-			67,567
Property taxes		-		25,328		22,767		-			48,095
Lease market valuation liability		-		319,129		-		-			319,129
Other		7,402		19,640		51,203		-			78,245
		17,147		486,276		1,158,867		799,202			2,461,492
	$	4,332,572	$	5,219,654	$	4,809,870	$	(4,351,529	)	$	10,010,567

144

FIRSTENERGY SOLUTIONS CORP.	FIRSTENERGY SOLUTIONS CORP.												FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS	CONSOLIDATING BALANCE SHEETS												CONSOLIDATING BALANCE SHEETS
(Unaudited)	(Unaudited)												(Unaudited)

As of December 31, 2007		FES		FGCO		NGC		Eliminations			Consolidated			FES		FGCO		NGC		Eliminations			Consolidated
		(In thousands)												(In thousands)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents		$	2	$	-	$	-	$	-		$	2		$	2	$	-	$	-	$	-		$	2
Receivables-
Customers			133,846		-		-		-			133,846			133,846		-		-		-			133,846
Associated companies			327,715		237,202		98,238		(286,656	)		376,499			327,715		237,202		98,238		(286,656	)		376,499
Other			2,845		978		-		-			3,823			2,845		978		-		-			3,823
Notes receivable from associated companies			23,772		-		69,012		-			92,784			23,772		-		69,012		-			92,784
Materials and supplies, at average cost			195		215,986		210,834		-			427,015			195		215,986		210,834		-			427,015
Prepayments and other			67,981		21,605		2,754		-			92,340			67,981		21,605		2,754		-			92,340
			556,356		475,771		380,838		(286,656	)		1,126,309			556,356		475,771		380,838		(286,656	)		1,126,309

PROPERTY, PLANT AND EQUIPMENT:
In service			25,513		5,065,373		3,595,964		(392,082	)		8,294,768			25,513		5,065,373		3,595,964		(392,082	)		8,294,768
Less - Accumulated provision for depreciation			7,503		2,553,554		1,497,712		(166,756	)		3,892,013			7,503		2,553,554		1,497,712		(166,756	)		3,892,013
			18,010		2,511,819		2,098,252		(225,326	)		4,402,755			18,010		2,511,819		2,098,252		(225,326	)		4,402,755
Construction work in progress			1,176		571,672		188,853		-			761,701			1,176		571,672		188,853		-			761,701
			19,186		3,083,491		2,287,105		(225,326	)		5,164,456			19,186		3,083,491		2,287,105		(225,326	)		5,164,456

OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts			-		-		1,332,913		-			1,332,913			-		-		1,332,913		-			1,332,913
Long-term notes receivable from associated companies			-		-		62,900		-			62,900			-		-		62,900		-			62,900
Investment in associated companies			2,516,838		-		-		(2,516,838	)		-			2,516,838		-		-		(2,516,838	)		-
Other			2,732		37,071		201		-			40,004			2,732		37,071		201		-			40,004
			2,519,570		37,071		1,396,014		(2,516,838	)		1,435,817
															2,519,570		37,071		1,396,014		(2,516,838	)		1,435,817
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes			16,978		522,216		-		(262,271	)		276,923			16,978		522,216		-		(262,271	)		276,923
Lease assignment receivable from associated companies			-		215,258		-		-			215,258			-		215,258		-		-			215,258
Goodwill			24,248		-		-		-			24,248			24,248		-		-		-			24,248
Property taxes			-		25,007		22,767		-			47,774			-		25,007		22,767		-			47,774
Pension asset			3,217		13,506		-		-			16,723			3,217		13,506		-		-			16,723
Unamortized sale and leaseback costs			-		27,597		-		43,206			70,803			-		27,597		-		43,206			70,803
Other			22,956		52,971		6,159		(38,133	)		43,953			22,956		52,971		6,159		(38,133	)		43,953
			67,399		856,555		28,926		(257,198	)		695,682			67,399		856,555		28,926		(257,198	)		695,682
TOTAL ASSETS		$	3,162,511	$	4,452,888	$	4,092,883	$	(3,286,018	)	$	8,422,264
														$	3,162,511	$	4,452,888	$	4,092,883	$	(3,286,018	)	$	8,422,264
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	-	$	596,827	$	861,265	$	(16,896	)	$	1,441,196		$	-	$	596,827	$	861,265	$	(16,896	)	$	1,441,196
Short-term borrowings-
Associated companies			-		238,786		25,278		-			264,064			-		238,786		25,278		-			264,064
Other			300,000		-		-		-			300,000			300,000		-		-		-			300,000
Accounts payable-
Associated companies			287,029		175,965		268,926		(286,656	)		445,264			287,029		175,965		268,926		(286,656	)		445,264
Other			56,194		120,927		-		-			177,121			56,194		120,927		-		-			177,121
Accrued taxes			18,831		125,227		28,229		(836	)		171,451			18,831		125,227		28,229		(836	)		171,451
Other			57,705		131,404		11,972		36,725			237,806			57,705		131,404		11,972		36,725			237,806
			719,759		1,389,136		1,195,670		(267,663	)		3,036,902			719,759		1,389,136		1,195,670		(267,663	)		3,036,902

CAPITALIZATION:
Common stockholder's equity			2,414,231		951,542		1,562,069		(2,513,611	)		2,414,231			2,414,231		951,542		1,562,069		(2,513,611	)		2,414,231
Long-term debt and other long-term obligations			-		1,597,028		242,400		(1,305,716	)		533,712			-		1,597,028		242,400		(1,305,716	)		533,712
			2,414,231		2,548,570		1,804,469		(3,819,327	)		2,947,943
															2,414,231		2,548,570		1,804,469		(3,819,327	)		2,947,943
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction			-		-		-		1,060,119			1,060,119			-		-		-		1,060,119			1,060,119
Accumulated deferred income taxes			-		-		259,147		(259,147	)		-			-		-		259,147		(259,147	)		-
Accumulated deferred investment tax credits			-		36,054		25,062		-			61,116			-		36,054		25,062		-			61,116
Asset retirement obligations			-		24,346		785,768		-			810,114			-		24,346		785,768		-			810,114
Retirement benefits			8,721		54,415		-		-			63,136			8,721		54,415		-		-			63,136
Property taxes			-		25,328		22,767		-			48,095			-		25,328		22,767		-			48,095
Lease market valuation liability			-		353,210		-		-			353,210			-		353,210		-		-			353,210
Other			19,800		21,829		-		-			41,629			19,800		21,829		-		-			41,629
			28,521		515,182		1,092,744		800,972			2,437,419			28,521		515,182		1,092,744		800,972			2,437,419
TOTAL LIABILITIES AND CAPITALIZATION		$	3,162,511	$	4,452,888	$	4,092,883	$	(3,286,018	)	$	8,422,264
														$	3,162,511	$	4,452,888	$	4,092,883	$	(3,286,018	)	$	8,422,264

~~121~~145

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Nine Months Ended September 30, 2008	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)

NET CASH PROVIDED FROM OPERATING ACTIVITIES:	$	47,463		$	267,933		$	247,054		$	(8,317	)	$	554,133

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			328,325			209,050			-			537,375
Equity contribution from parent		280,000			675,000			175,000			(850,000	)		280,000
Short-term borrowings, net		700,000			-			139,363			(91,677	)		747,686
Redemptions and Repayments-
Long-term debt		(1,777	)		(286,776	)		(180,666	)		8,317			(460,902	)
Short-term borrowings, net		-			(91,677	)		-			91,677			-
Common stock dividend payment		(43,000	)		-			-			-			(43,000	)
Net cash provided from financing activities		935,223			624,872			342,747			(841,683	)		1,061,159

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(38,481	)		(778,329	)		(600,395	)		-			(1,417,205	)
Proceeds from asset sales		-			15,218			-			-			15,218
Sales of investment securities held in trusts		-			-			596,291			-			596,291
Purchases of investment securities held in trusts		-			-			(624,899	)		-			(624,899	)
Loan repayments from (loans to) associated companies, net		(94,755	)		(38,399	)		69,012			-			(64,142	)
Investment in subsidiary		(850,000	)		-			-			850,000			-
Restricted funds for debt redemption		-			(52,090	)		(29,550	)		-			(81,640	)
Other		550			(39,205	)		(260	)		-			(38,915	)
Net cash used for investing activities		(982,686	)		(892,805	)		(589,801	)		850,000			(1,615,292	)

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

146

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Nine Months Ended September 30, 2007	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)

NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES	$	(7,937	)	$	350,927		$	179,037		$	-		$	522,027

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			1,328,919			-			(1,328,919	)		-
Equity contribution from parent		700,000			700,000			-			(700,000	)		700,000
Short-term borrowings, net		223,942			-			13,128			(237,070	)		-
Redemptions and Repayments-
Common stock		(600,000	)		-			-			-			(600,000	)
Long-term debt		-			(795,019	)		(315,155	)		-			(1,110,174	)
Short-term borrowings, net		-			(1,022,197	)		-			237,070			(785,127	)
Common stock dividend payment		(67,000	)		-			-			-			(67,000	)
Net cash provided from (used for) financing activities		256,942			211,703			(302,027	)		(2,028,919	)		(1,862,301	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(10,119	)		(332,499	)		(140,289	)		-			(482,907	)
Proceeds from asset sales		-			12,990			-			-			12,990
Proceeds from sale and leaseback transaction		-			-			-			1,328,919			1,328,919
Sales of investment securities held in trusts		-			-			521,535			-			521,535
Purchases of investment securities held in trusts		-			-			(552,779	)		-			(552,779	)
Loan repayments from (loans to) associated companies, net		460,023			(242,612	)		292,896			-			510,307
Investment in subsidiary		(700,000	)		-						700,000			-
Other		1,091			(509	)		1,627			-			2,209
Net cash provided from (used for) investing activities		(249,005	)		(562,630	)		122,990			2,028,919			1,340,274

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

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Three Months Ended March 31, 2008 FES FGCO NGC Eliminations Consolidated
(In thousands)

NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES $ 273,827 $ (122,171 ) $ 8,108 $ 188 $ 159,952

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net 400,000 646,975 234,921 - 1,281,896
Redemptions and Repayments-
Long-term debt - (135,063 ) (153,540 ) - (288,603 )
Common stock dividend payments (10,000 ) - - - (10,000 )
Net cash provided from financing activities 390,000 511,912 81,381 - 983,293

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (19,406 ) (375,391 ) (81,545 ) (187 ) (476,529 )
Proceeds from asset sales - 5,088 - - 5,088
Sales of investment securities held in trusts - - 173,123 - 173,123
Purchases of investment securities held in trusts - - (181,079 ) - (181,079 )
Loans to associated companies, net (644,604 ) - - - (644,604 )
Other 183 (19,438 ) 12 (1 ) (19,244 )
Net cash used for investing activities (663,827 ) (389,741 ) (89,489 ) (188 ) (1,143,245 )

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

~~122~~147

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Three Months Ended March 31, 2007 FES FGCO NGC Eliminations Consolidated
(In thousands)

NET CASH PROVIDED FROM
OPERATING ACTIVITIES $ 65,870 $ 55,003 $ 177,456 $ - $ 298,329

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Equity contribution from parent 700,000 700,000 - (700,000 ) 700,000
Short-term borrowings, net 250,000 - - (52,269 ) 197,731
Redemptions and Repayments-
Long-term debt - (616,728 ) (128,716 ) - (745,444 )
Short-term borrowings, net - (52,269 ) - 52,269 -
Net cash provided from (used for) financing activities 950,000 31,003 (128,716 ) (700,000 ) 152,287

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (214 ) (81,400 ) (35,892 ) - (117,506 )
Sales of investment securities held in trusts - - 178,632 - 178,632
Purchases of investment securities held in trusts - - (188,076 ) - (188,076 )
Loans to associated companies, net (316,003 ) - (3,895 ) - (319,898 )
Investment in subsidiary (700,000 ) - - 700,000 -
Other 347 (4,606 ) 491 - (3,768 )
Net cash used for investing activities (1,015,870 ) (86,006 ) (48,740 ) 700,000 (450,616 )

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

~~123~~

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Information” in Item 2 above.

ITEM 4. CONTROLS AND PROCEDURES

(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES – FIRSTENERGY

FirstEnergy’s chief executive officer and chief financial officer have reviewed and evaluated the registrant's disclosure controls and procedures. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that the registrant's disclosure controls and procedures are effective and were designed to bring to their attention material information relating to the registrant and its consolidated subsidiaries by others within those entities.

(b) CHANGES IN INTERNAL CONTROLS

During the quarter ended ~~March 31,~~September 30, 2008, there were no changes in FirstEnergy’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant’s internal control over financial reporting.

ITEM 4T. CONTROLS AND PROCEDURES – FES, OE, CEI, TE, JCP&L, MET-ED AND PENELEC

(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Each registrant's chief executive officer and chief financial officer have reviewed and evaluated such registrant's disclosure controls and procedures. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that such registrant's disclosure controls and procedures are effective and were designed to bring to their attention material information relating to such registrant and its consolidated subsidiaries by others within those entities.

(b) CHANGES IN INTERNAL CONTROLS

During the quarter ended ~~March 31,~~September 30, 2008, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.

~~124~~148

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 10 and 11 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A. RISK FACTORS

~~See Item 1A RISK FACTORS in Part I of the~~FirstEnergy’s Annual Report on Form 10-K for the year ended December 31, 2007, and Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, include a detailed discussion of its risk factors. The information presented below updates certain of those risk factors and should be read in conjunction with the risk factors and information disclosed in FirstEnergy’s prior SEC filings.

FirstEnergy relies on access to the credit and capital markets to finance a portion of its working capital requirements and to support its liquidity needs. Access to these markets may be adversely affected by factors beyond FirstEnergy’s control, including turmoil in the financial services industry, volatility in securities trading markets and general economic downturns. In particular, recent disruptions in the variable-rate demand bond markets could require utilization of a significant portion of the sources of liquidity currently available to FirstEnergy and its subsidiaries.

FirstEnergy relies upon access to the ~~subsidiary registrants. For~~credit and capital markets as a source of liquidity for the ~~quarter ended March 31, 2008, there have been no material changes~~portion of its working capital requirements not provided by cash from operations and to ~~these risk factors.~~comply with various regulatory requirements. Market disruptions such as those currently being experienced in the United States and abroad may increase FirstEnergy’s cost of borrowing or adversely affect its ability to access sources of liquidity upon which it relies to finance operations and satisfy obligations as they become due. These disruptions may include turmoil in the financial services industry, including substantial uncertainty surrounding particular lending institutions and counterparties with whom FirstEnergy does business, unprecedented volatility in the markets where FirstEnergy’s outstanding securities trade, and general economic downturns in the areas where FirstEnergy does business. If FirstEnergy is unable to access credit at competitive rates, or if its short-term or long-term borrowing costs dramatically increase, FirstEnergy’s ability to finance its operations, meet its short-term obligations and implement its operating strategy could be adversely affected.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

(c) FirstEnergy

The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock.

	Period				Period
	January 1-31,	February 1-29,	March 1-31,	First	July 1-31,	August 1-31,	September 1-30,	Third
	2008	2008	2008	Quarter	2008	2008	2008	Quarter
Total Number of Shares Purchased (a)	329,106	16,853	988,386	1,334,345	52,166	32,187	208,772	293,125
Average Price Paid per Share	$76.56	$71.68	$68.55	$70.57	$81.63	$71.63	$72.09	$73.74
Total Number of Shares Purchased
As Part of Publicly Announced Plans
or Programs ~~(b)~~	-	-	-	-
Maximum Number (or Approximate Dollar					-	-	-	-
Value) of Shares that May Yet Be
Purchased Under the Plans or Programs	-	-	-	-	-	-	-	-

Commission	Registrant; State of Incorporation;	I.R.S. Employer
File Number	Address; and Telephone Number	Identification No.

333-21011	FIRSTENERGY CORP.	34-1843785
	(An Ohio Corporation)
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

333-145140-01	FIRSTENERGY SOLUTIONS CORP.	31-1560186
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2578	OHIO EDISON COMPANY	34-0437786
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2323	THE CLEVELAND ELECTRIC ILLUMINATING COMPANY	34-0150020
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3583	THE TOLEDO EDISON COMPANY	34-4375005
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3141	JERSEY CENTRAL POWER & LIGHT COMPANY	21-0485010
	(A New Jersey Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-446	METROPOLITAN EDISON COMPANY	23-0870160
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3522	PENNSYLVANIA ELECTRIC COMPANY	25-0718085
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

Yes (X) No ( )	FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company
Yes ( ) No (X)	FirstEnergy Solutions Corp.~~, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company and Metropolitan Edison Company~~

Large Accelerated Filer (X)	FirstEnergy Corp.
Accelerated Filer ( )	N/A
Non-accelerated Filer (Do not check if a smaller reporting company) (X)	FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company

	OUTSTANDING
CLASS	AS OF ~~MAY 8,~~November 6, 2008
FirstEnergy Corp., $0.10 par value	304,835,407
FirstEnergy Solutions Corp., no par value	7
Ohio Edison Company, no par value	60
The Cleveland Electric Illuminating Company, no par value	67,930,743
The Toledo Edison Company, $5 par value	29,402,054
Jersey Central Power & Light Company, $10 par value	14,421,637
Metropolitan Edison Company, no par value	859,500
Pennsylvania Electric Company, $20 par value	4,427,577

		Pages

Glossary of Terms		iii-v

Part I. Financial Information

Items 1. and 2. - Financial Statements and Management’s Discussion and Analysis ofFinancial Condition and Results of Operations.

FirstEnergy Corp.

	Management's Discussion and Analysis of Financial Condition and	~~1-32~~
	Results of Operations	1-46
	Report of Independent Registered Public Accounting Firm	3347
	Consolidated Statements of Income	3448
	Consolidated Statements of Comprehensive Income	3549
	Consolidated Balance Sheets	3650
	Consolidated Statements of Cash Flows	3751

FirstEnergy Solutions Corp.

	Management's Narrative Analysis of Results of Operations	~~38-40~~52-54
	Report of Independent Registered Public Accounting Firm	4155
	Consolidated Statements of Income and Comprehensive Income	4256
	Consolidated Balance Sheets	4357
	Consolidated Statements of Cash Flows	4458

Ohio Edison Company

	Management's Narrative Analysis of Results of Operations	~~45-46~~59-60
	Report of Independent Registered Public Accounting Firm	4761
	Consolidated Statements of Income and Comprehensive Income	4862
	Consolidated Balance Sheets	4963
	Consolidated Statements of Cash Flows	5064

The Cleveland Electric Illuminating Company

	Management's Narrative Analysis of Results of Operations	~~51-52~~65-66
	Report of Independent Registered Public Accounting Firm	5367
	Consolidated Statements of Income and Comprehensive Income	5468
	Consolidated Balance Sheets	5569
	Consolidated Statements of Cash Flows	5670

The Toledo Edison Company

	Management's Narrative Analysis of Results of Operations	~~57-58~~71-73
	Report of Independent Registered Public Accounting Firm	5974
	Consolidated Statements of Income and Comprehensive Income	6075
	Consolidated Balance Sheets	6176
	Consolidated Statements of Cash Flows	6277

ATSI	American Transmission Systems, ~~Inc.,~~Incorporated, owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
~~Companies~~	~~OE, CEI, TE, JCP&L, Met-Ed and Penelec~~
FENOC	FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES	FirstEnergy Solutions Corp., provides energy-related products and services
FESC	FirstEnergy Service Company, provides legal, financial and other corporate support services
FGCO	FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstEnergy	FirstEnergy Corp., a public utility holding company
GPU	GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on November 7, 2001
JCP&L	Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
JCP&L Transition Funding	JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds
JCP&L Transition Funding II	JCP&L Transition Funding II LLC, a Delaware limited liability company and issuer of transition bonds
Met-Ed	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
NGC	FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies	CEI, OE and TE
Penelec	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies	Met-Ed, Penelec and Penn
PNBV	PNBV Capital Trust, a special purpose entity created by OE in 1996
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
Signal Peak	A joint venture between FirstEnergy Ventures Corp. and Boich Companies, that owns mining and coal transportation operations near Roundup, Montana, formerly known as Bull Mountain
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
~~TEBSA~~Utilities	~~Termobarranquila S.A. Empresa de Servicios Publicos~~OE, CEI, TE, JCP&L, Met-Ed and Penelec

The following abbreviations and acronyms are used to identify frequently used terms in this report:

ACO	Administrative Consent Order
AEP	American Electric Power Company, Inc.
ALJ	Administrative Law Judge
AMP-Ohio	American Municipal Power-Ohio, Inc.
AOCL	Accumulated Other Comprehensive Loss
~~AQC~~	~~Air Quality Control~~
ARB	Accounting Research Bulletin
ARO	Asset Retirement Obligation
ASM	Ancillary Services Market
BGS	Basic Generation Service
~~BPJ~~	~~Best Professional Judgment~~
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CBP	Competitive Bid Process
CO2	Carbon Dioxide
DFI	Demand for Information
DOJ	United States Department of Justice
DRA	Division of Ratepayer Advocate
EIS	Energy Independence Strategy
EITF	Emerging Issues Task Force
EMP	Energy Master Plan
EPA	United States Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ESP	Electric Security Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
FIN 46R	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"

FIN 47	FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"
FIN 48	FIN 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109”
~~FirstCom~~	~~First Communications, Inc.~~

FMB	First Mortgage ~~Bonds~~
~~FSP~~	~~FASB Staff Position~~
~~FSP FAS 157-2~~	~~FSP FAS 157-2, “Effective Date of FASB Statement No. 157”~~Bond
FTR	Financial Transmission Rights
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases
~~ICE~~	~~Intercontinental Exchange~~
IRS	Internal Revenue Service
ISO	Independent System Operator
kV	Kilovolt
KWH	Kilowatt-hours
LIBOR	London Interbank Offered Rate
LOC	Letter of Credit
MEIUG	Met-Ed Industrial Users Group
MEW	Mission Energy Westside, Inc.
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service
MRO	Market Rate Offer
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
~~NOPR~~	~~Notice of Proposed Rulemaking~~
NOV	Notice of Violation
NOX	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NSR	New Source Review
NUG	Non-Utility Generation
NUGC	Non-Utility Generation Charge
NYMEX	New York Mercantile Exchange
OCA	Office of Consumer Advocate
OTC	Over the Counter
OVEC	Ohio Valley Electric Corporation
PCRB	Pollution Control Revenue Bond
PICA	Penelec Industrial Customer Alliance
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last Resort
PPUC	Pennsylvania Public Utility Commission
PRP	Potentially Responsible Party
PSA	Power Supply Agreement
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RCP	Rate Certainty Plan
RECB	Regional Expansion Criteria and Benefits
RFP	Request for Proposal
RPM	Reliability Pricing Model
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Ratings Service
SB221	Amended Substitute Senate Bill 221
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment
SFAS	Statement of Financial Accounting Standards
SFAS ~~109~~	~~SFAS No. 109, “Accounting for Income Taxes”~~
~~SFAS 123(R)~~	~~SFAS No. 123(R), "Share-Based Payment"~~
~~SFAS~~ 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”

SFAS ~~141(R)~~142	SFAS ~~No 141(R), “Business Combinations”~~	No. 142, “Goodwill and Other Intangible Assets”
SFAS 143	SFAS No. 143, “Accounting for Asset Retirement Obligations”
SFAS 157	SFAS No. 157, “Fair Value Measurements”
SFAS 159	SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115”
~~SFAS 160~~	~~SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an Amendment~~ ~~of ARB No. 51”~~
~~SFAS 161~~	~~SFAS No 161, “Disclosure about Derivative Instruments and Hedging Activities – an Amendment~~ ~~of FASB Statement No. 133”~~

SIP	State Implementation Plan(s) Under the Clean Air Act
SNCR	Selective Non-Catalytic Reduction
SO2	Sulfur Dioxide
~~TBC~~	~~Transition Bond Charge~~
TMI-1	Three Mile Island Unit 1
TMI-2	Three Mile Island Unit 2
TSC	Transmission Service Charge
VIE	Variable Interest Entity

~~Change in Basic Earnings Per Share~~ ~~From Prior Year First Quarter~~

~~Basic Earnings Per Share – First Quarter 2007~~	~~$ 0.92~~
~~Gain on non-core asset sales – 2008~~	~~0.06~~
~~Saxton decommissioning regulatory asset – 2007~~	~~(0.05)~~
~~Trust securities impairment~~	~~(0.02)~~
~~Revenues~~	~~0.55~~
~~Fuel and purchased power~~	~~(0.42)~~
~~Depreciation and amortization~~	~~(0.03)~~
~~Deferral of new regulatory assets~~	~~(0.03)~~
~~Energy Delivery O&M expenses~~	~~(0.03)~~
~~General taxes~~	~~(0.02)~~
~~Corporate-owned life insurance~~	~~(0.06)~~
~~Other expenses~~	~~0.01~~
~~Reduced common shares outstanding~~	~~0.03~~
~~Basic Earnings Per Share – First Quarter 2008~~	~~$ 0.91~~

	Three Months			Nine Months
Change in Basic Earnings Per Share	Ended			Ended
From Prior Year Periods	September 30			September 30

Basic Earnings Per Share – 2007	$	1.36		$	3.39
Gain on non-core asset sales – 2008/2007		(0.04	)		0.02
Litigation settlement – 2008		-			0.03
Saxton decommissioning regulatory asset – 2007		-			(0.05	)
Trust securities impairment		(0.05	)		(0.09	)
Revenues		0.57			1.36
Fuel and purchased power		(0.34	)		(1.16	)
Depreciation and amortization		(0.02	)		(0.07	)
Deferral of new regulatory assets		(0.10	)		(0.23	)
Investment Income – decommissioning trusts and corporate-owned life insurance		0.04			(0.05	)
Income tax adjustments		0.12			0.12
Other expense reductions		0.01			0.02
Reduced common shares outstanding		-			0.03
Basic Earnings Per Share – 2008	$	1.55		$	3.32

													Three Months Ended September 30,							Nine Months Ended September 30,
	Three Months Ended																	Increase							Increase
	March 31,								Increase				2008		2007			(Decrease)		2008		2007			(Decrease)
	2008				2007				(Decrease)				(In millions, except per share data)
Net Income	(In millions, except per share data)
By Business Segment
By Business Segment:
Energy delivery services		$	179			$	218			$	(39	)	$	283	$	269		$	14	$	655	$	695		$	(40	)
Competitive energy services			87				98				(11	)		164		148			16		317		388			(71	)
Ohio transitional generation services			23				24				(1	)		19		16			3		62		69			(7	)
Other and reconciling adjustments*			(13	)			(50	)			37			5		(20	)		25		(24)		(111	)		87
Total		$	276			$	290			$	(14	)	$	471	$	413		$	58	$	1,010	$	1,041		$	(31	)

Basic Earnings Per Share		$	0.91			$	0.92			$	(0.01	)	$	1.55	$	1.36		$	0.19	$	3.32	$	3.39		$	(0.07	)
Diluted Earnings Per Share		$	0.90			$	0.92			$	(0.02	)	$	1.54	$	1.34		$	0.20	$	3.29	$	3.35		$	(0.06	)

Electric Distribution KWH Deliveries
Residential	~~2.4~~(1.9)	%
Commercial	~~1.9~~(1.1)	%
Industrial	~~(1.0~~(4.1)	)%
Total Distribution KWH Deliveries	~~1.2~~(2.3)	%

Sources of Change in Generation Revenues	Increase (Decrease)			Increase (Decrease)
	(In millions)			(In millions)
Retail:
Effect of 0.7% decrease in sales volumes	$	(5	)
Effect of 1.9 % decrease in sales volumes				$	(18	)
Change in prices		75			62
		70			44
Wholesale:
Effect of 8.9% increase in sales volumes		12
Effect of 2.4% decrease in sales volumes					(5	)
Change in prices		75			84
		87			79
Net Increase in Generation Revenues	$	157		$	123

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to increased unit costs	$	84
Change due to decreased volumes		(18	)
		66
Purchases from FES:
Change due to decreased unit costs		(4	)
Change due to increased volumes		17
		13

Decrease in NUG costs deferred		60
Net Increase in Purchased Power Costs	$	139

Source of Change in Non-Affiliated Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 14.2% decrease in sales volumes	$	(27	)
Change in prices		9
		(18	)
Wholesale:
Effect of 28.8% increase in sales volumes		43
Change in prices		18
		61
Net Increase in Non-Affiliated Generation Revenues	$	43

Source of Change in Affiliated Generation Revenues	Increase (Decrease)
	(In millions)
Ohio Companies:
Effect of 3.6% decrease in sales volumes	$	(22	)
Change in prices		19
		(3	)
Pennsylvania Companies:
Effect of 5.9% decrease in sales volumes		(11	)
Change in prices		(6	)
		(17	)
Net Decrease in Affiliated Generation Revenues	$	(20	)

Source of Change in Retail Generation Revenues	Increase (Decrease)
	(In millions)
Effect of 3.1% decrease in sales volumes	$	(19	)
Change in prices		72
Total Increase in Retail Generation Revenues	$	53

Electric Distribution KWH Deliveries
Residential	(1.3)	%
Commercial	(0.5)	%
Industrial	(1.8)	%
Total Distribution KWH Deliveries	(1.2)	%

Source of Change in Retail Generation Revenues	Increase
Source of Change in Generation Revenues			Increase
	(In millions)		(In millions)
Effect of 1.3% increase in sales volumes	$	7
Retail:
Effect of 1.4% decrease in sales volumes			$	(24	)
Change in prices		53		180
Total Increase in Retail Generation Revenues	$	60	$	156

Company	Type	Maturity	Commitment	Available
			(In millions)
FirstEnergy(1)	Revolving	Aug. 2012	$2,750	404
FirstEnergy and FES	Revolving	May 2009	300	300
FirstEnergy	Bank lines	Various(2)	120	20
FGCO	Term loan	Oct. 2009(3)	300	300
Ohio and Pennsylvania Companies	A/R financing	Various(4)	550	445
		Subtotal:	$4,020	$1,469
		Cash:	-	456
		Total:	$4,020	$1,925

	Aggregate LOC
	Amount(5)			Reimbursements of
LOC Bank	(In millions)		LOC Termination Date	LOC Draws Due
Barclays Bank(1)	$	149	June 2009	June 2009
Bank of America(1) (2)		101	June 2009	June 2009
The Bank of Nova Scotia(1)		255	Beginning June 2010	Shorter of 6 months or LOC termination date
The Royal Bank of Scotland(1)		131	June 2012	6 months
KeyBank(1) (3)		266	June 2010	6 months
Wachovia Bank		648	March 2009	March 2009
Barclays Bank(4)		528	Beginning December 2010	30 days
PNC Bank		70	Beginning December 2010	5 days
Total	$	2,148

Currently Payable Long-term Debt
		(In millions)
PCRBs supported by bank LOCs (1)	$	2,126
CEI FMBs (2)		125
CEI secured PCRBs (2)		82
Penelec unsecured notes (3)		100
NGC collateralized lease obligation bonds (4)		37
Sinking fund requirements (5)		39
	$	2,509

	Three Months Ended
	March 31,
Securities Issued or Redeemed	2008		2007
	(In millions)
New issues
Unsecured notes	$	-	$	250

Redemptions
Pollution control notes(1)	$	362	$	-
Senior secured notes		6		13
Common stock		-		891
	$	368	$	904

Short-term borrowings, net	$	746	$	1,139

(1) Includes the repurchase of certain auction rate PCRBs described below, which were extinguished from FirstEnergy’s consolidated balance sheet.

	Nine Months Ended
Securities Issued or	September 30,
Redeemed / Repurchased	2008		2007
	(In millions)
New issues
Pollution control notes	$	611	$	-
Unsecured notes		20		1,100
	$	631	$	1,100
Redemptions / Repurchases
First mortgage bonds	$	1	$	287
Pollution control notes		534		4
Senior secured notes		23		203
Unsecured notes		175		153
Common stock		-		918
	$	733	$	1,565

Borrowing Capability (In millions)
Short-term credit facilities(1)	$	2,870
Accounts receivable financing facilities		550
Utilized		(1,646	)
LOCs		(60	)
Net available capability	$	1,714

(1) Includes the $2.75 billion revolving credit facility described below, a $100 million revolving credit facility that expires in December 2009 and a $20 million uncommitted line of credit.

	Revolving			Regulatory and			Revolving			Regulatory and
	Credit Facility			Other Short-Term			Credit Facility			Other Short-Term
Borrower	Sub-Limit			Debt Limitations(1)			Sub-Limit			Debt Limitations
	(In millions)						(In millions)
FirstEnergy	$	2,750		$	-	(2)	$	2,750		$	-	(1)
OE		500			500			500			500
Penn		50			39	(3)		50			39	(2)
CEI		250	(4)		500			250	(3)		500
TE		250	(4)		500			250	(3)		500
JCP&L		425			428	(3)		425			428	(2)
Met-Ed		250			300	(3)		250			300	(2)
Penelec		250			300	(3)		250			300	(2)
FES		1,000			-	(2)		1,000			-	(1)
ATSI		-	(5)		50			-	(4)		50

(1)As of March 31, 2008. (2)No regulatory approvals, statutory or charter limitations applicable. (3)Excluding amounts which may be borrowed under the regulated companies’ money pool. (4)Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody’s. (5)The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that either (i) ATSI has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guaranteed ATSI’s obligations of such borrower under the facility.

Borrower
FirstEnergy	5859.6	%
OE	4346.0	%
Penn	2519.2	%
CEI	5755.8	%
TE	4244.5	%
JCP&L	3031.0	%
Met-Ed	4743.7	%
Penelec	4950.1	%
FES	6156.6	%

Issuer	Securities	S&P	Moody’s

FirstEnergy	Senior unsecured	BBB-	Baa3

FES	Senior unsecured	BBB	Baa2

OE	Senior secured	BBB+	Baa1
	Senior unsecured	~~BBB-~~BBB	Baa2

CEI	Senior secured	BBB+	Baa2
	Senior unsecured	~~BBB-~~BBB	Baa3

TE	Senior unsecured	~~BBB-~~BBB	Baa3

Penn	Senior secured	A-	Baa1

JCP&L	Senior unsecured	BBB	Baa2

Met-Ed	Senior unsecured	BBB	Baa2

Penelec	Senior unsecured	BBB	Baa2

Summary of Cash Flows	Property
Provided from (Used for) Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	(In millions)
Three Months Ended March 31, 2008
Energy delivery services	$	(255	)	$	33		$	2		$	(220	)
Competitive energy services		(462	)		(3	)		(19	)		(484	)
Other		(12	)		68			-			56
Inter-Segment reconciling items		18			(12	)		-			6
Total	$	(711	)	$	86		$	(17	)	$	(642	)

Three Months Ended March 31, 2007
Energy delivery services	$	(155	)	$	44		$	10		$	(101	)
Competitive energy services		(124	)		(9	)		(4	)		(137	)
Other		(1	)		(16	)		(4	)		(21	)
Inter-Segment reconciling items		(16	)		(15	)		-			(31	)
Total	$	(296	)	$	4		$	2		$	(290	)

Summary of Cash Flows Provided from	Property
(Used for) Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	(In millions)
Nine Months Ended September 30, 2008
Energy delivery services	$	(621	)	$	33		$	(3	)	$	(591	)
Competitive energy services(1)		(1,430	)		(13	)		(121	)		(1,564	)
Other(2)		(106	)		57			(54	)		(103	)
Inter-Segment reconciling items		(20	)		(12	)		-			(32	)
Total	$	(2,177	)	$	65		$	(178	)	$	(2,290	)

Nine Months Ended September 30, 2007
Energy delivery services	$	(609	)	$	6		$	(2	)	$	(605	)
Competitive energy services		(462	)		1,311			2			851
Other		(6	)		(4	)		1			(9	)
Inter-Segment reconciling items		(50	)		(15	)		-			(65	)
Total	$	(1,127	)	$	1,298		$	1		$	172

(1) Other investing activities include approximately $82 million in restricted funds to redeem outstanding debt in the fourth quarter of 2008. (2) Other investing activities include approximately $64 million in cash investments for the equity interest in Signal Peak.

	Maximum
Guarantees and Other Assurances	Exposure
	(In millions)
FirstEnergy Guarantees of Subsidiaries
Energy and Energy-Related Contracts (1)	$	441
LOC (long-term debt) – interest coverage (2)		6
Other (3)		503
		950

Subsidiaries’ Guarantees
Energy and Energy-Related Contracts		86
LOC (long-term debt) – interest coverage (2)		6
Other (4)		2,641
		2,733

Surety Bonds		66
LOC (long-term debt) – interest coverage (2)		5
LOC (non-debt) (5)(6)		679
		750
Total Guarantees and Other Assurances	$	4,433

Collateral Provisions	FES		Utilities		Total
	(in millions)
Credit rating downgrade to below investment grade	$	216	$	293	$	509
Material adverse event		56		8		64
Total	$	272	$	301	$	573

										Three Months									Nine Months
Increase (Decrease) in the Fair Value										Ended September 30, 2008									Ended September 30, 2008
of Commodity Derivative Contracts	Non-Hedge			Hedge			Total
of Derivative Contracts										Non-Hedge			Hedge			Total			Non-Hedge			Hedge			Total
	(In millions)									(In millions)
Change in the Fair Value of
Commodity Derivative Contracts:
Outstanding net liability as of January 1, 2008	$	(713	)	$	(26	)	$	(739	)
Outstanding net liability at beginning of period										$	(616	)	$	(37	)	$	(653	)	$	(713	)	$	(26	)	$	(739	)
Additions/change in value of existing contracts		-			(11	)		(11	)		23			33			56			(10	)		9			(1	)
Settled contracts		58			17			75			18			(6	)		12			148			7			155
Outstanding net liability as of March 31, 2008 (1)	$	(655	)	$	(20	)	$	(675	)
Outstanding net liability at end of period (1)											(575	)		(10	)		(585	)		(575	)		(10	)		(585	)

Non-commodity Net Liabilities as of March 31, 2008:
Non-commodity Net Assets at End of Period:
Interest rate swaps (2)		-			(3	)		(3	)		-			-			-			-			-			-
Net Liabilities - Derivative Contracts as of March 31, 2008	$	(655	)	$	(23	)	$	(678	)
Net Liabilities - Derivative Contracts at End of Period										$	(575	)	$	(10	)	$	(585	)	$	(575	)	$	(10	)	$	(585	)

Impact of Changes in Commodity Derivative Contracts(3)
Income Statement effects (pre-tax)	$	-		$	-		$	-		$	(1	)	$	-		$	(1	)	$	-		$	-		$	-
Balance Sheet effects:
Other comprehensive income (pre-tax)	$	-		$	6		$	6		$	-		$	27		$	27		$	-		$	16		$	16
Regulatory assets (net)	$	(58	)	$	-		$	(58	)	$	(42	)	$	-		$	(42	)	$	(138	)	$	-		$	(138	)