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. NO_X 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 NO_X reductions at FirstEnergy's facilities. The EPA's NO_X Transport Rule imposes uniform reductions of NO_X emissions (an approximate 85% reduction in utility plant NO_X 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 NO_X emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NO_X budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.

On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal ~~Clean Air Act,~~CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the ~~Mansfield~~ Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On ~~July 25,~~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.

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 ~~PennFuture entered into~~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 ~~Tolling~~motion to dismiss the citizen suit claims against it and ~~Confidentiality Agreement that provides for~~ a ~~60-day negotiation period during~~stipulation in which the parties ~~have~~ agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the Court. Although it remains liable for civil or criminal penalties and fines that may be assessed relating to ~~not file a lawsuit.~~events prior to the sale of the Portland Station in 1999, Met-Ed is indemnified by Sithe Energy against any other liability arising under the CAA whether it arises out of pre-1999 or post-1999 events.

103

National Ambient Air Quality Standards

~~In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter.~~ In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR ~~allowed each affected state until 2006 to develop implementing regulations to achieve additional~~requires reductions of NO_X and SO₂ emissions in two phases (Phase I in 2009 for NO_X, 2010 for SO₂ and Phase II in 2015 for both NO_X and SO₂). FirstEnergy's Michigan, Ohio and Pennsylvania ~~fossil-fired~~fossil generation facilities will be subject to caps on SO₂ and NO_X emissions, whereas its New Jersey ~~fossil-fired~~fossil generation facility will be subject to only a cap on NO_X emissions. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. NO_X 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 1.3 million tons annually. CAIR has been challenged in the United States Court of Appeals for the District of Columbia. The future cost of compliance with these regulations may be substantial and ~~will~~may depend on the outcome of this litigation and how ~~they are~~CAIR is ultimately ~~implemented by the states in which FirstEnergy operates affected facilities.~~implemented.

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,~~phases; initially, capping national mercury emissions ~~will be capped nationally~~ at 38 tons by 2010 (as a "co-benefit" from implementation of SO₂ and NO_X emission caps under the EPA's CAIR program)~~. Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at~~ and 15 tons per year by 2018. ~~However, the final rules give~~Several states ~~substantial discretion in developing rules to implement these programs. In addition, both the CAIR~~ and environmental groups appealed the CAMR ~~have been challenged in~~to the United States Court of Appeals for the District of Columbia. ~~FirstEnergy's~~On February 8, 2008, the 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 program. The EPA must now seek further judicial review of that ruling or take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with ~~these~~mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately ~~implemented by the states in which FirstEnergy operates affected facilities.~~implemented.

The model rules for both CAIR and CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. FirstEnergy would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, FirstEnergy will be disadvantaged if these model rules were implemented as proposed because FirstEnergy’s substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a ~~cap and trade~~cap-and-trade approach as in the CAMR, but rather follows a ~~command and control~~command-and-control approach imposing emission limits on individual sources. Pennsylvania’s mercury regulation would deprive FES of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving FirstEnergy system-wide compliance. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the 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 ~~or compliance orders to nine utilities alleging violations of~~and the ~~Clean Air Act~~DOJ filed a civil complaint against OE and Penn based on operation and maintenance of ~~44 power plants, including~~ the ~~W. H.~~W.H. Sammis Plant ~~which was owned at that time by OE~~(Sammis NSR Litigation) and ~~Penn, and is now owned by FGCO. In addition, the DOJ~~ filed ~~eight civil~~similar complaints ~~against various investor-owned utilities, including a complaint against OE and Penn in the~~involving 44 other U.S. ~~District Court for the Southern District of Ohio. These~~power plants. This case, along with seven other similar cases, are referred to as the ~~New Source Review, or~~ 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 NO_X and SO₂ emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install 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 ~~settlement agreement~~consent decree are currently estimated to be ~~$1.7~~$1.3 billion for ~~2007 through 2011~~2008-2012 ($~~400~~650 million of which is expected to be spent during ~~2007,~~2008, with the largest portion of the remaining ~~$1.3 billion~~$650 million expected to be spent in ~~2008 and~~ 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.

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 ~~Sammis NSR Litigation consent decree also requires FirstEnergy to spend up to $25 million toward environmentally beneficial projects, $14 million~~EPA has not yet issued a final regulation. FGCO’s future cost of ~~which is satisfied by entering into 93 MW (or 23 MW if federal tax credits~~compliance with those regulations may be substantial and will depend on how they are ~~not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.~~ultimately implemented.

104

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by ~~5.2% from 1990 levels between 2008 and~~ 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. AtAlso, in an April 16, 2008 speech, President Bush set a policy goal of stopping the ~~international level, efforts have begun to develop climate change agreements for post-2012~~growth of GHG ~~reductions. The~~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.~~States, and the Senate Environmental and Public Works Committees have 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 ~~Clean Air Act.~~CAA. Although this decision did not address CO₂ emissions from electric generating plants, the EPA has similar authority under the ~~Clean Air Act~~CAA to regulate “air pollutants” from those and other facilities. Also 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, the EPA proposed to change the NSR regulations, on May 8, 2007, to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.

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 federal Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to EPA for further rulemaking and eliminated the restoration option from EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment (BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. FirstEnergy is evaluating various control options and their costs and effectiveness. Depending on the outcome of such studies, the EPA’s further rulemaking and any action taken by the states exercising BPJ, the future cost of compliance with these standards may require material capital expenditures.

~~Regulation of Hazardous Waste~~

As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of June 30, 2007, FirstEnergy had approximately $1.5 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley and Perry. As part of the application to the NRC to transfer the ownership of these nuclear facilities to NGC, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. 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 plans to seek for these facilities.

The Companies 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 are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of June 30, 2007, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $88 million (JCP&L - $60 million, TE - $3 million, CEI - $1 million, and other subsidiaries - $24 million) have been accrued through June 30, 2007.

~~(C) 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 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 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 on July 8, 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, on March 7, 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 on May 9, 2007. Proceedings are continuing in the Superior Court. FirstEnergy is vigorously defending this class action but is unable to predict the outcome of this matter. No liability has been accrued as of June 30, 2007.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. – Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.

FirstEnergy companies also are defending four separate complaint cases before the PUCO relating to the August 14, 2003 power outages. Two of those cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Two other pending PUCO complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc., as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. A fifth case in which a carrier sought reimbursement for claims paid to insureds was voluntarily dismissed by the claimant in April 2007. A sixth case involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed. The four cases were consolidated for hearing by the PUCO in an order dated March 7, 2006. In that order the PUCO also limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy as a defendant; and ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence. In response to a motion for rehearing filed by one of the claimants, the PUCO ruled on April 26, 2006 that the insurance company claimants, as insurers, may prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed amended complaints and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. On September 27, 2006, the PUCO dismissed certain parties and claims and otherwise ordered the complaints to go forward to hearing. The cases have been set for hearing on January 8, 2008.

On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga County Common Pleas Court seeking reimbursement for claims paid to numerous insureds who allegedly suffered losses as a result of the August 14, 2003 outages. All of the insureds appear to be non-customers. The plaintiff insurance companies are the same claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies and Penn were served on October 27, 2006. On January 18, 2007, the Court granted the Companies’ motion to dismiss the case and they have not been appealed. However, on April 25, 2007, one of the insurance carriers refiled the complaint naming only FirstEnergy as the defendant. On July 30, 2007, the case was voluntarily dismissed. No estimate of potential liability is available for any of these cases.

FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy were based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. The plaintiff has not appealed.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. Although FirstEnergy is unable to predict the impact of these proceedings, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

~~Nuclear Plant Matters~~

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and corrective action. On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Nuclear Power Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections would continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.

On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Nuclear Power Plant and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. By two letters dated March 2, 2007, the NRC closed the CAL commitments for Perry, the two outstanding white findings, and crosscutting issues. Moreover, the NRC removed Perry from the Multiple Degraded Cornerstone Column of the NRC Action Matrix and placed the plant in the Licensee Response Column (regular agency oversight).

On April 30, 2007, the UCS filed a petition with the NRC under Section 2.206 of the NRC’s regulations based on a report prepared at FENOC’s request by expert witnesses for an insurance arbitration. In December 2006, the expert witnesses for FENOC completed a report that analyzed the crack growth rates in control rod drive mechanism penetrations and wastage of the former reactor pressure vessel head at Davis-Besse. Citing the findings in the expert witness' report, the Section 2.206 petition requested that: (1) Davis-Besse be immediately shut down; (2) that the NRC conduct an independent review of the consultant's report and that all pressurized water reactors be shut down until remedial actions can be implemented; and (3) Davis-Besse’s operating license be revoked.

In a letter dated May 18, 2007, the NRC stated that the “current reactor pressure vessel (RPV) head inspection requirements are adequate to detect RPV degradation issues before they result in significant corrosion.” The NRC also indicated that, “no immediate safety concern exists at Davis-Besse” and denied UCS’ first demand (to shut down the facility). On June 18, 2007, the NRC Petition Review Board indicated that the agency had initially denied petitioner’s other requests, and provided an opportunity for UCS to provide additional information prior to the final determination. By letter dated July 12, 2007, the NRC denied the remainder of the UCS petition.

On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for Information to FENOC following FENOC’s reply to an April 2, 2007 NRC request for information about the expert witnesses’ report and another report. The NRC indicated that this information is needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand for Information reaffirming that 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. The NRC held a public meeting on June 27, 2007 with FENOC to discuss FENOC’s response to the Demand for Information. In follow-up discussions, FENOC was requested to provide supplemental information to clarify certain aspects of the Demand for Information response and provide additional details regarding plans to implement the commitments made therein. FENOC submitted this supplemental response to the NRC on July 16, 2007. FirstEnergy can provide no assurances as to the ultimate resolution of this matter.

~~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 plaintiff’s motion to amend their complaint which OE has opposed.

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 granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. JCP&L intends to re-file an appeal again in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005. The parties met on June 27, 2007 before an arbitrator to assert their positions regarding the finality of damages. A hearing before the arbitrator is set for September 7, 2007.

The union employees at the W. H. Sammis Plant have been working without a labor contract since July 1, 2007. The union expects to vote on a new contract on August 9, 2007. While it is expected the union will ratify a new contract, FirstEnergy has a strike mitigation plan ready in the event of a strike.

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.

~~10. REGULATORY MATTERS~~

~~(A) RELIABILITY INITIATIVES~~

In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. – Canada Power System Outage Task Force) regarding enhancements to regional reliability. In 2004, FirstEnergy completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readiness and training and emergency response preparedness recommended for completion in 2004. On July 14, 2004, NERC independently verified that FirstEnergy had implemented the various initiatives to be completed by June 30 or summer 2004, with minor exceptions noted by FirstEnergy, which exceptions are now essentially complete. FirstEnergy is proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new equipment or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability entities may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future, which could require additional, material expenditures.

As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L’s service reliability. In 2004, the NJBPU adopted an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L’s ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a stipulation that incorporates the final report of an SRM who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L’s Planning and Operations and Maintenance programs and practices. On February 11, 2005, JCP&L met with the DRA to discuss reliability improvements. The SRM completed his work and issued his final report to the NJBPU on June 1, 2006. JCP&L filed a comprehensive response to the NJBPU on July 14, 2006. JCP&L continues to file compliance reports reflecting activities associated with the MOU and stipulation.

The EPACT served partly to amend the Federal Power Act with Section 215, which requires that an ERO establish and enforce reliability standards for the bulk-power system, subject to review of the FERC. Subsequently, the FERC certified NERC as the ERO, approved NERC's Compliance Monitoring and Enforcement Program and approved a set of reliability standards, which became mandatory and enforceable on June 18, 2007 with penalties and sanctions for noncompliance. The FERC also approved a delegation agreement between NERC and Reliability~~First~~ ~~Corporation, one of eight Regional Entities that carry out enforcement for NERC. All of FirstEnergy’s facilities are located within the Reliability~~~~First~~ ~~region.~~

While the FERC approved 83 of the 107 reliability standards proposed by NERC, the FERC has directed NERC to submit improvements to 56 of them, endorsing NERC's process for developing reliability standards and its associated work plan. On May 4, 2007, NERC also submitted 24 proposed Violation Risk Factors. The FERC issued an order approving 22 of those factors on June 26, 2007. Further, NERC adopted eight cyber security standards that became effective on June 1, 2006 and filed them with the FERC for approval. On December 11, 2006, the FERC Staff provided its preliminary assessment of the cyber security standards and cited various deficiencies in the proposed standards. Numerous parties, including FirstEnergy, provided comments on the assessment by February 12, 2007. The standards remain pending before the FERC. On July 20, 2007, the FERC issued a NOPR proposing to adopt eight Critical Infrastructure Protection Reliability Standards. Comments will not be due to the FERC until September or October of 2007.

FirstEnergy believes it is in compliance with all current NERC reliability standards. However, based upon a review of the FERC's guidance to NERC in its March 16, 2007 Final Rule on Mandatory Reliability Standards, it appears that the FERC will eventually adopt stricter NERC reliability standards than those just approved. The financial impact of complying with the new standards cannot be determined at this time. However, the EPACT required that all prudent costs incurred to comply with the new reliability standards be recovered in rates. If FirstEnergy is unable to meet the reliability standards for its bulk power system in the future, it could have a material adverse effect on FirstEnergy’s and its subsidiaries’ financial condition, results of operations and cash flows.

~~On April 18-20, 2007, Reliabilit~~~~yFirst~~ performed a routine compliance audit of FirstEnergy's bulk-power system within the Midwest ISO region and found FirstEnergy to be in full compliance with all audited reliability standards. Similarly, Reliability~~First~~ has scheduled a compliance audit of FirstEnergy's bulk-power system within the PJM region in 2008. FirstEnergy does not expect any material adverse impact to its financial condition as a result of these audits.

~~(B) OHIO~~

On October 21, 2003, the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to the PUCO’s concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order in all respects, except it remanded back to the PUCO the matter of ensuring the availability of sufficient means for customer participation in the marketplace. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006, the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio’s findings on customer participation. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and considered to be null and void. On July 20, 2006, the OCC and NOAC also submitted to the PUCO a conceptual proposal addressing the issue raised by the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry directing the Ohio Companies to file a plan in a new docket to address the Court’s concern. The Ohio Companies filed their RSP Remand CBP on September 29, 2006. Initial comments were filed on January 12, 2007 and reply comments were filed on January 29, 2007. In their reply comments the Ohio Companies described the highlights of a new tariff offering they would be willing to make available to customers that would allow customers to purchase renewable energy certificates associated with a renewable generation source, subject to PUCO approval. On May 29, 2007, the Ohio Companies, together with the PUCO Staff and the OCC, filed a stipulation with the PUCO agreeing to offer a standard bid product and a green resource tariff product. The stipulation is currently pending before the PUCO. No further proceedings are scheduled at this time.

On August 31, 2005, the PUCO approved a rider recovery mechanism through which the Ohio Companies may recover all MISO transmission and ancillary service related costs incurred during each year ending June 30. Pursuant to the PUCO’s order, the Ohio Companies, on May 1, 2007, filed revised riders, which became effective on July 1, 2007. The revised riders represent an increase over the amounts collected through the 2006 riders of approximately $64 million annually. If it is subsequently determined by the PUCO that adjustments to the rider as filed are necessary, such adjustments, with carrying costs, will be incorporated into the 2008 transmission rider filing.

On May 8, 2007, the Ohio Companies filed with the PUCO a notice of intent to file for an increase in electric distribution rates. The Ohio Companies filed the application and rate request with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operating and maintenance expenses and recovery of regulatory assets created by deferrals that were approved in prior cases. On August 6, 2007, the Ohio Companies provided an update filing supporting a distribution rate increase of $332 million to the PUCO to establish the test period data that will be used as the basis for setting rates in that proceeding. The PUCO Staff is expected to issue its report in the case in the fourth quarter of 2007 with evidentiary hearings to follow in late 2007. The PUCO order is expected to be issued by March 9, 2008. The new rates, subject to evidentiary hearings and approval at the PUCO, would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.

On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per kilowatt-hour would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The Ohio Companies requested that the PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process. The PUCO has scheduled a technical conference for August 16, 2007.

~~(C) PENNSYLVANIA~~

Met-Ed and Penelec have been purchasing a portion of their PLR requirements from FES through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, FES retained the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec. The FES agreements have reduced Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR capacity and energy costs during the term of these agreements with FES.

On April 7, 2006, the parties entered into a tolling agreement that arose from FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the partial requirements agreement effective midnight December 31, 2006. On November 29, 2006, Met-Ed, Penelec and FES agreed to suspend the April 7 tolling agreement pending resolution of the PPUC’s proceedings regarding the Met-Ed and Penelec comprehensive transition rate cases filed April 10, 2006, described below. Separately, on September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligation for the period December 1, 2006 through December 31, 2008. FES was one of the successful bidders in that RFP process and on September 26, 2006 entered into a supplier master agreement to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market prices that substantially exceed the fixed price in the partial requirements agreements.

Based on the outcome of the 2006 comprehensive transition rate filing, as described below, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR obligations. The parties also have separately terminated the tolling, suspension and supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the supplier master agreement will now be provided under the restated partial requirements agreement. The fixed price under the restated agreement is expected to remain below wholesale market prices during the term of the agreement.

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 its 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.

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 in accordance with the April 7, 2006 tolling agreement described above. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs, but only for those costs incurred during 2006. In this rate filing, Met-Ed and Penelec also 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 the merger savings, with the comprehensive transmission 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, when new transmission rates were effective, 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 in 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 expenses and the transmission deferral. 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). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s, Penelec’s and the other parties’ petitions for procedural purposes. Due to that ruling, the period for appeals to the Commonwealth Court of Pennsylvania was tolled until 30 days after the PPUC entered a subsequent order ruling on the substantive issues raised in the petitions. On March 1, 2007, the PPUC issued three orders: (1) a tentative order regarding the reconsideration by the PPUC of its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part the MEIUG’s and PICA’s Petition for Reconsideration; and (3) an order approving the Compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the 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. On June 19, 2007, initial briefs were filed by all parties. Responsive briefs are due August 20, 2007, with reply briefs due September 4, 2007. Oral arguments are expected to take place in late 2007 or early 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the financial condition and results of operations of Met-Ed, Penelec and FirstEnergy.

As of June 30, 2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the 2006 comprehensive transition rate case, the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation were $493 million and $127 million, respectively. $82 million of Penelec’s deferral is subject to final resolution of an IRS settlement associated with NUG trust fund proceeds. During the PPUC’s annual audit of Met-Ed’s and Penelec’s NUG stranded cost balances in 2006, it noted a modification to the NUG purchased power stranded cost accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC Order was entered requiring Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded cost accounting methodology modification had not been implemented. As a result of this PPUC order, Met-Ed recognized a pre-tax charge of approximately $10.3 million in the third quarter of 2006, representing incremental costs deferred under the revised methodology in 2005. Met-Ed and Penelec continue to believe that the stranded cost accounting methodology modification is appropriate and on August 24, 2006 filed a petition with the PPUC pursuant to its order for authorization to reflect the stranded cost accounting methodology modification effective January 1, 1999. Hearings on this petition were held in late February 2007 and briefing was completed on March 28, 2007. The ALJ’s initial decision was issued on May 3, 2007 and denied Met-Ed's and Penelec’s request to modify their NUG stranded cost accounting methodology. The companies filed exceptions to the initial decision on May 23, 2007 and replies to those exceptions were filed on June 4, 2007. It is not known when the PPUC may issue a final decision in this matter.

On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from June 2008 through May 2011. The filing proposes multiple, competitive RFPs with staggered delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service will be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. The PPUC is requested to act on the proposal no later than November 2007 for the initial RFP to take place in January 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 programs to meet demand 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 an optional 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 will be convened in mid-September 2007 to consider other aspects of the EIS. The final form of any legislation arising from the special legislative session is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.

~~(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 June 30, 2007, the accumulated deferred cost balance totaled approximately $392 million.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a 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. 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 PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that would 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. Comments on the alternative proposal were submitted on June 15, 2006. On November 3, 2006, the Staff circulated a revised draft proposal to interested stakeholders. Another revised draft was circulated by the NJBPU Staff on February 8, 2007.

New Jersey statutes require that the state periodically undertake a planning process, known as the Energy Master Plan (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 with the issuance of a proposed set of objectives which, as to electricity, included the following:

·~~Reduce the total projected electricity demand by 20% by 2020;~~

·~~Meet 22.5% of New Jersey’s electricity needs with renewable energy resources by that date;~~

·~~Reduce air pollution related to energy use;~~

·~~Encourage and maintain economic growth and development;~~

· ~~Achieve a 20% reduction in both Customer Average Interruption Duration Index and System Average Interruption Frequency Index by 2020;~~

· ~~Unit prices for electricity should remain no more than +5% of the regional average price (region includes New York, New Jersey, Pennsylvania,~~

~~Delaware, Maryland and the District of Columbia); and~~

·~~Eliminate transmission congestion by 2020.~~

Comments on the objectives and participation in the development of the EMP have been solicited and a number of working groups have been formed to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. EMP working groups addressing (1) energy efficiency and demand response, (2) renewables, (3) reliability, and (4) pricing issues have completed their assigned tasks of data gathering and analysis and have provided reports to the EMP Committee. Public stakeholder meetings were held in the fall of 2006 and in early 2007, and further public meetings are expected later in 2007. A final draft of the EMP is expected to be presented to the Governor in late 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation 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 August 1, 2007, the NJBPU approved publication of a formal proposal in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following a period for public comment. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such regulations may have on its operations or those of JCP&L.

~~(E) FERC MATTERS~~

On November 18, 2004, the FERC issued an order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECA mechanism to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES participated in the FERC hearings held in May 2006 concerning the calculation and imposition of the SECA charges. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by the RTOs and transmission owners, ruling on various issues and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in the third quarter of 2007.

On January 31, 2005, certain PJM transmission owners made three 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. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. Hearings were held and numerous parties appeared and litigated various issues; including American Electric Power Company, Inc., which filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. At the conclusion of the hearings, the ALJ issued an initial decision adopting the FERC Trial Staff’s position that the cost of all PJM transmission facilities should be recovered through a postage stamp rate.The ALJ recommended an April 1, 2006 effective date for this change in rate design. Numerous parties, including FirstEnergy, submitted briefs opposing the ALJ’s decision and recommendations. On April 19, 2007, the FERC issued an order rejecting the ALJ’s findings and recommendations in nearly every respect. The FERC found that the PJM transmission owners’ existing “license plate” 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 socialized 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. Nevertheless, 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. Subsequently, FirstEnergy and other parties filed pleadings opposing the requests for rehearing. The FERC’s Orders on PJM rate design, if sustained on rehearing and appeal, will prevent the allocation of the cost 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 future transmission costs shifting to the JCP&L, Met-Ed and Penelec zones.

On August 1, 2007, a number of filings were made with the FERC by transmission owning utilities in the MISO and PJM footprint that could affect the transmission rates paid by FirstEnergy’s operating companies and FES.

FirstEnergy joined in a filing made by the MISO transmission owners that would maintain the existing “license plate” rates for transmission service within MISO provided over existing transmission facilities. FirstEnergy also joined in a filing made by both the MISO and PJM transmission owners proposing to maintain existing transmission rates between MISO and PJM. If accepted by the FERC, these filings would not affect the rates charged to load-serving FirstEnergy affiliates for transmission service over existing transmission facilities. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV transmission facilities across the entire MISO footprint be maintained. All of these filings were supported by the majority of transmission owners in either MISO or PJM.

The Midwest Stand-Alone Transmission Companies made a filing under Section 205 of the Federal Power Act requesting that 100% of the cost of new qualifying 345 kV transmission facilities be spread throughout the entire MISO footprint. If adopted by the FERC, this proposal would shift a greater portion of the cost of new 345 kV transmission facilities to the FirstEnergy footprint, and increase the transmission rates paid by load-serving FirstEnergy affiliates.

American Electric Power (AEP) filed a letter with the FERC Commissioners stating its intent to file a complaint under Section 206 of the Federal Power Act challenging the justness and reasonableness of the rate designs underlying the MISO and PJM transmission tariffs. AEP will propose the adoption of a regional rate design that is expected to reallocate the cost of both existing and new high voltage transmission facilities across the combined MISO and PJM footprint. Based upon the position advocated by AEP in a related proceeding, the AEP proposal is expected to result in a greater allocation of costs to FirstEnergy transmission zones in MISO and PJM. If approved by the FERC, AEP’s proposal would increase the transmission rates paid by load-serving FirstEnergy affiliates.

Any increase in rates charged for transmission service to FirstEnergy affiliates is dependent upon the outcome of these proceedings at FERC. All or some of these proceedings may be consolidated by the FERC and set for hearing. The outcome of these cases cannot be predicted. Any material adverse impact on FirstEnergy would depend upon the ability of the load-serving FirstEnergy affiliates to recover increased transmission costs in their retail rates. FirstEnergy believes that current retail rate mechanisms in place for PLR service for the Ohio Companies and for Met-Ed and Penelec would permit them to pass through increased transmission charges in their retail rates. Increased transmission charges in the JCP&L and Penn transmission zones would be the responsibility of competitive electric retail suppliers, including FES.

On February 15, 2007, MISO filed documents with the FERC to establish a market-based, competitive ancillary services market. MISO contends that the filing will integrate operating reserves into MISO’s existing day-ahead and real-time settlements process, incorporate opportunity costs into these markets, address scarcity pricing through the implementation of a demand curve methodology, foster demand response in the provision of operating reserves, and provide for various efficiencies and optimization with regard to generation dispatch. The filing also proposes amendments to existing documents to provide for the transfer of balancing functions from existing local balancing authorities to MISO. MISO will then carry out this reliability function as the NERC-certified balancing authority for the MISO region with implementation in the third or fourth quarter of 2008. FirstEnergy filed comments on March 23, 2007, supporting the ancillary service market in concept, but proposing certain changes in MISO’s proposal. MISO requested FERC action on its filing by June 2007 and the FERC issued its Order June 22, 2007. The FERC found MISO’s filing to be deficient in two key areas: (1) MISO has not submitted a market power analysis in support of its proposed Ancillary Services Market and (2) MISO has not submitted a readiness plan to ensure reliability during the transition from the current reserve and regulation system managed by the individual Balancing Authorities to a centralized Ancillary Services Market managed by MISO. MISO was ordered to remedy these deficiencies and the FERC provided more guidance on other issues brought up in filings by stakeholders to assist MISO to re-file a complete proposal. This Order should facilitate MISO’s timetable to incorporate final revisions to ensure a market start in Spring 2008. FirstEnergy will be participating in working groups and task forces to ensure the Spring 2008 implementation of the Ancillary Services Market.

On February 16, 2007, the FERC issued a final rule that revises its decade-old open access transmission regulations and policies. The FERC explained that the final rule is intended to strengthen non-discriminatory access to the transmission grid, facilitate FERC enforcement, and provide for a more open and coordinated transmission planning process. The final rule became effective on May 14, 2007. MISO, PJM and ATSI will be filing revised tariffs to comply with the FERC’s order. As a market participant in both MISO and PJM, FirstEnergy will conform its business practices to each respective revised tariff.

~~11. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS~~

~~SFAS 159 – “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115”~~

In February 2007, the FASB issued SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value. This Statement requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. The Standard also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157~~and SFAS 107~~. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.

~~SFAS 157 – “Fair Value Measurements”~~

In September 2006, the FASB issued SFAS 157 that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value which focuses on an exit price rather than entry price; (2) the methods used to measure fair value such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.

~~EITF 06-11 – “Accounting for Income Tax Benefits of Dividends or Share-based Payment Awards”~~

In June 2007, the FASB released EITF 06-11, which provides guidance on the appropriate accounting for income tax benefits related to dividends earned on nonvested share units that are charged to retained earnings under SFAS 123(R). The consensus requires that an entity recognize the realized tax benefit associated with the dividends on nonvested shares as an increase to additional paid-in capital (APIC). This amount should be included in the APIC pool, which is to be used when an entity’s estimate of forfeitures increases or actual forfeitures exceed its estimates, at which time the tax benefits in the APIC pool would be reclassified to the income statement. The consensus is effective for income tax benefits of dividends declared during fiscal years beginning after December 15, 2007. EITF 06-11 is not expected to have a material effect on FirstEnergy’s financial statements.

~~12. SEGMENT INFORMATION~~

Effective January 1, 2007, FirstEnergy has three reportable operating segments: competitive energy services, energy delivery services and Ohio transitional generation services. None of the aggregate “Other” segments individually meet the criteria to be considered a reportable segment. The competitive energy services segment primarily consists of unregulated generation and commodity operations, including competitive electric sales, and generation sales to affiliated electric utilities. The energy delivery services segment consists of regulated transmission and distribution operations, including transition cost recovery, and PLR generation service for FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. The Ohio transitional generation services segment represents PLR generation service by FirstEnergy’s Ohio electric utility subsidiaries. “Other” primarily consists of telecommunications services and other non-core assets. The assets and revenues for the 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 PLR 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 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 sales primarily in Ohio, Pennsylvania, Maryland and Michigan and owns 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 power 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 power sales.

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 securing electric generation from the competitive energy services segment through full requirements PSA arrangements and the net MISO transmission revenues and expenses related to the delivery of that generation load.

Segment reporting in 2006 has been revised to conform to the current year business segment organization and operations. Changes in the current year operations reporting and revised 2006 segment reporting primarily reflect the transfer from FES to the regulated utilities of the responsibility for obtaining PLR generation for the utilities’ non-shopping customers. This reflects FirstEnergy’s alignment of its business units to accommodate its retail strategy and participation in competitive electricity marketplaces in Ohio, Pennsylvania and New Jersey. The differentiation of the regulated generation commodity operations between the two regulated business segments recognizes that generation sourcing for the Ohio Companies is currently in a transitional state through 2008 as compared to the segregated commodity sourcing of their Pennsylvania and New Jersey utility affiliates. The results of the energy delivery services and the Ohio transitional generation services segments now include their electric generation revenues and the corresponding generation commodity costs under affiliated and non-affiliated purchased power arrangements and related net retail PJM/MISO transmission expenses associated with serving electricity load in their respective franchise areas.

FSG completed the sale of its five remaining subsidiaries in 2006. Its assets and results for 2006 are combined in the “Other” segments in this report, as the remaining business does not meet the criteria of a reportable segment. Interest expense on holding company debt and corporate support services revenues and expenses are included in "Reconciling Items."

Segment Financial Information

Ohio

Energy

Competitive

Transitional

Delivery

Energy

Generation

Reconciling

Three Months Ended

Services

Services

Services

Other

Adjustments

Consolidated

(In millions)

June 30, 2007

External revenues $ 2,095 $ 404 $ 625 $ 9 $ (24 ) $ 3,109
Internal revenues - 691 - - (691 ) -
Total revenues 2,095 1,095 625 9 (715 ) 3,109
Depreciation and amortization 249 51 (49 ) 1 5 257
Investment income 62 5 - - (37 ) 30
Net interest charges 116 42 - 1 39 198
Income taxes 141 96 19 (3 ) (31 ) 222
Net income 207 142 30 6 (47 ) 338
Total assets 23,602 7,284 260 236 651 32,033
Total goodwill 5,873 24 - 1 - 5,898
Property additions 245 139 - 2 15 401

June 30, 2006

External revenues $ 1,773 $ 384 $ 575 $ 39 $ (20 ) $ 2,751
Internal revenues 6 623 - - (629 ) -
Total revenues 1,779 1,007 575 39 (649 ) 2,751
Depreciation and amortization 173 48 (29 ) 1 6 199
Investment income 81 2 - - (52 ) 31
Net interest charges 102 47 - 2 22 173
Income taxes 155 67 22 2 (30 ) 216
Income from
continuing operations 233 101 31 (7 ) (46 ) 312
Discontinued operations - - - (8 ) - (8 )
Net income 233 101 31 (15 ) (46 ) 304
Total assets 24,399 6,740 231 355 853 32,578
Total goodwill 5,916 24 - - - 5,940
Property additions 177 103 - - 12 292

Six Months Ended

June 30, 2007

External revenues $ 4,135 $ 732 $ 1,245 $ 20 $ (50 ) $ 6,082
Internal revenues - 1,404 - - (1,404 ) -
Total revenues 4,135 2,136 1,245 20 (1,454 ) 6,082
Depreciation and amortization 469 102 (64 ) 2 11 520
Investment income 132 8 1 - (78 ) 63
Net interest charges 223 92 1 2 60 378
Income taxes 289 160 35 2 (64 ) 422
Net income 425 240 53 7 (97 ) 628
Total assets 23,602 7,284 260 236 651 32,033
Total goodwill 5,873 24 - 1 - 5,898
Property additions 400 263 - 3 31 697

June 30, 2006

External revenues $ 3,570 $ 738 $ 1,118 $ 68 $ (38 ) $ 5,456
Internal revenues 14 1,235 - - (1,249 ) -
Total revenues 3,584 1,973 1,118 68 (1,287 ) 5,456
Depreciation and amortization 430 94 (49 ) 2 11 488
Investment income 164 17 - 1 (108 ) 74
Net interest charges 201 90 1 3 38 333
Income taxes 281 89 40 (3 ) (55 ) 352
Income from
continuing operations 422 133 61 5 (90 ) 531
Discontinued operations - - - (6 ) - (6 )
Net income 422 133 61 (1 ) (90 ) 525
Total assets 24,399 6,740 231 355 853 32,578
Total goodwill 5,916 24 - - - 5,940
Property additions 370 347 - - 22 739

~~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.~~

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2007

2006

2007

2006

(In millions, except per share amounts)

REVENUES:

Electric utilities $ 2,744 $ 2,341 $ 5,425 $ 4,681
Unregulated businesses 365 410 657 775
Total revenues * 3,109 2,751 6,082 5,456

EXPENSES:

Fuel and purchased power 1,185 991 2,306 1,989
Other operating expenses 750 718 1,499 1,471
Provision for depreciation 159 144 315 292
Amortization of regulatory assets 246 201 497 422
Deferral of new regulatory assets (148 ) (146 ) (292 ) (226 )
General taxes 189 173 392 366
Total expenses 2,381 2,081 4,717 4,314

OPERATING INCOME
728 670 1,365 1,142

OTHER INCOME (EXPENSE):

Investment income 30 31 63 74
Interest expense (205 ) (178 ) (390 ) (343 )
Capitalized interest 7 7 12 14
Subsidiaries’ preferred stock dividends - (2 ) - (4 )
Total other expense (168 ) (142 ) (315 ) (259 )

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
560 528 1,050 883

INCOME TAXES
222 216 422 352

INCOME FROM CONTINUING OPERATIONS
338 312 628 531

Discontinued operations (net of income tax expense (benefits) of
$1 million and ($1) million in the three months and
six months ended June 30, 2006, respectively) (Note 3) - (8 ) - (6 )

NET INCOME
$ 338 $ 304 $ 628 $ 525

BASIC EARNINGS PER SHARE OF COMMON STOCK:

Income from continuing operations $ 1.11 $ 0.94 $ 2.03 $ 1.61
Discontinued operations - (0.02 ) - (0.02 )
Net earnings per basic share $ 1.11 $ 0.92 $ 2.03 $ 1.59

WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
304 328 309 328

DILUTED EARNINGS PER SHARE OF COMMON STOCK:

Income from continuing operations $ 1.10 $ 0.93 $ 2.01 $ 1.60
Discontinued operations - (0.02 ) - (0.02 )
Net earnings per diluted share $ 1.10 $ 0.91 $ 2.01 $ 1.58

WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
308 330 313 330

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK
$ 0.50 $ 0.45 $ 1.00 $ 0.90

* Includes excise tax collections of $102 million and $90 million in the second quarter of 2007 and 2006, respectively, and $206 million
and $189 million in the six months ended June 2007 and 2006, respectively.

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

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2007

2006

2007

2006

(In millions)

NET INCOME
$ 338 $ 304 $ 628 $ 525

OTHER COMPREHENSIVE INCOME (LOSS):

Pension and other postretirement benefits (11 ) - (22 ) -
Unrealized gain (loss) on derivative hedges (1 ) 36 20 73
Change in unrealized gain on available for sale securities 46 (24 ) 63 13
Other comprehensive income 34 12 61 86
Income tax expense related to other
comprehensive income 10 4 19 31
Other comprehensive income, net of tax 24 8 42 55

COMPREHENSIVE INCOME
$ 362 $ 312 $ 670 $ 580

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

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30,

December 31,

2007

2006

(In millions)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ 37 $ 90
Receivables-
Customers (less accumulated provisions of $39 million and
$43 million, respectively, for uncollectible accounts) 1,413 1,135
Other (less accumulated provisions of $22 million and
$24 million, respectively, for uncollectible accounts) 181 132
Materials and supplies, at average cost 583 577
Prepayments and other 322 149
2,536 2,083
PROPERTY, PLANT AND EQUIPMENT:

In service 24,555 24,105
Less - Accumulated provision for depreciation 10,330 10,055
14,225 14,050
Construction work in progress 785 617
15,010 14,667
INVESTMENTS:

Nuclear plant decommissioning trusts 2,092 1,977
Investments in lease obligation bonds 738 811
Other 734 746
3,564 3,534
DEFERRED CHARGES AND OTHER ASSETS:

Goodwill 5,898 5,898
Regulatory assets 4,155 4,441
Pension assets 297 -
Other 573 573
10,923 10,912
$ 32,033 $ 31,196
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Currently payable long-term debt $ 2,000 $ 1,867
Short-term borrowings 2,416 1,108
Accounts payable 801 726
Accrued taxes 320 598
Other 745 956
6,282 5,255
CAPITALIZATION:

Common stockholders’ equity-
Common stock, $.10 par value, authorized 375,000,000 shares-
304,835,407 and 319,205,517 shares outstanding, respectively 30 32
Other paid-in capital 5,550 6,466
Accumulated other comprehensive loss (217 ) (259 )
Retained earnings 3,279 2,806
Unallocated employee stock ownership plan common stock-
134,681 and 521,818 shares, respectively (2 ) (10 )
Total common stockholders' equity 8,640 9,035
Long-term debt and other long-term obligations 8,742 8,535
17,382 17,570
NONCURRENT LIABILITIES:

Accumulated deferred income taxes 2,849 2,740
Asset retirement obligations 1,228 1,190
Power purchase contract loss liability 877 1,182
Retirement benefits 917 944
Lease market valuation liability 704 767
Other 1,794 1,548
8,369 8,371
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)

$ 32,033 $ 31,196

The preceding 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)

Six Months Ended

June 30,

2007

2006

(In millions)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 628 $ 525
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 315 292
Amortization of regulatory assets 497 421
Deferral of new regulatory assets (292 ) (226 )
Nuclear fuel and lease amortization 50 42
Deferred purchased power and other costs (185 ) (239 )
Deferred income taxes and investment tax credits, net 85 32
Investment impairment 12 12
Deferred rents and lease market valuation liability (92 ) (105 )
Accrued compensation and retirement benefits (69 ) 33
Commodity derivative transactions, net 4 25
Gain on asset sales (12 ) (4 )
Income from discontinued operations - 6
Cash collateral (19 ) (55 )
Pension trust contribution (300 ) -
Decrease (increase) in operating assets-
Receivables (282 ) 83
Materials and supplies 22 (71 )
Prepayments and other current assets (157 ) (159 )
Increase (decrease) in operating liabilities-
Accounts payable 28 (40 )
Accrued taxes (17 ) (45 )
Electric service prepayment programs (36 ) (29 )
Other (49 ) (13 )
Net cash provided from operating activities 131 485

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Long-term debt 800 1,053
Short-term borrowings, net 1,308 371
Redemptions and Repayments-
Common stock (918 ) -
Preferred stock - (30 )
Long-term debt (471 ) (485 )
Net controlled disbursement activity 32 5
Stock-based compensation tax benefit 14 -
Common stock dividend payments (311 ) (296 )
Net cash provided from financing activities 454 618

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (697 ) (739 )
Proceeds from asset sales 12 63
Sales of investment securities held in trusts 583 959
Purchases of investment securities held in trusts (591 ) (966 )
Cash investments 54 118
Other 1 (19 )
Net cash used for investing activities (638 ) (584 )

Net increase (decrease) in cash and cash equivalents (53 ) 519
Cash and cash equivalents at beginning of period 90 64
Cash and cash equivalents at end of period $ 37 $ 583

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

~~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 June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 30, 2007 and 2006. 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, 2006, and the related consolidated statements of income, capitalization, common stockholders’ equity, preferred stock, and of 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 defined benefit pension and other postretirement benefit plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(K) and Note 12 to the consolidated financial statements) dated February 27, 2007, 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, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~August 6, 2007~~

~~FIRSTENERGY CORP.~~

~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~EXECUTIVE SUMMARY~~

Net income in the second quarter of 2007 was $338 million, or basic earnings of $1.11 per share of common stock ($1.10 diluted), compared with net income of $304 million, or basic earnings of $0.92 per share of common stock ($0.91 diluted) in the second quarter of 2006. Net income in the first six months of 2007 was $628 million, or basic earnings of $2.03 per share of common stock ($2.01 diluted), compared with net income of $525 million, or basic earnings of $1.59 per share of common stock ($1.58 diluted) in the first six months of 2006. The increases in FirstEnergy’s earnings in both periods of 2007 were driven primarily by higher electric sales revenues, partially offset by increased fuel and purchased power costs, higher other operating expenses and increased interest expense.

Change in Basic Earnings Per Share
From Prior Year Periods

Three Months Ended June 30,

Six Months
Ended June 30,

Basic Earnings Per Share – 2006 $ 0.92 $ 1.59
Revenues 0.71 1.22
Fuel and purchased power (0.38 ) (0.62 )
Depreciation and amortization (0.12 ) (0.19 )
Deferral of new regulatory assets - 0.08
Other expenses (0.03 ) (0.10 )
Non-core asset sales/impairments - 2006 0.03 0.03
Saxton decommissioning regulatory asset -2007 - 0.05
Trust securities impairment - 2007 (0.02 ) (0.03 )
Basic Earnings Per Share – 2007 $ 1.11 $ 2.03

~~Financial Matters~~

On July 13, 2007, FGCO completed a $1.3 billion sale and leaseback transaction for its 779 MW portion of the Bruce Mansfield Plant Unit 1. The terms of the agreement provide for an approximate 33-year lease of the unit. There will be no material gain from this transaction reflected in earnings during the third quarter of 2007. FirstEnergy used the net, after-tax proceeds of approximately $1.2 billion to repay short-term debt that was used to fund its recent $900 million share repurchase program and $300 million pension contribution. FGCO will continue to operate the plant.

On May 21, 2007, JCP&L issued $550 million of senior unsecured debt securities. The offering was in two tranches, consisting of $250 million of 5.65% Senior Notes due 2017 and $300 million of 6.15% Senior Notes due 2037. The proceeds from the transaction were used to redeem all of JCP&L’s outstanding first mortgage bonds, repay short-term debt and repurchase common stock from FirstEnergy.

~~Regulatory Matters~~

~~Ohio~~

On June 7, 2007, the Ohio Companies filed their base distribution rate increase request and supporting testimony with the PUCO. The requested increase (updated on August 6, 2007) in annualized distribution revenues of approximately $332 million is needed to recover expenses related to distribution operations and the costs deferred under previously approved rate plans. Concurrent with the effective dates of the proposed distribution rate increases, the Ohio Companies will reduce or eliminate their RTC, resulting in a net reduction of $262 million on the regulated portion of customers’ bills. The PUCO Staff is expected to issue its report in the case in the fourth quarter of 2007 with evidentiary hearings to follow in late 2007. The PUCO order is expected to be issued by March 9, 2008. The new rates would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.

On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per kilowatt-hour included in rates would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. The proposal also provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The Ohio Companies requested that the PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process.

~~Pennsylvania~~

On May 2, 2007, Penn made a filing with the PPUC proposing how it will procure the power supply needed for default service customers from June 1, 2008 through May 2011. Hearings are scheduled for September 10-11, 2007, with a recommended ALJ decision expected by October 25, 2007. A PPUC order is expected by November 29, 2007. The initial RFP is expected to take place in January 2008.

On May 3, 2007, an ALJ issued her initial decision denying Met-Ed’s and Penelec’s request to modify their NUG stranded cost accounting methodology. The companies filed exceptions to the initial decision on May 23, 2007 and replies to those exceptions were filed on June 4, 2007. It is not known when the PPUC may issue a final decision in this matter.

On June 19, 2007, initial briefs were filed with the Commonwealth Court of Pennsylvania by all parties in the appeal of Met-Ed’s and Penelec’s comprehensive rate filing. Responsive briefs are due August 20, 2007, with reply briefs due September 4, 2007. Met-Ed and Penelec appealed the PPUC’s decision on the denial of generation rate relief and consolidated tax savings, while other parties appealed the PPUC’s decision on transmission rate relief. Oral arguments are expected to take place in the fourth quarter of 2007.

~~Operations~~

Second Quarter KWH Sales Record - FirstEnergy set a new second quarter generation sales record in 2007 of 32.8 billion KWH, which represents a 2.9% increase over the second quarter of 2006. Distribution deliveries also increased in the second quarter to 26.9 billion KWH – a 4.4% increase from the second quarter of 2006. The higher KWH sales and distribution deliveries were primarily attributable to continued customer growth in FirstEnergy’s service territories and weather impacts during the quarter.

Generation Output Record - FirstEnergy set a new second quarter generation output record of 20.4 billion KWH in 2007, which represents a 0.4% increase over the prior record established last year. The generation record was primarily attributable to performance of the fossil generation fleet, which established its best quarterly output ever.

NRC Demand for Information - On May 14, 2007, the NRC issued a Demand for Information related to recent reports prepared for arbitration of an insurance claim for replacing the damaged reactor head at the Davis-Besse Plant in 2002. FENOC responded to the NRC on June 13, 2007. FirstEnergy officials participated in a public meeting with the NRC on June 27, 2007 to discuss circumstances leading up to the Demand for Information and FENOC’s response. In follow-up discussions, FENOC was requested to provide supplemental information to clarify certain aspects of the Demand for Information response and to provide supplemental details regarding plans to implement the commitments established therein. This supplemental information was submitted to the NRC on July 16, 2007.

Perry Plant Outage - FirstEnergy’s Perry Nuclear Power Plant completed its regularly scheduled refueling outage on May 13, 2007. Major work activities performed on the 1,258 MW facility included replacing approximately one-third of the fuel assemblies in the reactor and two of the three low-pressure turbine rotors in the main generator. On June 29, 2007, Perry began an unplanned outage to replace a 30-ton motor in the reactor recirculation system. In addition to the motor replacement, routine and preventive maintenance and several system inspections will be performed during the outage to assure continued safe and reliable operation of the plant. On July 25, 2007 the plant was returned to service.

Environmental Update - On May 30, 2007, FirstEnergy announced that FGCO plans to install an ECO system on Units 4 and 5 of its R.E. Burger Plant. Design engineering for the new Burger Plant ECO system will begin in 2007 with an anticipated start-up date in the first quarter of 2011. The incremental cost installing the system at the Burger Plant instead of Bay Shore Unit 4, as originally planned, is approximately $38 million.

~~FIRSTENERGY’S BUSINESS~~

~~FirstEnergy is a diversified energy company headquartered in Akron, Ohio, that operates primarily through three core business segments (see Results of Operations).~~

~~Energy Delivery Services~~ transmits and distributes electricity through FirstEnergy's eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey and purchases power for its PLR requirements in Pennsylvania and New Jersey. This business segment derives its revenues principally from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation service to non-shopping retail customers under the PLR obligations in its Pennsylvania and New Jersey franchise areas. Its net income reflects the commodity costs of securing electricity from the Competitive Energy Services Segment under partial requirements purchased power agreements with FES and non-affiliated power suppliers, including associated transmission costs.

~~Competitive Energy Services~~ supplies the electric power needs of end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the PLR requirements of FirstEnergy's Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business segment owns or leases and operates FirstEnergy's generating facilities and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from affiliated company power sales and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission and ancillary costs charged by PJM and MISO to deliver energy to the segment’s customers.

~~Ohio Transitional Generation Services~~ supplies the electric power needs of non-shopping customers under the PLR requirements of FirstEnergy's Ohio Companies. The segment's net income is primarily derived from electric generation sales revenues less the cost of power purchased from the competitive energy services segment through a full-requirements PSA arrangement with FES, including net transmission and ancillary costs charged by MISO to deliver energy to retail customers.

~~RESULTS OF OPERATIONS~~

The financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 12 to the consolidated financial statements. Net income by major business segment was as follows:

Three Months Ended June 30,

Six Months Ended June 30,

Increase

Increase

2007

2006

(Decrease)

2007

2006

(Decrease)

(In millions, except per share amounts)

Net Income (Loss)

By Business Segment:

Energy delivery services $ 207 $ 233 $ (26 ) $ 425 $ 422 $ 3
Competitive energy services 142 101 41 240 133 107
Ohio transitional generation services 30 31 (1 ) 53 61 (8 )
Other and reconciling adjustments* (41 ) (61 ) 20 (90 ) (91 ) 1
Total $ 338 $ 304 $ 34 $ 628 $ 525 $ 103

Basic Earnings Per Share:

Income from continuing operations $ 1.11 $ 0.94 $ 0.17 $ 2.03 $ 1.61 $ 0.42
Discontinued operations - (0.02 ) 0.02 - (0.02 ) 0.02
Net earnings per basic share $ 1.11 $ 0.92 $ 0.19 $ 2.03 $ 1.59 $ 0.44

Diluted Earnings Per Share:

Income from continuing operations $ 1.10 $ 0.93 $ 0.17 $ 2.01 $ 1.60 $ 0.41
Discontinued operations - (0.02 ) 0.02 - (0.02 ) 0.02
Net earnings per diluted share $ 1.10 $ 0.91 $ 0.19 $ 2.01 $ 1.58 $ 0.43

* Represents other operating segments and reconciling items including interest expense on holding company debt and corporate

~~support services revenues and expenses.~~

~~Summary of Results of Operations – Second Quarter of 2007 Compared with the Second Quarter of 2006~~

~~Financial results for FirstEnergy's major business segments in the second quarter of 2007 and 2006 were as follows:~~

Ohio

Energy

Competitive

Transitional

Other and

Delivery

Energy

Generation

Reconciling

FirstEnergy

Second Quarter 2007 Financial Results

Services

Services

Services

Adjustments

Consolidated

(In millions)

Revenues:
External
Electric $ 1,933 $ 359 $ 612 $ - $ 2,904
Other 162 45 13 (15 ) 205
Internal - 691 - (691 ) -
Total Revenues 2,095 1,095 625 (706 ) 3,109

Expenses:
Fuel and purchased power 879 460 537 (691 ) 1,185
Other operating expenses 410 283 87 (30 ) 750
Provision for depreciation 100 51 - 8 159
Amortization of regulatory assets 242 - 6 (2 ) 246
Deferral of new regulatory assets (93 ) - (55 ) - (148 )
General taxes 155 26 1 7 189
Total Expenses 1,693 820 576 (708 ) 2,381

Operating Income 402 275 49 2 728
Other Income (Expense):
Investment income 62 5 - (37 ) 30
Interest expense (118 ) (47 ) - (40 ) (205 )
Capitalized interest 2 5 - - 7
Total Other Expense (54 ) (37 ) - (77 ) (168 )

Income From Continuing Operations Before
Income Taxes 348 238 49 (75 ) 560
Income taxes 141 96 19 (34 ) 222
Net Income $ 207 $ 142 $ 30 $ (41 ) $ 338

Ohio

Energy

Competitive

Transitional

Other and

Delivery

Energy

Generation

Reconciling

FirstEnergy

Second Quarter 2006 Financial Results

Services

Services

Services

Adjustments

Consolidated

(In millions)

Revenues:
External
Electric $ 1,646 $ 338 $ 569 $ - $ 2,553
Other 127 46 6 19 198
Internal 6 623 - (629 ) -
Total Revenues 1,779 1,007 575 (610 ) 2,751

Expenses:
Fuel and purchased power 690 434 496 (629 ) 991
Other operating expenses 363 289 53 13 718
Provision for depreciation 89 48 - 7 144
Amortization of regulatory assets 197 - 4 - 201
Deferral of new regulatory assets (113 ) - (33 ) - (146 )
General taxes 144 23 2 4 173
Total Expenses 1,370 794 522 (605 ) 2,081

Operating Income 409 213 53 (5 ) 670
Other Income (Expense):
Investment income 81 2 - (52 ) 31
Interest expense (101 ) (50 ) - (27 ) (178 )
Capitalized interest 4 3 - - 7
Subsidiaries' preferred stock dividends (5 ) - - 3 (2 )
Total Other Expense (21 ) (45 ) - (76 ) (142 )

Income From Continuing Operations Before
Income Taxes 388 168 53 (81 ) 528
Income taxes 155 67 22 (28 ) 216
Income from continuing operations 233 101 31 (53 ) 312
Discontinued operations - - - (8 ) (8 )
Net Income $ 233 $ 101 $ 31 $ (61 ) $ 304

Changes Between Second Quarter 2007 and

Second Quarter 2006 Financial Results

Increase (Decrease)

Revenues:
External
Electric $ 287 $ 21 $ 43 $ - $ 351
Other 35 (1 ) 7 (34 ) 7
Internal (6 ) 68 - (62 ) -
Total Revenues 316 88 50 (96 ) 358

Expenses:
Fuel and purchased power 189 26 41 (62 ) 194
Other operating expenses 47 (6 ) 34 (43 ) 32
Provision for depreciation 11 3 - 1 15
Amortization of regulatory assets 45 - 2 (2 ) 45
Deferral of new regulatory assets 20 - (22 ) - (2 )
General taxes 11 3 (1 ) 3 16
Total Expenses 323 26 54 (103 ) 300

Operating Income (7 ) 62 (4 ) 7 58
Other Income (Expense):
Investment income (19 ) 3 - 15 (1 )
Interest expense (17 ) 3 - (13 ) (27 )
Capitalized interest (2 ) 2 - - -
Subsidiaries' preferred stock dividends 5 - - (3 ) 2
Total Other Income (33 ) 8 - (1 ) (26 )

Income From Continuing Operations Before
Income Taxes (40 ) 70 (4 ) 6 32
Income taxes (14 ) 29 (3 ) (6 ) 6
Income from continuing operations (26 ) 41 (1 ) 12 26
Discontinued operations - - - 8 8
Net Income $ (26 ) $ 41 $ (1 ) $ 20 $ 34

Net income increased $3 million (or 1%) to $425 million in the first six months of 2007 compared to $422 million in the first six months of 2006, primarily due to increased revenues partially offset by higher operating expenses and lower investment income.

~~Revenues –~~

~~The increase in total revenues resulted from the following sources:~~

Six Months Ended

June 30,

Revenues by Type of Service

2007

2006

Increase

(In millions)

Distribution services

$
1,892

$
1,848

$
44

Generation sales:

Retail

1,476

1,281

195

Wholesale

281

105

176

Total generation sales

1,757

1,386

371

Transmission

376

247

129

Other

110

103

7

Total Revenues

$
4,135

$
3,584

$
551

~~The increases in distribution deliveries by customer class are summarized in the following table:~~

~~Electric Distribution Deliveries~~
~~Residential~~	~~8.0~~	%
~~Commercial~~	~~4.6~~	%
~~Industrial~~	-
~~Total Distribution Deliveries~~	~~4.2~~	%

The increase in electric distribution deliveries to customers was primarily due to higher weather-related usage during the first six months of 2007 compared to the same period of 2006 (heating degree days increased by 15.4% and cooling degree days increased by 39.8%). The higher revenues from increased distribution deliveries were offset principally by distribution rate decreases for Met-Ed and Penelec as a result of a January 11, 2007 PPUC rate decision (see Outlook – State Regulatory Matters – Pennsylvania).

~~The following table summarizes the price and volume factors contributing to the $371 million increase in non-affiliated generation sales revenues in 2007 compared to 2006:~~

Sources of Change in Generation Sales

Increase

(In millions)

Retail:
  Effect of 0.6% increase in customer usage $ 8
  Change in prices

187

195

Wholesale:
  Effect of 135% increase in KWH sales 141
  Change in prices

35

176

Net Increase in Generation Sales $ 371

The increase in retail generation prices during the first six months of 2007 compared to 2006 was primarily due to increased generation rates for JCP&L resulting from the New Jersey BGS auction process and an increase in NUGC rates authorized by the NJBPU. Wholesale generation sales increased principally as a result of Met-Ed and Penelec selling additional available power into the PJM market beginning in January 2007.

Transmission revenues increased $129 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization for transmission cost recovery. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred, with no material effect on current period earnings

~~Expenses –~~

~~The net increases in revenues discussed above were partially offset by a $486 million increase in expenses due to the following:~~

Purchased power costs were $339 million higher in the first six months of 2007 due to higher unit costs and volumes purchased. The increased unit prices reflected the effect of higher JCP&L purchased power unit costs resulting from the BGS auction process. The increased KWH purchases in 2007 were due in part to higher customer usage and sales to the wholesale market. The following table summarizes the sources of changes in purchased power costs:

Sources of Change in Purchased Power

Increase

(In millions)

Purchased Power:
   Change due to increased unit costs $ 168
   Change due to increased volume 128
   Decrease in NUG costs deferred 43
      Net Increase in Purchased Power Costs $ 339

~~Other operating expenses increased $90 million due to the net effects of:~~

-	~~An increase of $101 million in MISO and PJM transmission expenses, resulting primarily from higher congestion costs;~~

-	~~A decrease in miscellaneous operating expenses of $18 million primarily due to reduced billings for employee benefits from FESC; and~~

-	~~An increase in operation and maintenance expenses of $10 million primarily due to reduced employee benefits applicable to construction activities and storm-related costs;~~

~~Amortization of regulatory assets increased $75 million compared to 2006 due primarily to recovery of deferred BGS costs through higher NUGC rates for JCP&L as discussed above; and~~

The deferral of new regulatory assets during the first six months of 2007 was $49 million higher in 2007 primarily due to the deferral of previously expensed decommissioning costs of $27 million related to the Saxton nuclear research facility (see Outlook – State Regulatory Matters - Pennsylvania), increased deferrals of PJM transmission expenses of $10 million and increased RCP Distribution Deferrals of $10 million.

~~Other Income and Expense –~~

Other income decreased $54 million in 2007 compared to the first six months of 2006 primarily due to lower interest income of $32 million resulting from the repayment of notes receivable from affiliates since the second quarter of 2006 and increased interest expense of $26 million related to new debt issuances by CEI and JCP&L.

~~Ohio Transitional Generation Services – First Six Months of 2007 Compared to First Six Months of 2006~~

Net income for this segment decreased to $53 million in the first six months of 2007 from $61 million in the same period last year. Higher generation revenues were offset by higher operating expenses, primarily for purchased power.

~~Revenues –~~

~~The increase in reported segment revenues resulted from the following sources:~~

Six Months Ended

June 30,

Increase

Revenues by Type of Service

2007

2006

(Decrease)

(In millions)

Generation sales:

Retail

$
1,090

$
976

$
114

Wholesale

4

9

(5
)
Total generation sales

1,094

985

109

Transmission

150

132

18

Other

1

1

-

Total Revenues

$
1,245

$
1,118

$
127

~~The following table summarizes the price and volume factors contributing to the increase in sales revenues from retail customers:~~

Source of Change in Generation Sales

Increase

(In millions)

Retail:
Effect of 6% increase in customer usage
$ 54
Change in prices

60

Total Increase in Retail Generation Sales
$
114

The increase in generation sales was primarily due to higher weather-related usage in the first six months of 2007 compared to the same period of 2006 as discussed above and reduced customer shopping. Average prices increased primarily due to higher composite unit prices for returning customers. The percentage of generation services provided by alternative suppliers to total sales delivered by the Ohio Companies in their service areas decreased by 2 percentage points from the same period last year.

~~Expenses -~~

~~Purchased power costs were $127 million higher due primarily to higher unit prices for power purchased from FES. The factors contributing to the higher costs are summarized in the following table:~~

Source of Change in Purchased Power

Increase

(In millions)

Purchases from non-affiliates:
Change due to increased unit costs
$ 7
Change due to volume purchased
1
8
Purchases from FES:
Change due to increased unit costs
76
Change due to volume purchased
43
119
Total Increase in Purchased Power Costs $ 127

The increase in KWH purchases was due to the higher retail generation sales requirements. The higher unit costs resulted from the provision of the full-requirements PSA with FES under which purchased power unit costs reflected the increases in the Ohio Companies’ retail generation sales unit prices.

Other operating expenses increased $29 million primarily due to MISO transmission-related expenses. The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings.

~~Competitive Energy Services – First Six Months of 2007 Compared to First Six Months of 2006~~

Net income for this segment was $240 million in the first six months of 2007 compared to $133 million in the same period last year. This increase reflects an improvement in gross generation margin and lower other operating expenses, which were partially offset by increased depreciation, general taxes and reduced investment income.

~~Revenues –~~

Total revenues increased $163 million in the first six months of 2007 compared to the same period in 2006. This increase primarily resulted from higher unit prices under affiliated generation sales to the Ohio Companies, which was partially offset by lower non-affiliated wholesale sales.

The higher retail revenues resulted from increased sales in both the MISO and PJM markets. Lower non-affiliated wholesale revenues reflected the effect of decreased generation available for the non-affiliated wholesale market due to increased affiliated company power sales under the Ohio Companies’ full-requirements PSA and the partial-requirements power sales agreement with Met-Ed and Penelec.

The increased affiliated company generation revenues were due to higher unit prices and increased KWH sales. Factors contributing to the revenue increase from PSA sales to the Ohio Companies are discussed under the purchased power costs analysis in the Ohio Transitional Generation Services results above. The higher KWH sales to the Pennsylvania affiliates were due to increased Met-Ed and Penelec generation sales requirements. These increases were partially offset by lower sales to Penn due to the implementation of its competitive solicitation process in 2007.

~~The increase in reported segment revenues resulted from the following sources:~~

Six Months Ended

June 30,

Increase

Revenues by Type of Service

2007

2006

(Decrease)

(In millions)

Non-Affiliated Generation Sales:

Retail

$
359

$
267

$
92

Wholesale

276

375

(99
)
Total Non-Affiliated Generation Sales

635

642

(7
)
Affiliated Generation Sales

1,404

1,235

169

Transmission

45

64

(19
)
Other

52

32

20

Total Revenues

$
2,136

$
1,973

$
163

~~Transmission revenues decreased $19 million due to reduced retail load in the MISO market, lower transmission rates and reduced FTR auction revenue.~~

~~The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:~~

Increase

Source of Change in Non-Affiliated Generation Sales

(Decrease)

(In millions)

Retail:
Effect of 19% increase in sales volume
$ 51
Change in prices

41

92

Wholesale:
Effect of 31% decrease in KWH sales
(118 )
Change in prices

19

(99
)
Net Decrease in Non-Affiliated Generation Sales
$
(7
)

Source of Change in Affiliated Generation Sales

Increase

(In millions)

Ohio Companies:
Effect of 5% increase in KWH sales
$ 43
Change in prices

77

120

Pennsylvania Companies:
Effect of 14% increase in KWH sales
40
Change in prices

9

49

Net Increase in Affiliated Generation Sales
$
169

~~Expenses -~~

~~Total expenses were $26 million lower in the first six months of 2007 due to the following factors:~~

Fuel costs were $26 million lower primarily due to reduced coal costs and emission allowance costs offset by increases in nuclear fuel and natural gas consumption. Coal costs were reduced due to a $14 million inventory adjustment and $35 million of reduced coal consumption reflecting lower generation, partially offset by a $19 million increase in coal prices. Reduced emission allowance costs ($12 million) were more than offset by increased natural gas costs ($6 million) and nuclear fuel costs ($9 million) due to increased generation and higher prices; and

~~Nuclear operating costs were $58 million lower due to fewer outages in 2007 compared to 2006 and reduced employee benefit costs.~~

~~Partially offsetting the lower costs were the following:~~

~~Purchased power costs increased $31 million due primarily to higher volumes purchased;~~

~~Higher fossil operating costs of $12 million due to increased labor costs;~~

~~Higher depreciation expenses of $8 million due to property additions; and~~

~~Higher general taxes of $5 million.~~

~~Other Income –~~

Investment income in the first six months of 2007 was $11 million lower than the 2006 period primarily due to decreased earnings on nuclear decommissioning trust investments (including a $12 million impairment).

~~Other – First Six Months of 2007 Compared to First Six Months of 2006~~

FirstEnergy’s financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $1 million increase in FirstEnergy’s net income in the first six months of 2007. The increase was caused by the absence of a $6 million loss included in 2006 results from discontinued operations (see Note 3) offset by increased interest expense in 2007 compared to 2006 due to higher short-term borrowings.

~~CAPITAL RESOURCES AND LIQUIDITY~~

FirstEnergy’s business is capital intensive, requiring considerable capital resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2007 and in subsequent years, FirstEnergy expects to satisfy these requirements primarily with a combination of cash from operations and funds from the capital markets. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.

~~Changes in Cash Position~~

FirstEnergy's primary source of cash required for continuing operations as a holding company is cash from the operations of its subsidiaries. FirstEnergy and certain of its subsidiaries also have access to $2.75 billion of short-term financing under a revolving credit facility which expires in 2011. Under the terms of the facility, FirstEnergy is permitted to have up to $1.5 billion in outstanding borrowings at any given time, subject to the facility cap of $2.75 billion of aggregate outstanding borrowings by it and its subsidiaries that are also parties to such facility. In the first six months of 2007, FirstEnergy received $637 million of cash dividends and return of capital from its subsidiaries and paid $311 million in cash dividends to common shareholders. With the exception of Met-Ed, which is currently in an accumulated deficit position, there are no material restrictions on the payment of cash dividends by the subsidiaries of FirstEnergy.

On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or approximately 4.5%, of its outstanding common stock at an initial price of approximately $900 million pursuant to an accelerated share repurchase program. FirstEnergy acquired these shares under its previously announced authorization to repurchase up to 16 million shares of its common stock. The share repurchase was funded with short-term borrowings, including $500 million from bridge loan facilities that have since been repaid.

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in the Bruce Mansfield Plant Unit 1, representing 779 MW of net demonstrated capacity. The purchase price of approximately $1.329 billion for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034. A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates. The lessor trusts leased the undivided interest back to FGCO for a term of approximately 33 years under substantially identical leases. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The notes and 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. The transaction will be classified as a financing under GAAP until FGCO’s and FES’ registration obligations under the registration rights agreement applicable to the $1.135 billion principal amount of pass through certificates issued in connection with the transaction are satisfied, at which time it is expected to be classified as an operating lease under GAAP. FirstEnergy used the net after-tax proceeds of approximately $1.2 billion to repay short-term debt that was used to fund its recent $900 million accelerated share repurchase program and $300 million pension contribution. FGCO continues to operate the plant. CEI has an existing sale and leaseback arrangement for the remaining 51 MW portion of Bruce Mansfield Unit 1. This transaction generated tax capital gains of approximately $830 million, a substantial portion of which will be offset by existing tax capital loss carryforwards. FirstEnergy will reduce its tax loss carryforward valuation allowances in the third quarter of 2007 and anticipates an immaterial impact to net income as the majority of the unrecognized tax benefits will reduce goodwill.

As of June 30, 2007, FirstEnergy had $37 million of cash and cash equivalents compared with $90 million as of December 31, 2006. The major sources of changes in these balances are summarized below.

~~Cash Flows From Operating Activities~~

FirstEnergy's consolidated net cash from operating activities is provided primarily by its regulated services and power supply management services businesses (see Results of Operations above). Net cash provided from operating activities was $131 million and $485 million in the first six months of 2007 and 2006, respectively, summarized as follows:

Six Months Ended

June 30,

Operating Cash Flows

2007

2006

(In millions)

Net income $ 628 $ 525
Non-cash charges 277 260
Pension trust contribution (300 ) -
Working capital and other (474 ) (300 )
$ 131 $ 485

Net cash provided from operating activities decreased by $354 million in the first six months of 2007 compared to the first six months of 2006 primarily due to a $300 million pension trust contribution in 2007 and $174 million from working capital charges, partially offset by a $103 million increase in net income (see Results of Operations above). The decrease from working capital and other changes primarily resulted from a $365 million increase in receivables due to higher sales, partially offset by $93 million from reduced materials and supplies inventories and $68 million of decreased payments for accounts payable.

~~Cash Flows From Financing Activities~~

In the first six months of 2007, cash provided from financing activities was $454 million compared to $618 million in the first six months of 2006. The decrease was primarily due to the repurchase of common stock in 2007, partially offset by higher short-term borrowings. The following table summarizes security issuances and redemptions.

Six Months Ended

June 30,

Securities Issued or Redeemed

2007

2006

(In millions)

New issues

Pollution control notes $ - $ 253
Secured notes - 200
Unsecured notes 800 600
$ 800 $ 1,053
Redemptions

First mortgage bonds $ 275 $ 1
Pollution control notes - 307
Senior secured notes 43 177
Unsecured notes 153 -
Common stock 918 -
Preferred stock - 30
$ 1,389 $ 515

Short-term borrowings, net $ 1,308 $ 371

FirstEnergy had approximately $2.4 billion of short-term indebtedness as of June 30, 2007 compared to approximately $1.1 billion as of December 31, 2006. This increase resulted from interim funding of FirstEnergy’s $900 million share repurchase program and $300 million pension contribution in the first half of the year. Available bank borrowing capability as of June 30, 2007 included the following:

Borrowing Capability (In millions)

Short-term credit facilities⁽¹⁾
$ 3,220
Accounts receivable financing facilities 550
Utilized (2,413 )
LOCs (339 )
Net $ 1,018

⁽¹⁾ Includes the $2.75 billion revolving credit facility described below, a $100 million revolving credit facility that expires in December 2009, a $20 million uncommitted line of credit and $350 million bridge loan facilities.

As of June 30, 2007, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.9 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE, CEI and TE is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $463 million, $515 million and $127 million, respectively, as of June 30, 2007. Because JCP&L satisfied the provision of its senior note indenture for the release of all FMBs held as collateral for senior notes in May 2007, it is no longer required to issue FMBs as collateral for senior notes and therefore is not limited as to the amount of senior notes it may issue.

The applicable earnings coverage tests in the respective charters of OE, TE, Penn and JCP&L are currently inoperative. In the event that any of them issues preferred stock in the future, the applicable earnings coverage test will govern the amount of preferred stock that may be issued. CEI, Met-Ed and Penelec do not have similar restrictions and could issue up to the number of preferred shares authorized under their respective charters.

As of June 30, 2007, approximately $1.0 billion of capacity remained unused under an existing FirstEnergy shelf registration statement filed with the SEC in 2003 to support future securities issuances. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units. As of June 30, 2007, OE had approximately $400 million of capacity remaining unused under a shelf registration for unsecured debt securities filed with the SEC in 2006.

FirstEnergy and certain of its subsidiaries are parties to a $2.75 billion five-year revolving credit facility (included in the borrowing capability table above). FirstEnergy may request an increase in the total commitments available under this facility up to a maximum of $3.25 billion. Commitments under the facility are available until August 24, 2011, unless the lenders agree, at the request of the Borrowers, to two additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each Borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations.

The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations:

Revolving

Regulatory and

Credit Facility

Other Short-Term

Borrower

Sub-Limit

Debt Limitations⁽¹⁾

(In millions)

FirstEnergy
$ 2,750 $ -
⁽²⁾
OE
500 500
Penn
50 40
CEI
250
⁽³⁾
500
TE
250
⁽³⁾
500
JCP&L
425 431
Met-Ed
250 250
⁽⁴⁾
Penelec
250 250
⁽⁴⁾
FES
250 -
⁽²⁾
ATSI
-
⁽⁵⁾
50

⁽¹⁾

~~As of June 30, 2007.~~

⁽²⁾

~~No regulatory approvals, statutory or charter limitations applicable.~~

⁽³⁾

~~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.~~

⁽⁴⁾

~~Excluding amounts which may be borrowed under the regulated money pool.~~

⁽⁵⁾

~~The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the~~

~~administrative agent that either (i) such borrower has senior unsecured debt ratings of at least~~

~~BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guaranteed the obligations of such~~

~~borrower under the facility.~~

The revolving credit facility, combined with an aggregate $550 million ($287 million unused as of June 30, 2007) of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet working capital requirements and for other general corporate purposes for FirstEnergy and its subsidiaries.

Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit.

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of June 30, 2007, FirstEnergy and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

~~Borrower~~
~~FirstEnergy~~	61	%
OE	48	%
~~Penn~~	24	%
~~CEI~~	60	%
TE	56	%
~~JCP&L~~	32	%
~~Met-Ed~~	46	%
~~Penelec~~	38	%
~~FES~~	57	%

The revolving credit facility does not contain provisions that either restrict the ability to borrow or accelerate repayment of outstanding advances as a result of any change in credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to the credit ratings of the company borrowing the funds.

FirstEnergy's regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first six months of 2007 was 5.64% for both the regulated and the unregulated companies' money pools.

FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. The following table displays FirstEnergy’s and the Companies’ securities ratings as of June 30, 2007. The ratings outlook from Moody’s is stable for FES and positive for all other companies. The ratings outlook from S&P on all securities is stable. The rating outlook from Fitch on CEI and Toledo Edison is positive and stable on all other operating companies.

~~Issuer~~	~~Securities~~	~~S&P~~	~~Moody’s~~	~~Fitch~~

~~FirstEnergy~~	~~Senior unsecured~~	~~BBB-~~	~~Baa3~~	~~BBB~~

OE	~~Senior unsecured~~	~~BBB-~~	~~Baa2~~	~~BBB~~

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

TE	~~Senior secured~~	~~BBB~~	~~Baa2~~	~~BBB~~
	~~Senior unsecured~~	~~BBB-~~	~~Baa3~~	~~BBB-~~

~~Penn~~	~~Senior secured~~	~~BBB+~~	~~Baa1~~	~~BBB+~~

~~JCP&L~~	~~Senior secured~~	~~BBB+~~	~~Baa1~~	A-
	~~Senor unsecured~~	~~BBB~~	~~Baa2~~	~~BBB+~~

~~Met-Ed~~	~~Senior unsecured~~	~~BBB~~	~~Baa2~~	~~BBB~~

~~Penelec~~	~~Senior unsecured~~	~~BBB~~	~~Baa2~~	~~BBB~~

~~FES~~	~~Corporate Credit/Issuer Rating~~	~~BBB~~	~~Baa2~~

On February 21, 2007, FirstEnergy made a $700 million equity investment in FES, all of which was subsequently contributed to FGCO and used to pay-down generation asset transfer-related promissory notes owed to the Ohio Companies and Penn. OE used its $500 million of proceeds to repurchase shares of its common stock from FirstEnergy.

On March 27, 2007, CEI issued $250 million of 5.70% unsecured senior notes due 2017. The proceeds of the offering were used to reduce CEI’s short-term borrowings and for general corporate purposes.

On May 21, 2007, JCP&L issued $550 million of senior unsecured debt securities, consisting of $250 million of 5.65% Senior Notes due 2017 and $300 million of 6.15% Senior Notes due 2037. A portion of the proceeds of the offering were used to redeem outstanding FMB of JCP&L comprised of $125 million principal amount of 7.50% series and $150 million principal amount of 6.75% series. On July 1, 2007, JCP&L also redeemed all $12.2 million outstanding principal amount of its remaining series of FMB. In addition, $125 million of proceeds were used to repurchase shares of its common stock from FirstEnergy. The remaining proceeds were used for general corporate purposes.

As described above, on July 13, 2007, FGCO completed the sale and leaseback of a 93.825% undivided interest in Unit 1 of the Bruce Mansfield Generating Plant. Net after-tax proceeds of approximately $1.2 billion to FGCO from the transaction were used to repay short-term borrowings from, and to invest in, the FirstEnergy non-utility money pool. The repayments and investment allowed FES to reduce its investment in that money pool in order to repay approximately $250 million of external bank borrowings and fund a $600 million equity repurchase from FirstEnergy. FirstEnergy used these funds to reduce its external short term borrowings as discussed above.

~~Cash Flows From Investing Activities~~

Net cash flows used in investing activities resulted principally from property additions. Energy delivery services expenditures for property additions primarily include expenditures related to transmission and distribution facilities. Capital expenditures by the competitive energy services segment are principally generation-related. The following table summarizes investing activities for the second quarter of 2007 and 2006 by segment:

Summary of Cash Flows

Property

Used for Investing Activities

Additions

Investments

Other

Total

Sources (Uses)

(In millions)

Six Months Ended June 30, 2007

Energy delivery services

$
(400
)
$
84

$
-

$
(316
)
Competitive energy services

(263
)

16

(1
)
(248
)
Other

(34
)

(22
)
(3
)

(59
)
Inter-Segment reconciling items

-

(15
)
-

(15
)
Total

$
(697
)
$
63

$
(4
)
$
(638
)

Six Months Ended June 30, 2006

Energy delivery services

$
(370
)
$
198

$
(6
)
$
(178
)
Competitive energy services

(347
)

(20
)

(4
)
(371
)
Other

(22
)

46

4

28

Inter-Segment reconciling items

-

(63
)

-

(63
)
Total

$
(739
)
$
161

$
(6
)
$
(584
)

Net cash used for investing activities in the first six months of 2007 increased by $54 million compared to the same period of 2006. The increase was principally due to a $64 million decrease in cash provided from cash investments, primarily from the use of restricted cash investments to repay debt during 2006. Partially offsetting the decrease in cash provided from cash investments was a $42 million decrease in property additions which reflects the replacement of the steam generators and reactor head at Beaver Valley Unit 1 in 2006.

During the second half of 2007, capital requirements for property additions and capital leases are expected to be $820 million. FirstEnergy and the Companies have additional requirements of approximately $172 million for maturing long-term debt during the remainder of 2007. These cash requirements are expected to be satisfied from a combination of internal cash, short-term credit arrangements, and funds raised in the capital markets.

FirstEnergy's capital spending for the period 2007-2011 is expected to be nearly $7.9 billion (excluding nuclear fuel), of which approximately $1.5 billion applies to 2007. Investments for additional nuclear fuel during the 2007-2011 period are estimated to be approximately $1.2 billion, of which about $95 million applies to 2007. During the same period, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $804 million and $102 million, respectively, as the nuclear fuel is consumed.

~~GUARANTEES AND OTHER ASSURANCES~~

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds, and LOCs. Some of the guaranteed contracts contain collateral provisions that are contingent upon FirstEnergy’s credit ratings.

~~As of June 30, 2007, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.1 billion, as summarized below:~~

Maximum

Guarantees and Other Assurances

Exposure

(In millions)

FirstEnergy Guarantees of Subsidiaries
Energy and Energy-Related Contracts ⁽¹⁾
$ 800
LOC ⁽²⁾
864
Other ⁽³⁾

587

2,251

Surety Bonds 95
LOC ⁽⁴⁾⁽⁵⁾

1,737

Total Guarantees and Other Assurances
$
4,083

⁽¹⁾

~~Issued for open-ended terms, with a 10-day termination right by FirstEnergy.~~

⁽²⁾

~~LOC’s issued on behalf of FGCO and NGC in support of pollution~~

~~control revenue bonds with various maturities, which are~~

~~recognized on FirstEnergy’s consolidated balance sheets.~~

⁽³⁾

~~Includes guarantees of $300 million for OVEC obligations and~~

~~$80 million for nuclear decommissioning funding assurances.~~

⁽⁴⁾

~~Includes $339 million issued for various terms pursuant to LOC~~

~~capacity available under FirstEnergy’s revolving credit facility and~~

~~an additional $779 million outstanding in support of pollution~~

~~control revenue bonds issued with various maturities on behalf of~~

~~FGCO and NGC, which are recognized on FirstEnergy’s~~

~~consolidated balance sheets.~~

⁽⁵⁾

~~Includes approximately $194 million pledged in connection with~~

~~the sale and leaseback of Beaver Valley Unit 2 by CEI and TE,~~

~~$291 million pledged in connection with the sale and leaseback of~~

~~Beaver Valley Unit 2 by OE and $134 million pledged in~~

~~connection with the sale and leaseback of Perry Unit 1 by OE.~~

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of its subsidiaries directly involved in these energy and energy-related transactions or financings where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty's legal claim to be satisfied by FirstEnergy’s other assets. The likelihood that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy and energy-related contracts is remote.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of June 30, 2007, FirstEnergy’s maximum exposure under these collateral provisions was $421 million.

Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

~~FirstEnergy has guaranteed the obligations of the operators of the TEBSA project up to a maximum of~~ $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($27 million as of June 30, 2007), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

As described above, on July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in the Bruce Mansfield Plant 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.

~~OFF-BALANCE SHEET ARRANGEMENTS~~

The Ohio Companies have obligations that are not included on FirstEnergy’s Consolidated Balance Sheets related to the sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through operating lease payments. As of June 30, 2007, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.1 billion.

FirstEnergy has equity ownership interests in certain businesses that are accounted for using the equity method. There are no undisclosed material contingencies related to these investments. Certain guarantees that FirstEnergy does not expect to have a material current or future effect on its financial condition, liquidity or results of operations are disclosed under Guarantees and Other Assurances above.

~~MARKET RISK INFORMATION~~

FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.

~~Commodity Price Risk~~

FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices -- electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowances. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of FirstEnergy’s derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the tables below. Contracts that are not exempt from such treatment include certain power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The change in the fair value of commodity derivative contracts related to energy production during the three months and six months ended June 30, 2007 is summarized in the following table:

Three Months Ended

Six Months Ended

Increase (Decrease) in the Fair Value
June 30, 2007

June 30, 2007

of Commodity Derivative Contracts
Non-Hedge

Hedge

Total

Non-Hedge

Hedge

Total

(In millions)

Change in the Fair Value of

Commodity Derivative Contracts:

Outstanding net liability at beginning of period $ (1,028 ) $ 1 $ (1,027 ) $ (1,140 ) $ (17 ) $ (1,157 )
Additions/change in value of existing contracts 91 (11 ) 80 197 (6 ) 191
Settled contracts 92 (2 ) 90 98 11 109
Outstanding net liability at end of period ⁽¹⁾
(845 ) (12 ) (857 ) (845 ) (12 ) (857 )

Non-commodity Net Liabilities at End of Period:

Interest rate swaps ⁽²⁾
- (24 ) (24 ) - (24 ) (24 )
Net Liabilities - Derivative Contracts
at End of Period
$ (845 ) $ (36 ) $ (881 ) $ (845 ) $ (36 ) $ (881 )

Impact of Changes in Commodity Derivative Contracts⁽³⁾

Income Statement effects (pre-tax) $ (2 ) $ - $ (2 ) $ - $ - $ -
Balance Sheet effects:
Other comprehensive income (pre-tax) $ - $ (13 ) $ (13 ) $ - $ 5 $ 5
Regulatory assets (net) $ (185 ) $ - $ (185 ) $ (295 ) $ - $ (295 )

⁽¹⁾	~~Includes $841 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.~~

⁽²⁾

~~Interest rate swaps are treated as cash flow or fair value hedges (see Interest Rate Swap Agreements below).~~

⁽³⁾

~~Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.~~

~~Derivatives are included on the Consolidated Balance Sheet as of June 30, 2007 as follows:~~

Balance Sheet Classification

Non-Hedge

Hedge

Total

(In millions)

Current-

Other assets

$
-

$
35

$
35

Other liabilities

(4
)

(50
)
(54
)

Non-Current-

Other deferred charges

37

24

61

Other non-current liabilities

(878
)
(45
)

(923
)

Net liabilities

$
(845
)
$
(36
)
$
(881
)

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts as of June 30, 2007 are summarized by year in the following table:

Source of Information

- Fair Value by Contract Year

2007⁽¹⁾

2008

2009

2010

2011

Thereafter

Total

(In millions)

Prices actively quoted⁽²⁾
$ (1 ) $ - $ - $ - $ - $ - $ (1 )
Other external sources⁽³⁾
(112 ) (221 ) (172 ) (146 ) - - (651 )
Prices based on models

-

-

-

-

(100
)

(105
)

(205
)
Total⁽⁴⁾

$
(113
)
$
(221
)
$
(172
)
$
(146
)
$
(100
)
$
(105
)
$
(857
)

⁽¹⁾ ~~For the last two quarters of 2007.~~

⁽²⁾ ~~Exchange traded.~~

⁽³⁾ ~~Broker quote sheets.~~

⁽⁴⁾

~~Includes $841 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.~~

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of June 30, 2007. Based on derivative contracts held as of June 30, 2007, an adverse 10% change in commodity prices would decrease net income by approximately $9 million during the next 12 months.

~~Interest Rate Swap Agreements- Fair Value Hedges~~

FirstEnergy utilizes fixed-for-floating interest rate swap agreements as part of its ongoing effort to manage the interest rate risk associated with its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues – protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. During the first six months of 2007, FirstEnergy paid $8 million to terminate swaps with a notional amount $150 million as its subsidiary redeemed the associated hedged debt. The loss was recognized as interest expense during the current period. As of June 30, 2007, the debt underlying the $600 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.11%, which the swaps have converted to a current weighted average variable rate of 6.06%.

June 30, 2007

December 31, 2006

Notional

Maturity

Fair

Notional

Maturity

Fair

Interest Rate Swaps

Amount

Date

Value

Amount

Date

Value

(In millions)

Fair value hedges $
100

2008
$
(2
)
$
100

2008
$
(2)

50

2010

(1
)
50

2010

(1)

300

2013

(13
)
300

2013

(6)

150

2015

(14
)

150

2015

(10)

-

2025

-

50

2025

(2)

-

2031

-

100

2031

(6)

$
600

$
(30
)
$
750

$
(27)

~~Forward Starting Swap Agreements - Cash Flow Hedges~~

FirstEnergy utilizes forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the anticipated future issuances of fixed-rate, long-term debt securities for one or more of its consolidated subsidiaries in 2007 and 2008. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the first six months of 2007, FirstEnergy terminated forward swaps with an aggregate notional value of $950 million. FirstEnergy paid $2 million in cash related to the terminations, which will be recognized over the terms of the associated future debt. There was no ineffective portion associated with the loss. As of June 30, 2007, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $250 million and an aggregate fair value of $6 million.

June 30, 2007

December 31, 2006

Notional

Maturity

Fair

Notional

Maturity

Fair

Forward Starting Swaps

Amount

Date

Value

Amount

Date

Value

(In millions)

Cash flow hedges $
25

2015
$
1
$
25

2015
$
-

150

2017

2

200

2017

(4
)

25

2018

-

25

2018

(1
)

50

2020

3

50

2020

1

$
250

$
6

$
300

$
(4
)

~~Equity Price Risk~~

Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $1.4 billion as of June 30, 2007 and December 31, 2006. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $136 million reduction in fair value as of June 30, 2007.

~~CREDIT RISK~~

Credit risk is the risk of an obligor’s failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. FirstEnergy engages in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.

FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of June 30, 2007, the largest credit concentration with one party (currently rated investment grade) represented 11% of FirstEnergy‘s total credit risk. Within FirstEnergy’s unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserves, were with investment-grade counterparties as of June 30, 2007.

~~Outlook~~

~~State Regulatory Matters~~

In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the Companies' respective state regulatory plans. These provisions include:

·	~~restructuring the electric generation business and allowing the Companies' customers to select a competitive electric generation supplier other than the Companies;~~

·	~~establishing or defining the PLR obligations to customers in the Companies' service areas;~~

·	~~providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;~~

·	~~itemizing (unbundling) the price of electricity into its component elements – including generation, transmission, distribution and stranded costs recovery charges;~~

·	~~continuing regulation of the Companies' transmission and distribution systems; and~~

·	~~requiring corporate separation of regulated and unregulated business activities.~~

The Companies and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $219 million as of June 30, 2007 (JCP&L - $103 million, Met-Ed - $34 million and Penelec - $82 million). Regulatory assets not earning a current return will be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec. The following table discloses regulatory assets by company:

June 30,

December 31,

Increase

Regulatory Assets*

2007

2006

(Decrease)

(In millions)

OE $ 733 $ 741 $ (8 )
CEI 863 855 8
TE 230 248 (18 )
JCP&L 1,825 2,152 (327 )
Met-Ed 464 409 55
ATSI

40

36

4

Total
$
4,155

$
4,441

$
(286
)

*	~~Penelec had net regulatory liabilities of approximately $74 million~~ ~~and $96 million as of June 30, 2007 and December 31, 2006,~~ ~~respectively. These net regulatory liabilities are included in Other~~ ~~Non-current Liabilities on the Consolidated Balance Sheets.~~

~~Regulatory assets by source are as follows:~~

June 30,

December 31,

Increase

Regulatory Assets By Source

2007

2006

(Decrease)

(In millions)

Regulatory transition costs $ 2,731 $ 3,266 $ (535 )
Customer shopping incentives 562 603 (41 )
Customer receivables for future income taxes 259 217 42
Societal benefits charge (2 ) 11 (13 )
Loss on reacquired debt 59 43 16
Employee postretirement benefits 43 47 (4 )
Nuclear decommissioning, decontamination
and spent fuel disposal costs (114 ) (145 ) 31
Asset removal costs (173 ) (168 ) (5 )
Property losses and unrecovered plant costs 13 19 (6 )
MISO/PJM transmission costs 292 213 79
Fuel costs - RCP 154 113 41
Distribution costs - RCP 246 155 91
Other

85

67

18

Total
$
4,155

$
4,441

$
(286
)

~~Reliability Initiatives~~

~~Ohio~~

On October 21, 2003, the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to the PUCO’s concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order in all respects, except it remanded back to the PUCO the matter of ensuring the availability of sufficient means for customer participation in the marketplace. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio’s findings on customer participation. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and considered to be null and void. On July 20, 2006, the OCC and NOAC also submitted to the PUCO a conceptual proposal addressing the issue raised by the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry directing the Ohio Companies to file a plan in a new docket to address the Court’s concern. The Ohio Companies filed their RSP Remand CBP on September 29, 2006. Initial comments were filed on January 12, 2007 and reply comments were filed on January 29, 2007. In their reply comments the Ohio Companies described the highlights of a new tariff offering they would be willing to make available to customers that would allow customers to purchase renewable energy certificates associated with a renewable generation source, subject to PUCO approval. On May 29, 2007, the Ohio Companies, together with the PUCO Staff and the OCC, filed a stipulation with the PUCO agreeing to offer a standard bid product and a green resource tariff product. The stipulation is currently pending before the PUCO. No further proceedings are scheduled at this time.

The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies’ RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2007 through 2010:

Amortization
Period


        OE

        CEI
  TE

Total
Ohio

(In millions)

2007
$
179
$
108
$
93
$
380
2008 208 124 119 451
2009 - 216 - 216
2010

-

273

-

273

Total Amortization

$
387

$
721

$
212

$
1,320

~~Pennsylvania~~

Met-Ed and Penelec made a comprehensive 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 in accordance with the April 7, 2006 tolling agreement described above. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs, but only for those costs incurred during 2006. In this rate filing, Met-Ed and Penelec also 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 the merger savings, with the comprehensive transmission 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, when new transmission rates were effective, 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 in 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 expenses and the transmission deferral. 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). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s, Penelec’s and the other parties’ petitions for procedural purposes. Due to that ruling, the period for appeals to the Commonwealth Court of Pennsylvania was tolled until 30 days after the PPUC entered a subsequent order ruling on the substantive issues raised in the petitions. On March 1, 2007, the PPUC issued three orders: (1) a tentative order regarding the reconsideration by the PPUC of its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part MEIUG’s and PICA’s Petition for Reconsideration; and (3) an order approving the Compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.

On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from June 2008 through May 2011. The filing proposes multiple, competitive RFPs with staggered delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service would be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. The PPUC is requested to act on the proposal no later than November 2007 for the initial RFP to take place in January 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 programs to meet demand 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 an optional 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 will be convened in mid-September 2007 to consider other aspects of the EIS. The final form of any legislation arising from the special legislative session is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.

~~New Jersey~~

·~~Reduce the total projected electricity demand by 20% by 2020;~~

·~~Meet 22.5% of New Jersey’s electricity needs with renewable energy resources by that date;~~

·~~Reduce air pollution related to energy use;~~

·~~Encourage and maintain economic growth and development;~~

· ~~Achieve a 20% reduction in both Customer Average Interruption Duration Index and System Average Interruption Frequency Index by 2020;~~

· ~~Unit prices for electricity should remain no more than +5% of the regional average price (region includes New York, New Jersey, Pennsylvania, Delaware, Maryland~~

~~and the District of Columbia); and~~

·~~Eliminate transmission congestion by 2020.~~

~~FERC Matters~~

~~Environmental Matters~~

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 SO~~₂ emissions regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO₂ regulations in Ohio that allows for compliance based on a 30-day averaging period. 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 Clean Air Act. FirstEnergy has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding the opacity limit applicable to the common stack for Bay Shore Units 2, 3 and 4.

~~FirstEnergy complies with SO~~₂ ~~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. NO~~_X 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 NO_X ~~reductions at FirstEnergy's facilities. The EPA's NO~~_X ~~Transport Rule imposes uniform reductions of NO~~_X ~~emissions (an approximate 85% reduction in utility plant NO~~_X ~~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 NO~~_X ~~emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NO~~_X ~~budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.~~

On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal Clean Air Act, alleging violations of air pollution laws at the Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Mansfield Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On July 25, 2007, FirstEnergy and PennFuture entered into a Tolling and Confidentiality Agreement that provides for a 60-day negotiation period during which the parties have agreed to not file a lawsuit.

~~National Ambient Air Quality Standards~~

In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter. In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR allowed each affected state until 2006 to develop implementing regulations to achieve additional reductions of NO_X ~~and SO~~₂ ~~emissions in two phases (Phase I in 2009 for NO~~_X~~, 2010 for SO~~₂ ~~and Phase II in 2015 for both NO~~_X ~~and SO~~₂~~). FirstEnergy's Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to caps on SO~~₂ ~~and NO~~_X ~~emissions, whereas its New Jersey fossil-fired 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, capping SO~~₂ ~~emissions in affected states to just 2.5 million tons annually. NO~~_X ~~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 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.

~~Mercury Emissions~~

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap and trade approach as in the CAMR, but rather follows a command and control approach imposing emission limits on individual sources. Pennsylvania’s mercury regulation would deprive FES of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving FirstEnergy system-wide compliance. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Mansfield Plant, FirstEnergy’s only coal-fired Pennsylvania power plant, until 2015, if at all.

~~W. H. Sammis Plant~~

In 1999 and 2000, the EPA issued NOV or compliance orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn, and is now owned by FGCO. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as the New Source Review, or 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 NO_X ~~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 settlement agreement are currently estimated to be $1.7 billion for 2007 through 2011 ($400 million of which is expected to be spent during 2007, with the largest portion of the remaining $1.3 billion expected to be spent in 2008 and 2009).

The Sammis NSR Litigation consent decree also requires FirstEnergy to spend up to $25 million toward environmentally beneficial projects, $14 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.

~~Climate Change~~

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. At the international level, efforts have begun to develop climate change agreements for post-2012 GHG reductions. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

~~On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO~~₂ ~~emissions from automobiles as “air pollutants” under the Clean Air Act. Although this decision did not address CO~~₂ emissions from electric generating plants, the EPA has similar authority under the Clean Air Act to regulate “air pollutants” from those and other facilities. Also 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, the EPA proposed to change the NSR regulations, on May 8, 2007, to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.

~~FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO~~₂ ~~emissions could require significant capital and other expenditures. The CO~~₂ ~~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-CO~~₂ ~~emitting gas-fired and nuclear generators.~~

~~Clean Water Act~~

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~~(when aquatic organisms are pinned against screens or other parts of a cooling water intake ~~system,~~system) and entrainment ~~which~~(which occurs when aquatic life is drawn into a facility's cooling water ~~system.~~system). On January 26, 2007, the ~~federal~~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 of the Second Circuit’s decision. FirstEnergy is ~~evaluating~~studying various control options and their costs and effectiveness. Depending on the ~~outcome~~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, the future ~~cost~~costs of compliance with these standards may require material capital expenditures.

Regulation of Hazardous Waste

105

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of ~~June 30, 2007,~~March 31, 2008, FirstEnergy had approximately ~~$1.5~~$2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and ~~Perry.~~TMI-2. As part of the application to the NRC to transfer the ownership of ~~these nuclear facilities~~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 ~~plans~~(and Exelon for TMI-1 as it relates to ~~seek~~the timing of the decommissioning of TMI-2) seeks for these facilities.

The Companies 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 ~~are~~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 ~~June 30, 2007,~~March 31, 2008, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. ~~In addition,~~Total liabilities of approximately $92 million (JCP&L - $65 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through March 31, 2008. Included in the total for JCP&L ~~has~~are accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants in New Jersey; ~~those costs~~which are being recovered by JCP&L through a non-bypassable SBC. ~~Total liabilities of approximately $88 million have been accrued through June 30, 2007.~~

~~Other Legal Proceedings~~(C) OTHER LEGAL PROCEEDINGS

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 material items not otherwise discussed above are described below.

Power Outages and Related Litigation

In August 2002, the trial 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 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 onin July 8, 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, onin March 7, 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 onin May 9, 2007. Proceedings are continuing in the Superior ~~Court.~~Court and a case management conference with the presiding Judge is scheduled for June 13, 2008. FirstEnergy is ~~vigorously~~ defending this class action but is unable to predict the outcome of this matter. No liability has been accrued as of ~~June 30, 2007.~~March 31, 2008.

68106

Nuclear Plant Matters

On May 14, 2007, the Office of Enforcement of the NRC issued a ~~Demand for Information~~DFI to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information, about ~~the~~two reports prepared by expert ~~witnesses’ report and another report.~~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 iswas needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s ~~Demand for Information~~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. ~~The NRC held~~FENOC submitted a ~~public meeting on June 27, 2007 with FENOC to discuss FENOC’s~~supplemental response ~~to the Demand for Information. In follow-up discussions, FENOC was requested to provide supplemental information to clarify~~clarifying certain aspects of the ~~Demand for Information response and provide additional details regarding plans to implement the commitments made therein. FENOC submitted this supplemental~~DFI response to the NRC on July 16, 2007. ~~FirstEnergy can provide no assurances as~~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’s compliance with these commitments is subject to ~~the ultimate resolution of this matter.~~future NRC review.

Other Legal Matters

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 granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. JCP&L intends to re-file an appeal in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005. The parties met on June 27, 2007 before an arbitrator to assert their positions regarding the finality of damages. A hearing before the arbitrator is set for September 7, 2007.

~~NEW ACCOUNTING STANDARDS AND INTERPRETATIONS~~

~~SFAS 159 – “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115”~~

~~SFAS 157 – “Fair Value Measurements”~~

~~EITF 06-11 – “Accounting for Income Tax Benefits of Dividends or Share-based Payment Awards”~~

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2007

2006

2007

2006

STATEMENTS OF INCOME

(In thousands)

REVENUES:

Electric sales $ 569,430 $ 546,176 $ 1,163,774 $ 1,103,405
Excise tax collections 27,351 26,916 58,605 55,890
Total revenues 596,781 573,092 1,222,379 1,159,295

EXPENSES:

Fuel 2,312 2,821 5,327 5,772
Purchased power 322,639 293,033 672,491 576,053
Nuclear operating costs 47,654 43,506 89,168 84,590
Other operating costs 97,120 91,604 185,606 182,414
Provision for depreciation 19,110 17,547 37,958 35,563
Amortization of regulatory assets 46,126 43,444 91,543 97,305
Deferral of new regulatory assets (54,344 ) (42,083 ) (90,993 ) (78,323 )
General taxes 45,393 43,931 95,138 89,826
Total expenses 526,010 493,803 1,086,238 993,200

OPERATING INCOME
70,771 79,289 136,141 166,095

OTHER INCOME (EXPENSE):

Investment income 21,346 32,818 47,976 65,860
Miscellaneous income (expense) 2,319 (1,001 ) 2,692 (804 )
Interest expense (21,416 ) (17,366 ) (42,438 ) (35,598 )
Capitalized interest 152 643 262 1,134
Subsidiary's preferred stock dividend requirements - (155 ) - (311 )
Total other income 2,401 14,939 8,492 30,281

INCOME BEFORE INCOME TAXES
73,172 94,228 144,633 196,376

INCOME TAXES
27,559 35,019 44,985 73,337

NET INCOME
45,613 59,209 99,648 123,039

PREFERRED STOCK DIVIDEND REQUIREMENTS AND

REDEMPTION PREMIUM
- 3,587 - 4,246

EARNINGS ON COMMON STOCK
$ 45,613 $ 55,622 $ 99,648 $ 118,793

��
STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME
$ 45,613 $ 59,209 $ 99,648 $ 123,039

OTHER COMPREHENSIVE INCOME (LOSS):

Pension and other postretirment benefits (3,424 ) - (6,847 ) -
Change in unrealized gain on available for sale securities 5,099 (4,063 ) 4,973 1,672
Other comprehensive income (loss) 1,675 (4,063 ) (1,874 ) 1,672
Income tax expense (benefit) related to other
comprehensive income 388 (1,466 ) (1,115 ) 603
Other comprehensive income (loss), net of tax 1,287 (2,597 ) (759 ) 1,069

TOTAL COMPREHENSIVE INCOME
$ 46,900 $ 56,612 $ 98,889 $ 124,108

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these
statements.

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30,

December 31,

2007

2006

(In thousands)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ 899 $ 712
Receivables-
Customers (less accumulated provisions of $8,990,000 and $15,033,000,
respectively, for uncollectible accounts) 263,316 234,781
Associated companies 173,200 141,084
Other (less accumulated provisions of $5,090,000 and $1,985,000,
respectively, for uncollectible accounts) 13,380 13,496
Notes receivable from associated companies 367,971 458,647
Prepayments and other 20,482 13,606
839,248 862,326
UTILITY PLANT:

In service 2,690,282 2,632,207
Less - Accumulated provision for depreciation 1,043,183 1,021,918
1,647,099 1,610,289
Construction work in progress 37,019 42,016
1,684,118 1,652,305
OTHER PROPERTY AND INVESTMENTS:

Long-term notes receivable from associated companies 639,227 1,219,325
Investment in lease obligation bonds 274,248 291,393
Nuclear plant decommissioning trusts 125,906 118,209
Other 37,970 38,160
1,077,351 1,667,087
DEFERRED CHARGES AND OTHER ASSETS:

Regulatory assets 733,147 741,564
Pension assets 100,682 68,420
Property taxes 60,080 60,080
Unamortized sale and leaseback costs 47,634 50,136
Other 53,914 18,696
995,457 938,896
$ 4,596,174 $ 5,120,614
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Currently payable long-term debt $ 335,812 $ 159,852
Short-term borrowings-
Associated companies - 113,987
Other 119,943 3,097
Accounts payable-
Associated companies 120,493 115,252
Other 17,907 13,068
Accrued taxes 94,615 187,306
Accrued interest 23,406 24,712
Other 61,611 64,519
773,787 681,793
CAPITALIZATION:

Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
60 and 80 shares outstanding, respectively 1,208,498 1,708,441
Accumulated other comprehensive income 2,449 3,208
Retained earnings 309,656 260,736
Total common stockholder's equity 1,520,603 1,972,385
Long-term debt and other long-term obligations 937,676 1,118,576
2,458,279 3,090,961
NONCURRENT LIABILITIES:

Accumulated deferred income taxes 717,373 674,288
Accumulated deferred investment tax credits 18,748 20,532
Asset retirement obligations 90,801 88,223
Retirement benefits 162,078 167,379
Deferred revenues - electric service programs 67,566 86,710
Other 307,542 310,728
1,364,108 1,347,860
COMMITMENTS AND CONTINGENCIES (Note 9)

$ 4,596,174 $ 5,120,614

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of
these balance sheets.

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended

June 30,

2007

2006

(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 99,648 $ 123,039
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 37,958 35,563
Amortization of regulatory assets 91,543 97,305
Deferral of new regulatory assets (90,993 ) (78,323 )
Amortization of lease costs (4,367 ) (4,334 )
Deferred income taxes and investment tax credits, net 3,017 (17,351 )
Accrued compensation and retirement benefits (25,829 ) 930
Pension trust contribution (20,261 ) -
Decrease (increase) in operating assets-
Receivables (60,535 ) 66,215
Prepayments and other current assets (3,162 ) (7,913 )
Increase (decrease) in operating liabilities-
Accounts payable 10,080 (45,894 )
Accrued taxes (87,969 ) 9,378
Accrued interest (1,306 ) (1,183 )
Electric service prepayment programs (19,144 ) (16,838 )
Other 2,854 (8,051 )
Net cash provided from (used for) operating activities (68,466 ) 152,543

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Long-term debt - 599,778
Short-term borrowings, net 2,859 -
Redemptions and Repayments-
Common stock (500,000 ) -
Long-term debt (1,181 ) (145,316 )
Short-term borrowings, net - (176,708 )
Dividend Payments-
Common stock (50,000 ) (35,000 )
Preferred stock - (1,317 )
Net cash provided from (used for) financing activities (548,322 ) 241,437

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (66,607 ) (63,294 )
Sales of investment securities held in trusts 22,225 29,168
Purchases of investment securities held in trusts (24,187 ) (29,860 )
Loan repayments from associated companies, net 670,774 112,840
Cash investments - 78,248
Other 14,770 23,281
Net cash provided from investing activities 616,975 150,383

Net increase in cash and cash equivalents 187 544,363
Cash and cash equivalents at beginning of period 712 929
Cash and cash equivalents at end of period $ 899 $ 545,292

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part
of these statements.

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of Ohio Edison Company:~~

We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes 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 defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005 as discussed in Note 3, Note 2(G) and Note 11 to the consolidated financial statements) dated February 27, 2007, 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, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~August 6, 2007~~

~~OHIO EDISON COMPANY~~

~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. OE also provides generation services to those customers electing to retain OE as their power supplier. OE’s power supply requirements are provided by FES – an affiliated company.

~~Results of Operations~~

Earnings on common stock in the second quarter of 2007 decreased to $46 million from $56 million in the second quarter of 2006. In the first six months of 2007, earnings on common stock decreased to $100 million from $119 million in the same period of 2006. The decrease in earnings in both periods primarily resulted from higher purchased power costs and lower other income, partially offset by higher electric sales revenues and the deferral of new regulatory assets.

~~Revenues~~

Revenues increased by $24 million or 4.1% in the second quarter of 2007 compared with the same period in 2006, primarily due to higher retail generation revenues of $15 million and wholesale generation revenues of $5 million.

Higher retail generation revenues from residential customers reflected increased sales volume and the impact of higher average unit prices. Weather conditions in the second quarter of 2007 compared to the same period in 2006 contributed to the higher KWH sales to residential customers (heating degree days increased 7.0% and 8.5% and cooling degree days increased by 74.5% and 83.8% in OE’s and Penn’s service territories, respectively). Commercial retail generation revenues increased primarily due to higher average unit prices, partially offset by reduced KWH sales. Average prices increased due to the higher generation prices that went into effect in January 2007 under Penn’s competitive RFP process. Retail generation revenues from the industrial sector decreased primarily due to an increase in customer shopping in the second quarter of 2007 as compared to the same period in 2006. The percentage of shopping customers increased to 27.6 percent during the second quarter of 2007 from 15.2 percent in the second quarter of 2006.

Revenues increased by $63 million or 5.4% in the first six months of 2007 compared with the same period in 2006, primarily due to higher retail generation revenues of $63 million and wholesale generation revenues of $2 million, partially offset by decreases in revenues from distribution throughput of $13 million.

Retail generation revenues increased for residential and commercial customers due to the higher prices and increased sales volume. Weather conditions in the first six months of 2007 compared to the same period in 2006 contributed to the higher KWH sales to residential and commercial customers (heating degree days increased 13.9% and 10.7% in OE’s and Penn’s service territories, respectively). Retail generation revenues from the industrial sector decreased primarily due to an increase in customer shopping in the first six months of 2007 as compared to the same period in 2006. The percentage of shopping customers increased to 26.9 percent in the first six months of 2007 from 15.9 percent in the first six months of 2006.

~~Changes in retail electric generation KWH sales and revenues in the second quarter and first six months of 2007 from the corresponding periods of 2006 are summarized in the following tables:~~

Retail Generation KWH Sales

Three Months

Six Months

Increase (Decrease)

Residential 9.0 % 10.8 %
Commercial (1.3 )% 0.7 %
Industrial (16.8 )% (14.9 )%
Net Decrease in Generation Sales

(4.3
)%

(1.7
)%

Retail Generation Revenues

Three Months

Six Months

Increase (Decrease)

(In millions)

Residential $ 24 $ 61
Commercial 6 22
Industrial (15 ) (20 )
Net Increase in Generation Revenues

$
15

$
63

Increased revenues from distribution throughput to residential customers reflected the impact of weather conditions described above in the second quarter and first six months of 2007 as compared to the same periods in 2006, partially offset by lower composite unit prices. Reduced revenues from distribution throughput to commercial customers in the second quarter and first six months of 2007 resulted from lower unit prices, partially offset by increased KWH deliveries. Revenues from distribution throughput to industrial customers decreased in the second quarter and first six months of 2007 as a result of lower unit prices and reduced KWH deliveries.

~~Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 from the corresponding periods of 2006 are summarized in the following tables.~~

Changes in Distribution KWH Deliveries

Three Months

Six Months

Increase (Decrease)

Residential 7.5 % 8.7 %
Commercial 4.7 % 4.6 %
Industrial (2.5 )% (2.0 )%
Net Increase in Distribution Deliveries

2.7
%

3.5
%

Changes in Distribution Revenues

Three Months

Six Months

Increase (Decrease)

(In millions)

Residential $ 4 $ 3
Commercial (1 ) (5 )
Industrial (3 ) (11 )
Changes in Distribution Revenues

$
-

$
(13
)

~~Expenses~~

Total expenses increased by $32 million in the second quarter of 2007 and $93 million in the first six months of 2007 from the same periods of 2006. The following table presents changes from the prior year by expense category.

Expenses – Changes

Three Months

Six Months
Increase (Decrease)

(In millions)
Purchased power costs $ 30 $ 97
Nuclear operating costs 4 4
Other operating costs 5 3
Provision for depreciation 1 2
Amortization of regulatory assets 3 (5 )
Deferral of new regulatory assets (12 ) (13 )
General taxes 1 5
Net Increase in Expenses

$
32

$
93

Higher purchased power costs in the second quarter and first six months of 2007 primarily reflected higher unit prices under Penn’s competitive RFP process and OE’s PSA with FES. The increase in nuclear operating costs during the second quarter and first six months of 2007 was due to expenses related to the second quarter 2007 nuclear refueling outage at the Perry Plant. The increase in other operating costs during the second quarter of 2007 was primarily due to higher transmission expenses related to MISO operations, partially offset by lower employee benefit expenses. Lower amortization of regulatory assets for the first six months of 2007 was due to the completion of the generation-related transition cost amortization under OE’s and Penn’s respective transition plans at the end of January 2006. The decreases in expense related to the deferral of new regulatory assets for the second quarter of 2007 and first six months of 2007 were primarily due to increases in MISO cost deferrals and related interest. General taxes were higher in the first six months of 2007 as compared to the same period last year as a result of higher real and personal property taxes and KWH excise taxes.

~~Other Income~~

Other income decreased $13 million in the second quarter of 2007 and $22 million in the first six months of 2007 as compared with the same periods of 2006, primarily due to reductions in interest income on notes receivable resulting from principal payments from associated companies. Higher interest expense in the second quarter and first six months of 2007 also contributed to the decrease in other income in both periods of 2007 and was largely due to OE’s issuance of $600 million of long-term debt in June 2006, partially offset by debt redemptions that have occurred since the second quarter of 2006.

~~Income Taxes~~

~~In the first six months of 2007, OE’s income taxes included a $7.2 million adjustment related to an inter-company federal tax allocation arrangement between FirstEnergy and its subsidiaries.~~

~~Capital Resources and Liquidity~~

During 2007, OE expects to meet its contractual obligations primarily with cash from operations and short-term credit arrangements. Borrowing capacity under OE’s credit facilities is available to manage its working capital requirements.

~~Changes in Cash Position~~

~~OE had $899,000 of cash and cash equivalents as of June 30, 2007 compared with $712,000 as of December 31, 2006. The major sources for changes in these balances are summarized below.~~

~~Cash Flows From Operating Activities~~

~~Net cash provided from operating activities in the first six months of 2007 and 2006 were as follows:~~

Six Months Ended
June 30,

Operating Cash Flows

2007

2006

(In millions)

Net income

$
100

$
123

Non-cash charges (credits)

(7
)
18

Pension trust contribution

(20
)
-

Working capital and other

(141
)
12

Net cash provided from (used for) operating activities

$
(68
)
$
153

The changes in net income and non-cash charges are described above under “Results of Operations.” The decrease from working capital changes primarily reflects changes in accounts receivable of $127 million and accrued taxes of $97 million, partially offset by changes in accounts payable of $56 million.

~~Cash Flows From Financing Activities~~

In the first six months of 2007, net cash used for financing activities was $548 million compared to $241 million provided from financing activities in the same period last year. This change primarily resulted from a $500 million repurchase of common stock from FirstEnergy, a $276 million net decrease in new financing activity and a $15 million increase in common stock dividends to FirstEnergy.

OE had approximately $369 million of cash and temporary cash investments (which include short-term notes receivable from associated companies) and $120 million of short-term indebtedness as of June 30, 2007. OE has authorization from the PUCO to incur short-term debt of up to $500 million through bank facilities and the utility money pool. Penn has authorization from the FERC to incur short-term debt up to its charter limit of $39 million as of June 30, 2007, and also has access to bank facilities and the utility money pool.

In February 2007, FES made a $562 million payment on its fossil generation asset transfer notes owed to OE and Penn. OE used $500 million of the proceeds to repurchase shares of its common stock from FirstEnergy.

~~See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of OE’s financing capabilities.~~

~~Cash Flows From Investing Activities~~

Net cash provided from investing activities increased $467 million in the first six months of 2007 from the same period in 2006. The increase resulted primarily from a $558 million increase in loan repayments from associated companies (including the $562 million payment from FES described above), partially offset by a $78 million change in cash investments.

During the second half of 2007, OE’s capital spending is expected to be approximately $70 million. OE has additional requirements of approximately $3 million for maturing long-term debt during that period. These cash requirements are expected to be satisfied from a combination of cash from operations and short-term credit arrangements. OE’s capital spending for the period 2007-2011 is expected to be about $769 million, of which approximately $139 million applies to 2007.

~~Off-Balance Sheet Arrangements~~

Obligations not included on OE’s Consolidated Balance Sheets primarily consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2. As of June 30, 2007, the present value of these operating lease commitments, net of trust investments, was $619 million.

~~Equity Price Risk~~

Included in OE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $82 million and $80 million as of June 30, 2007 and December 31, 2006, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $8 million reduction in fair value as of June 30, 2007.

~~Regulatory Matters~~

~~See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to OE.~~

~~Environmental Matters~~

~~See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to OE.~~

~~Other Legal Proceedings~~

~~See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to OE.~~

~~New Accounting Standards and Interpretations~~

See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to OE.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2007

2006

2007

2006

(In thousands)

REVENUES:

Electric sales $ 433,014 $ 416,690 $ 855,819 $ 807,189
Excise tax collections 16,468 15,681 34,495 32,992
Total revenues 449,482 432,371 890,314 840,181

EXPENSES:

Fuel 14,332 13,413 27,523 26,976
Purchased power 178,669 157,941 359,326 301,711
Other operating costs 83,075 68,436 158,026 141,331
Provision for depreciation 18,713 11,050 37,181 28,251
Amortization of regulatory assets 35,047 29,476 68,176 61,006
Deferral of new regulatory assets (43,059 ) (31,697 ) (77,016 ) (62,223 )
General taxes 34,098 31,510 72,992 66,580
Total expenses 320,875 280,129 646,208 563,632

OPERATING INCOME
128,607 152,242 244,106 276,549

OTHER INCOME (EXPENSE):

Investment income 16,324 24,674 34,011 51,610
Miscellaneous income 3,226 5,642 3,957 5,396
Interest expense (37,267 ) (34,634 ) (73,007 ) (69,366 )
Capitalized interest 141 837 346 1,510
Total other expense (17,576 ) (3,481 ) (34,693 ) (10,850 )

INCOME BEFORE INCOME TAXES
111,031 148,761 209,413 265,699

INCOME TAXES
42,082 57,709 76,915 102,234

NET INCOME
68,949 91,052 132,498 163,465

OTHER COMPREHENSIVE INCOME:

Pension and other postretirement benefits 1,203 - 2,405 -
Income tax expense related to other comprehensive income 357 - 712 -
Other comprehensive income, net of tax 846 - 1,693 -

TOTAL COMPREHENSIVE INCOME
$ 69,795 $ 91,052 $ 134,191 $ 163,465

The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an
integral part of these statements.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30,

December 31,

2007

2006

(In thousands)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ 236 $ 221
Receivables-
Customers (less accumulated provisions of $8,554,000 and $6,783,000
respectively, for uncollectible accounts) 290,711 245,193
Associated companies 59,852 249,735
Other 12,775 14,240
Notes receivable from associated companies 24,898 27,191
Prepayments and other 2,002 2,314
390,474 538,894
UTILITY PLANT:

In service 2,183,308 2,136,766
Less - Accumulated provision for depreciation 839,003 819,633
1,344,305 1,317,133
Construction work in progress 46,543 46,385
1,390,848 1,363,518
OTHER PROPERTY AND INVESTMENTS:

Long-term notes receivable from associated companies 353,293 486,634
Investment in lessor notes 463,436 519,611
Other 10,316 13,426
827,045 1,019,671
DEFERRED CHARGES AND OTHER ASSETS:

Goodwill 1,688,521 1,688,521
Regulatory assets 862,758 854,588
Pension assets 15,124 -
Property taxes 65,000 65,000
Other 51,028 33,306
2,682,431 2,641,415
$ 5,290,798 $ 5,563,498
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Currently payable long-term debt $ 120,597 $ 120,569
Short-term borrowings-
Associated companies 179,892 218,134
Accounts payable-
Associated companies 71,407 365,678
Other 6,517 7,194
Accrued taxes 88,277 128,829
Accrued interest 22,150 19,033
Lease market valuation liability 58,750 60,200
Other 37,473 52,101
585,063 971,738

CAPITALIZATION:

Common stockholder's equity-
Common stock, without par value, authorized 105,000,000 shares -
67,930,743 shares outstanding 860,206 860,133
Accumulated other comprehensive loss (102,738 ) (104,431 )
Retained earnings 741,439 713,201
Total common stockholder's equity 1,498,907 1,468,903
Long-term debt and other long-term obligations 1,936,862 1,805,871
3,435,769 3,274,774
NONCURRENT LIABILITIES:

Accumulated deferred income taxes 492,203 470,707
Accumulated deferred investment tax credits 19,422 20,277
Lease market valuation liability 505,725 547,800
Retirement benefits 110,329 122,862
Deferred revenues - electric service programs 40,459 51,588
Other 101,828 103,752
1,269,966 1,316,986
COMMITMENTS AND CONTINGENCIES (Note 9)

$ 5,290,798 $ 5,563,498

The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these balance sheets.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended

June 30,

2007

2006

(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 132,498 $ 163,465
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 37,181 28,251
Amortization of regulatory assets 68,176 61,006
Deferral of new regulatory assets (77,016 ) (62,223 )
Nuclear fuel and capital lease amortization 116 120
Deferred rents and lease market valuation liability (45,858 ) (55,043 )
Deferred income taxes and investment tax credits, net (7,103 ) (4,745 )
Accrued compensation and retirement benefits 1,594 1,584
Pension trust contribution (24,800 ) -
Decrease (increase) in operating assets-
Receivables 156,526 46,262
Prepayments and other current assets 163 399
Increase (decrease) in operating liabilities-
Accounts payable (308,551 ) (6,388 )
Accrued taxes (40,119 ) (1,932 )
Accrued interest 3,117 (76 )
Electric service prepayment programs (11,129 ) (7,695 )
Other 573 (4,162 )
Net cash provided from (used for) operating activities (114,632 ) 158,823

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Long-term debt 247,426 -
Redemptions and Repayments-
Long-term debt (103,397 ) (118,152 )
Short-term borrowings, net (52,894 ) (57,675 )
Dividend Payments-
Common stock (104,000 ) (63,000 )
Net cash used for financing activities (12,865 ) (238,827 )

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (64,366 ) (65,551 )
Loan repayments from associated companies, net 2,292 108,169
Collection of principal on long-term notes receivable 133,341 -
Redemption of lessor notes 56,175 44,551
Other 70 (7,155 )
Net cash provided from investing activities 127,512 80,014

Net increase in cash and cash equivalents 15 10
Cash and cash equivalents at beginning of period 221 207
Cash and cash equivalents at end of period $ 236 $ 217

The preceeding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these statements.

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of The Cleveland Electric Illuminating Company:~~

We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 30, 2007 and 2006. 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, 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.

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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes 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 defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 11 to those consolidated financial statements) dated February 27, 2007, 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, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~August 6, 2007~~

~~THE CLEVELAND ELECTRIC ILLUMINATING COMPANY~~

~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. CEI’s power supply requirements are primarily provided by FES – an affiliated company.

~~Results of Operations~~

Net income in the second quarter of 2007 decreased to $69 million from $91 million in the same period of 2006. In the first six months of 2007, net income decreased to $132 million from $163 million in the same period of 2006. The decrease in both periods resulted primarily from higher purchased power costs and other operating costs, partially offset by higher revenues and the deferral of new regulatory assets.

~~Revenues~~

Revenues increased by $17 million or 4% in the second quarter of 2007 from the same period of 2006 primarily due to higher retail generation and distribution revenues. Retail generation revenues increased $11 million due to increased KWH sales in the residential and commercial sectors and higher composite unit prices in the commercial and industrial sectors. More extreme weather in the second quarter of 2007 compared to the unseasonably mild weather in the same period in 2006 contributed to the higher KWH sales for both residential and commercial customers (cooling degree days increased 82% and heating degree days were 10% higher in 2007).

In the first six months of 2007, revenues increased by $50 million or 6% compared to the same period of 2006 primarily due to higher retail generation and wholesale revenues. Retail generation revenues increased by $33 million due to increased KWH sales and higher composite unit prices in all classes. The weather contributed to the increased KWH sales in the residential and commercial sectors (cooling degree days increased 84% and heating degree days increased 16% from the same period in 2006). Increased industrial KWH sales reflected a slight decrease in customer shopping.

Wholesale generation revenues increased by $1 million in the second quarter and $12 million in the first six months of 2007 compared to the corresponding periods of 2006. The increases in both periods were primarily due to higher unit prices for PSA sales to associated companies. In the first six months of 2007 higher unit prices were partially offset by a decrease in sales volume due in part to maintenance outages at the Bruce Mansfield Plant in the first quarter of 2007. CEI sells KWH from its leasehold interests in the Bruce Mansfield Plant to FGCO.

~~Increases in retail electric generation sales and revenues in the second quarter and the first six months of 2007 compared to the corresponding periods of 2006 are summarized in the following tables:~~

Retail Generation KWH Sales
Three Months

Six Months

Residential 5.3 % 6.8 %
Commercial 6.6 % 6.9 %
Industrial 0.8 % 2.0 %
Increase in Retail Generation Sales

3.3
%

4.5
%

Retail Generation Revenues

Three Months

Six Months

(In millions)

Residential $ 2 $ 9
Commercial 5 12
Industrial 4 12
Increase in Generation Revenues

$
11

$
33

Revenues from distribution throughput increased by $3 million in the second quarter and $1 million in the first six months of 2007 compared to the same periods of 2006 primarily due to increased residential and commercial KWH deliveries, offset by lower composite unit prices in all classes. Increased KWH deliveries were primarily a result of the more extreme weather in 2007 as described above.

~~Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 compared to the corresponding periods of 2006 are summarized in the following tables.~~

Increase in Distribution KWH Deliveries

Three Months

Six Months

    Residential 5.4 % 6.9 %
    Commercial 4.6 % 4.8 %
    Industrial 0.9 % 1.5 %
Total Increase in Distribution Deliveries

3.0
%

3.8
%

Change in Distribution Revenues

Three Months

Six Months

Increase (Decrease)

(In millions)

Residential $ 3 $ 5
Commercial 2 3
Industrial (2 ) (7 )
Net Increase in Distribution Revenues
$
3

$
1

~~Expenses~~

Total expenses increased by $41 million in the second quarter and $83 million in the first six months of 2007 compared to the corresponding periods of 2006. The following table presents changes in each period from the prior year by expense category:

Expenses - Changes

Three Months

Six Months

Increase (Decrease)

(In millions)

Fuel costs $ 1 $ 1
Purchased power costs 21 58
Other operating costs 15 17
Provision for depreciation 8 9
Amortization of regulatory assets 5 7
Deferral of new regulatory assets (11 ) (15 )
General taxes 2 6
Net Increase in Expenses
$ 41 $ 83

Higher purchased power costs in the second quarter and the first six months of 2007 compared to the corresponding periods of 2006 primarily reflect higher unit prices associated with the PSA with FES and an increase in KWH purchases to meet CEI’s higher retail generation sales requirements. The higher other operating costs in the second quarter and the first six months of 2007 compared to the same periods of 2006 reflect an increase in MISO transmission related expenses. The difference between transmission revenues accrued and transmission costs incurred is deferred, resulting in no material impact to current period earnings. The increased depreciation in the second quarter of 2007 and the first six months of 2007 is primarily due to the absence of credit adjustments in the second quarter of 2006 related to prior periods ($6.5 million pre-tax, $4 million net of tax).

The increased amortization of regulatory assets in the second quarter and the first six months of 2007 compared to the corresponding periods of 2006 was due to increased transition cost amortization reflecting the higher KWH sales discussed above. The increases in the deferral of new regulatory assets in the second quarter and the first six months of 2007 compared to the same periods of 2006 reflect a higher level of MISO costs that were deferred in excess of transmission revenues and increased distribution cost deferrals under CEI’s RCP. General taxes were higher in the second quarter and the first six months of 2007 as a result of higher real and personal property taxes and KWH excise taxes.

~~Other Expense~~

Other expense increased by $14 million in the second quarter and $24 million in the first six months of 2007 compared to the corresponding periods of 2006 primarily due to lower investment income on associated company notes receivable in 2007. CEI received principal repayments from FGCO and NGC subsequent to the second quarter of 2006 on notes receivable related to the generation asset transfers. In addition, there was a $6 million benefit recognized in the second quarter of 2006 related to the sale of the Ashtabula C.

~~Capital Resources and Liquidity~~

~~During 2007, CEI expects to meet its contractual obligations with cash from operations and short-term credit arrangements.~~

~~Changes in Cash Position~~

~~As of June 30, 2007, CEI had $236,000 of cash and cash equivalents, compared with $221,000 as of December 31, 2006. The major sources of changes in these balances are summarized below.~~

~~Cash Flows from Operating Activities~~

~~Cash used for operating activities during the first six months of 2007, compared with cash provided from operating activities for the first six months of 2006, were as follows:~~

Six Months Ended
June 30,

Operating Cash Flows

2007

2006

(In millions)

Net Income
$
132

$
163

Non-cash credits
(34
)
(38
)
Pension trust contribution
(25
)
-

Working capital and other
(188
)
34

Net cash provided from (used for) operating activities
$
(115
)
$
159

Net cash used for operating activities was $115 million in the first six months of 2007 compared to $159 million provided from operating activities for the same period in 2006. The $274 million change was primarily due to a $25 million pension trust contribution in the first quarter of 2007 and a $222 million change in working capital and other. The change in working capital was due to changes in accounts payable of $302 million (primarily for the settlement of payables with associated companies) and accrued taxes of $38 million, partially offset by changes in accounts receivable of $110 million. The changes in net income and non–cash credits are described above under “Results of Operations.”

~~Cash Flows from Financing Activities~~

Net cash used for financing activities was $13 million in the first six months of 2007 compared to $239 million in the same period of 2006. The change reflects $248 million of new long-term debt financing and a $14 million decrease in repayments of long-term debt, partially offset by a $41 million increase in common stock dividend payments to FirstEnergy.

CEI had $25 million of cash and temporary investments (which included short-term notes receivable from associated companies) and approximately $180 million of short-term indebtedness as of June 30, 2007. CEI has obtained authorization from the PUCO to incur short-term debt of up to $500 million through bank facilities and the utility money pool.

On March 27, 2007, CEI issued $250 million of 5.70% unsecured senior notes due 2017. The proceeds of the offering were used to reduce short-term borrowings and for general corporate purposes. On June 1, 2007 CEI redeemed $103 million of Trust C preferred securities.

~~See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of CEI’s financing capabilities.~~

~~Cash Flows from Investing Activities~~

Net cash provided from investing activities increased by $47 million in the first six months of 2007 compared to the same period of 2006. The change was primarily due to the collection of principal on long-term notes receivable, partially offset by a decrease in loan repayments from associated companies.

CEI’s capital spending for the last two quarters of 2007 is expected to be about $92 million. These cash requirements are expected to be satisfied with cash from operations and short-term credit arrangements. CEI’s capital spending for the period 2007-2011 is expected to be about $843 million, of which approximately $160 million applies to 2007.

~~Off-Balance Sheet Arrangements~~

Obligations not included on CEI’s Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant. As of June 30, 2007, the present value of these operating lease commitments, net of trust investments, total $82 million.

~~Regulatory Matters~~

~~See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to CEI.~~

~~Environmental Matters~~

~~See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to CEI.~~

~~Other Legal Proceedings~~

~~See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to CEI.~~

~~New Accounting Standards and Interpretations~~

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2007

2006

2007

2006

STATEMENTS OF INCOME

(In thousands)

REVENUES:

Electric sales $ 233,637 $ 219,139 $ 466,693 $ 430,013
Excise tax collections 6,700 6,459 14,100 13,562
Total revenues 240,337 225,598 480,793 443,575

EXPENSES:

Fuel 10,461 9,638 20,608 19,400
Purchased power 96,276 80,659 192,445 156,079
Nuclear operating costs 17,846 17,866 35,567 35,198
Other operating costs 46,164 39,718 89,085 80,143
Provision for depreciation 9,127 8,240 18,244 16,337
Amortization of regulatory assets 24,948 22,117 48,824 46,573
Deferral of new regulatory assets (18,247 ) (14,190 ) (31,728 ) (27,846 )
General taxes 13,000 12,253 26,734 25,184
Total expenses 199,575 176,301 399,779 351,068

OPERATING INCOME
40,762 49,297 81,014 92,507

OTHER INCOME (EXPENSE):

Investment income 7,309 8,945 14,534 18,725
Miscellaneous expense (2,056 ) (1,926 ) (5,156 ) (4,610 )
Interest expense (8,916 ) (4,364 ) (16,419 ) (8,674 )
Capitalized interest 164 344 247 558
Total other income (expense) (3,499 ) 2,999 (6,794 ) 5,999

INCOME BEFORE INCOME TAXES
37,263 52,296 74,220 98,506

INCOME TAXES
15,392 19,924 26,489 37,128

NET INCOME
21,871 32,372 47,731 61,378

PREFERRED STOCK DIVIDEND REQUIREMENTS
- 1,161 - 2,436

EARNINGS ON COMMON STOCK
$ 21,871 $ 31,211 $ 47,731 $ 58,942

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME
$ 21,871 $ 32,372 $ 47,731 $ 61,378

OTHER COMPREHENSIVE INCOME (LOSS):

Pension and other postretirement benefits 573 - 1,146 -
Change in unrealized gain on available for sale securities (669 ) 191 (290 ) (947 )
Other comprehensive income (loss) (96 ) 191 856 (947 )
Income tax expense (benefit) related to other
comprehensive income (43 ) 69 291 (342 )
Other comprehensive income (loss), net of tax (53 ) 122 565 (605 )

TOTAL COMPREHENSIVE INCOME
$ 21,818 $ 32,494 $ 48,296 $ 60,773

The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of
these statements.

THE TOLEDO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30,

December 31,

2007

2006

(In thousands)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ 22 $ 22
Receivables-
Customers 1,081 772
Associated companies 37,927 13,940
Other (less accumulated provisions of $408,000 and $430,000,
respectively, for uncollectible accounts) 4,334 3,831
Notes receivable from associated companies 120,101 100,545
Prepayments and other 792 851
164,257 119,961
UTILITY PLANT:

In service 907,710 894,888
Less - Accumulated provision for depreciation 403,634 394,225
504,076 500,663
Construction work in progress 14,573 16,479
518,649 517,142
OTHER PROPERTY AND INVESTMENTS:

Investment in lessor notes 154,647 169,493
Long-term notes receivable from associated companies 96,521 128,858
Nuclear plant decommissioning trusts 62,289 61,094
Other 1,808 1,871
315,265 361,316
DEFERRED CHARGES AND OTHER ASSETS:

Goodwill 500,576 500,576
Regulatory assets 230,002 247,595
Pension assets 5,379 -
Property taxes 22,010 22,010
Other 45,194 30,042
803,161 800,223
$ 1,801,332 $ 1,798,642
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Currently payable long-term debt $ 30,000 $ 30,000
Accounts payable-
Associated companies 36,974 84,884
Other 4,020 4,021
Notes payable to associated companies 242,253 153,567
Accrued taxes 46,153 47,318
Lease market valuation liability 23,655 24,600
Other 18,755 37,551
401,810 381,941
CAPITALIZATION:

Common stockholder's equity-
Common stock, $5 par value, authorized 60,000,000 shares -
29,402,054 shares outstanding 147,010 147,010
Other paid-in capital 166,801 166,786
Accumulated other comprehensive loss (36,239 ) (36,804 )
Retained earnings 212,071 204,423
Total common stockholder's equity 489,643 481,415
Long-term debt 358,227 358,281
847,870 839,696
NONCURRENT LIABILITIES:

Accumulated deferred income taxes 160,799 161,024
Accumulated deferred investment tax credits 10,597 11,014
Lease market valuation liability 198,688 218,800
Retirement benefits 76,270 77,843
Asset retirement obligations 27,439 26,543
Deferred revenues - electric service programs 18,212 23,546
Other 59,647 58,235
551,652 577,005
COMMITMENTS AND CONTINGENCIES (Note 9)

$ 1,801,332 $ 1,798,642

The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are
an integral part of these balance sheets.

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended

June 30,

2007

2006

(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 47,731 $ 61,378
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 18,244 16,337
Amortization of regulatory assets 48,824 46,573
Deferral of new regulatory assets (31,728 ) (27,846 )
Deferred rents and lease market valuation liability (41,981 ) (45,843 )
Deferred income taxes and investment tax credits, net (11,924 ) (13,322 )
Accrued compensation and retirement benefits 1,277 1,268
Pension trust contribution (7,659 ) -
Decrease (increase) in operating assets-
Receivables (21,594 ) (18,257 )
Prepayments and other current assets 59 (4,076 )
Increase (decrease) in operating liabilities-
Accounts payable (56,784 ) (14,231 )
Accrued taxes 751 3,748
Accrued interest 1 (222 )
Electric service prepayment programs (5,334 ) (4,454 )
Other 1,093 3,326
Net cash provided from (used for) operating activities (59,024 ) 4,379

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Short-term borrowings, net 88,686 71,882
Redemptions and Repayments-
Preferred stock - (30,000 )
Long-term debt - (53,650 )
Dividend Payments-
Common stock (40,000 ) (25,000 )
Preferred stock - (2,436 )
Net cash provided from (used for) financing activities 48,686 (39,204 )

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (19,804 ) (29,361 )
Loan repayments from (loans to) associated companies, net (19,546 ) 2,611
Collection of principal on long-term notes receivable 32,327 53,766
Redemption of lessor notes 14,846 9,305
Sales of investment securities held in trusts 32,499 30,954
Purchases of investment securities held in trusts (32,796 ) (31,043 )
Other 2,812 (1,399 )
Net cash provided from investing activities 10,338 34,833
��
Net change in cash and cash equivalents - 8
Cash and cash equivalents at beginning of period 22 15
Cash and cash equivalents at end of period $ 22 $ 23

The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral
part of these statements.

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of The Toledo Edison Company:~~

We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 30, 2007 and 2006. 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, 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.

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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes 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 defined benefit pension and other postretirement benefit plans as of December 31, 2006 as discussed in Note 3 to those consolidated financial statements) dated February 27, 2007, 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, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~August 6, 2007~~

~~THE TOLEDO EDISON COMPANY~~

~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier. TE’s power supply requirements are provided by FES – an affiliated company.

~~Results of Operations~~

Earnings on common stock in the second quarter of 2007 decreased to $22 million from $31 million in the second quarter of 2006. Earnings on common stock in the first six months of 2007 decreased to $48 million from $59 million in the same period of 2006. The decreases in both periods resulted primarily from higher purchased power and other operating costs, partially offset by higher electric sales revenues and the deferral of new regulatory assets.

~~Revenues~~

Revenues increased $15 million or 6.5% in the second quarter of 2007 compared to the same period of 2006 primarily due to higher retail and wholesale generation revenues. Retail generation revenues increased by $8 million in the second quarter of 2007 due to higher average prices and increased sales volume across all customer classes. Average prices increased primarily due to higher composite unit prices for retail generation shopping customers returning to TE. Generation services provided by alternative suppliers as a percentage of total sales delivered in TE’s franchise area decreased by 1 percentage point for residential customers from the second quarter of 2006. The increase in sales volume also resulted from changes in weather in the second quarter of 2007 (heating and cooling degree days increased 14.3% and 38.4%, respectively, from the second quarter of 2006).

The increase in wholesale revenues ($2 million) resulted primarily from increased KWH sales to associated companies, partially offset by lower unit prices. TE sells KWH from its leasehold interests in Beaver Valley Unit 2 and the Bruce Mansfield Plant to CEI and FGCO, respectively.

Revenues increased $37 million or 8.4% in the first six months of 2007 compared to the same period of 2006 primarily due to higher retail generation revenues of $20 million, higher wholesale generation revenues of $12 million and higher transmission revenues from non-associated companies of $2 million. Retail generation revenues increased for all customer sectors in the first six months of 2007 due to higher average prices and increased sales volume as compared to the same period of 2006. Average prices increased primarily due to higher composite unit prices for retail generation shopping customers returning to TE. Generation services provided by alternative suppliers as a percentage of total sales delivered in TE’s franchise area decreased by 3 percentage points and 1 percentage point for residential and commercial customers, respectively. The increase in sales volume also reflects weather impacts in the first six months of 2007 (heating and cooling degree days increased 16.9% and 39.3%, respectively, from the same period of 2006).

The increase in wholesale revenues resulted primarily from increased KWH sales to associated companies and higher unit prices. Wholesale revenues from non-associated companies decreased $2 million primarily due to lower sales to municipal customers.

~~Increases in electric generation KWH sales and revenues in the second quarter and first six months of 2007 from the corresponding periods of 2006 are summarized in the following tables.~~

Increase in Retail Generation KWH Sales

Three Months

Six Months

Residential 9.7 % 11.9 %
Commercial 3.7 % 4.5 %
Industrial 0.4 % 0.6 %
Total Retail Electric Generation Sales

2.9
%

3.9
%

Increase in Retail Generation Revenues

Three Months

Six Months

(In millions)

Residential $ 2 $ 7
Commercial 2 4
Industrial 4 9
Total Retail Generation Revenues

$
8

$
20

Revenues from distribution throughput increased by $4 million and $2 million in the second quarter and first six months of 2007, respectively, compared to the respective periods in 2006 due to higher KWH deliveries to all customer sectors, partially offset by lower composite unit prices. The higher KWH deliveries to residential and commercial customers in both the second quarter and first six months of 2007 reflected the impact of weather variations described above in both periods of 2007 compared to the respective periods in 2006.

~~Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 from the corresponding periods of 2006 are summarized in the following tables.~~

Increase in Distribution KWH Deliveries

Three Months

Six Months

Residential 8.6 % 8.2 %
Commercial 4.3 % 3.5 %
Industrial 0.7 % 0.6 %
Total Increase in Distribution Deliveries

3.2
%

3.1
%

Changes in Distribution Revenues

Three Months

Six Months

Increase (Decrease)

(In millions)

Residential $ 2 $ 4
Commercial 2 2
Industrial - (4 )
Net Increase in Distribution Revenues

$
4

$
2

~~Expenses~~

Total expenses increased by $23 million and $49 million in the second quarter and the first six months of 2007, respectively, from the same periods of 2006. The following table presents changes from the prior year by expense category:

Expenses – Changes

Three Months

Six Months

Increase (Decrease)

(In millions)

Fuel $ 1 $ 1
Purchased power costs 15 36
Other operating costs 6 9
Provision for depreciation 1 2
Amortization of regulatory assets 3 2
Deferral of new regulatory assets (4 ) (3 )
General taxes

1

2

Net increase in expenses
$ 23 $ 49

Higher purchased power costs in the second quarter of 2007 compared to the second quarter of 2006 reflected higher unit prices associated with the PSA with FES and an increase in KWH purchases to meet the higher retail generation sales requirements. Other operating costs were higher due to a $7 million increase in MISO network transmission expense assessments in the second quarter of 2007. Higher amortization of regulatory assets reflected increased amortization of transition cost deferrals and MISO transmission deferrals. The change in the deferral of new regulatory assets was primarily due to $5 million of increased deferrals for MISO transmission expenses. The difference between transmission revenues accrued and transmission costs incurred is deferred, resulting in no material impact to current period earnings.

Higher purchased power costs in the first six months of 2007 compared to the same period of 2006 reflected higher unit prices associated with the PSA with FES and an increase in KWH purchases to meet the higher retail generation sales requirements. Higher amortization of regulatory assets reflected increased amortization of transition cost deferrals and MISO transmission deferrals. The change in the deferral of new regulatory assets was primarily due to increased deferrals for MISO transmission expenses and RCP reliability costs, partially offset by lower RCP fuel cost deferrals. Other operating costs were higher due to an $8 million increase in MISO network transmission expenses in the first six months of 2007. Depreciation expense was higher due to an increase in depreciable property as a result of plant additions. Higher general taxes primarily reflected increased property taxes and higher KWH excise taxes.

~~Other Expense~~

Other expense increased $6 million in the second quarter of 2007 and $13 million in the first six months of 2007 compared to the same periods of 2006 primarily due to lower investment income and higher interest expense. The decrease in investment income resulted primarily from the principal repayments since the second quarter of 2006 on notes receivable from associated companies. The higher interest expense is principally associated with new long-term debt issued in November 2006.

~~Capital Resources and Liquidity~~

During 2007, TE expects to meet its contractual obligations primarily with cash from operations and short-term credit arrangements. Borrowing capacity under TE’s credit facilities is available to manage its working capital requirements.

~~Changes in Cash Position~~

~~There was no change as of June 30, 2007 from December 31, 2006 in TE’s cash and cash equivalents of $22,000.~~

~~Cash Flows From Operating Activities~~

~~Net cash provided from (used for) operating activities in the first six months of 2007 and 2006 were as follows:~~

Six Months Ended
June 30,

Operating Cash Flows

2007

2006

(In millions)

Net income

$
48

$
61

Non-cash credits

(22
)
(27
)
Pension trust contribution

(8
)
-

Working capital and other

(77
)
(30
)
Net cash provided from (used for)
operating activities

$
(59
)
$
4

Net cash used for operating activities was $59 million in the first six months of 2007 compared to net cash provided from operating activities of $4 million in the same period of 2006. The change was the result of a $13 million decrease in net income, an $8 million pension trust contribution in the first six months of 2007 and a $47 million decrease from changes in working capital and other, partially offset by a $5 million decrease in net non-cash credits. The change in net income is described above under “Results of Operations.” The changes in working capital and other are primarily due to increased cash outflows for accounts payable of $43 million.

~~Cash Flows From Financing Activities~~

Net cash provided from financing activities increased by $88 million in the first six months of 2007 compared to the same period of 2006. The increase resulted primarily from a $17 million increase in short-term borrowings, a $30 million decrease in preferred stock redemptions and a $54 million decrease in long-term debt redemptions, partially offset by a $15 million increase in common stock dividends to FirstEnergy in the first six months of 2007.

TE had $120 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $242 million of short-term indebtedness as of June 30, 2007. TE has authorization from the PUCO to incur short-term debt of up to $500 million through bank facilities and the utility money pool.

~~See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of TE’s financing capabilities.~~

~~Cash Flows From Investing Activities~~

Net cash provided from investing activities decreased by $24 million in the first six months of 2007 compared to the same period of 2006. The change was primarily due to a $44 million net decrease in loan repayments from associated companies, partially offset by a $10 million decrease in property additions and a $6 million increase from the redemption of lessor notes.

TE’s capital spending for the last two quarters of 2007 is expected to be about $38 million. TE has additional requirements of $30 million for maturing long-term debt during the remainder of 2007. These cash requirements are expected to be satisfied primarily with cash from operations and short-term credit arrangements. TE’s capital spending for the period 2007-2011 is expected to be nearly $322 million, of which approximately $61 million applies to 2007.

~~Off-Balance Sheet Arrangements~~

Obligations not included on TE’s Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2. As of June 30, 2007, the present value of these operating lease commitments, net of trust investments, total $442 million.

~~Regulatory Matters~~

~~See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to TE.~~

~~Environmental Matters~~

~~See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to TE.~~

~~Other Legal Proceedings~~

~~See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to TE.~~

~~New Accounting Standards and Interpretations~~

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2007

2006

2007

2006

STATEMENTS OF INCOME

(In thousands)

REVENUES:

Electric sales $ 768,190 $ 600,560 $ 1,439,097 $ 1,164,110
Excise tax collections 11,845 10,924 24,681 23,166
Total revenues 780,035 611,484 1,463,778 1,187,276

EXPENSES:

Purchased power 464,505 343,045 851,002 658,755
Other operating costs 74,564 72,105 149,215 155,133
Provision for depreciation 21,319 20,826 41,835 41,454
Amortization of regulatory assets 93,890 65,526 189,118 132,271
General taxes 15,553 14,272 32,552 30,504
Total expenses 669,831 515,774 1,263,722 1,018,117

OPERATING INCOME
110,204 95,710 200,056 169,159

OTHER INCOME (EXPENSE):

Miscellaneous income 3,238 2,528 6,299 6,071
Interest expense (24,494 ) (20,367 ) (46,910 ) (40,983 )
Capitalized interest 563 1,037 1,076 1,929
Total other expense (20,693 ) (16,802 ) (39,535 ) (32,983 )

INCOME BEFORE INCOME TAXES
89,511 78,908 160,521 136,176

INCOME TAXES
39,698 38,632 72,362 62,190

NET INCOME
49,813 40,276 88,159 73,986

PREFERRED STOCK DIVIDEND REQUIREMENTS
- 125 - 250

EARNINGS ON COMMON STOCK
$ 49,813 $ 40,151 $ 88,159 $ 73,736

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME
$ 49,813 $ 40,276 $ 88,159 $ 73,986

OTHER COMPREHENSIVE INCOME (LOSS):

Pension and other postretirement benefits (2,115 ) - (4,230 ) -
Unrealized gain on derivative hedges 69 38 166 107
Other comprehensive income (loss) (2,046 ) 38 (4,064 ) 107
Income tax expense (benefit) related to other
comprehensive income (995 ) 15 (1,979 ) 43
Other comprehensive income (loss), net of tax (1,051 ) 23 (2,085 ) 64

TOTAL COMPREHENSIVE INCOME
$ 48,762 $ 40,299 $ 86,074 $ 74,050

The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral
part of these statements.

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30,

December 31,

2007

2006

(In thousands)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ 87 $ 41
Receivables-
Customers (less accumulated provisions of $4,042,000 and $3,524,000,
respectively, for uncollectible accounts) 378,940 254,046
Associated companies 186 11,574
Other (less accumulated provisions of $701,000 and $204,000,
respectively, for uncollectible accounts) 64,010 40,023
Notes receivable - associated companies 23,691 24,456
Materials and supplies, at average cost 1,953 2,043
Prepaid taxes 122,391 13,333
Other 10,480 18,076
601,738 363,592
UTILITY PLANT:

In service 4,074,918 4,029,070
Less - Accumulated provision for depreciation 1,484,602 1,473,159
2,590,316 2,555,911
Construction work in progress 97,539 78,728
2,687,855 2,634,639
OTHER PROPERTY AND INVESTMENTS:

Nuclear fuel disposal trust 170,840 171,045
Nuclear plant decommissioning trusts 172,371 164,108
Other 2,065 2,047
345,276 337,200
DEFERRED CHARGES AND OTHER ASSETS:

Regulatory assets 1,824,873 2,152,332
Goodwill 1,962,361 1,962,361
Pension Assets 39,609 14,660
Other 15,724 17,781
3,842,567 4,147,134
$ 7,477,436 $ 7,482,565
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Currently payable long-term debt $ 39,082 $ 32,683
Short-term borrowings-
Associated companies 263,809 186,540
Accounts payable-
Associated companies 7,325 80,426
Other 229,023 160,359
Accrued taxes 18,600 1,451
Accrued interest 10,621 14,458
Cash collateral from suppliers 8,505 32,300
Other 83,766 96,150
660,731 604,367
CAPITALIZATION:

Common stockholder's equity-
Common stock, $10 par value, authorized 16,000,000 shares-
14,421,637 and 15,009,335 shares outstanding, respectively 144,216 150,093
Other paid-in capital 2,789,235 2,908,279
Accumulated other comprehensive loss (46,339 ) (44,254 )
Retained earnings 218,545 145,480
Total common stockholder's equity 3,105,657 3,159,598
Long-term debt and other long-term obligations 1,575,430 1,320,341
4,681,087 4,479,939
NONCURRENT LIABILITIES:

Power purchase contract loss liability 877,297 1,182,108
Accumulated deferred income taxes 780,004 803,944
Nuclear fuel disposal costs 188,205 183,533
Asset retirement obligations 87,018 84,446
Other 203,094 144,228
2,135,618 2,398,259
COMMITMENTS AND CONTINGENCIES (Note 9)

$ 7,477,436 $ 7,482,565

The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an
integral part of these balance sheets.

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended

June 30,

2007

2006

(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 88,159 $ 73,986
Adjustments to reconcile net income to net cash from operating activities -
Provision for depreciation 41,835 41,454
Amortization of regulatory assets 189,118 132,271
Deferred purchased power and other costs (111,517 ) (134,759 )
Deferred income taxes and investment tax credits, net (3,116 ) 10,942
Accrued compensation and retirement benefits (11,467 ) (3,436 )
Cash collateral returned to suppliers (23,905 ) (108,791 )
Pension trust contribution (17,800 ) -
Decrease (increase) in operating assets-
Receivables (137,492 ) (24,074 )
Materials and supplies 90 91
Prepaid taxes (109,058 ) (100,650 )
Other current assets 2,540 1,718
Increase (decrease) in operating liabilities-
Accounts payable (4,438 ) 23,589
Accrued taxes 27,515 (9,062 )
Accrued interest (3,837 ) 362
Tax collections payable (12,478 ) (10,322 )
Other (6,114 ) 8,680
Net cash used for operating activities (91,965 ) (98,001 )

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Long-term debt 550,000 200,003
Short-term borrowings, net 77,269 183,818
Redemptions and Repayments-
Long-term debt (304,579 ) (157,659 )
Common Stock (125,000 ) -
Dividend Payments-
Common stock (15,000 ) (25,000 )
Preferred stock - (250 )
Net cash provided from financing activities 182,690 200,912

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (95,310 ) (91,101 )
Loan repayments from (loans to) associated companies, net 765 (9,347 )
Sales of investment securities held in trusts 77,941 131,079
Purchases of investment securities held in trusts (79,388 ) (132,526 )
Other 5,313 (1,023 )
Net cash used for investing activities (90,679 ) (102,918 )

Net increase (decrease) in cash and cash equivalents 46 (7 )
Cash and cash equivalents at beginning of period 41 102
Cash and cash equivalents at end of period $ 87 $ 95

The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these statements.

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of Jersey Central Power & Light Company:~~

We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 30, 2007 and 2006. 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, 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.

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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes 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 defined benefit pension and other postretirement benefit plans as of December 31, 2006, as discussed in Note 3 to those consolidated financial statements) dated February 27, 2007, 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, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~August 6, 2007~~

~~JERSEY CENTRAL POWER & LIGHT COMPANY~~

~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also provides generation services to those customers electing to retain JCP&L as their power supplier.

~~Results of Operations~~

Earnings on common stock in the second quarter of 2007 increased to $50 million from $40 million in 2006. The increase was primarily due to higher revenues, partially offset by higher purchased power costs, increased amortization of regulatory assets, interest expense and other operating costs. In the first six months of 2007, earnings on common stock increased to $88 million compared to $74 million for the same period in 2006. The increase was primarily due to higher revenues and lower other operating costs, partially offset by higher purchased power costs, increased amortization of regulatory assets and interest expense.

~~Revenues~~

Revenues increased $169 million or 27.6% in the second quarter of 2007 and $277 million or 23.3% in the first six months of 2007 compared with the same periods of 2006, reflecting higher retail and wholesale generation revenues. Retail generation revenues increased by $102 million and $164 million in the second quarter and the first six months of 2007, respectively. Wholesale revenues increased $19 million in the second quarter and $27 million in the first six months of 2007.

Generation revenues from all customer classes increased in the second quarter and first six months of 2007 as compared to 2006. The increases in both periods of 2007 were due to higher unit prices resulting from the BGS auctions effective June 1, 2006 and June 1, 2007 and higher retail generation KWH sales. Sales volume increased as a result of weather conditions in the second quarter of 2007 (heating degree days were 35% greater than the second quarter of 2006). Industrial generation KWH sales declined in the second quarter and first six months of 2007 from the same period in 2006 due to an increase in customer shopping.

Wholesale generation revenues increased ($19 million in the second quarter and $27 million in the first six months of 2007) due to higher market prices, partially offset by sales volume decreases of 3.9% and 1.4% from the second quarter and first six months of 2006, respectively.

~~Changes in retail generation KWH sales and revenues by customer class in the second quarter and the first six months of 2007 compared to the same periods of 2006 are summarized in the following table:~~

Retail Generation KWH Sales

Three Months

Six Months

Increase (Decrease)
Residential 13.6 % 8.9 %
Commercial 5.3 % 3.2 %
Industrial (8.4 )% (4.9 )%
Net Increase in Generation Sales

9.0
%

5.8
%

Retail Generation Revenues

Three Months

Six Months

(In millions)

Residential $ 64 $ 100
Commercial 36 60
Industrial 2 4
Increase in Generation Revenues

$
102

$
164

Distribution revenues increased $39 million and $67 million in the second quarter and first six months of 2007, respectively, compared to the same periods of 2006 due to higher composite unit prices and increased KWH deliveries, reflecting the weather impacts described above. The higher unit prices resulted from a NUGC rate increase effective in December 2006 as approved by the NJBPU.

~~100~~

~~Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 compared to the corresponding periods of 2006 are summarized in the following tables.~~

Increase in Distribution KWH Deliveries

Three Months

Six Months

Residential 13.7 % 8.9 %
Commercial 5.4 % 4.8 %
Industrial 2.9 % 2.3 %
Total Increase in Distribution Deliveries

8.5
%

6.2
%

Increase in Distribution Revenues
Three Months

Six Months

(In millions)

Residential $ 24 $ 38
Commercial 13 25
Industrial 2 4
Total Increase in Distribution Revenues

$
39

$
67

The higher revenues for the second quarter and first six months of 2007 also included $8 million and $16 million, respectively, of increased revenues resulting from the August 2006 securitization of deferred costs associated with JCP&L’s BGS supply.

~~Expenses~~

Total expenses increased by $154 million in the second quarter and $246 million in the first six months of 2007 as compared to the same periods of 2006. The following table presents changes from the prior year by expense category:

Expenses - Changes

Three Months

Six Months

Increase (Decrease)

(In millions)

Purchased power costs $ 121 $ 192
Other operating costs 2 (6 )
Provision for depreciation 1 1
Amortization of regulatory assets 29 57
General Taxes 1 2
Net increase in expenses
$ 154 $ 246

The increase in purchased power costs (35.4% in the second quarter of 2007 and 29.2% in the first six months) primarily reflected higher unit prices resulting from the BGS auctions. Other operating costs increased $2 million in the second quarter of 2007 due to higher labor costs from storm damage repairs in 2007, but decreased $6 million in the first six months of 2007 primarily due to lower employee benefit costs. Amortization of regulatory assets increased $29 million in the second quarter and $57 million in the first six months of 2007 due to higher transition cost recovery associated with the December 2006 NUGC rate increase.

~~Capital Resources and Liquidity~~

During the remainder of 2007, JCP&L expects to meet its contractual obligations with a combination of cash from operations and short-term borrowings. Borrowing capacity under JCP&L’s credit facilities is available to manage its working capital requirements.

~~Changes in Cash Position~~

~~As of June 30, 2007, JCP&L had $87,000 of cash and cash equivalents compared with $41,000 as of December 31, 2006. The major sources for changes in these balances are summarized below.~~

~~101~~

~~Cash Flows From Operating Activities~~

~~Cash provided from operating activities in the first six months of 2007 compared with the first six months of 2006 were as follows:~~

Six Months Ended

June 30,

Operating Cash Flows

2007

2006

(In millions)

Net income $ 88 $ 74
Net non-cash charges 105 46
Pension trust contribution (18 ) -
Cash collateral returned to suppliers (24 ) (109 )
Working capital and other (243 ) (109 )
Net cash used for operating activities $ (92 ) $ (98 )

Net cash used for operating activities decreased $6 million in the first six months of 2007 from the same period of 2006. This decrease was primarily due to an $85 million reduction in cash collateral payments made to suppliers in the first six months of 2007 compared to the same period in 2006, an increase of $59 million in non-cash charges and an increase in net income of $14 million. These increases were largely offset by a $134 million decrease from working capital (due to changes in the collection of receivables and tax payments) and an $18 million pension trust contribution in the first quarter of 2007. The changes in net income and non-cash charges are described above in “Results of Operations.”

~~Cash Flows From Financing Activities~~

Net cash provided from financing activities was $183 million in the first six months of 2007 compared to $201 million in same period of 2006. The decrease primarily resulted from a $107 million reduction in short-term borrowings, a $125 million repurchase of common stock from FirstEnergy and $147 million of additional long-term debt redemptions, partially offset by a $350 million increase in new long-term debt financing and a $10 million reduction in common stock dividend payments to FirstEnergy.

JCP&L had $24 million of cash and temporary investments (which includes short-term notes receivable from associated companies) and approximately $229 million of short-term indebtedness as of June 30, 2007. JCP&L has authorization from the FERC to incur short-term debt up to its charter limit of $431 million (including the utility money pool).

~~See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of JCP&L’s financing capabilities.~~

~~Cash Flows From Investing Activities~~

Net cash used for investing activities was $91 million in the first six months of 2007 compared to $103 million in the previous year. The $12 million decrease primarily resulted from the absence of $10 million in loans to associated companies in 2006.

During the last half of 2007, capital requirements for property additions and improvements are expected to be about $95 million. These cash requirements are expected to be satisfied from a combination of internal cash and short-term credit arrangements.

~~JCP&L’s capital spending for the period 2007-2011 is expected to be about $1.3 billion for property additions, of which approximately $192 million applies to 2007.~~

~~Market Risk Information~~

During the first six months of 2007, the value of commodity derivative contracts decreased by $302 million as a result of settled contracts ($196 million) and changes in the value of existing contracts ($106 million). These non-trading contracts (primarily with NUG entities) are adjusted to fair value at the end of each quarter with a corresponding offset to regulatory assets, resulting in no impact to current period earnings. Commodity derivative contracts were valued at $869 million and $1.2 billion as of June 30, 2007 and December 31, 2006, respectively. See the “Market Risk Information” section of JCP&L’s 2006 Annual Report on Form 10-K for additional discussion of market risk.

~~102~~

~~Equity Price Risk~~

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $104 million and $97 million as of June 30, 2007 and December 31, 2006, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $10 million reduction in fair value as of June 30, 2007.

~~Regulatory Matters~~

~~See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to JCP&L.~~

~~Environmental Matters~~

~~See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to JCP&L.~~

~~Other Legal Proceedings~~

~~See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to JCP&L.~~

~~New Accounting Standards and Interpretations~~

~~103~~

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2007

2006

2007

2006

(In thousands)

REVENUES:

Electric sales $ 344,241 $ 266,533 $ 696,377 $ 560,570
Gross receipts tax collections 17,502 15,686 35,622 32,862
Total revenues 361,743 282,219 731,999 593,432

EXPENSES:

Purchased power 182,818 143,070 374,407 302,957
Other operating costs 111,105 59,575 209,123 120,654
Provision for depreciation 10,531 10,288 20,815 21,193
Amortization of regulatory assets 30,972 25,669 65,112 55,717
Deferral of new regulatory assets (31,895 ) (45,581 ) (74,621 ) (45,581 )
General taxes 20,170 18,595 41,222 39,216
Total expenses 323,701 211,616 636,058 494,156

OPERATING INCOME
38,042 70,603 95,941 99,276

OTHER INCOME (EXPENSE):

Interest income 7,775 8,964 15,501 17,714
Miscellaneous income 1,498 1,792 2,607 4,404
Interest expense (13,424 ) (12,071 ) (25,180 ) (23,255 )
Capitalized interest 388 344 648 611
Total other expense (3,763 ) (971 ) (6,424 ) (526 )

INCOME BEFORE INCOME TAXES
34,279 69,632 89,517 98,750

INCOME TAXES
14,809 29,555 38,408 40,759

NET INCOME
19,470 40,077 51,109 57,991

OTHER COMPREHENSIVE INCOME (LOSS):

Pension and other postretirement benefits (1,453 ) - (2,905 ) -
Unrealized gain on derivative hedges 84 84 168 168
Other comprehensive income (loss) (1,369 ) 84 (2,737 ) 168
Income tax expense (benefit) related to other
comprehensive income (693 ) 35 (1,385 ) 70
Other comprehensive income (loss), net of tax (676 ) 49 (1,352 ) 98

TOTAL COMPREHENSIVE INCOME
$ 18,794 $ 40,126 $ 49,757 $ 58,089

The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of
these statements.

~~104~~

METROPOLITAN EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30,

December 31,

2007

2006

(In thousands)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ 127 $ 130
Receivables-
Customers (less accumulated provisions of $4,480,000 and $4,153,000,
respectively, for uncollectible accounts) 160,147 127,084
Associated companies 27,213 3,604
Other 20,163 8,107
Notes receivable from associated companies 34,399 31,109
Prepaid taxes 23,598 13,533
Other 353 1,424
266,000 184,991
UTILITY PLANT:

In service 1,945,821 1,920,563
Less - Accumulated provision for depreciation 750,937 739,719
1,194,884 1,180,844
Construction work in progress 33,474 18,466
1,228,358 1,199,310
OTHER PROPERTY AND INVESTMENTS:

Nuclear plant decommissioning trusts 283,596 269,777
Other 1,361 1,362
284,957 271,139
DEFERRED CHARGES AND OTHER ASSETS:

Goodwill 496,129 496,129
Regulatory assets 464,434 409,095
Pension assets 23,583 7,261
Other 38,885 46,354
1,023,031 958,839
$ 2,802,346 $ 2,614,279
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Currently payable long-term debt $ - $ 50,000
Short-term borrowings-
Associated companies 158,731 141,501
Other 197,000 -
Accounts payable-
Associated companies 26,435 100,232
Other 70,566 59,077
Accrued taxes 513 11,300
Accrued interest 7,050 7,496
Other 22,978 22,825
483,273 392,431
CAPITALIZATION:

Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares-
859,000 shares outstanding 1,276,119 1,276,075
Accumulated other comprehensive loss (27,868 ) (26,516 )
Accumulated deficit (183,560 ) (234,620 )
Total common stockholder's equity 1,064,691 1,014,939
Long-term debt and other long-term obligations 542,070 542,009
1,606,761 1,556,948
NONCURRENT LIABILITIES:

Accumulated deferred income taxes 405,170 387,456
Accumulated deferred investment tax credits 8,830 9,244
Nuclear fuel disposal costs 42,514 41,459
Asset retirement obligations 155,867 151,107
Retirement benefits 17,187 19,522
Other 82,744 56,112
712,312 664,900
COMMITMENTS AND CONTINGENCIES (Note 9)

$ 2,802,346 $ 2,614,279

The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part
of these balance sheets.

~~105~~

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended

June 30,

2007

2006

(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 51,109 $ 57,991
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 20,815 21,193
Amortization of regulatory assets 65,112 55,717
Deferred costs recoverable as regulatory assets (38,540 ) (50,570 )
Deferral of new regulatory assets (74,621 ) (45,581 )
Deferred income taxes and investment tax credits, net 27,069 22,463
Accrued compensation and retirement benefits (11,150 ) (4,712 )
Cash collateral 4,850 (2,250 )
Pension trust contribution (11,012 ) -
Decrease (increase) in operating assets-
Receivables (64,465 ) 38,182
Prepayments and other current assets (8,994 ) (24,564 )
Increase (decrease) in operating liabilities-
Accounts payable (62,308 ) 6,161
Accrued taxes (10,788 ) (12,045 )
Accrued interest (446 ) 297
Other 4,238 (4,011 )
Net cash provided from (used for) operating activities (109,131 ) 58,271

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Short-term borrowings, net 214,229 -
Redemptions and Repayments-
Long-term debt (50,000 ) -
Short-term borrowings, net - (1,707 )
Net cash provided from (used for) financing activities 164,229 (1,707 )

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (49,852 ) (47,301 )
Sales of investment securities held in trusts 55,603 113,637
Purchases of investment securities held in trusts (57,571 ) (118,379 )
Loans to associated companies, net (3,290 ) (4,054 )
Other 9 (453 )
Net cash used for investing activities (55,101 ) (56,550 )

Net increase (decrease) in cash and cash equivalents (3 ) 14
Cash and cash equivalents at beginning of period 130 120
Cash and cash equivalents at end of period $ 127 $ 134

The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
part of these statements.

~~106~~

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of Metropolitan Edison Company:~~

We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiaries as of June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 30, 2007 and 2006. 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, 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.

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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes 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 defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 9 to those consolidated financial statements) dated February 27, 2007, 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, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~August 6, 2007~~

~~107~~

~~METROPOLITAN EDISON COMPANY~~

~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITIONAND RESULTS OF OPERATIONS~~

Met-Ed is a wholly owned, electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also provides generation service to those customers electing to retain Met-Ed as their power supplier.

~~Results of Operations~~

Net income in the second quarter of 2007 decreased to $19 million from $40 million in the second quarter of 2006. The decrease was primarily due to higher purchased power costs, other operating costs and lower deferrals of new regulatory assets due to the May 2006 PPUC order as discussed below, partially offset by higher revenues. For the first six months of 2007, net income decreased to $51 million from $58 million in the same period of 2006. The decrease in the six month period reflects higher purchased power costs and other operating costs, partially offset by higher revenues and increased deferrals of new regulatory assets.

~~Revenues~~

Revenues increased by $80 million, or 28.2%, in the second quarter of 2007 and $139 million, or 23.4%, in the first six months of 2007 compared with the same periods of 2006. The increases in both periods were primarily due to higher retail and wholesale generation revenues.

In the second quarter of 2007, retail generation revenues increased by $10 million primarily due to higher KWH sales in the residential and commercial sectors, partially offset by slightly lower KWH sales in the industrial sector. The increase in retail generation revenues in the residential and commercial sectors primarily resulted from higher weather-related usage in the second quarter of 2007 as compared to the same period of 2006 (heating degree days increased by 34.9% and cooling degree days increased by 19.3%).

In the first six months of 2007, retail generation revenues increased by $15 million due to higher KWH sales in all customer sectors. The increase in retail generation revenues in the residential and commercial sectors was primarily due to weather conditions during the first six months of 2007 (heating degree days increased by 18.3% and cooling degree days increased by 19.3% as compared to the same period of 2006).

~~Increases in retail electric generation sales and revenues in the second quarter and the first six months of 2007 compared to the same periods of 2006 are summarized in the following tables:~~

Retail Generation KWH Sales

Three Months

Six Months

Increase (Decrease)

Residential 11.7 % 8.7 %
Commercial 4.7 % 4.2 %
Industrial (0.2 )% 1.3 %
Total Retail Electric Generation Sales

5.6
%

5.0
%

Retail Generation Revenues

Three Months

Six Months

(In millions)

Residential $ 7 $ 10
Commercial 3 5
Industrial - -
Increase in Generation Revenues

$
10

$
15

Wholesale revenues increased by $36 million in the second quarter of 2007 and $62 million in the first six months of 2007 compared with the same periods of 2006. The increases in both periods were due to Met-Ed selling additional available power into the PJM market beginning in January 2007.

~~108~~

Revenues from distribution throughput increased by $22 million in the second quarter and $43 million in the first six months of 2007 compared to the same periods in 2006. The increases are due to higher KWH deliveries, reflecting the effect of the weather discussed above, and an increase in composite unit prices resulting from a January 2007 PPUC authorization to increase transmission rates, partially offset by a 5% decrease in distribution rates.

~~Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 compared to the same periods of 2006 are summarized in the following tables:~~

Distribution KWH Deliveries

Three Months

Six Months

Residential 11.7 % 8.7 %
Commercial 4.7 % 4.1 %
Industrial 0.5 % 0.7 %
Total Increase in Distribution Deliveries

5.7
%

4.8
%

Distribution Revenues

Three Months

Six Months

(In millions)

Residential $ 15 $ 32
Commercial 2 1
Industrial 5 10
Increase in Distribution Revenues

$
22

$
43

PJM transmission revenues increased by $13 million and $20 million in the second quarter and first six months of 2007, respectively, as a result of higher transmission volumes and additional PJM auction revenue rights, compared to the prior year periods. Met-Ed defers the difference between revenue from its transmission rider and transmission costs incurred, resulting in no material effect to current period earnings.

~~Expenses~~

Total expenses increased by $112 million and $142 million in the second quarter and first six months of 2007, respectively, compared to the same periods of 2006. The following table presents changes from the prior year by expense category:

Expenses – Changes

Three Months

Six Months

Increase (Decrease)

(In millions)

Purchased power costs $ 40 $ 72
Other operating costs 52 88
Amortization of regulatory assets 5 9
Deferral of new regulatory assets 13 (29 )
General taxes 2 2
Net increase in expenses
$ 112 $ 142

Purchased power costs increased in the second quarter and first six months of 2007 by $40 million and $72 million, respectively, due to increased KWH purchases to source higher generation sales, combined with higher composite unit costs. In the second quarter of 2007, other operating costs increased primarily due to $47 million in higher congestion costs and other transmission expenses associated with the increased transmission volumes discussed above and $4 million of increased contractor service and labor costs for increased work on reliability-related projects. In the first six months of 2007, other operating costs increased primarily due to higher congestion costs and other transmission expenses ($84 million) and increased customer expenses ($3 million) related to Met-Ed’s customer assistance programs.

Met-Ed’s revenue in the first six months of 2007 included the recovery of a portion of the transmission costs that were deferred in 2006. As a result, amortization of regulatory assets increased in the second quarter and first six months of 2007 compared to the prior year. In the second quarter of 2007, the deferral of new regulatory assets decreased primarily due to higher PJM transmission cost deferrals recognized in the second quarter of 2006. The deferral in the second quarter of 2006 also included PJM Transmission costs incurred in the first quarter following authorization by the PPUC in May 2006. The deferral of new regulatory assets increased in the first six months of 2007 due to the deferral of previously expensed decommissioning costs of $15 million associated with the Saxton nuclear research facility as approved by the PPUC in January 2007 and higher PJM transmission costs and associated interest deferrals.

~~For both periods, general taxes increased primarily due to higher gross receipts taxes.~~

~~109~~

~~Capital Resources and Liquidity~~

During 2007, Met-Ed expects to meet its contractual obligations with a combination of cash from operations and funds from the capital markets. Borrowing capacity under Met-Ed’s credit facilities is available to manage its working capital requirements.

~~Changes in Cash Position~~

~~As of June 30, 2007, Met-Ed had cash and cash equivalents of $127,000 compared with $130,000 as of December 31, 2006. The major sources of changes in these balances are summarized below.~~

~~Cash Flows From Operating Activities~~

Net cash used for operating activities was $109 million in the first six months of 2007 compared to net cash provided from operating activities of $58 million in the same period of 2006, as summarized in the following table:

Six Months Ended
June 30,

Operating Cash Flows

2007

2006

(In millions)

Net income

$
51

$
58

Net non-cash charges (credits)

(11
)
(2
)
Pension trust contribution

(11
)

-

Working capital and other

(138
)

2

Net cash provided from (used for) operating activities

$
(109
)
$
58

The decrease from working capital primarily resulted from a $103 million change in receivables, due in part to increased billings associated with the January 2007 rate increase that were delayed until the second quarter of 2007, and a $68 million change in accounts payable, partially offset by a $16 million decrease in prepayments, a $7 million increase in cash collateral received from suppliers and an $8 million increase in cash flows from other operating activities. Changes in net income and non-cash charges (credits) are described above under “Results of Operations.”

~~Cash Flows From Financing Activities~~

Net cash provided from financing activities was $164 million in the first six months of 2007 compared to net cash used for financing of $2 million in the first six months of 2006. The increase reflects a $216 million increase in short-term borrowings, offset by a $50 million increase in long-term debt redemptions in the first six months of 2007.

As of June 30, 2007, Met-Ed had approximately $34 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $356 million of short-term borrowings (including $72 million from its receivables financing arrangement and $138 million from money pool borrowings). Met-Ed has authorization from the FERC to incur short-term debt up to $250 million (excluding receivables financing and money pool borrowings) and authorization from the PPUC to incur money pool borrowings up to $300 million.

~~See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of Met-Ed’s financing capabilities.~~

~~Cash Flows From Investing Activities~~

In the first six months of 2007, Met-Ed's cash used for investing activities totaled $55 million, compared to $56 million in the same period of 2006. The decrease primarily resulted from a reduction in loan repayments to associated companies.

During the last half of 2007, capital requirements for property additions and improvements are expected to be approximately $42 million. This cash requirement is expected to be satisfied from a combination of cash from operations, short-term credit arrangements and funds from the capital markets. Met-Ed's capital spending for the period 2007 through 2011 is expected to be about $520 million, of which approximately $92 million applies to 2007.

In June 2007, Met-Ed entered into an agreement to sell 100% of its ownership interest in York Haven Power Company, pending approval from the PPUC. The sale is subject to regulatory accounting and is not expected to have a material impact on Met-Ed’s earnings.

~~110~~

~~Market Risk Information~~

During the first six months of 2007, the value of commodity derivative contracts decreased by $5 million as a result of settled contracts ($6 million) and changes in the value of existing contracts ($1 million). These non-trading contracts are adjusted to fair value at the end of each quarter with a corresponding offset to regulatory liabilities, resulting in no impact to current period earnings. Commodity derivative contracts were valued at $18 million and $23 million as of June 30, 2007 and December 31, 2006, respectively. See the “Market Risk Information” section of Met-Ed’s 2006 Annual Report on Form 10-K for additional discussion of market risk.

~~Equity Price Risk~~

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $175 million and $164 million as of June 30, 2007 and December 31, 2006, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $18 million reduction in fair value as of June 30, 2007.

~~Regulatory Matters~~

~~See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to Met-Ed.~~

~~Environmental Matters~~

~~See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to Met-Ed.~~

~~Other Legal Proceedings~~

~~See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to Met-Ed.~~

~~New Accounting Standards and Interpretations~~

~~111~~

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2007

2006

2007

2006

(In thousands)

REVENUES:

Electric sales $ 315,745 $ 250,400 $ 654,971 $ 526,227
Gross receipts tax collections 15,672 14,599 32,352 30,524
Total revenues 331,417 264,999 687,323 556,751

EXPENSES:

Purchased power 184,494 146,875 385,336 308,516
Other operating costs 58,267 48,133 117,728 86,475
Provision for depreciation 12,335 11,798 24,112 24,441
Amortization of regulatory assets 13,845 12,979 29,239 27,794
Deferral of new regulatory assets (364 ) (11,815 ) (17,452 ) (11,815 )
General taxes 18,350 17,458 38,201 36,847
Total expenses 286,927 225,428 577,164 472,258

OPERATING INCOME
44,490 39,571 110,159 84,493

OTHER INCOME (EXPENSE):

Miscellaneous income 2,135 1,627 3,552 3,997
Interest expense (13,072 ) (11,599 ) (24,409 ) (22,135 )
Capitalized interest 285 422 543 769
Total other expense (10,652 ) (9,550 ) (20,314 ) (17,369 )

INCOME BEFORE INCOME TAXES
33,838 30,021 89,845 67,124

INCOME TAXES
14,375 14,564 38,638 28,518

NET INCOME
19,463 15,457 51,207 38,606

OTHER COMPREHENSIVE INCOME (LOSS):

Pension and other postretirement benefits (2,825 ) - (5,650 ) -
Unrealized gain on derivative hedges 17 16 33 32
Change in unrealized gain on available for sale securities (13 ) (14 ) (16 ) (18 )
Other comprehensive income (loss) (2,821 ) 2 (5,633 ) 14
Income tax expense (benefit) related to other
comprehensive income (1,302 ) 1 (2,600 ) 7
Other comprehensive income (loss), net of tax (1,519 ) 1 (3,033 ) 7

TOTAL COMPREHENSIVE INCOME
$ 17,944 $ 15,458 $ 48,174 $ 38,613

The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral
part of these statements.

~~112~~

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30,

December 31,

2007

2006

(In thousands)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ 40 $ 44
Receivables-
Customers (less accumulated provisions of $4,216,000 and $3,814,000
respectively, for uncollectible accounts) 143,874 126,639
Associated companies 73,743 49,728
Other 19,809 16,367
Notes receivable from associated companies 18,263 19,548
Prepaid taxes 24,740 3,016
Other 314 1,220
280,783 216,562
UTILITY PLANT:

In service 2,169,653 2,141,324
Less - Accumulated provision for depreciation 822,098 809,028
1,347,555 1,332,296
Construction work in progress 28,719 22,124
1,376,274 1,354,420
OTHER PROPERTY AND INVESTMENTS:

Nuclear plant decommissioning trusts 133,103 125,216
Non-utility generation trusts 101,240 99,814
Other 531 531
234,874 225,561
DEFERRED CHARGES AND OTHER ASSETS:

Goodwill 860,716 860,716
Pension assets 31,293 11,474
Other 32,785 36,059
924,794 908,249
$ 2,816,725 $ 2,704,792
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Short-term borrowings-
Associated companies $ 166,534 $ 199,231
Other 199,000 -
Accounts payable-
Associated companies 23,354 92,020
Other 46,225 47,629
Accrued taxes 2,920 11,670
Accrued interest 7,404 7,224
Other 21,703 21,178
467,140 378,952
CAPITALIZATION:

Common stockholder's equity-
Common stock, $20 par value, authorized 5,400,000 shares-
5,290,596 shares outstanding 105,812 105,812
Other paid-in capital 1,189,479 1,189,434
Accumulated other comprehensive loss (10,226 ) (7,193 )
Retained earnings 116,165 90,005
Total common stockholder's equity 1,401,230 1,378,058
Long-term debt and other long-term obligations 477,704 477,304
1,878,934 1,855,362
NONCURRENT LIABILITIES:

Regulatory liabilities 73,990 96,151
Asset retirement obligations 79,348 76,924
Accumulated deferred income taxes 185,969 193,662
Retirement benefits 50,974 50,328
Other 80,370 53,413
470,651 470,478
COMMITMENTS AND CONTINGENCIES (Note 9)

$ 2,816,725 $ 2,704,792

The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an
integral part of these balance sheets.

~~113~~

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended

June 30,

2007

2006

(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 51,207 $ 38,606
Adjustments to reconcile net income to net cash from operating activities
Provision for depreciation 24,112 24,441
Amortization of regulatory assets 29,239 27,794
Deferral of new regulatory assets (17,452 ) (11,815 )
Deferred costs recoverable as regulatory assets (34,691 ) (54,092 )
Deferred income taxes and investment tax credits, net 13,548 13,206
Accrued compensation and retirement benefits (12,130 ) 893
Cash collateral 3,250 -
Pension trust contribution (13,436 ) -
Decrease (increase) in operating assets
Receivables (39,530 ) 30,485
Prepayments and other current assets (20,819 ) (18,565 )
Increase (decrease) in operating liabilities
Accounts payable (70,070 ) (9,008 )
Accrued taxes (8,750 ) (10,756 )
Accrued interest 181 190
Other 1,377 8,817
Net cash provided from (used for) operating activities (93,964 ) 40,196

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing
Short-term borrowings, net 166,303 26,642
Dividend Payments
Common stock (25,000 ) -
Net cash provided from financing activities 141,303 26,642

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (43,904 ) (60,747 )
Loan repayments from (loans to) associated companies, net 1,285 (3,466 )
Sales of investment securities held in trust 26,882 60,650
Purchases of investment securities held in trust (29,610 ) (60,650 )
Other, net (1,996 ) (2,611 )
Net cash used for investing activities (47,343 ) (66,824 )

Net increase (decrease) in cash and cash equivalents (4 ) 14
Cash and cash equivalents at beginning of period 44 35
Cash and cash equivalents at end of period $ 40 $ 49

The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an
integral part of these statements.

~~114~~

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of Pennsylvania Electric Company:~~

We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 30, 2007 and 2006. 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, 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.

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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes 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 defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 9 to those consolidated financial statements) dated February 27, 2007, 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, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~August 6, 2007~~

~~115~~

~~PENNSYLVANIA ELECTRIC COMPANY~~

~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also provides generation services to those customers electing to retain Penelec as their power supplier.

~~Results of Operations~~

Net income in the second quarter of 2007 increased to $19 million, compared to $15 million in the second quarter of 2006. This increase resulted from higher revenues partially offset by higher purchased power costs, other operating costs and lower deferrals of new regulatory assets due to the May 2006 PPUC order discussed below. In the first six months of 2007, net income increased to $51 million, compared to $39 million in the first six months of 2006. This increase in net income was due to higher revenues and deferrals of new regulatory assets, partially offset by increased purchased power costs and other operating costs.

~~Revenues~~

Revenues increased by $66 million, or 25.1%, in the second quarter of 2007 and $131 million, or 23.5%, in the first six months of 2007. The increases in both periods were primarily due to higher retail and wholesale generation revenues.

Retail generation revenues increased by $6 million in the second quarter of 2007 primarily due to higher KWH sales to residential and commercial customers. The increase in retail generation revenues in the residential and commercial classes was primarily due to higher weather-related usage in the second quarter of 2007 compared to the second quarter of 2006 (heating degree days increased 6.2% and cooling degree days increased 58.5%).

Retail generation revenues increased $12 million for the first six months of 2007 primarily due to higher KWH sales to all customer classes. The increase in retail generation revenues in the residential and commercial sectors was primarily due to weather conditions in the first six months of 2007 (heating degree days increased 12.5% and cooling degree days increased 58.5% as compared to the same time period of 2006).

~~Increases in retail electric generation sales and revenues in the second quarter and first six months of 2007 compared to the corresponding periods of 2006 are summarized in the following tables:~~

Retail Generation KWH Sales

Three Months

Six Months

Increase (Decrease)

Residential 5.2 % 5.5 %
Commercial 4.9 % 5.0 %
Industrial (0.1 )% -
Total Retail Electric Generation Sales

3.3
%

3.6
%

Retail Generation Revenues

Three Months

Six Months

(In millions)

Residential $ 3 $ 6
Commercial 3 6
Industrial - -
Increase in Retail Generation Revenues

$
6

$
12

Wholesale revenues increased $39 million in the second quarter of 2007 and $74 million in the first six months of 2007, compared with the same periods of 2006 due to Penelec selling additional available power into the PJM market beginning in January 2007.

Revenues from distribution throughput increased $13 million in the second quarter and $29 million in the first six months of 2007 due to higher KWH deliveries reflecting the effect of the weather discussed above and an increase in composite unit prices resulting from a January 2007 PPUC authorization to increase transmission rates, partially offset by a 4.5% decrease in distribution rates.

~~116~~

~~Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 compared to the same periods in 2006 are summarized in the following tables:~~

Distribution KWH Deliveries

Three Months

Six Months

Increase (Decrease)

Residential 5.2 % 5.5 %
Commercial 4.9 % 5.0 %
Industrial - (0.9 )%
Total Distribution Deliveries

3.2
%

3.1
%

Distribution Revenues

Three Months

Six Months

Increase (Decrease)

(In millions)

Residential $ 13 $ 30
Commercial (1 ) (3 )
Industrial 1 2
Total Distribution Revenues

$
13

$
29

PJM transmission revenues increased by $9 million in the second quarter of 2007 and $15 million in the first six months of 2007 compared to the same period in 2006 due to higher transmission volumes and additional PJM auction revenue rights in 2007. Penelec defers the difference between revenue from its transmission rider and transmission costs incurred, with no material effect to current period earnings.

~~Expenses~~

Total expenses increased by $62 million in the second quarter of 2007 and $105 million in the first six months of 2007 compared with the same periods in 2006. The following table presents changes from the prior year by expense category:

Three

Six

Expenses - Changes

Months

Months

(In millions)
Increase (Decrease)

Purchased power costs $ 38 $ 77
Other operating costs 10 31
Provision for depreciation 1 -
Amortization of regulatory assets 1 1
Deferral of new regulatory assets 11 (5 )
General taxes 1 1
Net increase in expenses
$ 62 $ 105

Purchased power costs increased by $38 million, or 25.6%, in the second quarter of 2007 and $77 million, or 24.9%, in the first six months of 2007, compared to the same period of 2006. The increases were due primarily to higher KWH purchases to source higher retail and wholesale generation sales combined with higher composite unit costs. Other operating costs increased by $9 million in the second quarter of 2007 and $32 million in the first six months of 2007 principally due to higher congestion costs and other transmission expenses associated with the increased transmission volumes discussed above.

In the second quarter of 2007, the deferral of new regulatory assets decreased primarily due to higher PJM transmission cost deferrals recognized in the second quarter of 2006. The deferral in the second quarter of 2006 also included PJM transmission costs incurred in the first quarter following authorization by the PPUC in May 2006. The deferral of new regulatory assets increased in the first six months of 2007 due to the deferral of previously expensed decommissioning costs of $12 million associated with the Saxton nuclear research facility as approved by the PPUC in January 2007, partially offset by lower PJM transmission cost deferrals.

~~Capital Resources and Liquidity~~

During 2007, Penelec expects to meet its contractual obligations with a combination of cash from operations and funds from the capital markets. Borrowing capacity under Penelec’s credit facilities is available to manage its working capital requirements.

~~117~~

~~Changes in Cash Position~~

~~As of June 30, 2007, Penelec had $40,000 of cash and cash equivalents compared with $44,000 as of December 31, 2006. The major sources for changes in these balances are summarized below.~~

~~Cash Flows From Operating Activities~~

~~Net cash provided (used) for operating activities in the second quarter of 2007 and 2006 were as follows:~~

Six Months Ended

June 30,

Operating Cash Flows

2007

2006

(In millions)

Net income $ 51 $ 39
Net non-cash charges 3 -
Pension trust contribution (13 ) -
Working capital and other (135 ) 1
Net cash provided from (used for) operating activities $ (94 ) $ 40

The $136 million change from working capital principally resulted from a $70 million change in accounts receivable due in part to increased billings associated with the January 2007 rate increase that were delayed until the second quarter of 2007, increased cash payments of $61 million for accounts payable and $8 million in increased cash outflows from other operating activities partially offset by a $3 million increase in cash collateral received from suppliers. Changes in net income and non-cash charges are described under “Results of Operations.”

~~Cash Flows From Financing Activities~~

Net cash provided from financing activities was $141 million in the first six months of 2007 compared to $26 million in the first six months of 2006. The increase reflects a $140 million increase in short-term borrowings, partially offset by a $25 million increase in common stock dividend payments to FirstEnergy.

Penelec had approximately $18 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $366 million of short-term indebtedness (including $74 million from its receivables financing arrangement and $167 million in money pool borrowings) as of June 30, 2007. Penelec has authorization from the FERC to incur short-term debt of up to $250 million (excluding receivables financing and money pool borrowings) and authorization from the PPUC to incur money pool borrowings of up to $300 million.

~~See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of Penelec’s financing capabilities.~~

~~Cash Flows From Investing Activities~~

In the first six months of 2007, net cash used for investing activities totaled $47 million compared to $67 million in the first six months of 2006. The decrease primarily resulted from a $17 million decrease in property additions and a $5 million increase in loan repayments from associated companies, partially offset by a $3 million increase in the investments in the nuclear decommissioning trust fund.

During the last half of 2007, capital requirements for property additions are expected to be about $46 million. Penelec’s capital spending for the period 2007-2011 is expected to be about $614 million, of which approximately $92 million applies to 2007.

~~Market Risk Information~~

During the first six months of 2007, the value of commodity derivative contracts decreased by $2 million as a result of settled contracts. These non-trading contracts are adjusted to fair value at the end of each quarter with a corresponding offset to regulatory liabilities, resulting in no impact to current period earnings. Commodity derivative contracts were valued at $10 million and $12 million as of June 30, 2007 and December 31, 2006, respectively. See the “Market Risk Information” section of Penelec’s 2006 Annual Report on Form 10-K for additional discussion of market risk.

~~118~~

~~Equity Price Risk~~

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $80 million and $72 million as of June 30, 2007 and December 31, 2006, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $8 million reduction in fair value as of June 30, 2007.

~~Regulatory Matters~~

~~See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to Penelec.~~

~~Environmental Matters~~

~~See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to Penelec.~~

~~Other Legal Proceedings~~

~~See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to Penelec.~~

~~New Accounting Standards and Interpretations~~

~~119~~

~~COMBINED MANAGEMENT’S DISCUSSION~~

~~AND ANALYSIS OF REGISTRANT SUBSIDIARIES~~

The following is a combined presentation of certain disclosures referenced in Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Companies. This information should be read in conjunction with (i) the Companies’ respective Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations; (ii) the Notes to Consolidated Financial Statements as they relate to the Companies; and (iii) the Companies’ respective 2006 Annual Reports on Form 10-K.

~~Financing Capability~~ ~~(Applicable to each of the Companies)~~

As of June 30, 2007, OE, CEI and TE had the capability to issue approximately $1.5 billion, $557 million and $797 million, respectively, of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE, CEI and TE is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $463 million, $515 million and $127 million, respectively, as of June 30, 2007. Because JCP&L satisfied the provision of its senior note indenture for the release of all FMBs held as collateral for senior notes in May 2007, it is no longer required to issue FMBs as collateral for senior notes and therefore is not limited as to the amount of senior notes it may issue.

~~As of June 30, 2007, OE had approximately $400 million of capacity remaining unused under its existing shelf registration for unsecured debt securities filed with the SEC in 2006.~~

Revolving

Regulatory and

Credit Facility

Other Short-Term

Borrower

Sub-Limit

Debt Limitations⁽¹⁾

(In millions)

FirstEnergy
$ 2,750 $ -
⁽²⁾
OE
500 500
Penn
50 39
CEI
250
⁽³⁾
500
TE
250
⁽³⁾
500
JCP&L
425 431
Met-Ed
250 250
⁽⁴⁾
Penelec
250 250
⁽⁴⁾

⁽¹⁾

~~As of June 30, 2007.~~

⁽²⁾

~~No regulatory approvals, statutory or charter limitations applicable.~~

⁽³⁾

~~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.~~

⁽⁴⁾

~~Excluding amounts which may be borrowed under the regulated money pool.~~

~~120~~

~~Borrower~~
~~FirstEnergy~~	61	%
OE*	48	%
~~Penn~~	24	%
CEI*	60	%
TE*	56	%
~~JCP&L~~	32	%
~~Met-Ed~~	46	%
Penelec*	38	%

*The ratios of June 30, 2007, as adjusted for common stock dividends declared

~~in July 2007 would be: OE – 50%, CEI – 63%, TE – 61% and Penelec – 39%.~~

The Companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. FESC administers the money pool and tracks surplus funds of FirstEnergy and the Companies, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first six months of 2007 was 5.64%.

Each of the Companies’ access to capital markets and costs of financing are influenced by the ratings of its securities and the securities of FirstEnergy. The following table displays FirstEnergy’s and the Companies’ securities ratings as of June 30, 2007. The ratings outlook from Moody’s is positive for all securities. The ratings outlook from S&P on all securities is stable. The ratings outlook from Fitch on CEI and TE is positive and stable on all other operating companies.

~~Issuer~~	~~Securities~~	~~S&P~~	~~Moody’s~~	~~Fitch~~

~~FirstEnergy~~	~~Senior unsecured~~	~~BBB-~~	~~Baa3~~	~~BBB~~

OE	~~Senior unsecured~~	~~BBB+~~	~~Baa1~~	~~BBB+~~

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

TE	~~Senior secured~~	~~BBB~~	~~Baa2~~	~~BBB~~
	~~Senior unsecured~~	~~BBB-~~	~~Baa3~~	~~BBB-~~

~~Penn~~	~~Senior secured~~	~~BBB+~~	~~Baa1~~	~~BBB+~~

~~JCP&L~~	~~Senior secured~~	~~BBB+~~	~~Baa1~~	A-

~~Met-Ed~~	~~Senior unsecured~~	~~BBB~~	~~Baa2~~	~~BBB~~

~~Penelec~~	~~Senior unsecured~~	~~BBB~~	~~Baa2~~	~~BBB~~

OE, CEI, Penn, Met-Ed and Penelec each have a wholly owned subsidiary whose borrowings are secured by customer accounts receivable purchased from its respective parent company. The CEI subsidiary's borrowings are also secured by customer accounts receivable purchased from TE. Each subsidiary company has its own receivables financing arrangement and, as a separate legal entity with separate creditors, would have to satisfy its obligations to creditors before any of its remaining assets could be available to its parent company. The receivables financing borrowing capacity and outstanding balance by company, as of June 30, 2007, are shown in the following table.

~~121~~

Subsidiary Company

Parent Company

Borrowing
Capacity

Outstanding Balance

Annual Facility Fee

(In millions)
OES Capital, Incorporated OE $ 170 $ 100    0.15%
Centerior Funding Corp. CEI 200 - 0.15
Penn Power Funding LLC Penn 25 17   0.125
Met-Ed Funding LLC Met-Ed 80 72   0.125
Penelec Funding LLC Penelec 75 74   0.125
$ 550 $ 263

~~Regulatory Matters~~~~(Applicable to each of the Companies)~~

·	~~restructuring the electric generation business and allowing customers to select a competitive electric generation supplier other than the Companies;~~

·	~~establishing or defining the PLR obligations to customers in the Companies' service areas;~~

·	~~providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;~~

·	~~itemizing (unbundling) the price of electricity into its component elements – including generation, transmission, distribution and stranded costs recovery charges;~~

·	~~continuing regulation of the Companies' transmission and distribution systems; and~~

·	~~requiring corporate separation of regulated and unregulated business activities.~~

The Companies recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $219 million as of June 30, 2007 (JCP&L - $103 million, Met-Ed - $34 million and Penelec - $82 million). Regulatory assets not earning a current return will be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec. The following table discloses regulatory assets by company:

*	~~Penelec had net regulatory liabilities of approximately $74 million~~ ~~and $96 million as of June 30, 2007 and December 31, 2006,~~ ~~respectively. These net regulatory liabilities are included in Other~~ ~~Non-current Liabilities on the Consolidated Balance Sheets.~~

~~122~~

~~Ohio~~ ~~(Applicable to OE, CEI and TE)~~

On October 21, 2003, the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to the PUCO’s concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order in all respects, except it remanded back to the PUCO the matter of ensuring the availability of sufficient means for customer participation in the marketplace. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio’s findings on customer participation. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and considered to be null and void. On July 20, 2006, the OCC and NOAC also submitted to the PUCO a conceptual proposal addressing the issue raised by the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry directing the Ohio Companies to file a plan in a new docket to address the Court’s concern. The Ohio Companies filed their RSP Remand CBP on September 29, 2006. Initial comments were filed on January 12, 2007 and reply comments were filed on January 29, 2007. In their reply comments the Ohio Companies described the highlights of a new tariff offering they would be willing to make available to customers that would allow customers to purchase renewable energy certificates associated with a renewable generation source, subject to PUCO approval. On May 29, 2007, the Ohio Companies, together with the PUCO Staff and the OCC, filed a stipulation with the PUCO agreeing to offer a standard bid product and a green resource tariff product. The stipulation is currently pending before the PUCO. No further proceedings are scheduled at this time.

Amortization

Total

Period

OE

CEI

TE

Ohio

(In millions)

2007
$
179
$
108
$
93
$
380
2008 208 124 119 451
2009 - 216 - 216
2010

-

273

-

273

Total Amortization

$
387

$
721

$
212

$
1,320

On May 8, 2007, the Ohio Companies filed with the PUCO a notice of intent to file for an increase in electric distribution rates. The Ohio Companies filed the application and rate request with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operating and maintenance expenses and recovery of regulatory assets created by deferrals that were approved in prior cases. On August 6, 2007, the Ohio Companies provided an update filing supporting a distribution rate increase of $332��million to the PUCO to establish the test period data that will be used as the basis for setting rates in that proceeding. The PUCO Staff is expected to issue its report in the case in the fourth quarter of 2007 with evidentiary hearings to follow in late 2007. The PUCO order is expected to be issued by March 9, 2008. The new rates, subject to evidentiary hearings and approval at the PUCO, would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.

~~123~~

~~Pennsylvania~~ ~~(Applicable to Met-Ed, Penelec and Penn)~~

~~124~~

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, when new transmission rates were effective, 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 in 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 expenses and the transmission deferral. 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). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s, Penelec’s and the other parties’ petitions for procedural purposes. Due to that ruling, the period for appeals to the Commonwealth Court of Pennsylvania was tolled until 30 days after the PPUC entered a subsequent order ruling on the substantive issues raised in the petitions. On March 1, 2007, the PPUC issued three orders: (1) a tentative order regarding the reconsideration by the PPUC of its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part MEIUG’s and PICA’s Petition for Reconsideration; and (3) an order approving the Compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.

On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from June 2008 through May 2011. The filing proposes multiple, competitive RFPs with staggered delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service would be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. The PPUC is requested to act on the proposal no later than November 2007 for the initial RFP to take place in January 2008.

~~125~~

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 programs to meet demand 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 an optional 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 will be convened in mid-September 2007 to consider other aspects of the EIS. The final form of any legislation arising from the special legislative session is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.

~~New Jersey~~ ~~(Applicable to JCP&L)~~

·~~Reduce the total projected electricity demand by 20% by 2020;~~

· ~~Meet 22.5% of New Jersey’s electricity needs with renewable energy resources by that date;~~

·~~Reduce air pollution related to energy use;~~

·~~Encourage and maintain economic growth and development;~~

· ~~Achieve a 20% reduction in both Customer Average Interruption Duration Index and System Average Interruption Frequency Index by 2020;~~

· ~~Unit prices for electricity should remain no more than +5% of the regional average price (region includes New York, New Jersey, Pennsylvania, Delaware, Maryland and the~~

~~District of Columbia); and~~

·~~Eliminate transmission congestion by 2020.~~

~~126~~

~~FERC Matters~~ ~~(Applicable to each of the Companies)~~

~~127~~

On February 16, 2007, the FERC issued a final rule that revises its decade-old open access transmission regulations and policies. The FERC explained that the final rule is intended to strengthen non-discriminatory access to the transmission grid, facilitate FERC enforcement, and provide for a more open and coordinated transmission planning process. The final rule became effective on May 14, 2007. MISO, PJM and ATSI will be filing revised tariffs to comply with the FERC’s order. As market participants in both MISO and PJM, the Companies will conform their business practices to each respective revised tariff.

~~Environmental Matters~~~~(Applicable to each of the Companies)~~

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

~~128~~

~~Regulation of Hazardous Waste~~

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

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 NO_X ~~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 settlement agreement are currently estimated to be $1.7 billion for FGCO for 2007 through 2011 ($400 million of which is expected to be spent during 2007, with the largest portion of the remaining $1.3 billion expected to be spent in 2008 and 2009).

~~Other Legal Proceedings~~~~(Applicable to each of the Companies)~~

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to the Companies’ normal business operations pending against FirstEnergy and the Companies. The other material items not otherwise discussed above are described below.

~~Power Outages and Related Litigation~~

~~129~~

~~130~~

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. Although FirstEnergy is unable to predict the impact of these proceedings, if FirstEnergy or the Companies were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or the Companies' financial condition, results of operations and cash flows.

~~Other Legal Matters~~

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 ~~plaintiff’s~~plaintiffs’ motion to amend their complaint which OE ~~has~~ 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.

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 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 to confirm the award and JCP&L ~~intends~~filed its answer and counterclaim to ~~re-file an appeal~~vacate the award on December 31, 2007. The court held a scheduling conference in ~~federal district court once the damages associated~~April 2008 where it set a briefing schedule with ~~this case are identified at an individual employee level.~~all briefs to be concluded by July 2008. 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 ~~met on June 27, 2007 before an arbitrator~~are continuing to ~~assert their positions regarding~~bargain with the ~~finality~~assistance of ~~damages. A hearing before~~a federal mediator. FirstEnergy has a strike mitigation plan ready in the ~~arbitrator is set for September 7, 2007.~~event of a strike.

~~131~~

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 ~~the Companies~~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 ~~the Companies’~~its subsidiaries' financial condition, results of operations and cash flows.

107

11. REGULATORY MATTERS

~~New Accounting Standards~~(A) RELIABILITY INITIATIVES

In late 2003 and ~~Interpretations~~~~(Applicable~~early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. – Canada Power System Outage Task Force) regarding enhancements to ~~each~~regional reliability. The proposed enhancements were divided into two groups: enhancements that were to be completed in 2004; and enhancements that were to be completed after 2004. In 2004, FirstEnergy completed all of the ~~Companies)~~enhancements that were recommended for completion in 2004. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.

As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU performed a review of JCP&L’s service reliability. On June 9, 2004, the NJBPU approved a stipulation that addresses a third-party consultant’s recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation incorporates the consultant’s focused audit of, and recommendations regarding, JCP&L’s Planning and Operations and Maintenance programs and practices. On June 1, 2005, the consultant completed his work and issued his final report to the NJBPU. On July 14, 2006, JCP&L filed a comprehensive response to the consultant’s report with the NJBPU. JCP&L will complete the remaining substantive work described in the stipulation in 2008. JCP&L continues to file compliance reports with the NJBPU reflecting JCP&L’s activities associated with implementing the stipulation.

In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Companies and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including the ReliabilityFirst Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards.

FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clear that NERC, ReliabilityFirst and the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time. However, the 2005 amendments to the Federal Power Act provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could have a material adverse effect on its financial condition, results of operations and cash flows.

In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the Midwest ISO region and found it to be in full compliance with all audited reliability standards. Similarly, ReliabilityFirst has scheduled a compliance audit of FirstEnergy’s bulk-power system within the PJM region in 2008. FirstEnergy currently does not expect any material adverse financial impact as a result of these audits.

108

(B) OHIO

On January 4, 2006, the PUCO issued an order authorizing the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a twenty-five-year period through distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” and remanded the matter to the PUCO for further consideration. On September 10, 2007 the Ohio Companies filed an application with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. On January 9, 2008 the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $189 million. In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider, with alternative options for the recovery period ranging from five to twenty-five years. This second application is currently pending before the PUCO and a hearing has been set for July 15, 2008.

The Ohio Companies filed an application and rate request for an increase in electric distribution rates with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the average electric bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operation and maintenance expenses and recovery of regulatory assets that were authorized in prior cases. On August 6, 2007, the Ohio Companies updated their filing supporting a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of their investigation into the distribution rate request. In its reports, the PUCO Staff recommended a distribution rate increase in the range of $161 million to $180 million, with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. This amount excludes the recovery of deferred fuel costs, whose recovery is now being sought in a separate proceeding before the PUCO, discussed above. On January 3, 2008, the Ohio Companies and intervening parties filed objections to the Staff Reports and on January 10, 2008, the Ohio Companies filed supplemental testimony. Evidentiary hearings began on January 29, 2008 and continued through February 25, 2008. During the evidentiary hearings, the PUCO Staff submitted testimony decreasing their recommended revenue increase to a range of $114 million to $132 million. Additionally, in testimony submitted on February 11, 2008, the PUCO Staff adopted a position regarding interest deferred for RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by the PUCO, would result in the write-off of approximately $45 million of interest costs deferred through March 31, 2008 ($0.09 per share of common stock). The PUCO is expected to render its decision during the second or third quarter of 2008. The new rates would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.

On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing retail generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per KWH would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. A slice-of-system approach would require the successful bidder to be responsible for supplying a fixed percentage of the utility’s total load notwithstanding the customer’s classification. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The PUCO held a technical conference on August 16, 2007 regarding the filing. Initial and reply comments on the proposal were filed by various parties in September and October 2007, respectively. The proposal is currently pending before the PUCO.

On April 22, 2008, an amended version of Substitute SB221 was passed by the Ohio House of Representatives and sent back 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, with the PUCO. An ESP is required to contain a proposal for the supply and pricing of retail generation and may include proposals, without limitation, related to one or more of the following:

109

·	automatic recovery of prudently incurred fuel, purchased power, emission allowance costs and federally mandated energy taxes;

~~SFAS 159 – “The Fair Value Option~~
· construction work in progress for ~~Financial Assets~~costs of constructing an electric generating facility or environmental expenditure for any electric generating facility;

·	costs of an electric generating facility;

·	terms related to customer shopping, bypassability, standby, back-up and ~~Financial Liabilities – Including an amendment~~default service;

·	accounting for deferrals related to stabilizing retail electric service;

·	automatic increases or decreases in standard service offer price;

·	phase-in and securitization;

·	transmission service and related costs;

·	distribution service and related costs; and

·	economic development and energy efficiency.

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 that contemplate 25% of electrical usage from these sources by 2025. Energy efficiency measures in the bill require energy savings in excess of 22% by 2025. Requirements are in place to meet annual benchmarks for renewable energy resources and energy efficiency, subject to review by the PUCO. FirstEnergy is currently evaluating this legislation and expects to file an ESP in the second or third quarter of 2008.

(C) PENNSYLVANIA

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.

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.

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 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 in September 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the results of operations of Met-Ed, Penelec and FirstEnergy.

On April 14, 2008, Met-Ed and Penelec filed annual updates to the TSC rider for the period June 1, 2008, through May 31, 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 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 the other’s bill. On February 12, 2008, the Pennsylvania House passed House Bill 2200 which provides for energy efficiency and demand management programs and targets as well as the installation of smart meters within ten years. Other legislation has been introduced to address generation procurement, expiration of rate caps, conservation and renewable energy. The final form of this pending legislation is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.

(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, 2008, the accumulated deferred cost balance totaled approximately $264 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 comments from interested parties due on May 16, 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 the fall of 2006 and in early 2007.

On April 17, 2008, a draft EMP was released for public comment. The draft EMP establishes four 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);

112

·	meet 22.5% of ~~FASB Statement No. 115”~~the state’s electricity needs with renewable energy by 2020; and

·	develop low carbon emitting, efficient power plants and close the gap between the supply and demand for electricity.

Following the public comment period which is expected to extend into July 2008, a 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 transmission charges 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 in the second quarter of 2008.

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 future transmission revenue recovery 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 the settlement agreement is pending. The remaining merchant transmission cost allocation issues will proceed to hearing in May 2008. On February 13, 2008, AEP appealed the FERC’s 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.

113

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. 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 would permit 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 the FERC that the start of its ASM is delayed until September of 2008.

114

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 to pay the 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 in PJM’s May 2008 auction for the 2011-2012 RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification, wherein 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 contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with 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 the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction. Notwithstanding these events, on April 30, 2008 and May 1, 2008, certain members of the PJM Power Providers Group filed further pleadings on these issues. On May 2, 2008, FirstEnergy filed a responsive pleading. FirstEnergy is participating in the May 2008 RPM auction for the 2011-2012 RPM delivery year.

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 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 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 entities in its state. FirstEnergy generally supports 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 approved MISO’s Resource Adequacy proposal on March 26, 2008. Rehearing requests are pending on the FERC’s March 26 Order. A compliance filing establishing the enforcement mechanism for the reserve margin requirement is due on or before June 25, 2008.

Organized Wholesale Power Markets

On February 21, 2008, the FERC issued a NOPR through which it proposes to adopt 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 that the proposed rule will have a significant impact on its operations. Comments on the NOPR were filed on April 18, 2008.

115

12. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 141(R) – “Business Combinations”

In ~~February~~December 2007, the FASB issued SFAS ~~159,~~141(R), which ~~provides companies with an option~~requires the acquiring entity in a business combination to ~~report selected financial~~recognize all the assets acquired and liabilities atassumed in the transaction; establishes the acquisition-date fair ~~value. This Statement~~value as the measurement objective for all assets acquired and liabilities assumed; and requires ~~companies~~the acquirer to ~~provide additional information that will help~~disclose to investors and other users all of ~~financial statements~~the information they need to ~~more easily~~evaluate and understand the nature and financial effect of the ~~company’s choice~~business combination. SFAS 141(R) attempts to ~~use fair value~~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 tax valuation allowances 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 the impact of adopting this Standard on its ~~earnings. The Standard also requires companies to display~~financial statements.

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

In December 2007, the ~~fair value~~FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of ~~those assets and liabilities for which~~a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the ~~company has chosen to use fair value on~~consolidated entity that should be reported as equity in the face of the balance sheet. This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157~~and SFAS 107~~. consolidated financial statements. This Statement is effective for ~~financial statements issued for~~ fiscal years, ~~beginning after November 15, 2007,~~ and interim periods within those ~~years. The Companies are currently evaluating the impact of this Statement on their financial statements.~~

~~SFAS 157 – “Fair Value Measurements”~~

In September 2006, the FASB issued SFAS 157 that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value which focuses on an exit price rather than entry price; (2) the methods used to measure fair value such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement is effective for financial statements issued for fiscal years, beginning ~~after November 15, 2007, and interim periods within those years. The Companies are currently evaluating the impact of this Statement~~ on ~~their financial statements.~~

~~EITF 06-11 – “Accounting for Income Tax Benefits of Dividends~~ or ~~Share-based Payment Awards”~~

In June 2007, the FASB released EITF 06-11, which provides guidance on the appropriate accounting for income tax benefits related to dividends earned on nonvested share units that are charged to retained earnings under SFAS 123(R). The consensus requires that an entity recognize the realized tax benefit associated with the dividends on nonvested shares as an increase to additional paid-in capital (APIC). This amount should be included in the APIC pool, which is to be used when an entity’s estimate of forfeitures increases or actual forfeitures exceed its estimates, at which time the tax benefits in the APIC pool would be reclassified to the income statement. The consensus is effective for income tax benefits of dividends declared during fiscal years beginning after December 15, ~~2007. EITF 06-11~~2008. Early adoption is prohibited. The Statement is not expected to have a material impact on ~~the Companies’~~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 requires enhancements to 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 the fair values of derivative instruments and their gains and losses in a tabular format is designed to 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 Statement requires cross-referencing within the footnotes, which is intended to help users of financial statements locate important information about derivative instruments. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

13. 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 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 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.

~~132~~116

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

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

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.

The consolidating statements of income for the three months ended March 31, 2008 and 2007, consolidating balance sheets as of March 31, 2008 and December 31, 2007 and condensed consolidating statements of cash flows for the three months ended March 31, 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

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

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

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

REVENUES $ 1,019,387 $ 551,355 $ 234,091 $ (786,540 ) $ 1,018,293

EXPENSES:
Fuel 2,367 201,231 29,937 - 233,535
Purchased power from non-affiliates 186,203 2,367 - (2,367 ) 186,203
Purchased power from affiliates 784,172 59,069 17,415 (784,173 ) 76,483
Other operating expenses 51,249 99,095 113,252 - 263,596
Provision for depreciation 453 24,936 22,621 - 48,010
General taxes 4,934 10,568 6,216 - 21,718
Total expenses 1,029,378 397,266 189,441 (786,540 ) 829,545

OPERATING INCOME (LOSS) (9,991 ) 154,089 44,650 - 188,748

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees 113,948 916 5,200 (100,332 ) 19,732
Interest expense to affiliates - (24,331 ) (5,115 ) - (29,446 )
Interest expense - other (1,385 ) (6,760 ) (9,213 ) - (17,358 )
Capitalized interest 5 2,099 1,105 - 3,209
Total other income (expense) 112,568 (28,076 ) (8,023 ) (100,332 ) (23,863 )

INCOME BEFORE INCOME TAXES 102,577 126,013 36,627 (100,332 ) 164,885

INCOME TAXES 73 49,289 13,019 - 62,381

NET INCOME $ 102,504 $ 76,724 $ 23,608 $ (100,332 ) $ 102,504

119

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
120

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS
(Unaudited)

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

CURRENT ASSETS:
Cash and cash equivalents $ 2 $ - $ - $ - $ 2
Receivables-
Customers 133,846 - - - 133,846
Associated companies 327,715 237,202 98,238 (286,656 ) 376,499
Other 2,845 978 - - 3,823
Notes receivable from associated companies 23,772 - 69,012 - 92,784
Materials and supplies, at average cost 195 215,986 210,834 - 427,015
Prepayments and other 67,981 21,605 2,754 - 92,340
   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
Less - Accumulated provision for depreciation 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
Construction work in progress 1,176 571,672 188,853 - 761,701
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
Long-term notes receivable from associated companies - - 62,900 - 62,900
Investment in associated companies 2,516,838 - - (2,516,838 ) -
Other 2,732 37,071 201 - 40,004
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
Lease assignment receivable from associated companies - 215,258 - - 215,258
Goodwill 24,248 - - - 24,248
Property taxes - 25,007 22,767 - 47,774
Pension asset 3,217 13,506 - - 16,723
Unamortized sale and leaseback costs - 27,597 - 43,206 70,803
Other 22,956 52,971 6,159 (38,133 ) 43,953
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

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ - $ 596,827 $ 861,265 $ (16,896 ) $ 1,441,196
Short-term borrowings-
Associated companies - 238,786 25,278 - 264,064
Other 300,000 - - - 300,000
Accounts payable-
Associated companies 287,029 175,965 268,926 (286,656 ) 445,264
Other 56,194 120,927 - - 177,121
Accrued taxes 18,831 125,227 28,229 (836 ) 171,451
Other 57,705 131,404 11,972 36,725 237,806
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
Long-term debt and other long-term obligations - 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

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction - - - 1,060,119 1,060,119
Accumulated deferred income taxes - - 259,147 (259,147 ) -
Accumulated deferred investment tax credits - 36,054 25,062 - 61,116
Asset retirement obligations - 24,346 785,768 - 810,114
Retirement benefits 8,721 54,415 - - 63,136
Property taxes - 25,328 22,767 - 48,095
Lease market valuation liability - 353,210 - - 353,210
Other 19,800 21,829 - - 41,629
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

121

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

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

~~The applicable registrant's~~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 ~~applicable~~ 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 ~~June 30, 2007,~~March 31, 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, 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.

~~133~~124

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 910 and 1011 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 Form 10-K for the year ended December 31, ~~2006~~2007 for a discussion of the risk factors of FirstEnergy and the subsidiary registrants. For the quarter ended ~~June 30, 2007,~~March 31, 2008, there have been no material changes to these risk factors.

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
	April 1-30,		May 1-31,		June 1-30,		Second		January 1-31,	February 1-29,	March 1-31,	First
	2007		2007		2007		Quarter		2008	2008	2008	Quarter
Total Number of Shares Purchased ^(a)	194,553		304,287		219,445		718,285		329,106	16,853	988,386	1,334,345
Average Price Paid per Share	$68.41		$71.09		$68.12		$69.46		$76.56	$71.68	$68.55	$70.57
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		1,629,890		1,629,890		1,629,890		1,629,890	-	-	-	-

^(a)	Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its ~~Executive and Director~~ 2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred ~~Comp ensation~~ Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the 2007 Incentive Compensation Plan and the Executive ~~and Director Incentive~~ Deferred Compensation Plan, and shares purchased as part of publicly announced plans.

^(b)	~~FirstEnergy publicly announced, on January 30,~~On December 10, 2007, aFirstEnergy’s plan to repurchase up to 16 million shares of its common stock through June 30, ~~2008. On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding~~ ~~common stock under this plan through an accelerated share repurchase program with an affiliate of Morgan Stanley and Co.,~~ ~~Incorporated at an initial price of $62.63 per share.~~ 2008, was concluded.

~~ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS~~

~~(a)~~

~~The annual meeting of FirstEnergy shareholders was held on May 15, 2007.~~

~~(b)~~

~~At this meeting, the following persons were elected to FirstEnergy's Board of Directors for one-year terms:~~

Number of Votes

For

Withheld

Paul T. Addison 188,720,311 74,174,290
Anthony J. Alexander 188,700,783 74,193,818
Michael J. Anderson 249,806,449 13,088,152
Dr. Carol A. Cartwright 159,733,696 103,160,905
William T. Cottle 166,930,916 95,963,685
Robert B. Heisler, Jr. 190,762,159 72,132,442
Ernest J. Novak, Jr. 188,312,120 74,582,481
Catherine A. Rein 188,486,982 74,407,619
George M. Smart 166,422,193 96,472,408
Wes M. Taylor 188,651,197 74,243,404
Jesse T. Williams, Sr. 166,684,440 96,210,161

~~134~~125

~~The following Directors retired from the Board effective May 15, 2007: Russell W. Maier and Robert C. Savage.~~

~~(c)~~ ~~(i)~~ ~~At this meeting, the appointment of PricewaterhouseCoopers LLP, an independent registered public accounting firm, as auditor for the year 2007 was ratified:~~

Number of Votes

For

Against

Abstentions

258,877,611 1,368,549 2,648,441

~~(ii)~~ ~~At this meeting, the FirstEnergy Corp. 2007 Incentive Plan was approved:~~

Number of Votes

Broker

For

Against

Abstentions

Non-Votes

207,313,123 23,286,182 3,901,643 28,393,653

~~(iii)~~ At this meeting, a shareholder proposal recommending that the Board of Directors change the company’s jurisdiction from Ohio to Delaware was not approved (approval required a favorable vote of a majority of the votes cast):

Number of Votes

Broker

For

Against

Abstentions

Non-Votes

80,014,916 149,489,965 5,026,051 28,363,669

~~(iv)~~ At this meeting, a shareholder proposal recommending that the Board of Directors adopt a policy establishing an engagement process with proponents of shareholder proposals that are supported by a majority of the votes cast was not approved (approval required a favorable vote of a majority of the votes cast):

Number of Votes

Broker

For

Against

Abstentions

Non-Votes

91,938,193 137,204,324 5,358,416 28,393,668

~~(v)~~ At this meeting, a shareholder proposal recommending that the Board of Directors adopt simple majority shareholder voting was approved (approval required a favorable vote of a majority of the votes cast):

Number of Votes

Broker

For

Against

Abstentions

Non-Votes

175,884,412 53,721,749 4,893,976 28,394,464

~~Based on this result, the Board of directors will further review this proposal~~
~~and consider the appropriate steps to take in response.~~

ITEM 6.    EXHIBITS

Exhibit
Number

~~FirstEnergy~~

~~10-1~~
~~Participation Agreement, dated as of June 26, 2007, among~~ FirstEnergy Generation Corp., as Lessee, FirstEnergy Solutions Corp., as Guarantor,  the applicable Lessor, U.S. Bank Trust National Association, as Trust Company, the applicable Owner Participant, The Bank of New York Trust Company, N.A., as Indenture Trustee, and The Bank of New York Trust Company, N.A., as Pass Through Trustee⁽¹⁾⁽²⁾

~~135~~

~~10-2~~
~~Trust Agreement, dated as of June 26, 2007 between the applicable Owner Participant and U.S. Bank Trust National Association, as Owner Trustee~~⁽¹⁾⁽²⁾
~~10-3~~
~~Indenture of Trust, Open-End Mortgage and Security Agreement, dated as of July 1, 2007, between the applicable Lessor and The Bank of New York Trust Company, N.A., as Indenture Trustee~~⁽¹⁾⁽²⁾
~~10-4~~
~~6.85% Lessor Note due 2034~~⁽¹⁾⁽²⁾~~(included in Exhibit 10-3)~~
~~10-5~~
~~Bill of Sale and Transfer, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor~~⁽¹⁾⁽²⁾
~~10-6~~
~~Facility Lease Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor~~⁽¹⁾⁽²⁾
~~10-7~~
~~Site Lease, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor~~⁽¹⁾⁽²⁾
~~10-8~~
~~Site Sublease, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor~~⁽¹⁾⁽²⁾
~~10-9~~
~~Guaranty of FirstEnergy Solutions Corp., dated as of July 1, 2007~~⁽¹⁾⁽²⁾
~~10-10~~
~~Support Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor~~⁽¹⁾⁽²⁾
~~10-11~~
Second Amendment to the Bruce Mansfield Units 1, 2, and 3 Operating Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp., The Cleveland Electric Illuminating Company, and The Toledo Edison Company⁽¹⁾
~~10-12~~
~~Pass Through Trust Agreement, dated as of June 26, 2007, among FirstEnergy Generation Corp., FirstEnergy Solutions Corp., and The Bank of New York Trust Company, N.A., as Pass Through Trustee~~⁽¹⁾
~~10-13~~
~~6.85% Pass Through Trust Certificate due 2034~~⁽¹⁾⁽²⁾~~(included in Exhibit 10-12)~~
~~10-14~~
Registration Rights Agreement, dated as of July 13, 2007, among FirstEnergy Generation Corp., FirstEnergy Solutions Corp., The Bank of New York Trust Company, N.A., as Pass Through Trustee, Morgan Stanley & Co. Incorporated, and Credit Suisse Securities (USA) LLC, as representatives of the several initial purchasers⁽¹⁾
12 Fixed charge ratios
15 Letter from independent registered public accounting firm
31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a).
31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a).
32 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section ~~1350.~~1350

FES
31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
32 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
OE
12 Fixed charge ratios
15 Letter from independent registered public accounting firm
31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
32 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
CEI
31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
32 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
TE
31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
32 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
JCP&L
31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
32 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
Met-Ed

31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
32 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
Penelec

12 Fixed charge ratios
15 Letter from independent registered public accounting firm
31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a).
31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a).
32 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section ~~1350.~~
~~CEI~~
~~31.1~~ ~~Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a).~~
~~31.2~~ ~~Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a).~~
32 ~~Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.~~
TE
~~31.1~~ ~~Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a).~~
~~31.2~~ ~~Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a).~~
32 ~~Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.~~
~~JCP&L~~
  3 ~~Jersey Central Power & Light Company By-Laws, as amended July 11, 2007~~
12 ~~Fixed charge ratios~~
~~31.1~~ ~~Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a).~~
~~31.2~~ ~~Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a).~~
32 ~~Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.~~

~~136~~

~~Met-Ed~~
12 ~~Fixed charge ratios~~
~~31.1~~ ~~Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a).~~
~~31.2~~ ~~Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a).~~
32 ~~Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.~~
~~Penelec~~
12 ~~Fixed charge ratios~~
15 ~~Letter from independent registered public accounting firm~~
~~31.1~~ ~~Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a).~~
~~31.2~~ ~~Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a).~~
32 ~~Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.~~

⁽¹⁾ ~~Incorporated by reference to the Registrant’s Form 8-K/A filed on August 2, 2007.~~
⁽²⁾ Pursuant to the Instructions to Item 601(a), the Registrant has omitted the indentures, contracts and other documents required to be filed as exhibits since they are substantially identical in all material respects except as to the parties thereto and certain other details as noted in the schedule filed as Exhibit 99-1 to the Registrant’s Form 8-K/A file on August 2, 2007. The Registrant agrees to furnish these items at the request of the SEC.
1350

Pursuant to reporting requirements of respective financings, FirstEnergy, OE ~~JCP&L, Met-Ed~~ and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q.

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.

~~137~~126

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

~~August 7, 2007~~May 8, 2008

FIRSTENERGY CORP.
Registrant

~~OHIO EDISON COMPANY~~
FIRSTENERGY SOLUTIONS CORP.
Registrant

~~THE CLEVELAND ELECTRIC~~
~~ILLUMINATING~~OHIO EDISON COMPANY
Registrant

THE ~~TOLEDO EDISON~~CLEVELAND ELECTRIC
ILLUMINATING COMPANY
Registrant

~~METROPOLITAN~~THE TOLEDO EDISON COMPANY
Registrant

METROPOLITAN EDISON COMPANY
Registrant
PENNSYLVANIA ELECTRIC COMPANY
Registrant

/s/  Harvey L. Wagner
Harvey L. Wagner
Vice President, Controller
and Chief Accounting Officer

JERSEY CENTRAL POWER & LIGHT COMPANY
Registrant

/s/  Paulette R. Chatman
Paulette R. Chatman
Controller
(Principal Accounting Officer)

~~138~~127

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
	~~76 South Main Street~~
	~~Akron, OH 44308~~
	Telephone (800)736-3402

~~1-2578~~ 333-145140-01	~~OHIO EDISON COMPANY~~ FIRSTENERGY SOLUTIONS CORP.	~~34-0437786~~ 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
	~~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
	~~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
	~~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
	~~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
	~~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
	~~c/o FirstEnergy Corp.~~
	~~76 South Main Street~~
	~~Akron, OH 44308~~
	Telephone (800)736-3402

Yes ~~Yes~~ (X) No ~~( )~~ No ( )	FirstEnergy Corp., Ohio 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 ~~(X)~~(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 ~~AUGUST 7, 2007~~MAY 8, 2008
FirstEnergy Corp., ~~$.10~~$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	~~5,290,596~~4,427,577

Jersey Central Power & Light Company		Pages

	Management's Narrative Analysis of Results of Operations	63-64
	Report of Independent Registered Public Accounting Firm	65
	Consolidated Statements of Income and Comprehensive Income	66
	Consolidated Balance Sheets	67
	Consolidated Statements of Cash Flows	68

Metropolitan Edison Company

	Management's Narrative Analysis of Results of Operations	69-70
	Report of Independent Registered Public Accounting Firm	71
	Consolidated Statements of Income and Comprehensive Income	72
	Consolidated Balance Sheets	73
	Consolidated Statements of Cash Flows	74
	~~Report of Independent Registered Public Accounting Firm~~	75
	~~Management's Discussion and Analysis of Financial Condition and~~	~~76-79~~
	~~Results of Operations~~

~~The Cleveland~~Pennsylvania Electric ~~Illuminating~~ Company

	~~Consolidated Statements~~Management's Narrative Analysis of ~~Income and Comprehensive Income~~Results of Operations	80
	~~Consolidated Balance Sheets~~	81
	~~Consolidated Statements of Cash Flows~~	8275-76
	Report of Independent Registered Public Accounting Firm	83
	~~Management's Discussion and Analysis of Financial Condition and~~	~~84-87~~
	~~Results of Operations~~

~~The Toledo Edison Company~~
		77
	Consolidated Statements of Income and Comprehensive Income	8878
	Consolidated Balance Sheets	8979
	Consolidated Statements of Cash Flows	9080
	~~Report of Independent Registered Public Accounting Firm~~	91
		~~Management's~~ Combined Management’s Discussion and Analysis of ~~Financial Condition and~~Registrant Subsidiaries	~~92-95~~81-94

~~Results of Operations~~Combined Notes to Consolidated Financial Statements		95-123

Item 3. Quantitative and Qualitative Disclosures About Market Risk.		124

Item 4. Controls and Procedures – FirstEnergy.		124

Item 4T. Controls and Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.		124

Part II. Other Information

~~Jersey Central Power & Light Company~~Item 1. Legal Proceedings.

	~~Consolidated Statements of Income and Comprehensive Income~~	96
	~~Consolidated Balance Sheets~~	97
	~~Consolidated Statements of Cash Flows~~	98
	~~Report of Independent Registered Public Accounting Firm~~	99
	~~Management's Discussion and Analysis of Financial Condition and~~	~~100-103~~
	~~Results of Operations~~

		Pages
Glossary of Terms		~~iii-iv~~iii-v

Part I. Financial Information

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

		~~Notes to Consolidated Financial Statements~~	~~1-25~~

FirstEnergy Corp.

	~~Consolidated Statements of Income~~	26
	~~Consolidated Statements of Comprehensive Income~~	27
	~~Consolidated Balance Sheets~~	28
	~~Consolidated Statements of Cash Flows~~	29
	~~Report of Independent Registered Public Accounting Firm~~	30
	Management's Discussion and Analysis of Financial Condition and	~~31-71~~1-32
	Results of Operations
	Report of Independent Registered Public Accounting Firm	33
	Consolidated Statements of Income	34
	Consolidated Statements of Comprehensive Income	35
	Consolidated Balance Sheets	36
	Consolidated Statements of Cash Flows	37

~~Ohio Edison Company~~FirstEnergy Solutions Corp.

	Management's Narrative Analysis of Results of Operations	38-40
	Report of Independent Registered Public Accounting Firm	41
	Consolidated Statements of Income and Comprehensive Income	42
	Consolidated Balance Sheets	43
	Consolidated Statements of Cash Flows	44

Ohio Edison Company

	Management's Narrative Analysis of Results of Operations	45-46
	Report of Independent Registered Public Accounting Firm	47
	Consolidated Statements of Income and Comprehensive Income	48
	Consolidated Balance Sheets	49
	Consolidated Statements of Cash Flows	50

The Cleveland Electric Illuminating Company

	Management's Narrative Analysis of Results of Operations	51-52
	Report of Independent Registered Public Accounting Firm	53
	Consolidated Statements of Income and Comprehensive Income	54
	Consolidated Balance Sheets	55
	Consolidated Statements of Cash Flows	56

The Toledo Edison Company

	Management's Narrative Analysis of Results of Operations	57-58
	Report of Independent Registered Public Accounting Firm	59
	Consolidated Statements of Income and Comprehensive Income	60
	Consolidated Balance Sheets	61
	Consolidated Statements of Cash Flows	62

		~~Pages~~ 125

~~Metropolitan Edison Company~~Item 1A. Risk Factors.

	~~Consolidated Statements of Income and Comprehensive Income~~	~~104~~
	~~Consolidated Balance Sheets~~	~~105~~
	~~Consolidated Statements of Cash Flows~~	~~106~~
	~~Report of Independent Registered Public Accounting Firm~~	~~107~~
	~~Management's Discussion and Analysis of Financial Condition and~~	~~108-111~~
	~~Results of Operations~~

~~Pennsylvania Electric Company~~

	~~Consolidated Statements of Income and Comprehensive Income~~	~~112~~
	~~Consolidated Balance Sheets~~	~~113~~
	~~Consolidated Statements of Cash Flows~~	~~114~~
	~~Report of Independent Registered Public Accounting Firm~~	~~115~~
	~~Management's Discussion and Analysis of Financial Condition and~~	~~116-119~~
	~~Results of Operations~~

~~Combined Management’s Discussion and Analysis of Registrant Subsidiaries~~		~~120-132~~125

~~Item 3. Quantitative and Qualitative Disclosures About Market Risk.~~		~~133~~

~~Item 4. Controls and Procedures.~~		~~133~~

~~Part II. Other Information~~

~~Item 1. Legal Proceedings.~~		~~134~~

~~Item 1A. Risk Factors.~~		~~134~~

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.		~~134~~125

~~Item 4. Submission of Matters to a Vote of Security Holders.~~		~~134-135~~

Item 6. Exhibits.		~~135-137~~126

ATSI	American Transmission Systems, Inc., 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
~~FSG~~	~~FirstEnergy Facilities Services Group, LLC, former parent company of several heating, ventilation,~~ ~~air conditioning and energy management companies~~
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
~~MYR~~	~~MYR Group, Inc., a utility infrastructure construction service company~~
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
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
TEBSA	~~Termobarranquilla~~Termobarranquila S.A., Empresa de Servicios Publicos

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

~~ALJ~~AEP	~~Administrative Law Judge~~American Electric Power Company, 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
~~CAL~~	~~Confirmatory Action Letter~~
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
~~ECO~~	~~Electro-Catalytic Oxidation~~
~~ECAR~~	~~East Central Area Reliability Coordination Agreement~~
EIS	Energy Independence Strategy
EITF	Emerging Issues Task Force
~~EITF 06-11~~EMP	~~EITF Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends or Share-Based~~ ~~Payment Awards”~~ Energy Master Plan
EPA	United States Environmental Protection Agency
EPACT	Energy Policy Act of 2005
~~ERO~~ESP	Electric ~~Reliability Organization~~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”
~~Fitch~~FirstCom	~~Fitch Ratings, Ltd.~~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”
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
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service
~~MOU~~MRO	~~Memorandum of Understanding~~Market Rate Offer
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
~~NOAC~~	~~Northwest Ohio Aggregation Coalition~~
NOPR	Notice of Proposed Rulemaking
NOV	Notice of Violation
NO_X	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
~~OCC~~OTC	~~Office of~~Over the ~~Ohio Consumers’ Counsel~~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
~~RTOR~~	~~Regional Through and Out Rates~~
S&P	Standard & Poor’s Ratings Service
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment
SFAS	Statement of Financial Accounting Standards
SFAS ~~107~~	~~SFAS No. 107, “Disclosure about Fair Value of Financial Instruments”~~
~~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)	SFAS No 141(R), “Business Combinations”
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
~~SRM~~	~~Special Reliability Master~~
TBC	Transition Bond Charge
TMI-1	Three Mile Island Unit 1
TMI-2	Three Mile Island Unit 2
~~UCS~~TSC	~~Union of Concerned Scientists~~	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 Ended
	March 31,								Increase
	2008				2007				(Decrease)
Net Income	(In millions, except per share data)
By Business Segment
Energy delivery services		$	179			$	218			$	(39	)
Competitive energy services			87				98				(11	)
Ohio transitional generation services			23				24				(1	)
Other and reconciling adjustments*			(13	)			(50	)			37
Total		$	276			$	290			$	(14	)

Basic Earnings Per Share		$	0.91			$	0.92			$	(0.01	)
Diluted Earnings Per Share		$	0.90			$	0.92			$	(0.02	)

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
First Quarter 2008 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	2,050		$	289		$	691		$	-		$	3,030
Other		162			40			16			29			247
Internal		-			776			-			(776	)		-
Total Revenues		2,212			1,105			707			(747	)		3,277

Expenses:
Fuel and purchased power		983			533			588			(776	)		1,328
Other operating expenses		445			309			77			(31	)		800
Provision for depreciation		106			53			-			5			164
Amortization of regulatory assets		249			-			9			-			258
Deferral of new regulatory assets		(100	)		-			(5	)		-			(105	)
General taxes		173			32			1			9			215
Total Expenses		1,856			927			670			(793	)		2,660

Operating Income		356			178			37			46			617
Other Income (Expense):
Investment income		45			(6	)		1			(23	)		17
Interest expense		(103	)		(34	)		-			(42	)		(179	)
Capitalized interest		-			7			-			1			8
Total Other Income (Expense)		(58	)		(33	)		1			(64	)		(154	)

Income Before Income Taxes		298			145			38			(18	)		463
Income taxes		119			58			15			(5	)		187
Net Income	$	179		$	87		$	23		$	(13	)	$	276

Electric Distribution KWH Deliveries
Residential	2.4	%
Commercial	1.9	%
Industrial	(1.0	)%
Total Distribution KWH Deliveries	1.2	%

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

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 9.0% decrease in sales volumes	$	(16	)
Change in prices		2
		(14	)
Wholesale:
Effect of 3.5% increase in sales volumes		4
Change in prices		22
		26
Net Increase in Non-Affiliated Generation Revenues	$	12

Source of Change in Affiliated Generation Revenues	Increase (Decrease)
	(In millions)
Ohio Companies:
Effect of 1.2% increase in sales volumes	$	6
Change in prices		44
		50
Pennsylvania Companies:
Effect of 9.0% increase in sales volumes		16
Change in prices		(4	)
		12
Net Increase in Affiliated Generation Revenues	$	62

	Three Months Ended
	March 31,
Revenues by Type of Service	2008		2007		Increase
	(In millions)
Generation sales:
Retail	$	606	$	546	$	60
Wholesale		3		2		1
Total generation sales		609		548		61
Transmission		93		71		22
Other		5		-		5
Total Revenues	$	707	$	619	$	88

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

	Three Months Ended
	March 31,
Operating Cash Flows	2008			2007
	(In millions)
Net income	$	276		$	290
Non-cash charges		203			125
Pension trust contribution		-			(300	)
Working capital and other		(123	)		(172	)
	$	356		$	(57	)

	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.

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

Issuer	Securities	S&P	Moody’s

FirstEnergy	Senior unsecured	BBB-	Baa3

FES	Senior unsecured	BBB	Baa2

OE	Senior unsecured	BBB-	Baa2

CEI	Senior secured	BBB+	Baa2
	Senior unsecured	BBB-	Baa3

TE	Senior unsecured	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	)

	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

Increase (Decrease) in the Fair Value
of Commodity Derivative Contracts	Non-Hedge			Hedge			Total
	(In millions)
Change in the Fair Value of
Commodity Derivative Contracts:
Outstanding net liability as of January 1, 2008	$	(713	)	$	(26	)	$	(739	)
Additions/change in value of existing contracts		-			(11	)		(11	)
Settled contracts		58			17			75
Outstanding net liability as of March 31, 2008 (1)	$	(655	)	$	(20	)	$	(675	)

Non-commodity Net Liabilities as of March 31, 2008:
Interest rate swaps (2)		-			(3	)		(3	)
Net Liabilities - Derivative Contracts as of March 31, 2008	$	(655	)	$	(23	)	$	(678	)

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

Balance Sheet Classification	Non-Hedge			Hedge			Total
	(In millions)
Current-
Other assets	$	-		$	62		$	62
Other liabilities		-			(77	)		(77	)

Non-Current-
Other deferred charges		28			12			40
Other non-current liabilities		(683	)		(20	)		(703	)

Net liabilities	$	(655	)	$	(23	)	$	(678	)

Source of Information
- Fair Value by Contract Year	2008(1)			2009			2010			2011			2012			Thereafter			Total
	(In millions)
Prices actively quoted(2)	$	3		$	1		$	-		$	-		$	-		$	-		$	4
Other external sources(3)		(164	)		(192	)		(149	)		(92	)		-			-			(597	)
Prices based on models		-			-			-			-			(30	)		(52	)		(82	)
Total(4)	$	(161	)	$	(191	)	$	(149	)	$	(92	)	$	(30	)	$	(52	)	$	(675	)

	March 31, 2008						December 31, 2007
	Notional		Maturity		Fair		Notional		Maturity		Fair
Interest Rate Swaps	Amount		Date		Value		Amount		Date		Value
	(In millions)
Fair value hedges	$	100		2008	$	1	$	100		2008	$	-
		150		2015		4		150		2015		(3	)
	$	250			$	5	$	250			$	(3	)

·	restructuring the electric generation business and allowing the Companies' customers to select a competitive electric generation supplier other than the Companies;

·	establishing or defining the PLR obligations to customers in the Companies' service areas;

·	providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;

·	itemizing (unbundling) the price of electricity into its component elements – including generation, transmission, distribution and stranded costs recovery charges;

·	continuing regulation of the Companies' transmission and distribution systems; and

·	requiring corporate separation of regulated and unregulated business activities.

	March 31,		December 31,		Increase
Regulatory Assets*	2008		2007		(Decrease)
	(In millions)
OE	$	710	$	737	$	(27	)
CEI		854		871		(17	)
TE		188		204		(16	)
JCP&L		1,476		1,596		(120	)
Met-Ed		530		495		35
ATSI		39		42		(3	)
Total	$	3,797	$	3,945	$	(148	)

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.