ex99_2.htm

	EXHIBIT 99.2



	Ronald E. Seeholzer
	Vice President
	Investor Relations

	FirstEnergy Corp.
	76 S. Main Street
	Akron, Ohio 44308
	Tel 330-384-5415


	July 31, 2008

TO THE INVESTMENT COMMUNITY:1

As announced in today’s attached news release, FirstEnergy Corp.’s Ohio electric utility operating companies Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI) and The Toledo Edison Company (TE), (collectively, the Delivery Companies), filed a comprehensive Electric Security Plan (ESP or Plan) and supporting testimony with the Public Utilities Commission of Ohio (PUCO or Commission). A PUCO decision is required within 150 days, with new rates to be effective for the Companies’ customers January 1, 2009. The Companies also filed a Market Rate Offer (MRO), which outlines a competitive bidding process (CBP) that would be implemented if the ESP is not approved by the PUCO. This letter provides additional details about both the ESP and MRO.

Background

On May 1, 2008, Ohio Governor Ted Strickland signed into law Amended Substitute Senate Bill 221 (SB221). The bill requires all Ohio utilities to file an updated rate stabilization plan, now called an ESP, to address customer rates beginning January 1, 2009. A utility also may 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 Federal Energy Regulatory Commission (FERC) approved regional transmission organization (RTO), or there is comparable and nondiscriminatory access to the electric transmission grid;

·	the RTO has a market-monitor function and the ability to mitigate market power or the utility’s market conduct, or a similar market monitoring function exists with the ability to identify and monitor market conditions and conduct; and

·	a published source of information is available publicly or through subscription that identifies pricing information for traded electricity products, both on- and off-peak, that are contracts scheduled for delivery at least two years into the future.

______________________________

1 Please see the forward-looking statements at the end of this letter.

Overview of the ESP

The ESP provides a flexible approach to phase in new generation pricing for customers beginning in 2009 for a three-year period, with the third year being at the option of the PUCO. The Plan is designed to limit average overall total bill percentage increases across all three companies to single digits each year while achieving FirstEnergy’s financial, reliability and performance objectives.

The comprehensive Plan also addresses the Delivery Companies’ distribution rate case (Case No. 07-551-EL-AIR) and the Application on Remand (Case No. 08-124-EL-ATA) regarding the recovery mechanism to collect deferred fuel costs and associated carrying costs previously established in the Rate Certainty Plan (RCP), both of which are pending before the PUCO.

To support the ESP, the Delivery Companies will enter into a contract with FirstEnergy Solutions Corp. (FES) to provide wholesale generation service for their Ohio customers over the Plan’s term – 2009, 2010 and potentially 2011. The Plan is conditioned upon FERC approval.

Major Generation-Related Provisions of the ESP

The Plan proposes base generation charges for up to a three-year period, with customers receiving a phase-in credit which will reduce rates, with related costs deferred. The average overall per kWh base generation charge before phase-in credit will be $0.075 in 2009, $0.080 in 2010 and $0.085 in 2011, and includes a minimum default service charge for generation and administrative service in the amount of $0.010 per kWh.

These base customer generation charges will be reduced by the following per kWh phase-in credits: $0.0075 in 2009, $0.0085 in 2010 and $0.0095 in 2011. The related costs will be deferred for future collection by the Delivery Companies. Both base generation charges and phase-in credits will be adjusted for voltage and seasonality.

·	The resulting expected difference of $429 million in 2009, $488 million in 2010, and $553 million in 2011, plus carrying costs, will be deferred for collection under one of two proposed methods:

1.	Recovered over a period not to exceed 10 years effective January 1, 2011 for amounts deferred in 2009 and 2010 and effective January 1, 2013 for amounts deferred in 2011, if the third year of the Plan is not terminated by the PUCO; or

2.	Relying on authority provided in a PUCO Order, securitized and recovered over the period from the issuance to maturity of the applicable bonds not to exceed 10 years.

·	The proposed base generation charges include energy, capacity (not including planning reserve margin requirements discussed below), losses and any required renewable energy requirements contained in SB221 for the Plan period.

The Plan allows for recovery of costs incurred annually between May 1 and September 30 for capacity purchases to meet planning reserve margin requirements to meet FERC, North American Electric Reliability Corporation (NERC), Midwest Independent Transmission System Operator (MISO) or other applicable standards, if owned generation is insufficient. These purchases, if required and applicable, will be recovered through a rider as a Capacity Cost Adjustment charge.

The generation charges will be adjusted via a reconcilable rider to recover fuel transportation cost surcharges in excess of $30 million in 2009, $20 million in 2010 and $10 million in 2011. In addition, the generation charges will be adjusted to recover any increase in fuel costs in 2011 over fuel costs incurred in 2010 for FES generation assets used to support the ESP. The following items will not be considered part of fuel costs for this purpose: emission allowances, fuel handling, disposal, lime, urea and ammonia.

The base generation charges as proposed are not subject to adjustments for increased O&M, emission allowance costs, and other costs. However, such generation charges may be adjusted to recover the costs associated with new renewable requirements (other than required by SB221), new taxes and new environmental laws or new interpretations of existing environmental laws that take effect after January 1, 2008, if these costs exceed $50 million during the plan period and are related to the generation assets of FES used to support this Plan.

·	A deferred fuel cost rider will be effective January 1, 2009, for a period not to exceed 25 years, to recover the 2006-2007 accumulated deferred balance of $235 million, including projected accumulated interest, as of December 31, 2008.

Customers and government aggregation communities may switch to an alternative supplier during the ESP period, and choose to either pay or waive standby charges of $0.015 per kWh in 2009, $0.020 per kWh in 2010 and $0.025 per kWh in 2011. Non-governmental aggregation customers waiving the standby charge would pay the higher of market prices or ESP rates for generation if they return to the utility for generation service anytime during the ESP period; those electing to pay the charge would return to standard base generation pricing provided by the ESP. Governmental aggregation customers waiving the standby charges would return at market prices.

Major Energy Delivery-Related Provisions of the ESP

As part of the filing, the Delivery Companies are requesting approval of outstanding issues pending in the distribution rate case before the PUCO, including an annual distribution rate increase of $75 million for OE, $34.5 million for CEI and $40.5 million for TE. The new distribution rates would be effective January 1, 2009 for OE and TE and May 1, 2009 for CEI. CEI would be authorized to defer $25 million of distribution-related costs during the January through April 2009 period. The Delivery Companies will not seek additional distribution base rate increases to be effective prior to January 1, 2014, except in an emergency or for new or increased taxes. The plan would also establish the allowed rate of return on equity for each of the Delivery Companies at 10.5%.

A Delivery Service Improvement Rider will be established for each Delivery Company, effective January 1, 2009, through December 31, 2011, initially at an average $0.0020 per kWh, to ensure that the interests of the Delivery Companies and customers are aligned regarding reliability. This amount may be adjusted up or down by up to 15 percent annually, based on meeting certain goals related to distribution reliability.

RTC charges for CEI customers will be waived as of January 1, 2009. As a result, CEI would write off approximately $485 million of estimated unrecoverable transition costs and customer shopping incentives. This write-off would reduce FirstEnergy’s 2008 earnings on a GAAP basis by $1.01 per share, but would not affect normalized non-GAAP2 earnings per share.

Other Key Provisions

·	Transmission costs, including MISO, ancillary, and congestion charges, will continue to be recovered pursuant to a reconcilable rider.

A Deferred Transmission Costs Recovery Rider will be established beginning January 1, 2009, to recover transmission costs deferred by the Delivery Companies in 2005 and accumulated interest through December 31, 2008, with recovery over a two-year period. The estimated balance including interest as of December 31, 2008 is $43.9 million.

______________________________

2 A non-GAAP financial measure is a numerical measure of a company's historical or future financial performance, financial position, or cash flows that either excludes or includes amounts that are not normally excluded or included in the most directly comparable measure calculated and presented in accordance with accounting principles generally accepted in the United States (GAAP). Non-GAAP financial measures are intended to complement, and not considered as an alternative, to the most directly comparable GAAP financial measure. Also, non-GAAP financial measures may not be comparable to similarly titled measures used by other entities.

A Deferred Distribution Cost Recovery Rider will be effective January 1, 2011 to recover the balances of deferred distribution costs previously approved by the PUCO under the RCP, as well as the deferred transition taxes and line extension costs pending in the distribution rate case. CEI’s $25 million 2009 distribution-related cost deferrals would also be included in this rider. These balances are estimated at $355.2 million, not including carrying charges for 2009 and 2010, as of December 31, 2008 for OE and TE and April 30, 2009 for CEI. The CEI amount includes the additional $25 million of deferred distribution-related costs mentioned earlier.

During the five-year period covering January 1, 2009, through December 31, 2013, the Delivery Companies will defer annual storm damage expenses in excess of $13.9 million, certain line extension costs, as well as depreciation, property tax obligations and post in-service carrying charges on gross plant distribution capital investments placed in service after December 31, 2008, and made to improve reliability and/or enhance the efficiency of the energy delivery system. A Storm Damage and Distribution Enhancement rider will be established to recover the accumulated deferred balance over a 10-year period, including accumulated interest, with an effective date of January 1, 2014. Excluding storm damage expenses, these balances are estimated at $165 million, not inclusive of carrying charges, for the 2009 through 2011 period.

·	Separate Economic Development, Reasonable Arrangements, Demand Side Management and Energy Efficiency, and Delta Revenue Recovery riders will be established:

o	The Economic Development Rider will mitigate overall bill impacts for certain customers through a series of charges and credits, which reflect gradualism and differences in rate schedule prices from voltage-based costs.

o	The Reasonable Arrangements Rider provides the mechanism to administer tariff discounts allowed under SB221.

o	The Demand Side Management and Energy Efficiency Rider will recover the cost of energy efficiency and peak load reduction programs, including resulting lost distribution revenues, as well as unrecovered DSM program costs from the RCP.

o	A Delta Revenue Recovery Rider will be established to recover the difference in revenue between tariff pricing and the result of any reasonable arrangement, governmental special contract or unique arrangement approved by the PUCO.

·	Effective January 1, 2009, a Non-Distribution Service Uncollectible Rider will be established and reconciled annually to reflect actual uncollectible costs.

·	The PUCO, by Order prior to December 31, 2009, may terminate the generation service portion of the Plan, consisting of pricing and certain other provisions, effective January 1, 2011.

·	The Plan also provides for PUCO discretion to increase the generation phase-in credit amounts to customers to the extent any charges for planning reserves exceed 1.5 percent of the overall customer rate.

·	Upon Plan termination, generation prices for the Delivery Companies’ customers will be determined based on a competitive bid, unless agreed to otherwise by the Companies.

Delivery Company Commitments:

·	During the five-year period from January 1, 2009, through December 31, 2013, the Delivery Companies commit to make capital investments in their energy delivery systems in the aggregate of at least $1 billion.

·	From January 1, 2009, through December 31, 2013, the Delivery Companies will fund up to $5 million each year for customer energy efficiency and demand reduction improvements made after January 1, 2009, and up to $5 million each year for economic development and job retention activities.

·	The Delivery Companies will conduct an Advanced Metering Infrastructure (AMI) pilot, as well as an evaluation of the pilot, and will share the results with the PUCO staff and other interested parties. The Delivery Companies will fund the first $1 million for this study.

·	The Delivery Companies commit to undertake a comprehensive study of the energy delivery system, including smart grid technologies and other enhancements.

Generation and Environmental Commitments:

·	Commitment to adding 1,000 megawatts (MW) of capacity from January 1, 2007, to December 31, 2011, through:

o	New or existing generation upgrades, including renewable generation through contracts or otherwise;

o	Maintaining existing generation in service that otherwise would be shutdown; and/or

o	Additional generation sources.

FES will also support and/or undertake environmental remediation and reclamation of existing retired generating plants and/or manufactured gas sites owned by the Delivery Companies and for which they bear a remediation obligation. FES will be required and obligated to cover up to a maximum of $15 million per year for three years, and the Delivery Companies will endeavor to cause such remediation to occur during this period.

The Plan is presented on behalf of all three Delivery Companies collectively, and must be accepted with respect to all of them. PUCO approval of the ESP is requested by December 10, 2008.

In summary, the ESP is consistent with the objectives of mitigating potential customer rate increases over the Plan’s term while preserving FirstEnergy’s financial integrity through implementation of specified regulatory accounting practices, and the ability for the Delivery Companies to recover certain increased costs and meet performance and reliability objectives.

Overview of the MRO

Concurrent with today’s ESP filing, the Delivery Companies filed an application for an MRO, which proposes a competitive bidding process to procure generation supply if the ESP is not approved and implemented. The MRO satisfies specific requirements in SB221 related to RTO membership, an independent market monitor function and availability of market pricing information.

Major MRO Provisions

·	The CBP will use a slice-of-system approach, where wholesale suppliers bid on slices, called tranches, of the Delivery Companies’ total load. One tranche is designed to approximate 100 MW.

·	The initial procurement will use a staggered supply period approach and subsequently a multi-phased approach to smooth potential volatility of wholesale market fluctuations. The initial competitive solicitation, to procure supply for delivery on January 1, 2009, will have three components:

o	One-third of the total load of all three Companies will be bid for supply through May 31, 2010;

o	One-third of the total load will be bid for supply through May 31, 2011; and

o	One-third of the total load will be bid for supply through May 31, 2012.

·	At the conclusion of the solicitation, each of the delivery periods will align with the MISO planning year, which begins on June 1st of each year and ends on May 31st of the succeeding year.

·	After the initial procurement, commencing in 2009 and during each calendar year thereafter, the Delivery Companies will conduct two competitive solicitations to acquire one-third of the total load of all three Companies for a three-year period.

·	A reconciliation mechanism will be used to ensure no over- or under-recovery by the Delivery Companies related to the provision of generation service.

·	The application contains detailed methodologies by which the rates for generation service will be converted from the wholesale bid price to retail tariffs.

·	PUCO approval of the MRO application is required by late October.

Severable Short Term ESP Plan

Lastly, the Delivery Companies have included in the ESP a short-term pricing proposal, called a Severable Short Term ESP Standard Service Offer, if additional time is necessary for final PUCO approval of either the ESP or to conduct the MRO in a more measured approach. The base generation rate will be $0.0775 per kWh, reduced to $0.0675 per kWh to reflect the customer phase in/deferral.

The proposal calls for PUCO approval of the Short Term ESP on or before November 14, 2008, after which time the Delivery Companies would withdraw the option if not approved.

If approved, the Short Term ESP provides the PUCO until March 5, 2009 to act on the full ESP. If no action is taken by that date, or if the Commission rejects the full ESP, the Delivery Companies will proceed with implementation of the MRO, with a procurement auction in early to mid April. Power supply under the MRO under the Short Term ESP scenario would commence May 1, 2009.

Upcoming FirstEnergy Investor Events

Lehman Brothers Energy/Power Conference

September 3, 2008

New York City

Merrill Lynch Global Power & Gas Leaders Conference

September 24, 2008

New York City

Edison Electric Institute (EEI) Financial Conference

November 9-12, 2008

Phoenix, AZ

If you have any questions concerning information in this update, please contact Irene Prezelj, manager of Investor Relations, at (330) 384-3859, or Rey Jimenez, manager of Investor Relations, at (330) 761-4239, or me at (330) 384-5415.

Sincerely,

Ronald E. Seeholzer

Vice President, Investor Relations

Forward-looking Statements

This Letter to the Investment Community includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding our, or our management’s, intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Actual results may differ materially due to the speed and nature of increased competition in the electric utility industry and legislative and regulatory changes affecting how generation rates will be determined following the expiration of existing rate plans in Ohio and Pennsylvania, the impact of the PUCO’s rulemaking process on our Ohio utility subsidiaries’ Electric Security Plan and Market Rate Offer filings, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices and availability, replacement power costs being higher than anticipated or inadequately hedged, the continued ability of FirstEnergy’s regulated utilities to collect transition and other charges or to recover increased transmission costs, maintenance costs being higher than anticipated, other legislative and regulatory changes including revised environmental requirements and possible greenhouse gas emissions regulation, the impact of the U.S. Court of Appeals’ July 11, 2008 decision to vacate the CAIR rules and the scope of any laws, rules or regulations that may ultimately take their place, the uncertainty of the timing and amounts of the capital expenditures needed to, among other things, implement the Air Quality Compliance Plan (including that such amounts could be higher than anticipated) or levels of emission reductions related to the Consent Decree resolving the New Source Review litigation or other potential regulatory initiatives, adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits and oversight by the Nuclear Regulatory Commission including, but not limited to, the Demand for Information issued to FENOC on May 14, 2007) as disclosed in our SEC filings, the timing and outcome of various proceedings before the PUCO (including, but not limited to, the Distribution Rate Cases and the generation supply plan filing for the Ohio Companies and the successful resolution of the issues remanded to the PUCO by the Supreme Court of Ohio regarding the Rate Stabilization Plan and the Rate Certainty Plan, including the deferral of fuel costs) and Met-Ed and Penelec’s transmission service charge filings with the PPUC (as well as the resolution of the Petitions for Review filed with the Commonwealth Court of Pennsylvania with respect to the transition rate plan for Met-Ed and Penelec), the continuing availability of generating units and their ability to continue to operate at or near full capacity, the ability to comply with applicable state and federal reliability standards, the ability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives), the ability to improve electric commodity margins and to experience growth in the distribution business, changing market conditions that could affect the value of assets held in our nuclear decommissioning trust fund, pension fund and other trust funds, the ability to access the public securities and other capital markets and the cost of such capital, the risks and other factors discussed from time to time in our SEC filings, and other similar factors. The foregoing review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for us to predict all such factors, nor can we assess the impact of any such factor on our business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. We expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.