Forward Looking Statement

1. PJM 101: An Introduction to PJM’s Energy, Capacity and Ancillary Service Markets and How These Markets Impact Electricity Prices 18th Annual Ohio Energy Management ConferenceFebruary 18-19, 2014Lou D’Alessandris – Advisor, FirstEnergy Solutions

2. Forward Looking Statement This presentation 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 management's intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” "will," "intend," “believe,” “estimate” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause 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, in general, and the retail sales market in particular; the impact of the regulatory process on the pending matters before the Federal Energy Regulatory Commission and in the various states in which we do business including, but not limited to, matters related to rates and pending rate cases; the uncertainties of various cost recovery and cost allocation issues resulting from American Transmission Systems, Incorporated's realignment into PJM Interconnection LLC; economic or weather conditions affecting future sales and margins; regulatory outcomes associated with storm restoration, including but not limited to Hurricane Sandy, Hurricane Irene and the October snowstorm of 2011; changing energy, capacity and commodity market prices including, but not limited to, coal, natural gas and oil, and availability and their impact on retail margins; the continued ability of our regulated utilities to recover their costs; costs being higher than anticipated and the success of our policies to control costs and to mitigate low energy, capacity and market prices; other legislative and regulatory changes, and revised environmental requirements, including possible greenhouse gas emission, water discharge, water intake and coal combustion residual regulations, the potential impacts of Cross-State Air Pollution Rule, Clean Air Interstate Rule (CAIR), and/or any laws, rules or regulations that ultimately replace CAIR, and the effects of the United States Environmental Protection Agency's Mercury and Air Toxics Standards rules including our estimated costs of compliance; the uncertainty of the timing and amounts of the capital expenditures that may arise in connection with any litigation, including New Source Review litigation or potential regulatory initiatives or rulemakings (including that such expenditures could result in our decision to deactivate or idle certain generating units); the uncertainties associated with the deactivation of certain older regulated and competitive fossil units including the impact on vendor commitments, and the timing thereof as they relate to, among other things, Reliability Must-Run arrangements and the reliability of the transmission grid; adverse regulatory or legal decisions and outcomes with respect to our nuclear operations (including, but not limited to the revocation or non-renewal of necessary licenses, approvals or operating permits by the Nuclear Regulatory Commission or as a result of the incident at Japan's Fukushima Daiichi Nuclear Plant); issues arising from the indications of cracking in the shield building at Davis-Besse; the impact of future changes to the operational status or availability of our generating units; the risks and uncertainties associated with litigation, arbitration, mediation and like proceedings, including, but not limited to, any such proceedings related to vendor commitments; replacement power costs being higher than anticipated or not fully hedged; the ability to comply with applicable state and federal reliability standards and energy efficiency and peak demand reduction mandates; changes in customers' demand for power, including but not limited to, changes resulting from the implementation of state and federal energy efficiency and peak demand reduction mandates; the ability to accomplish or realize anticipated benefits from strategic and financial goals including, but not limited to, the successful implementation of our transmission plan, the ability to reduce costs and to successfully complete our announced financial plans designed to improve our credit metrics and strengthen our balance sheet, including but not limited to, the benefits from our announced dividend reduction and our proposed capital raising and debt reduction initiatives, and the proposed sale of non-core hydro assets; our ability to improve electric commodity margins and the impact of, among other factors, the increased cost of fuel and fuel transportation on such margins; the ability to experience growth in the Regulated Distribution and Regulated Transmission segments and to continue to successfully implement our direct retail sales strategy in the Competitive Energy Services segment; changing market conditions that could affect the measurement of liabilities and the value of assets held in our Nuclear Decommissioning Trusts, pension trusts and other trust funds, and cause us and our subsidiaries to make additional contributions sooner, or in amounts that are larger than currently anticipated; the impact of changes to material accounting policies; the ability to access the public securities and other capital and credit markets in accordance with our announced financial plan, the cost of such capital and overall condition of the capital and credit markets affecting us and our subsidiaries; actions that may be taken by credit rating agencies that could negatively affect us and our subsidiaries' access to financing, increase the costs thereof, and increase requirements to post additional collateral to support outstanding commodity positions, letters of credit and other financial guarantees; changes in national and regional economic conditions affecting us, our subsidiaries and our major industrial and commercial customers, and other counterparties including fuel suppliers, with which we do business; issues concerning the stability of domestic and foreign financial institutions and counterparties with which we do business; the risks and other factors discussed from time to time in our United States Securities and Exchange Commission 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 management to predict all such factors, nor assess the impact of any such factor on FirstEnergy's 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. FirstEnergy expressly disclaims any current intention to update, except as required by law, any forward-looking statements contained herein as a result of new information, future events or otherwise.

3. Who is FirstEnergy Solutions? • FirstEnergy Solutions is a competitive generation subsidiary of FirstEnergy Corp. • Supplies competitive electric generation supply to more than 2.7 million customers currently • Licensed active supplier in Ohio, Pennsylvania, New Jersey, Maryland, Michigan and Illinois • FirstEnergy Solutions has nearly 14,500 megawatts of competitive generation • Enough to power more than 13 million homes

4. Reliability Pricing Model • PJM’s capacity market uses the Reliability Pricing Model, RPM • RPM is designed to obtain sufficient resources to meet the needs of consumers in PJM • Goal is to promote most cost effective solution to ensure adequate resources every day of the year • Obtains resource commitments to meet system loads three years in the future • Resources can be any type of power plant (nuclear, coal, gas, wind, solar, hydro, etc.) or demand response/energy efficiency • All utility members could choose to participate in RPM or opt-out and become a Fixed Resource Requirement (FRR) entity • AEP Ohio was the only company to elect FRR at the start of the RPM Market • Capacity is typically the second largest component of the price

5. RPM Process • PJM determines the amount of capacity resources required to serve forecast peak load • PJM adds an installed reserve margin to load forecast • 15.4% reserve margin for June 1, 2015 to May 31, 2016 • Reliability criterion based on Loss of Load Expectation not exceeding one event in 10 years • PJM identifies any constrained sub-regions and establishes separate locational deliverability areas (LDAs) • An area can be constrained due to transmission limitations • These LDAs are cleared separately in RPM auction • Starting June 1, 2015, ATSI is a separate LDA • AEP Ohio, Duke and Dayton Power & Light are “Rest of Market”

6. RPM Auction • Base Residual Auction is held three years prior to the start of delivery year • PJM delivery year runs June 1 to May 31 • Base Residual Auction held this May will be for delivery June 1, 2017 through May 31, 2018, often called 17/18 • Three Incremental Auctions held prior to delivery • PJM updates forecasts and balances the amount of capacity required • PJM may be short or long on capacity based on new forecasts • Allows generators and demand response participants the ability to manage their portfolios • Three incremental auctions are held at set times each year • First: 20 months prior to delivery (September 2015 for 17/18 planning year) • Second: 10 months prior to delivery (July 2016 for 17/18 planning year) • Third: three months prior to delivery (February 2017 for 17/18 planning year) • PJM is looking to make changes to the number of auctions in the future

7. How Does the RPM Auction Work? • Generators within PJM are required to offer in to RPM auction • “Offer cap” on what a generator can offer a unit in at • Companies offering demand response may offer in to RPM and receive the auction clearing price • Generators outside PJM may offer in to the RPM auction • Similar to the energy markets, PJM stacks generator offers from low to high • PJM moves “up the stack” until the forecasted load (plus reserve margin) is met • Last offer accepted sets price paid to all offers • Any unit that does not clear does not get paid • Incremental auctions work the same way as the base residual auction • Clearing prices tend to be lower in incremental auctions

8. “Rest of Market” Base Residual Auction Clearing Prices

9. Calculating Your Capacity Obligation Capacity • Capacity Peak Load Share (PLS) – Based on average of your coincidental peak matched against highest five summer (June, July, August) hours against all of PJM • Forecast Pool Requirement – Added capacity planned to meet the unforced reserve margin • Zonal Scaling Factor – Accounts for forecasted load growth versus prior year and any changes to capacity portfolio. These are electric distribution company (EDC) specific. • Capacity Obligation – Amount of capacity supplier must procure to serve your facility = X X

10. Calculating Your Capacity Cost Capacity • Reliability Price Model (RPM) – The final RPM rate consists of a weighted average of the Base Residual Auction and the three incremental auctions • Capacity Cost – RPM price times your Capacity Obligation in MW-Day. Suppliers purchase adequate RPM Capacity and convert to kWh costs for inclusion in fixed price or capacity can be passed-through via a monthly demand charge = X X

11. Your Takeaways Capacity • Understand your peak consumption to determine if you can take action to lower your peak • Control your Peak Load Share (PLS) by subscribing to a peak notification service available from FirstEnergy Solutions • For flat usage, it’s easiest to have capacity bundled into your fixed kWh fee • Some suppliers only pass-through capacity cost to avoid under-recovery • Expect monthly fee to change in June when new Capacity Obligation is applied to the new RPM rate

12. Ancillary Services Capacity • Ancillary Services are a series of smaller products provided in addition to the main energy and capacity markets • Unlike Capacity and Energy, these are much smaller components and typically make up a fraction of your price • There are two types of Ancillary Services • Market Based – Market method is used to establish the price • Tariff Based – Price is set based on cost-to-serve • In most of Ohio, market-based charges are provided by the retail supplier, while tariff-based charges are provided by the utility to all customers (non-bypassable) • AEP is the only exception, though they have proposed this methodology in their ESP III filing

13. Market-Based Ancillary Services • Regulation Market • Provides for continuous balancing of generation and load • Generation and/or demand response resources that are able to provide “fine tuning” effective for necessary system control • Must be available within five minutes • Able to correct for small load changes that cause voltage fluctuations • Reserves Market • Generation capacity above the expected load designed to bring generation and load back in balance after the loss of generation or load forecasting errors • Synchronized Reserves – Online resources that can respond within 10 minutes • Non-Synchronized Reserves – Offline resources that can respond within 10 minutes

14. Tariff-Based Ancillary Services • Blackstart Service • Provides incentives to generating units that can start and synchronize to the system without having an outside source of AC Power • Combustion turbines or hydro units • Critical for system restoration in the event of complete system shutdown • Reactive Supply • Maintains transmission voltages within acceptable limits • Scheduling, System Control and Dispatch • Administrative charge for PJM to operate transmission system and energy market