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•	The speed and nature of increased competition in the electric utility industry, in general, and the retail sales market in particular.

•	The ability to experience growth in the Regulated Distribution and Regulated Transmission segments and to successfully implement our sales strategy for the CES segment.

•	The accomplishment of our regulatory and operational goals in connection with our transmission investment plan, including, but not limited to, the proposed transmission asset transfer to MAIT, and the effectiveness of our strategy to reflect a more regulated business profile.

•	Changes in assumptions regarding economic conditions within our territories, assessment of the reliability of our transmission system, or the availability of capital or other resources supporting identified transmission investment opportunities.

•

The impact of the regulatory process on the pending matters at the federal level and in the various states in which we do business including, but not limited to, matters related to rates and the ESP IV in Ohio, specifically related to a complaint filed at FERC against FES and the Ohio Companies that request FERC review the ESP IV PPA under Section 205 of the FPA, and other future complaints or challenges that could impact the ESP IV and the ESP IV PPA.

•

The impact of the federal regulatory process on FERC-regulated entities and transactions, in particular FERC regulation of wholesale energy and capacity markets, including PJM markets and FERC-jurisdictional wholesale transactions; FERC regulation of cost-of-service rates, including FERC Opinion No. 531's revised ROE methodology for FERC-jurisdictional wholesale generation and transmission utility service; and FERC’s compliance and enforcement activity, including compliance and enforcement activity related to NERC’s mandatory reliability standards.

•	The uncertainties of various cost recovery and cost allocation issues resulting from ATSI's realignment into PJM.

•	Economic or weather conditions affecting future sales and margins such as a polar vortex or other significant weather events, and all associated regulatory events or actions.

•	Changing energy, capacity and commodity market prices including, but not limited to, coal, natural gas and oil prices, and their availability and impact on margins and asset valuations.

•	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, but not limited to, the effects of the EPA's CPP, CCR, CSAPR and MATS programs, including our estimated costs of compliance, CWA waste water effluent limitations for power plants, and CWA 316(b) water intake regulation.

•	The uncertainty of the timing and amounts of the capital expenditures that may arise in connection with any litigation, including NSR litigation, or potential regulatory initiatives or rulemakings (including that such initiatives or rulemakings 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 as it relates to the reliability of the transmission grid, the timing thereof.

•	The impact of other future changes to the operational status or availability of our generating units and any capacity performance charges associated with unit unavailability.

•	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 NRC 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 risks and uncertainties associated with litigation, arbitration, mediation and like proceedings, including, but not limited to, any such proceedings related to vendor commitments.

•	The impact of labor disruptions by our unionized workforce.

•	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 ability to continue to reduce costs and to successfully execute our financial plans designed to improve our credit metrics and strengthen our balance sheet through, among other actions, our cash flow improvement plan and other proposed capital raising initiatives.

•	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.

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•	Changing market conditions that could affect the measurement of certain liabilities and the value of assets held in our NDTs, pension trusts and other trust funds, and cause us and/or 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 financial plans, 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/or our subsidiaries' access to financing, increase the costs thereof, and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees.

•	Changes in national and regional economic conditions affecting us, our subsidiaries and/or our major industrial and commercial customers, and other counterparties with which we do business, including fuel suppliers.

•	The impact of any changes in tax laws or regulations or adverse tax audit results or rulings.

•	Issues concerning the stability of domestic and foreign financial institutions and counterparties with which we do business.

•

The risks associated with cyber-attacks and other disruptions to our information technology system that may compromise our generation, transmission and/or distribution services and data security breaches of sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers, suppliers, business partners and other individuals in our data centers and on our networks.

•	The risks and other factors discussed from time to time in our SEC filings, and other similar factors.

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•	ASU 2016-05, “Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships”,

•	ASU 2016-06, “Contingent Put and Call Options in Debt Instruments (a consensus of the FASB Emerging Issues Task Force)", and

•	ASU 2016-07, “Simplifying the Transition to the Equity Method of Accounting”.

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(1)	For both the three months ended March 31, 2016 and March 31, 2015, one million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

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•

PNBV Trust - PNBV, a business trust established by OE in 1996, issued certain beneficial interests and notes to fund the acquisition of a portion of the bonds issued by certain owner trusts in connection with the sale and leaseback in 1987 of a portion of OE's interest in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. The beneficial ownership of PNBV includes a 3% interest by unaffiliated third parties.

•

Ohio Securitization - In September 2012, the Ohio Companies created separate, wholly-owned limited liability companies (SPEs) which issued phase-in recovery bonds to securitize the recovery of certain all-electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase-in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase-in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445 thousand that are recoverable through the usage-based charges. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of March 31, 2016 and December 31, 2015, $350 million and $362 million of the phase-in recovery bonds were outstanding, respectively.

•

JCP&L Securitization - In June 2002, JCP&L Transition Funding sold transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s and JCP&L’s Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consist primarily of bondable transition property. As of March 31, 2016 and December 31, 2015, $118 million and $128 million of the transition bonds were outstanding, respectively.

•	MP and PE Environmental Funding Companies - The entities issued bonds, the proceeds of which were used to construct environmental control facilities. The special purpose limited liability companies own the irrevocable right to collect non-bypassable environmental control charges from all customers who receive electric delivery service in MP's and PE's West

•

Global Holding - FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint venture's economic performance. FEV's ownership interest is subject to the equity method of accounting.

•

PATH WV - PATH is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of FE owns 100% of the Allegheny Series (PATH-Allegheny) and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of PATH-WV. FirstEnergy's ownership interest in PATH-WV is subject to the equity method of accounting.

•	Power Purchase Agreements - FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production.

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Sale and Leaseback Transactions - FES and certain of the Ohio Companies have obligations that are not included on their Consolidated Balance Sheets related to the Perry Unit 1, Beaver Valley Unit 2, and 2007 Bruce Mansfield Unit 1 sale and leaseback arrangements, which are satisfied through operating lease payments. FirstEnergy is not the primary beneficiary of these interests as it does not have control over the significant activities affecting the economics of the arrangements. As of March 31, 2016, FirstEnergy's leasehold interest was 3.75% of Perry Unit 1, 93.83% of Bruce Mansfield Unit 1 and 2.60% of Beaver Valley Unit 2.

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(1)	NUG contracts are subject to regulatory accounting treatment and do not impact earnings.

(2)	NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index.

(3)	Primarily consists of short-term cash investments.

(4)	Excludes $(6) million and $7 million as of March 31, 2016 and December 31, 2015, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

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(1)	NUG contracts are subject to regulatory accounting treatment and do not impact earnings.

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(1)	NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index.

(2)	Primarily consists of short-term cash investments.

(3)	Excludes $(8) million and $1 million as of March 31, 2016 and December 31, 2015, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

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(1)	Excludes short-term cash investments: FE Consolidated - $161 million; FES - $113 million.

(2)	Excludes short-term cash investments: FE Consolidated - $157 million; FES - $139 million.

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•	Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings.

•	Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings.

•	Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted.

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(1)	NUG contracts are subject to regulatory accounting treatment and do not impact earnings.

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•	A base distribution rate freeze through May 31, 2016;

•	Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;

•	Economic development and assistance to low-income customers for the two-year plan period at levels established in the prior ESP;

•	A 6% generation rate discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies);

•	A requirement to provide power to non-shopping customers at a market-based price set through an auction process;

•	Rider DCR that allows continued investment in the distribution system for the benefit of customers;

•	A commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million, subject to the outcome of certain FERC proceedings;

•	Securing generation supply for a longer period of time by conducting an auction for a three-year period rather than a one-year period, in each of October 2012 and January 2013, to mitigate any potential price spikes for the Ohio Companies' utility customers who do not switch to a competitive generation supplier; and

•	Extending the recovery period for costs associated with purchasing RECs mandated by SB221, Ohio's renewable energy and energy efficiency standard, through the end of the new ESP 3 period. This is expected to initially reduce the monthly renewable energy charge for all non-shopping utility customers of the Ohio Companies by spreading out the costs over the entire ESP period.

•	An eight-year term (June 1, 2016 - May 31, 2024);

•	Contemplates continuing a base distribution rate freeze through May 31, 2024;

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An Economic Stability Program that flows through charges or credits through Rider RRS representing the net result of the price paid to FES through an eight-year FERC-jurisdictional PPA, referred to as the ESP IV PPA, for the output of the ESP IV PPA Facilities against the revenues received from selling such output into the PJM markets over the same period, subject to the PUCO’s termination of Rider RRS associated with any of the ESP IV PPA Facilities that may be sold or transferred;

•	Continuing to provide power to non-shopping customers at a market-based price set through an auction process;

•	Continuing Rider DCR with increased revenue caps of approximately $30 million per year from June 1, 2016 through May 31, 2019; $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024 that supports continued investment related to the distribution system for the benefit of customers;

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•	Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;

•	A risk-sharing mechanism that would provide guaranteed credits under Rider RRS in years five through eight to customers as follows: $10 million in year five, $20 million in year six, $30 million in year seven and $40 million in year eight;

•

A continuing commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of such costs avoided by customers for certain types of products totals $360 million, including such costs from MISO along with such costs from PJM, subject to the outcome of certain FERC proceedings;

•	Potential procurement of 100 MW of new Ohio wind or solar resources subject to a demonstrated need to procure new renewable energy resources as part of a strategy to further diversify Ohio's energy portfolio;

•	An agreement to file a case with the PUCO by April 3, 2017, seeking to transition to decoupled base rates for residential customers;

•	An agreement to file by February 29, 2016, a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016);

•	A goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045;

•	A contribution of $3 million per year ($24 million over the eight-year term) to fund energy conservation programs, economic development and job retention in the Ohio Companies service territory;

•	Contributions of $2.4 million per year ($19 million over the eight-year term) to fund a fuel-fund in each of the Ohio Companies service territories to assist low-income customers; and

•	A contribution of $1 million per year ($8 million over the eight-year term) to establish a Customary Advisory Council to ensure preservation and growth of the competitive market in Ohio.

•	Limiting average customer bill amounts for the first two years of the plan, subject to certain exceptions, and permitting deferral for the second year;

•	Prohibiting recovery of retirement costs of the ESP IV PPA Facilities through Rider RRS;

•	Assigning the burden of capacity performance penalties incurred by the ESP IV PPA Facilities to the Ohio Companies, rather than customers, and to provide that all capacity performance bonuses earned by the ESP IV PPA Facilities be retained by the Ohio Companies, rather than customers; and

•	Providing for the modification of the severability provision previously included in ESP IV, to also address potential future PJM Tariff or rule changes prohibiting the Ohio Companies from offering output of the ESP IV PPA Facilities into PJM auctions.

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•	On February 11, 2016, the PPUC approved the Pennsylvania Companies' LTIIPs for infrastructure improvements over the 2016-2020 period totaling nearly $245 million. The Pennsylvania Companies filed DSIC riders on February 16, 2016, for quarterly cost recovery associated with the projects approved in the LTIIPs, PPUC approval for such DSIC riders remain pending.

•	The Ohio Companies’ ESP IV, Powering Ohio’s Progress, was approved by the PUCO on March 31, 2016, with certain modifications. The key terms of the approved ESP IV, as further described under Outlook below, include:

◦	An eight-year term;

◦	Contemplates continuing a base distribution rate freeze through May 31, 2024;

◦

An Economic Stability Program that flows through charges or credits through Rider RRS representing the net result of the price paid to FES through an eight-year FERC-jurisdictional PPA, referred to as the ESP IV PPA, for the output of the ESP IV PPA Facilities against the revenues received from selling such output into the PJM markets over the same period, subject to the PUCO’s termination of Rider RRS associated with any of the ESP IV PPA Facilities that may be sold or transferred;

◦	A risk-sharing mechanism that would provide guaranteed credits under Rider RRS in years five through eight to customers as follows: $10 million in year five, $20 million in year six, $30 million in year seven and $40 million in year eight;

◦	Limiting average customer bill amounts for the first two years of the plan, subject to certain exceptions, and permitting deferral for the second year;

◦	Continuing Rider DCR with increased revenue caps of approximately $30 million per year from June 1, 2016 through May 31, 2019; $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024 that supports continued investment related to the distribution system for the benefit of customers;

◦	A goal across FirstEnergy to reduce CO2 emissions by 90 percent below 2005 levels by 2045;

◦	An agreement to file by February 29, 2016, a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016); and

◦	An agreement to file a case seeking to transition to decoupled base rates for residential base distribution customers.

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•	The decrease in revenue at CES resulted from a 7 million MWHs decline in contract sales as the segment continues to align its sales to its generation, partially offset by higher wholesale sales, including increased capacity revenue associated with higher capacity auction prices.

•	The decrease in revenue at Regulated Distribution resulted from lower volumes, primarily associated with lower weather-related usage and the impact of low spot market energy prices on wholesale generation sales, partially offset by the impact of net rate increases implemented in 2015 as a result of approved rate cases at certain operating companies.

•	The increase in revenue at Regulated Transmission primarily reflected a higher rate base and recovery of incremental operating expenses.

•	Fuel expense declined $132 million, primarily at CES, resulting from lower economic dispatch of fossil units associated with low wholesale spot market energy prices, as well as lower unit prices on fuel contracts.

•

Other operating expenses decreased $139 million, primarily reflecting a decrease at CES associated with mark-to-market gains on commodity contract positions and lower transmission expenses, partially offset by an increase at Regulated Distribution resulting from the recognition of economic development and energy efficiency obligations in accordance with the PUCO's March 31 Opinion and Order adopting and approving, with modifications, the Ohio Companies' ESP IV.

•	Amortization of regulatory assets, net increased $29 million, primarily reflecting the recovery of deferred costs, including storm costs and West Virginia vegetation management expenses, partially offset by the deferral of network transmission expenses.

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•	Fuel expense decreased $7 million in the first three months of 2016, as compared to the same period of 2015, primarily related to lower economic dispatch resulting from low spot market energy prices.

•	Purchased power costs decreased $49 million during the first three months of 2016, as compared to the same period of 2015, due to decreased volumes primarily reflecting lower weather-related usage and increased customer shopping, as described above, partially offset by higher capacity expense at MP.

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•	Other operating expenses increased $51 million primarily due to:

•	An increase of $51 million resulting from the recognition of economic development and energy efficiency obligations in accordance with the PUCO's March 31 Opinion and Order adopting and approving, with modifications, the Ohio Companies' ESP IV.

•	Higher retirement benefit costs of $13 million.

•	Lower transmission expenses of $11 million primarily related to lower congestion expenses at MP, partially offset by an increase in network transmission expenses at the Ohio Companies. The difference between current transmission revenues and transmission costs incurred are deferred for future recovery, resulting in no material impact on current period earnings.

•	Net amortization of regulatory assets increased $30 million primarily due to:

•	Recovery of storm costs in New Jersey, Pennsylvania, and West Virginia effective with the implementation of new rates as discussed above ($29 million),

•	Recovery of West Virginia vegetation management program costs ($17 million), and

•	Recovery of Pennsylvania legacy meter costs effective with the implementation of new rates as discussed above($8 million), partially offset by

•	Higher deferral of Ohio network transmission expenses ($18 million).

•	General taxes decreased $5 million primarily due to lower property taxes in Ohio, partially offset by higher revenue-related taxes in Pennsylvania.

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•	Fuel costs decreased $125 million, primarily due to lower economic dispatch of fossil units resulting from low wholesale spot market energy prices, as described above, as well as lower unit prices on fuel contracts. Additionally, fuel costs were impacted by the absence of settlement and termination costs on coal contracts recognized in the first quarter of 2015.

•	Purchased power costs decreased $48 million due to lower volumes ($116 million), partially offset by higher unit prices ($24 million), and higher capacity expenses ($44 million). Lower volumes primarily resulted from lower contract sales as

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•	Fossil operating costs increased $7 million, primarily due to increased outage costs.

•	Nuclear operating costs decreased $11 million as a result of lower planned refueling outage costs. The refueling outage at Davis-Besse began March 26, 2016, while the refueling outage at Perry began on March 9, 2015.

•	Retirement benefit costs increased $8 million.

•	Transmission expenses decreased $118 million, primarily due to lower congestion and market-based ancillary costs associated with less volatile market conditions as compared to the first quarter of 2015, as well as lower load requirements.

•	Other operating expenses decreased $85 million, primarily due to $65 million in mark-to-market gains on commodity contract positions and a decrease in retail-related costs.

•	Depreciation expense increased $6 million as a result of a higher asset base.

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(1)	These PCRBs are classified as currently payable long-term debt because the applicable interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity.

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(1)	FE and the Utilities.

(2)	Includes FET, ATSI and TrAIL.

(1)	No limitations.

(2)	No limitation based upon blanket financing authorization from the FERC under existing open market tariffs.

(3)	Includes amounts which may be borrowed under the regulated companies' money pool.

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•	Distribution rate increases associated with the implementation of new rates, partially offset by a year-over-year decline in distribution deliveries primarily associated with lower weather-related usage;

•	Higher transmission revenue, reflecting recovery of incremental operating expenses and a higher rate base;

•	Higher capacity revenues at CES, partially offset by a decline in sales volume;

•	Lower disbursements for fuel and purchased power resulting from the lower sales volumes; and

•	Lower posted collateral.

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

(2)	Includes guarantees of $4 million for nuclear decommissioning funding assurances, $6 million for railcar leases and $5 million for various leases.

(3)	Includes Energy and Energy-Related Contracts associated with FES of approximately $248 million.

(4)	Reflects the $1 million of interest coverage portion of LOCs issued in support of floating rate PCRBs with various maturities and the principal amount of floating-rate PCRBs of $92 million, all of which is reflected in currently payable long-term debt on FirstEnergy's consolidated balance sheets.

(5)

Includes $54 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facilities, $87 million issued in connection with energy and energy related contracts, $1 million issued in connection with railcar leases, $7 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $3 million pledged in connection with the sale and leaseback of Perry by OE.

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(1)	Represents exchange traded New York Mercantile Exchange futures and options.

(2)	Primarily represents contracts based on broker and ICE quotes.

(3)	Includes $(135) million in non-hedge derivative contracts that are primarily related to NUG contracts at certain of the Utilities. NUG contracts are subject to regulatory accounting and do not impact earnings.

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•	A base distribution rate freeze through May 31, 2016;

•	Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;

•	Economic development and assistance to low-income customers for the two-year plan period at levels established in the prior ESP;

•	A 6% generation rate discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies);

•	A requirement to provide power to non-shopping customers at a market-based price set through an auction process;

•	Rider DCR that allows continued investment in the distribution system for the benefit of customers;

•	A commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million, subject to the outcome of certain FERC proceedings;

•	Securing generation supply for a longer period of time by conducting an auction for a three-year period rather than a one-year period, in each of October 2012 and January 2013, to mitigate any potential price spikes for the Ohio Companies' utility customers who do not switch to a competitive generation supplier; and

•	Extending the recovery period for costs associated with purchasing RECs mandated by SB221, Ohio's renewable energy and energy efficiency standard, through the end of the new ESP 3 period. This is expected to initially reduce the monthly renewable energy charge for all non-shopping utility customers of the Ohio Companies by spreading out the costs over the entire ESP period.

•	An eight-year term (June 1, 2016 - May 31, 2024);

•	Contemplates continuing a base distribution rate freeze through May 31, 2024;

•

An Economic Stability Program that flows through charges or credits through Rider RRS representing the net result of the price paid to FES through an eight-year FERC-jurisdictional PPA, referred to as the ESP IV PPA, for the output of the ESP IV PPA Facilities against the revenues received from selling such output into the PJM markets over the same period, subject to the PUCO’s termination of Rider RRS associated with any of the ESP IV PPA Facilities that may be sold or transferred;

•	Continuing to provide power to non-shopping customers at a market-based price set through an auction process;

•	Continuing Rider DCR with increased revenue caps of approximately $30 million per year from June 1, 2016 through May 31, 2019; $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024 that supports continued investment related to the distribution system for the benefit of customers;

•	Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;

•	A risk-sharing mechanism that would provide guaranteed credits under Rider RRS in years five through eight to customers as follows: $10 million in year five, $20 million in year six, $30 million in year seven and $40 million in year eight;

•

A continuing commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of such costs avoided by customers for certain types of products totals $360 million, including such costs from MISO along with such costs from PJM, subject to the outcome of certain FERC proceedings;

•	Potential procurement of 100 MW of new Ohio wind or solar resources subject to a demonstrated need to procure new renewable energy resources as part of a strategy to further diversify Ohio's energy portfolio;

•	An agreement to file a case with the PUCO by April 3, 2017, seeking to transition to decoupled base rates for residential customers;

•	An agreement to file by February 29, 2016, a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016);

•	A goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045;

•	A contribution of $3 million per year ($24 million over the eight-year term) to fund energy conservation programs, economic development and job retention in the Ohio Companies service territory;

•	Contributions of $2.4 million per year ($19 million over the eight-year term) to fund a fuel-fund in each of the Ohio Companies service territories to assist low-income customers; and

•	A contribution of $1 million per year ($8 million over the eight-year term) to establish a Customary Advisory Council to ensure preservation and growth of the competitive market in Ohio.

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•	Limiting average customer bill amounts for the first two years of the plan, subject to certain exceptions, and permitting deferral for the second year;

•	Prohibiting recovery of retirement costs of the ESP IV PPA Facilities through Rider RRS;

•	Assigning the burden of capacity performance penalties incurred by the ESP IV PPA Facilities to the Ohio Companies, rather than customers, and to provide that all capacity performance bonuses earned by the ESP IV PPA Facilities be retained by the Ohio Companies, rather than customers; and

•	Providing for the modification of the severability provision previously included in ESP IV, to also address potential future PJM Tariff or rule changes prohibiting the Ohio Companies from offering output of the ESP IV PPA Facilities into PJM auctions.

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•	ASU 2016-05, “Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships”,

•	ASU 2016-06, “Contingent Put and Call Options in Debt Instruments (a consensus of the FASB Emerging Issues Task Force)", and

•	ASU 2016-07, “Simplifying the Transition to the Equity Method of Accounting”.

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•	Nuclear operating costs decreased $11 million as a result of lower planned refueling outage costs. The refueling outage at Davis-Besse began March 26, 2016, while the refueling outage at Perry began on March 9, 2015.

•	Retirement benefit costs increased $8 million.

•	Transmission expenses decreased $101 million, primarily due to lower congestion and market-based ancillary costs associated with less volatile market conditions as compared to the first quarter of 2015, as well as lower load requirements.

•	Other operating expenses decreased $71 million, primarily due to $65 million in mark-to-market gains on commodity contract positions and a decrease in retail-related costs.

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4.	CONTROLS AND PROCEDURES

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