---

•	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.

•	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 and resulting outcomes on the 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.

•

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, including without limitation impairments thereon.

•	The risks and uncertainties at the CES segment, including FES, related to continued depressed wholesale energy and capacity markets, including the potential need to deactivate or sell additional generating units.

•	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, such as long-term fuel and transportation agreements, 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, such as long-term fuel and transportation agreements.

•	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.

---

•	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.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

•	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”.

---

•

Future Energy and Capacity Prices: Observable market information for near-term forward power prices, PJM auction results for near term capacity pricing, and a longer-term fundamental pricing model for energy and capacity that considered the impact of key factors such as load growth, plant retirements, carbon and other environmental regulations, and natural gas pipeline construction, as well as coal and natural gas pricing.

•	Retail Sales and Margin: CES' current retail targeted portfolio to estimate future retail sales volume as well as historical financial results to estimate retail margins.

•	Operating and Capital Costs: Estimated future operating and capital costs, including the estimated impact on costs of pending carbon and other environmental regulations, as well as costs associated with capacity performance reforms in the PJM market.

•	Discount Rate: A discount rate of 9.50%, based on selected comparable companies' capital structure, return on debt and return on equity.

•	Terminal Value: A terminal value of 7.0x earnings before interest, taxes, depreciation and amortization based on consideration of peer group data and analyst consensus expectations.

---

(1)	For both the three and six months ended June 30, 2016, three million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive as a result of the net loss. For both the three and six months ended June 30, 2015, one million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

---

---

---

---

---

---

•

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 June 30, 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 June 30, 2016 and December 31, 2015, $108 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 Virginia service territories. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the special purpose limited liability companies, have no recourse to any assets or revenues of the special purpose limited liability companies. As of June 30, 2016 and December 31, 2015, $418 million and $429 million of the environmental control bonds were outstanding, respectively.

•

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.

•

Sale and Leaseback Transactions - OE and FES have obligations that are not included on their Consolidated Balance Sheets related to Beaver Valley Unit 2 and 2007 Bruce Mansfield Unit 1 sale and leaseback arrangements, respectively, 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 June 30, 2016, FirstEnergy's leasehold interest was 2.60% of Beaver Valley Unit 2 and 93.83% of Bruce Mansfield Unit 1.

---

---

(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 $7 million as of June 30, 2016 and December 31, 2015, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

---

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

---

(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 $4 million and $1 million as of June 30, 2016 and December 31, 2015, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

---

(1)	Excludes short-term cash investments: FE Consolidated - $176 million; FES - $154 million.

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

---

•	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.

---

---

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

---

---

---

---

---

---

•	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;

•	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.

•	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.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

•	On February 11, 2016, the PPUC approved the Pennsylvania Companies' LTIIPs for infrastructure improvements over the 2016-2020 period totaling nearly $245 million. On June 9, 2016, the PPUC approved the Pennsylvania Companies’ DSIC riders to be effective July 1, 2016, subject to hearings and refund or reallocation among customers.

•

The Ohio Companies’ ESP IV, Powering Ohio’s Progress, was approved by the PUCO on March 31, 2016, with certain modifications and included 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. On April 1, 2016, the Ohio Companies and FES entered into the ESP IV PPA. However, on April 27, 2016, FERC issued an order prohibiting any transactions under the ESP IV PPA pending future authorization by FERC and directed FES to submit the ESP IV PPA for FERC review if the companies desired to transact under the agreement. FES did not file the ESP IV PPA for FERC review but rather agreed to suspend the ESP IV PPA prior to transacting thereunder, pending the outcome of the PUCO and FERC proceedings.

•

On April 28, 2016, JCP&L filed tariffs with the NJBPU proposing a general rate increase associated with its distribution operations that seeks to improve service and benefit customers by supporting equipment maintenance, tree trimming, and inspections of lines, poles and substations, while also compensating for other business and operating expenses. The filing requested approval to increase annual operating revenues by approximately $142.1 million based upon a hybrid test year for the twelve months ending June 30, 2016. JCP&L requested that the proposed new rates take effect in January 2017. On July 13, 2016, this matter was submitted to the Office of Administrative Law for hearing and the issuance of an Initial Decision. A procedural schedule has not yet been issued.

•

On April 28, 2016, each of the Pennsylvania Companies filed tariffs with the PPUC proposing general rate increases associated with their distribution operations that will benefit customers by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements. The filings request approval to increase annual operating revenues by approximately $140.2 million at ME, $158.8 million at PN, $42.0 million at Penn, and $98.2 million at WP, based upon fully projected future test years for the twelve months ending December 31, 2017 at each of the Pennsylvania Companies. As a result of Act 40 of 2016, the Pennsylvania Companies submitted testimony on July 7, 2016, quantifying the value of the elimination of the CTA and outlined their plan for investing 50% of that amount in rate base eligible equipment as required by the new law. A procedural schedule has been set with hearings commencing on September 6, 2016. The proposed new rates are expected to take effect in January 2017, pending regulatory approval.

---

---

---

•	Non-cash impairment charges of $800 million associated with goodwill at CES,

•	Non-cash impairment charges of $647 million associated with the announced plan to exit operations by 2020 of Units 1-4 of the W. H. Sammis generating station (720 MW) and the Bay Shore Unit 1 generating station (136 MW),

•	Coal contract settlement and termination costs of $58 million, and

•	Valuation allowances against state and local NOL carryforwards of $159 million.

•	The decrease in revenue at CES resulted from a 4 million MWHs decline in contract sales as the segment continues to align its sales to its generation. The decline in contract sales volume was partially offset by higher wholesale sales and increased capacity revenue associated with higher capacity auction prices.

•	The decrease in revenue at Regulated Distribution resulted from lower regulated generation sales volumes due to increased customer shopping as well as lower industrial usage in West Virginia. The declines in regulated generation sales volumes were partially offset by the impact of rate increases at the Pennsylvania companies implemented in May of 2015 as a result of approved rate cases.

•

The decrease in revenue at Regulated Transmission primarily reflected adjustments associated with ATSI's and TrAIL's annual rate filing for costs previously recovered as well as a lower ROE at ATSI under its FERC-approved comprehensive settlement related to the implementation of a forward-looking rate, partially offset by higher recovery of incremental operating expenses and a higher asset base at ATSI and TrAIL.

---

•	Fuel expense increased $55 million primarily resulting from settlement and termination costs on coal contracts recognized in the second quarter of 2016 at CES as well as higher generation at CES' and Regulated Distribution.

•	Purchased power decreased $100 million due to lower required volumes at Regulated Distribution as a result of higher customer shopping as well as lower volumes at CES associated with lower contract sales.

•	Other operating expenses increased $64 million, primarily reflecting an increase of $42 million at Regulated Distribution associated with higher transmission expenses and retirement benefit costs and an increase at CES due to mark-to-market losses on commodity contract positions.

•	Impairment of assets increased $1,431 million due to impairment charges at CES associated with goodwill ($800 million) and the announcement to exit operations of Units 1-4 of the W. H. Sammis generating station ($497 million) and the Bay Shore Unit 1 generating station ($150 million).

•	The decrease in revenue at CES resulted from an 11 million MWHs decline in contract sales as the segment continues to align its sales to its generation. The decline in contract sales volume was partially offset by higher wholesale sales and increased capacity revenue associated with higher capacity auction prices.

•

The decrease in revenue at Regulated Distribution resulted from lower distribution deliveries to residential and commercial customers resulting from decreased weather-related usage and lower average customer usage associated with more energy efficient products and services as well as lower deliveries to industrial customers. Regulated generation sales volumes were also lower year-over-year due to increased customer shopping and lower industrial usage in West Virginia. These declines were partially offset by the impact of net rate increases implemented in the first six months of 2015 as a result of approved rate cases at certain operating companies.

•

The increase in revenue at Regulated Transmission primarily reflected higher recovery of incremental operating expenses and higher rate base at ATSI and TrAIL, partially offset by adjustments associated with ATSI and TrAIL's annual rate filing for costs previously recovered as well as a lower ROE at ATSI under its FERC-approved comprehensive settlement related to the implementation of a forward-looking rate.

•	Fuel expense decreased $77 million resulting from lower generation at CES associated with outages and economic dispatch of fossil units.

•	Purchased power decreased $89 million due to lower volumes.

•

Other operating expenses decreased $75 million, reflecting a decrease of $177 million at CES resulting from lower transmission expenses and higher mark-to-market gains on commodity contract positions, partially offset by an increase of $93 million 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 Company’s ESP IV as well as higher retirement costs.

•	Impairment of assets increased $1,431 million as further described above.

---

•

Increased transmission revenue associated with increased investments at ATSI and TrAIL, partially offset by a lower ROE at ATSI. The lower ROE at ATSI is the result of its FERC-approved comprehensive settlement related to the implementation of its forward-looking rate. The ROE at ATSI for 2016 is 10.38% and compares to 12.38% for the period January 1, 2015 to June 30, 2015 and 11.06% from July 1, 2015 to December 31, 2015.

•	As part of FirstEnergy’s Energizing the Future transmission expansion plan, 2016 forecasted capital expenditures are $1.05 billion of which approximately $715 million will be within ATSI and TrAIL and subject to their forward-looking rates with the remaining capital expenditures of $335 million to be within the Utilities' transmission system.

•	Distribution deliveries of 146.4 million MWH in 2016 (assumes normal weather) versus 148.4 million MWH in 2015, resulting from lower weather-related usage and declining average customer usage associated with more energy efficient products and services.

•	Increased revenues from the full year impact of approved distribution rate increases for the Pennsylvania Companies (effective May 3, 2015) and higher DCR revenues at the Ohio Companies in connection with their ESP IV, partially offset by the full year impact of an approved distribution rate decrease at JCP&L (effective April 1, 2015).

•	Lower operation and maintenance expenses as the business continues its focus on cost management.

•	Increased depreciation and property taxes as a result of a higher asset base.

•	Increased Pension/OPEB expense primarily due to lower amortization of prior service credits and higher pension financing costs.

•	Increased regulatory charges primarily reflecting the Ohio Companies’ recognition of economic development and energy efficiency obligations in accordance with the PUCO's March 31 Opinion and Order adopting and approving, with modifications, their ESP IV.

•	Capital expenditures for 2016 are forecasted to be approximately $1.3 billion primarily associated with reliability improvements.

•	Lower CES capacity revenue resulting from lower capacity rates as discussed above.

•	Decreased operation and maintenance expenses primarily resulting from two nuclear refueling outages in 2016 versus three in 2015 and lower retail related costs.

•	Increased Pension/OPEB expense primarily due to lower amortization of prior service credits and higher pension financing costs.

•	Asset impairment and plant exit costs as a result of an impairment of goodwill ($800 million pre-tax), the impairment of Bay Shore Unit 1 and W. H. Sammis Units 1-4 generating stations ($647 million pre-tax), and other costs associated with the deactivation of certain power plants.

•	Lower tax benefits on forecasted pre-tax losses associated with valuation allowances against state and local NOL carryforwards of $159 million and the impact of the impairment of goodwill of which $433 million was non-deductible for tax purposes.

•	Capital expenditures for 2016 are forecasted to be $545 million.

•	Higher net financing costs primarily due to higher interest expense.

•	Reduced tax benefits on uncertain tax positions.

•	Capital expenditures for 2016 are forecasted to be $85 million.

---

---

---

---

---

•	Fuel expense increased $21 million in the second quarter of 2016, as compared to the same period in 2015, primarily related to higher generation.

•	Purchased power costs were $85 million lower in the second quarter of 2016, as compared to the same period in 2015, primarily due to decreased volumes reflecting increased customer shopping, as described above.

•	Other operating expenses increased $42 million primarily due to:

•	Higher transmission expenses of $22 million primarily due to an increase in network transmission expenses at the Ohio Companies. The difference between current revenues and transmission costs incurred are deferred for future recovery or refund, resulting in no material impact on current period earnings.

•	Higher retirement benefit costs of $12 million.

---

•	Net amortization of regulatory assets increased $4 million primarily due to recovery of storm costs in Pennsylvania and vegetation management program costs in West Virginia, partially offset by higher deferral of Ohio network transmission expenses.

---

---

•

Fuel costs increased $34 million, primarily due to a pre-tax charge of $58 million from settlement and termination costs on coal contracts recognized in the second quarter of 2016 and higher nuclear generation, partially offset by lower generation associated with outages and economic dispatch of fossil units resulting from low wholesale spot market energy prices, as described above, as well as lower unit prices on fossil fuel contracts.

•

Purchased power costs decreased $69 million due to lower volumes ($76 million) and lower capacity expense ($19 million), partially offset by higher losses on financially settled contracts ($13 million) and higher unit prices ($13 million). Lower volumes and capacity expense primarily resulted from lower contract sales as discussed above, partially offset by economic purchases, resulting from the low wholesale spot market price environment. Higher losses on financially settled contracts were due to lower wholesale spot market prices in the second quarter of 2016 compared to the second quarter of 2015. Higher unit prices were primarily due to a higher proportion of purchases coming from purchased power agreements for wind, solar and CES' entitlement in OVEC, partially offset by the lower wholesale spot prices.

•	Fossil operating costs increased $13 million, primarily due to increased outage costs.

•	Nuclear operating costs decreased $22 million, primarily due to lower refueling outage costs. There was one refueling outage during the second quarter of 2016, as compared to two refueling outages during the same period of 2015.

•	Retirement benefit costs increased $8 million.

•	Transmission expenses decreased $32 million, due to lower congestion and market-based ancillary costs, primarily resulting from lower sales.

---

•	Other operating expenses increased $54 million, primarily due to a $79 million increase in mark-to-market losses on commodity contract positions, partially offset by lower lease expense as a result of the expiration of a nuclear sale-leaseback agreement and lower retail-related costs.

•	General taxes decreased $7 million, primarily due to lower gross receipts taxes associated with lower retail sales volumes.

•	Impairment of assets increased $1,431 million primarily due to an $800 million impairment of goodwill and a decision to exit operations of Units 1-4 of the W. H. Sammis generating station by May 31, 2020 and the Bay Shore Unit 1 generating station by October 1, 2020, resulting in an impairment of $647 million.

---

---

---

---

---

•	Fuel expense increased $14 million in the first six months of 2016, as compared to the same period of 2015, primarily related to higher generation.

•	Purchased power costs decreased $134 million during the first six months of 2016, as compared to the same period of 2015 primarily due to decreased volumes reflecting lower weather-related usage and increased customer shopping, as described above.

---

•	Other operating expenses increased $93 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 $25 million.

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

•	Net amortization of regulatory assets increased $34 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 ($35 million),

•	Recovery of West Virginia vegetation management program costs ($27 million), partially offset by

•	Higher deferral of Ohio network transmission expenses ($26 million).

•	General taxes decreased $9 million primarily due to lower property taxes in Ohio, partially offset by higher revenue-related taxes in Pennsylvania.

---

---

---

•

Fuel costs decreased $91 million, primarily due to lower generation associated with outages and economic dispatch of fossil units resulting from low wholesale spot market energy prices, as described above, as well as lower unit prices on fossil fuel contracts. Additionally, fuel costs were impacted by a pre-tax charge of $58 million from settlement and termination costs on coal contracts in the second quarter of 2016.

•

Purchased power costs decreased $117 million due to lower volumes ($193 million) and lower unit prices ($3 million), partially offset by higher losses on financial settled contracts ($54 million) and higher capacity expenses ($25 million). Lower volumes primarily resulted from lower contract sales as discussed above, partially offset by economic purchases, resulting from the low wholesale spot market price environment. Lower unit prices and higher losses on financially settled contracts were both due to lower wholesale spot market prices in the first six months of 2016, compared to the same period of 2015. The increase in capacity expense, which is a component of CES' retail price, was primarily the result of higher capacity rates associated with CES' retail sales obligations.

•	Fossil operating costs increased $21 million, primarily due to increased outage costs.

•	Nuclear operating costs decreased $33 million as a result of lower refueling outage costs. There was one refueling outage during the first six months of 2016 as compared to two refueling outages during the same period of 2015.

•	Retirement benefit costs increased $16 million.

•	Transmission expenses decreased $151 million, primarily due to lower congestion and market-based ancillary costs associated with less volatile market conditions as compared to the first six months of 2015, as well as lower load requirements.

•	Other operating expenses decreased $30 million, primarily due to a $14 million increase in mark-to-market gains on commodity contract positions, lower lease expense as a result of the expiration of a nuclear sale-leaseback agreement and lower retail-related costs.

•	Depreciation expense increased $10 million as a result of a higher asset base.

•	General taxes decreased $9 million due to lower gross receipts taxes associated with lower retail sales volumes.

•	Impairment of assets increased $1,431 million primarily due to an $800 million impairment of goodwill and a decision to exit operations of Units 1-4 of the W. H. Sammis generating station by May 31, 2020 and the Bay Shore Unit 1 generating station by October 1, 2020, resulting in an impairment of $647 million.

---

---

(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.

(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.

---

---

•	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; and

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

---

---

(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, $5 million for railcar leases and $4 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 $7 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 and $4 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE.

---

---

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

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

(3)	Includes $(123) 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.

---

---

---

•	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;

•	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.

•	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.

---

---

---

---

---

---

---

---

---

---

•	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”.

---

---

---

---

•	Fossil operating costs increased $10 million primarily due to increased outage costs.

•	Nuclear operating costs decreased $33 million as a result of lower planned refueling outage costs. There was one planned refueling outage during the first six months of 2016 as compared to two planned refueling outages during the same period of 2015.

•	Retirement benefit costs increased $15 million.

•	Transmission expenses decreased $129 million, primarily due to lower congestion and market-based ancillary costs associated with less volatile market conditions as compared to the first six months of 2015, as well as lower load requirements.

•	Other operating expenses decreased $4 million, primarily due to a $14 million increase in mark-to-market gains on commodity contract positions, lower lease expense as a result of the expiration of a nuclear sale-leaseback agreement and lower retail-related costs.

---

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4.	CONTROLS AND PROCEDURES

---

---

---