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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.

•	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.

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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.

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The risks and uncertainties at the CES segment, including FES and its subsidiaries and FENOC, related to continued depressed wholesale energy and capacity markets, and the viability and/or success of strategic business alternatives, such as potential CES generating unit asset sales, the potential conversion of the remaining generation fleet from competitive operations to a regulated or regulated-like construct or the potential need to deactivate 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 older regulated and competitive 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.

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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 significant 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.

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Further 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, increase requirements to post additional collateral to support, or accelerate payments under outstanding commodity positions, LOCs and other financial guarantees, and the impact of these events on the financial condition and liquidity of FirstEnergy and/or its subsidiaries, specifically the subsidiaries within the CES segment.

•	The risks and uncertainties surrounding FirstEnergy's need to obtain waivers from its bank group under FirstEnergy's credit facilities caused by a debt to total capitalization ratio, as defined under each of the revolving credit facilities, in excess of 65% resulting from impairment charges or other events at CES.

•	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.

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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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•	Requests to post additional collateral or accelerated payments of up to $355 million resulting from current credit ratings at FES, including Moody's downgrade of the Senior Unsecured debt rating for FES to Caa1 as well as S&P's downgrade of the Senior Unsecured debt rating at FES to B, both of which occurred on November 4, 2016.

•	Adverse outcomes in the previously disclosed disputes regarding long-term coal transportation contracts.

•	The inability to extend or refinance debt maturities at CES, including at FES subsidiaries, in 2017 and 2018 of $130 million and $515 million, respectively.

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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),"

•	ASU 2016-07, “Simplifying the Transition to the Equity Method of Accounting," and

•	ASU 2016-17, “Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control.”

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•

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.

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(1)

For the nine months ended September 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 the period. For the three months ended September 30, 2016 and 2015, and for the nine months ended September 30, 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.

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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 September 30, 2016 and December 31, 2015, $339 million and $362 million of the phase-in recovery bonds were outstanding, respectively.

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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 September 30, 2016 and December 31, 2015, $97 million and $128 million of the transition bonds were outstanding, respectively.

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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 September 30, 2016 and December 31, 2015, $407 million and $429 million of the environmental control bonds were outstanding, respectively.

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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.

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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.

•	Purchase Power Agreements - FirstEnergy evaluated its PPAs 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 - OE and FES have obligations that are not included on their Consolidated Balance Sheets related to the 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 September 30, 2016, FirstEnergy's leasehold interest was 2.60% of Beaver Valley Unit 2 and FES' leasehold interest was 93.83% of Bruce Mansfield Unit 1.

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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 $(8) million and $7 million as of September 30, 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 $1 million as of September 30, 2016 and December 31, 2015, 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: FirstEnergy - $50 million; FES - $39 million.

(2)	Excludes short-term cash investments: FirstEnergy - $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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•	An eight-year term (June 1, 2016 - May 31, 2024).

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The Rider DMR which provides for the Ohio Companies to collect $132.5 million annually for three years, with the possibility of a two-year extension. The Rider DMR will be grossed up for taxes, resulting in an approved amount of approximately $204 million annually. Revenues from the Rider DMR will be excluded from the significantly excessive earnings test for the initial three-year term but the exclusion will be reconsidered upon application for a potential two-year extension.

•	Three conditions for continued recovery under the Rider DMR: (1) retention of the corporate headquarters and nexus of operations in Akron, Ohio; (2) no change in control of the Ohio Companies; and (3) a demonstration of sufficient progress in the implementation of grid modernization programs approved by the PUCO.

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No restrictions on the Ohio Companies’ use of funds collected under the Rider DMR. However, the PUCO directed the PUCO Staff to periodically review how the Ohio Companies and FE use the funds to ensure the funds are used, directly or indirectly, in support of grid modernization. Uses of funds to indirectly support grid modernization could include, e.g., reducing outstanding pension obligations or reducing debt.

•	Continuation of a base distribution rate freeze through May 31, 2024.

•	Continuation of the supply of power to non-shopping customers at a market-based price set through an auction process.

•	Continuation of 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.

•	Continuation of 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 such costs avoided by customers for certain types of products totals $360 million.

•	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.

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•	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 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.

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

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•	Requests to post additional collateral or accelerated payments of up to $355 million resulting from current credit ratings at FES, including Moody's downgrade of the Senior Unsecured debt rating for FES to Caa1 as well as S&P's downgrade of the Senior Unsecured debt rating at FES to B, both of which occurred on November 4, 2016.

•	Adverse outcomes in the previously disclosed disputes regarding long-term coal transportation contracts.

•	The inability to extend or refinance debt maturities at CES, including at FES subsidiaries, in 2017 and 2018 of $130 million and $515 million, respectively.

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•	The decrease in revenue at CES resulted from a 2.6 million MWH decline in contract sales as the segment continues to align its sales to its generation, as well as lower capacity revenue associated with lower capacity auction prices, partially offset by higher wholesale sales.

•	The increase in revenue at Regulated Distribution primarily resulted from a 7% increase in MWH deliveries mainly related to higher weather-related usage as well as higher rates associated with the recovery of deferred program costs, partially offset by lower default service generation sales resulting primarily from lower prices in Ohio and Pennsylvania.

•	The increase in revenue at Regulated Transmission resulted from recovery of incremental operating expenses and a higher rate base at ATSI and TrAIL, partially offset by a lower ROE at ATSI.

•	Fuel expense decreased $32 million, primarily resulting from lower generation at CES associated with outages and economic dispatch of fossil units resulting from low wholesale spot market energy prices, as well as lower unit prices on fossil fuel contracts.

•	Purchased power decreased $230 million, primarily due to lower capacity expense at CES as a result of lower contract sales and capacity rates, as well as lower default service and wholesale spot market prices.

•	Other operating expenses increased $111 million, primarily reflecting an increase of $81 million at Regulated Distribution primarily associated with higher storm restoration expenses, network transmission expenses in Ohio and retirement benefit costs as well as a $31 million increase at CES resulting primarily from a contract termination charge.

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•	Non-cash impairment charge of $800 million (pre-tax) associated with goodwill at CES,

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

•	Coal contract settlement and termination costs of $58 million (pre-tax), and

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

•	The decrease in revenue at CES resulted from a 13 million MWH 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, increased capacity revenue associated with capacity auction prices, and higher net gains on financially settled contracts.

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The increase in revenue at Regulated Transmission primarily reflected 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 $109 million mainly resulting from lower generation at CES associated with outages and economic dispatch of fossil units reflecting low wholesale spot market energy prices, as well as lower unit prices on fossil fuel contracts.

•	Purchased power decreased $319 million mainly due to lower volumes at CES and Regulated Distribution and lower capacity expense at CES.

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•	Fuel expense increased $16 million in the third quarter of 2016, as compared to the same period in 2015, primarily related to higher generation.

•	Purchased power costs were $78 million lower in the third quarter of 2016, as compared to the same period in 2015, primarily due to decreased unit cost reflecting lower default service auction prices in Ohio and Pennsylvania.

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•	Other operating expenses increased $81 million primarily due to:

•	Higher operating and maintenance expense of $37 million including higher storm restoration costs of $32 million, which are deferred for future recovery, resulting in no material impact on current period earnings.

•	Higher transmission expenses of $24 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 decreased $12 million primarily due to higher deferral of storm restoration costs, partially offset by increased recovery of vegetation management program costs in West Virginia and increased recovery of network transmission expenses in Ohio.

•	General taxes increased $18 million primarily due to higher property taxes and higher revenue-related taxes in Ohio.

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•	Fuel costs decreased $48 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.

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Purchased power costs decreased $176 million due to lower capacity expense ($137 million), lower prices ($27 million) and lower volumes ($12 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. The decrease in capacity expense, which is a component of CES' retail price, was primarily the result of lower contract sales and lower capacity rates associated with CES' retail sales obligation. Lower prices reflect lower realized prices on economic purchases.

•	Depreciation expense decreased $19 million, primarily as a result of an out-of-period adjustment to reduce the depreciation of a hydroelectric generating station.

•	Transmission expenses decreased $12 million due to lower congestion and market-based ancillary costs, primarily resulting from lower contract sales.

•	Other operating expenses increased $43 million, primarily due to lower mark-to-market gains on commodity contract positions of $41 million, higher benefit costs and a $32 million charge associated with the termination of a FES customer contract, partially offset by lower lease expense as a result of the expiration of a nuclear sale-leaseback agreement and lower retail-related costs.

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•	Fuel expense increased $30 million in the first nine months of 2016, as compared to the same period of 2015, primarily related to higher generation.

•	Purchased power costs decreased $212 million during the first nine months of 2016, as compared to the same period of 2015 primarily due to decreased volumes resulting from increased customer shopping, as described above, as well as lower unit costs reflecting lower default service auction prices in Ohio and Pennsylvania

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•	Other operating expenses increased $174 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 operating and maintenance expense of $42 million, including increased storm restoration costs of $39 million, which are deferred for future recovery, resulting in no material impact on current period earnings.

•	Higher retirement benefit costs of $37 million.

•	Higher transmission expenses of $36 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 $22 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 ($34 million), partially offset by

•	Higher deferral of storm restoration costs ($39 million), and

•	Higher deferral of Ohio network transmission expenses ($10 million).

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•	Fuel costs decreased $139 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 higher settlement and termination costs on coal contracts.

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Purchased power costs decreased $293 million, primarily due to lower volumes ($206 million) and lower capacity expenses ($112 million), partially offset by higher losses on financial settled contracts from lower wholesale spot market prices ($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. The decrease in capacity expense, which is a component of CES' retail price, was primarily the result of lower contract sales and lower capacity rates associated with CES' retail sales obligations.

•	Fossil operating costs increased $18 million, primarily due to increased outage costs and higher employee benefit costs.

•	Nuclear operating costs decreased $31 million, primarily as a result of lower refueling outage costs, partially offset by higher employee benefit costs. There was one refueling outage during the first nine months of 2016 as compared to two refueling outages during the same period of 2015.

•	Retirement benefit costs increased $24 million.

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•	Transmission expenses decreased $162 million, primarily due to lower congestion and market-based ancillary costs associated with less volatile market conditions as compared to the first nine months of 2015, as well as lower load requirements.

•	Other operating expenses increased $5 million, primarily due to lower mark-to-market gains on commodity contract positions of $54 million and a $32 million charge associated with the termination of a FES customer contract, partially offset by lower lease expense as a result of the expiration of a nuclear sale-leaseback agreement and lower retail-related costs.

•	Depreciation expense decreased $9 million, primarily as a result of an out-of-period adjustment to reduce the depreciation of a hydroelectric generating station, partially offset by a higher asset base.

•	General taxes decreased $14 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.

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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.

(1)	FE and the Utilities.

(2)	Includes FET, ATSI and TrAIL.

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(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 resulting from lower average customer 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.

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

(2)	CES related portion is $136 million.

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

(4)	Includes energy and energy-related contracts associated with FES of approximately $248 million.

(5)	Includes $9 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, and $4 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 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 $(118) 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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•	An eight-year term (June 1, 2016 - May 31, 2024).

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The Rider DMR which provides for the Ohio Companies to collect $132.5 million annually for three years, with the possibility of a two-year extension. The Rider DMR will be grossed up for taxes, resulting in an approved amount of approximately $204 million annually. Revenues from the Rider DMR will be excluded from the significantly excessive earnings test for the initial three-year term but the exclusion will be reconsidered upon application for a potential two-year extension.

•	Three conditions for continued recovery under the Rider DMR: (1) retention of the corporate headquarters and nexus of operations in Akron, Ohio; (2) no change in control of the Ohio Companies; and (3) a demonstration of sufficient progress in the implementation of grid modernization programs approved by the PUCO.

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No restrictions on the Ohio Companies’ use of funds collected under the Rider DMR. However, the PUCO directed the PUCO Staff to periodically review how the Ohio Companies and FE use the funds to ensure the funds are used, directly or indirectly, in support of grid modernization. Uses of funds to indirectly support grid modernization could include, e.g., reducing outstanding pension obligations or reducing debt.

•	Continuation of a base distribution rate freeze through May 31, 2024.

•	Continuation of the supply of power to non-shopping customers at a market-based price set through an auction process.

•	Continuation of 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.

•	Continuation of 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 such costs avoided by customers for certain types of products totals $360 million.

•	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 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.

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

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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),"

•	ASU 2016-07, “Simplifying the Transition to the Equity Method of Accounting," and

•	ASU 2016-17, “Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control.”

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•	Requests to post additional collateral or accelerated payments of up to $355 million resulting from current credit ratings at FES, including Moody's downgrade of the Senior Unsecured debt rating for FES to Caa1 as well as S&P's downgrade of the Senior Unsecured debt rating at FES to B, both of which occurred on November 4, 2016.

•	Adverse outcomes in the previously disclosed disputes regarding long-term coal transportation contracts.

•	The inability to extend or refinance debt maturities at FES subsidiaries in 2017 and 2018 of $130 million and $515 million, respectively.

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•	Nuclear operating costs decreased $31 million, primarily as a result of lower refueling outage costs, partially offset by higher employee benefit costs. There was one refueling outage during the first nine months of 2016 as compared to two refueling outages during the same period of 2015.

•	Retirement benefit costs increased $23 million.

•	Transmission expenses decreased $134 million, primarily due to lower congestion and market-based ancillary costs associated with less volatile market conditions as compared to the first nine months of 2015, as well as lower load requirements.

•	Other operating expenses increased $71 million, primarily due to lower mark-to-market gains on commodity contract positions of $54 million and a $32 million charge associated with the termination charge on a FES customer contract, partially offset by lower retail-related costs.

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4.	CONTROLS AND PROCEDURES

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•	requests to post additional collateral or accelerated payments of up to $355 million resulting from current credit ratings at FES, including Moody's downgrade of the Senior Unsecured debt rating for FES to Caa1 as well as S&P's downgrade of the Senior Unsecured debt rating at FES to B, both of which occurred on November 4, 2016;

•	adverse outcomes in previously disclosed disputes regarding long-term coal and coal transportation contracts; and

•	the inability to refinance debt maturities at FES subsidiaries of $130 million, $515 million, and $323 million in 2017, 2018 and 2019, respectively, and $155 million in 2019 at AE Supply at attractive rates or at all;

•	difficulty satisfying debt service and other obligations at FES and/or its individual subsidiaries;

•	the inability to refinance debt maturities at FES subsidiaries of $130 million, $515 million, and $323 million in 2017, 2018 and 2019, respectively, and $155 million in 2019 at AE Supply at attractive rates or at all;

•	the inability to extend or refinance on comparable terms the FES/AE Supply revolving credit facility, which expires in March of 2019;

•	a credit rating downgrade of FES debt, which could cause future debt costs and/or payments to increase and consume an even greater portion of cash flow and require additional posting of collateral or acceleration of payments of up to $355 million;

•	increasing the vulnerability of the business of FirstEnergy and CES, including FES, to general adverse industry and economic conditions;

•	reducing the availability of FES and AE Supply cash flow to fund other corporate purposes, including the ability to pay dividends to FirstEnergy;

•	limiting flexibility of FirstEnergy and the CES business, including FES, in planning for, or reacting to, changes in their business and the industry;

•	placing FirstEnergy and the CES business, including FES, at a competitive disadvantage to its competitors that are not as highly leveraged; and

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•	limiting, along with the financial and other restrictive covenants relating to such indebtedness, among other things, FE’s and the CES business’, including FES, ability to borrow additional funds as needed, take advantage of business opportunities as they arise or pay cash dividends.

(1)

Share amounts reflect shares that were surrendered to FirstEnergy by a participant under our 2007 Incentive Plan to satisfy tax withholding obligations relating to the vesting of a restricted stock award and the subsequent dividend reinvestments on such equity award. The total number of shares repurchased represents the net shares surrendered to FirstEnergy to satisfy tax withholding. All such repurchased shares are now held as treasury shares.

(2)	FirstEnergy does not currently have any publicly announced plan or program for share purchases.

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