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ITEM 1.	BUSINESS

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•	Legislative or regulatory solutions for generation assets that recognize their environmental or energy security benefits,

•	Additional asset sales and/or plant deactivations,

•	Restructuring FES debt with its creditors, and/or

•	Seeking protection under U.S. bankruptcy laws for FES and possibly FENOC.

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•	FE and the Utilities entered into a new $4 billion revolving credit facility, which represents an increase of $500 million over the existing $3.5 billion facility it replaced,

•	FET and its subsidiaries entered into a $1 billion revolving credit facility, which replaced their existing $1 billion facility, and

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FES and AE Supply terminated their unsecured $1.5 billion credit facility (commitments of $900 million and $600 million for FES and AE Supply, respectively) and FES entered into a new, two-year secured credit facility with FE in which FE provided a committed line of credit to FES of up to $500 million and additional credit support of up to $200 million to cover a $169 million surety bond for the benefit of the PA DEP with respect to LBR, and other bonds as designated in writing to FE. In connection with the cancellation of the prior FES/AE Supply facility and entry into the new FES secured facility with FE, certain commitments and amendments associated with shared services and operational matters were made including, without limitation, as follows: (i) FE reaffirmed its obligations under the Intercompany Tax Allocation Agreement, and (ii) amendments to the Service Agreement by and among FESC, FES, FG and NG, to prevent termination until the earlier of December 31, 2018, or a change in control of FES or its subsidiaries.

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(1)	FE and the Utilities.

(2)	Includes FET, ATSI and TrAIL.

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•	OE—5,655 MW on August 11, 2016;

•	Penn—994 MW on September 7, 2016;

•	CEI—4,193 MW on September 7, 2016;

•	TE—2,171 MW on September 7, 2016;

•	JCP&L—5,955 MW on August 12, 2016;

•	ME—2,904 MW on July 25, 2016;

•	PN—2,890 MW on December 15, 2016;

•	MP—2,053 MW on August 11, 2016;

•	PE—3,049 MW on February 12, 2016; and

•	WP—3,947 MW on July 25, 2016.

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ITEM 1A.	RISK FACTORS

•	requests to post additional collateral or accelerate payments

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•	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 in the event AE Supply’s pending sale of assets is not consummated, $155 million in 2019 at AE Supply, in each case, at attractive rates or at all.

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

•	the inability or unwillingness to refinance debt maturities at FES subsidiaries of $130 million, $515 million, and $323 million in 2017, 2018 and 2019, respectively;

•	additional postings of collateral or acceleration of payments;

•	increasing the vulnerability of the business of FirstEnergy and FES to adverse industry and economic conditions;

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

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

•	reducing the ability to enter into transactions with counterparties that may demand additional collateral or credit support from FE due to the creditworthiness;

•	increasing the likelihood of litigation, the costs of which may be material;

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

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

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•	the potential harmful effects on the environment, human health and safety, including loss of life, resulting from unplanned radiological releases associated with the operation of our nuclear facilities and the storage, handling and disposal of radioactive materials;

•	limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations, including any incidents of unplanned radiological release, or those of others in the United States;

•	uncertainties with respect to contingencies and assessments if insurance coverage is inadequate; and

•	uncertainties with respect to the technological and financial aspects of spent fuel storage and decommissioning nuclear plants, including but not limited to, waste disposal at the end of their licensed operation and increases in minimum funding requirements or costs of decommissioning.

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ITEM 1B.	UNRESOLVED STAFF COMMENTS

ITEM 2.	PROPERTIES

(1)	Includes FE's leasehold interest of 93.83% (779 MWs) from non-affiliates.

(2)	Subject to an asset purchase agreement with Aspen, as disclosed in Note 22, Subsequent Events.

(3)	Represents FES' 4.85%, AE Supply's 3.01% and MP's 0.49% entitlement based on their participation in OVEC.

(4)	Includes OE’s leasehold interest of 2.60% (24 MWs) from non-affiliates of which FES purchases all the output pursuant to full output cost-of-service PSAs.

(5)	Represents Buchanan Energy's 50% interest. Buchanan Energy is a subsidiary of AE Supply.

(6)	Represents AGC's 40% interest in Bath County. The station is operated by VEPCO. AGC is 59% owned by AE Supply and 41% owned by MP.

(7)	Represents JCP&L’s 50% ownership interest.

(8)	Includes 167 MWs from leased facilities and 329 MWs under power purchase agreements.

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(1)	Circuit Miles

(2)	Top rating of in-service power transformers only. Excludes grounding banks, station power transformers, and generator and customer-owned transformers.

(3)	Represents transmission line assets of 69 kV and greater located in the service territories of OE, Penn, CEI and TE.

ITEM 3.	LEGAL PROCEEDINGS

ITEM 4.	MINE SAFETY DISCLOSURES

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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ITEM 6.	SELECTED FINANCIAL DATA

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ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

•	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, our planned forward-looking formula rates 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 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.

•	The risks and uncertainties associated with the lack of viable alternative strategies regarding the CES segment, thereby causing FES, and possibly FENOC, to restructure its debt and other financial obligations with its creditors or seek protection under U.S. bankruptcy laws and the losses, liabilities and claims arising from such bankruptcy proceeding, including any obligations at FirstEnergy.

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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 substantial uncertainty as to FES’ ability to continue as a going concern and substantial risk that it may be necessary for FES, and possibly FENOC, to seek protection under U.S. bankruptcy laws.

•	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 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.

•	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.

•	Costs being higher than anticipated and the success of our policies to control costs and to mitigate low energy, capacity and market prices.

•	Replacement power costs being higher than anticipated or not fully hedged.

•	Our ability to improve electric commodity margins and the impact of, among other factors, the increased cost of fuel and fuel transportation on such margins.

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

•	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).

•	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.

•	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.

•	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 labor disruptions by our unionized workforce.

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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.

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•	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 Ohio DMR.

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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; 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.

•	The ability to comply with applicable state and federal reliability standards and energy efficiency and peak demand reduction mandates.

•	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.

•	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.

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

•	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.

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

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

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•	Legislative or regulatory solutions for generation assets that recognize their environmental or energy security benefits,

•	Additional asset sales and/or plant deactivations,

•	Restructuring FES debt with its creditors, and/or

•	Seeking protection under U.S. bankruptcy laws for FES and possibly FENOC.

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•	The impairment of $800 million of goodwill at CES in the second quarter of 2016, reflecting a weak outlook for energy and capacity markets.

•	Impairment charges totaling $647 million in the second quarter of 2016 resulting from management's decision to exit the Bay Shore Unit 1 generating station and Units 1-4 of the W.H. Sammis generating station.

•	Impairment charges of $9,218 million resulting from management's plans to exit competitive operations by mid-2018 and the anticipated cash flows over this shortened period.

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•	The decrease in revenue at CES resulted from a 15 million MWH decline in contract sales, as the segment continues to align sales to its generation, as well as lower capacity revenue associated with lower capacity auction prices. The decline in contract sales volume was partially offset by higher wholesale sales and higher net gains on financially settled contracts.

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The increase in revenue at Regulated Transmission primarily reflect recovery of incremental operating expenses and a 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 in 2016 at ATSI under its FERC-approved comprehensive settlement related to the implementation of its forward-looking rate.

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The increase in revenue at Regulated Distribution primarily resulted from higher weather-related distribution deliveries and the full year impact of net rate increases implemented in 2015, partially offset by lower generation sales. Distribution deliveries increased 0.3%, or 0.4 million MWHs, reflecting higher weather-related sales partially offset by the impact of lower weather-adjusted average customer usage reflecting the impact of more energy efficient products and services.

•	Purchased power decreased $505 million mainly due to lower volumes at CES and Regulated Distribution and lower capacity expense at CES.

•	Fuel expense decreased $189 million mainly resulting from lower generation at CES associated with outages and lower economic dispatch of fossil units reflecting low wholesale spot market energy prices, as well as lower unit prices on fossil fuel contracts.

•	Pension and OPEB mark-to-market adjustments decreased $95 million to $147 million in 2016. The 2016 adjustment resulted from a 25 bps decrease in the discount rate used to measure benefit obligations partially offset by higher than expected asset returns and changes in certain actuarial assumptions.

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Other operating expenses increased $109 million, primarily reflecting an increase at Regulated Distribution resulting from the recognition of economic development and energy efficiency obligations in accordance with the PUCO's order approving the Ohio Companies' ESP IV, higher network transmission expenses, which are recovered through transmission rates, higher retirement benefit costs, and higher operating and maintenance expenses associated with storm restoration costs, partially offset by lower PJM transmission costs and lower nuclear planned outage costs at CES.

•	The decrease in revenue at CES resulted from a 31 million MWHs decline in contract sales, in line with CES’ strategy to align sales to its generation, partially offset by higher wholesale sales, including increased capacity revenue associated with higher capacity auction prices.

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The increase in revenue at Regulated Distribution resulted from the implementation of new rates at certain operating companies as well as a year-over-year increase in generation revenue. Distribution deliveries decreased 0.8%, or 1.1 million MWHs, as weather adjusted sales declined as a result of energy efficiency products and services and decreases in certain industrial sectors, partially offset by an increase in weather-related sales.

•	The increase at Regulated Transmission primarily reflected a higher rate base and recovery of incremental operating expenses as well as ATSI’s transition to a forward-looking rate, effective January 1, 2015. These increases were partially offset by a lower ROE at ATSI in the last six months of 2015 as part of its FERC-approved settlement discussed above.

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•	Fuel expense declined $425 million, primarily at CES, resulting from lower fossil generation associated with low energy prices, lower unit costs, and lower settlement and termination charges on fuel and transportation contracts.

•	Purchased power decreased $398 million, primarily reflecting lower volumes at CES, resulting from lower contract sales, partially offset by higher volumes at Regulated Distribution due to lower customer shopping as discussed above, and higher capacity expense associated with higher capacity rates.

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Other operating expenses decreased $213 million, primarily reflecting a decrease at CES associated with lower PJM transmission costs and retail-related costs partially offset by higher nuclear planned outage costs. Regulated Distribution other operating expenses increased $163 million resulting from higher network transmission expenses, which are recovered through transmission rates, and higher operating and maintenance expenses associated with reliability improvements.

•	Amortization of regulatory assets, net increased $256 million primarily reflecting the recovery of deferred costs, including storm costs, associated with the implementation of new rates discussed above.

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•	Fuel expense increased $34 million in 2016, as compared to the same period of 2015, primarily related to higher generation.

•	Purchased power costs decreased $275 million in 2016, as compared to the same period of 2015, primarily due to lower 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 $196 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, 2016 Opinion and Order adopting and approving, with modifications, the Ohio Companies' ESP IV.

•	Higher retirement benefit costs of $57 million.

•	Higher transmission expenses of $56 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 transmission costs incurred are deferred for future recovery or refund, resulting in no material impact on current period earnings.

•	Higher operating and maintenance expense of $33 million, primarily due to increased storm restoration costs, which are deferred for future recovery resulting in no material impact on current period earnings.

•	Pension and OPEB mark-to-market adjustments decreased $78 million to $101 million in 2016. The 2016 adjustment resulted from a 25 bps decrease in the discount rate used to measure benefit obligations partially offset by higher than expected asset returns and changes in certain actuarial assumptions.

•	Depreciation expenses increased $12 million due to a higher asset base.

•	Net amortization of regulatory assets increased $52 million primarily due to:

•	A full year 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 ($40 million), partially offset by

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

•	General taxes increased $17 million primarily due to higher revenue-related taxes in Pennsylvania and higher property taxes in Ohio.

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Fuel costs decreased $223 million, primarily due to lower generation associated with outages and lower economic dispatch of fossil units resulting from low wholesale spot market energy prices, as discussed above, as well as lower unit prices on fossil fuel contracts. Additionally, fuel costs were impacted by lower settlement and termination costs on coal contracts. The impact of settlements and terminations of coal contracts resulted in a pre-tax loss of $58 million and $67 million in 2016 and 2015, respectively.

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Purchased power costs decreased $437 million due to lower capacity expenses ($234 million) and lower volumes ($203 million). 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. Lower volumes primarily resulted from lower contract sales, as discussed above, partially offset by higher economic purchases, resulting from the low wholesale spot market price environment.

•	Fossil operating costs increased $4 million, primarily due to increased outage costs and higher employee benefit costs, partially offset by lower operating costs from the deactivation of certain fossil plants in April 2015.

•	Nuclear operating costs decreased $39 million, primarily as a result of lower refueling outage costs, partially offset by higher employee benefit costs. There were two refueling outages in 2016 as compared to three refueling outages in 2015.

•	Retirement benefit costs increased $31 million.

•	Transmission expenses decreased $175 million, primarily due to lower congestion and market-based ancillary costs associated with less volatile market conditions as compared to 2015, as well as lower load requirements.

•	Other operating expenses increased $35 million, primarily due to lower mark-to-market gains on commodity contract positions of $84 million and a $37 million charge associated with the termination of an FES customer contract, partially offset by lower lease expense as a result of the expiration of a nuclear sale-leaseback agreement.

•	Pension and OPEB mark-to-market adjustments decreased $15 million to $45 million in 2016. The 2016 adjustment resulted from a 25 bps decrease in the discount rate used to measure benefit obligations, partially offset by higher than expected asset returns and changes in other actuarial assumptions.

•	Depreciation expense decreased $7 million, primarily as a result of an out-of-period adjustment to reduce depreciation of a hydroelectric generating station, partially offset by a higher asset base.

•	General taxes decreased $6 million, primarily due to lower gross receipts taxes associated with lower retail sales volumes.

•	Impairment of assets increased $10,631 million, primarily due to impairments of goodwill and the competitive generation assets discussed above.

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•	Fuel expense decreased $34 million in 2015 primarily related to lower economic dispatch resulting from low spot market energy prices.

•	Purchased power costs were $163 million higher in 2015 primarily due to increased volumes reflecting lower customer shopping as described above, higher unit costs related to higher default service auction prices, and higher capacity expense at MP, partially offset by lower volumes resulting from the termination of certain NUG contracts at JCP&L and PN.

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•	Higher transmission expenses of $73 million primarily due to an increase in network transmission expenses at the Ohio Companies, partially offset by lower congestion expenses at MP. The differences between current retail transmission revenues and transmission costs incurred are deferred for future recovery, resulting in no material impact on current period earnings.

•	Increased regulated generation operating and maintenance expenses of $7 million, reflecting higher planned outage expenses in 2015 compared to 2014.

•	Higher retirement benefit costs of $22 million.

•	Higher distribution operating and maintenance expenses of $61 million, reflecting increased reliability maintenance and other employee benefit costs, partially offset by lower storm restoration costs.

•	Pension and OPEB mark-to-market adjustments decreased $327 million to $179 million, which was impacted by lower than expected asset returns, partially offset by an increase in the discount rate used to measure benefit obligations.

•	Depreciation expense increased $13 million due to a higher asset base, partially offset by lower depreciation rates at JCP&L effective with the implementation of new rates from its distribution base rate case as well as lower depreciation rates in Pennsylvania based on updated asset life studies approved by the PPUC.

•	Net regulatory asset amortization increased $260 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 ($66 million),

•	Higher energy efficiency program cost recovery ($66 million),

•	Lower deferral of TTS costs in West Virginia ($37 million),

•	Higher amortizations of above-market NUG costs in Pennsylvania and New Jersey ($36 million),

•	Lower deferral of West Virginia vegetation management expenses ($31 million),

•	Higher default generation service cost amortization ($28 million), and

•	Recovery of Pennsylvania legacy meter costs ($22 million); partially offset by

•	Higher cost deferral of Ohio network transmission expenses ($33 million).

•	General taxes increased $11 million primarily due to higher revenue-related taxes in Pennsylvania, partially offset by lower property taxes in Ohio.

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Fuel costs decreased $391 million, primarily due to lower economic dispatch of fossil units resulting from low spot market energy prices and lower nuclear unit prices, resulting from the suspension of the DOE nuclear disposal fee, effective May 16, 2014. Additionally, fuel costs were impacted by a decrease in settlement and termination costs related to coal and transportation contracts. The impact of terminations and settlements of coal and transportation contracts resulted in a pre-tax loss of $67 million and $166 million in 2015 and 2014, respectively.

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Purchased power costs decreased $694 million due to lower volumes ($888 million), partially offset by higher unit prices ($39 million) and higher capacity expenses ($155 million). Lower volumes were primarily due to decreased load requirements resulting from lower sales, as discussed above, partially offset by lower fossil generation, as discussed above. The higher unit prices are primarily due to higher losses on financially settled contracts, partially offset by lower market prices in 2015 as compared to 2014. 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.

•	Nuclear operating costs increased $84 million as a result of higher refueling outage costs and higher employee benefit expenses. There were three refueling outages in 2015 as compared to two refueling outages in 2014.

•	Transmission expenses decreased $273 million, primarily due to lower operating reserve and market-based ancillary costs associated with market conditions resulting from the extreme weather events in 2014.

•	General taxes decreased $31 million, primarily due to lower gross receipts taxes associated with lower retail sales volumes.

•	Pension and OPEB mark-to-market adjustments decreased $267 million to $60 million, which was impacted by lower than expected asset returns, partially offset by an increase in the discount rate used to measure benefit obligations.

•	Other operating expenses decreased $216 million, primarily due to a $141 million decrease in mark-to-market expenses on commodity contract positions reflecting lower market prices and a $71 million decrease in retail-related costs.

•	Impairment of assets were $34 million in 2015 due to impairment charges associated with non-core assets.

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•	FE and the Utilities entered into a new $4 billion revolving credit facility, which represents an increase of $500 million over the existing $3.5 billion facility it replaced,

•	FET and its subsidiaries entered into a $1 billion revolving credit facility, which replaced their existing $1 billion facility, and

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FES and AE Supply terminated their unsecured $1.5 billion credit facility (commitments of $900 million and $600 million for FES and AE Supply, respectively) and FES entered into a new, two-year secured credit facility with FE in which FE provided a committed line of credit to FES of up to $500 million and additional credit support of up to $200 million to cover a $169 million surety bond for the benefit of the PA DEP with respect to LBR, and other bonds as designated in writing to FE. In connection with the cancellation of the prior FES/AE Supply facility and entry into the new FES secured facility with FE, certain commitments and amendments associated with shared services and operational matters were made including, without limitation, as follows: (i) FE reaffirmed its obligations under the Intercompany Tax Allocation Agreement, and (ii) amendments to the Service Agreement by and among FESC, FES, FG and NG, to prevent termination until the earlier of December 31, 2018, or a change in control of FES or its subsidiaries.

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(1)	FE and the Utilities.

(2)	Includes FET, ATSI and TrAIL.

(1)	No limitations.

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

(3)	Pending regulatory approval, as discussed under "Outlook - FERC Matters" below.

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•	A $239 million increase in cash contributions to the qualified pension plan, partially offset by;

•	Higher distribution deliveries and the full year impact of net rate increases implemented in 2015 at certain Utilities;

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

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•	Lower disbursements for fuel and purchased power resulting from the lower sales volumes partially offset by lower capacity revenues at CES.

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

•	Higher transmission revenue and earnings, reflecting recovery of incremental operating expenses, a higher rate base and forward-looking rates at ATSI;

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

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

•	Lower posted collateral; partially offset by,

•	A $143 million contribution to the qualified pension plan in 2015.

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•	a decrease of $351 million at CES, resulting from the absence of capital investments associated with the Davis-Besse steam generators that were placed into service in May 2014,

•	a decrease of $426 million at Regulated Transmission primarily relating to the timing of capital investments associated with its Energizing the Future investment program, partially offset by

•	an increase of $185 million at Regulated Distribution relating to utility specific project investments and costs associated with the Pennsylvania smart meter program.

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(1)	Excludes unamortized discounts and premiums, fair value accounting adjustments and capital leases.

(2)	Interest on variable-rate debt based on rates as of December 31, 2016.

(3)	See Note 7, Leases, of the Combined Notes to Consolidated Financial Statements.

(4)	Amounts under contract with fixed or minimum quantities based on estimated annual requirements.

(5)	Amounts represent committed capital expenditures as of December 31, 2016.

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

(2)	CES related portion is $139 million, including $53 million and $86 million at FES and FENOC, respectively.

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

(4)	Includes energy and energy-related contracts associated with FES.

(5)	NG funded a $10 million supplemental trust in December 2016 to replace this guarantee, which will terminate in April 2017.

(6)

FES provides a parental support agreement to NG of up to $400 million that may be required in the event of extraordinary circumstances. FE is working with FES to establish conditional credit support on terms and conditions to be agreed upon for the $400 million FES parental support agreement that is currently in place for the benefit of NG in the event that FES is unable to provide the necessary support to NG.

(7)	Effective January 2017, FE is an indemnitor for $169 million of FG surety bonds for the benefit of the PA DEP with respect to LBR.

(8)	Includes $9 million issued for various terms pursuant to LOC capacity available under FirstEnergy's revolving credit facilities and $3 million pledged in connection with the sale and leaseback of the 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 $(107) 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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•	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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•	Legislative or regulatory solutions for generation assets that recognize their environmental or energy security benefits,

•	Additional asset sales and/or plant deactivations,

•	Restructuring FES debt with its creditors, and/or

•	Seeking protection under U.S. bankruptcy laws for FES and possibly FENOC.

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•	Fossil operating costs decreased $12 million, primarily as a result of the deactivation of certain fossil plants in 2015, partially offset by increased outage costs and higher employee benefit costs

•	Nuclear operating costs decreased $39 million, primarily as a result of lower refueling outage costs, partially offset by higher employee benefit costs. There were two refueling outages in 2016 as compared to three refueling outages in 2015.

•	Retirement benefit costs increased $30 million.

•	Transmission expenses decreased $145 million, primarily due to lower congestion and market-based ancillary costs associated with less volatile market conditions as compared to 2015, as well as lower load requirements.

•	Other operating expenses increased $135 million, primarily due to lower mark-to-market gains on commodity contract positions of $85 million and a $37 million charge associated with the termination of an FES customer contract.

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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.

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ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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*	Includes excise tax collections of $406 million, $416 million and $420 million in 2016, 2015 and 2014, respectively.

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*	Includes excise tax collections of $28 million, $44 million and $69 million in 2016, 2015 and 2014, respectively.

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•	Legislative or regulatory solutions for generation assets that recognize their environmental or energy security benefits,

•	Additional asset sales and/or plant deactivations,

•	Restructuring FES debt with its creditors, and/or

•	Seeking protection under U.S. bankruptcy laws for FES and possibly FENOC.

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(1)

For the year ended December 31, 2016, approximately 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 years ended December 31, 2015 and 2014, approximately one million and two million shares were excluded from the calculation of diluted shares outstanding, respectively, as their inclusion would be antidilutive.

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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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•	Legislative or regulatory solutions for generation assets that recognize their environmental or energy security benefits,

•	Additional asset sales and/or plant deactivations,

•	Restructuring FES debt with its creditors, and/or

•	Seeking protection under U.S. bankruptcy laws for FES and possibly FENOC.

(1)	Includes the impairment of materials and supplies ($142 million), AE Supply coal contracts ($55 million) and AE Supply's investment in OVEC ($37 million).

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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)	Excludes $16 million as of December 31, 2016 of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

(2)	As a result of the $500 million equity contribution on December 13, 2016, there was $293 million of FE Stock included in the pension plan assets as of December 31, 2016.

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

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

(1)	Excludes $(7) million as of December 31, 2015, 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 and their amortization does not impact earnings.

(2)	Amortization expense excludes impairment charges related to intangible assets recognized in 2016, which totaled $92 million and are included in Impairment of Assets. See "Note 2, Asset Impairments" for further discussion.

(3)	The coal contracts were recorded with a regulatory offset and the amortization does not impact earnings. Accordingly, the amortization expense for these coal contracts is excluded from table above.

(4)	A gross amount of $40 million of coal contracts is related to FES. In June 2016, FES terminated a coal contract and the write-off is included in amortization expense in the table above.

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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 December 31, 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 December 31, 2016 and December 31, 2015, $85 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 of which the proceeds 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 December 31, 2016 and December 31, 2015, $406 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. See "Note 1, Organization, Basis of Presentation and Significant Accounting Policies - Investments", for additional information regarding FEV's investment in Global Holding.

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PATH WV - PATH, a proposed transmission line from West Virginia through Virginia into Maryland which PJM had previously suspended in February 2011, 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 power purchase agreements and determined that certain NUG entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production.

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Sale and Leaseback Transactions - 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 December 31, 2016, OE'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 cash and short-term cash investments.

(4)	Excludes $(3) million and $7 million as of December 31, 2016 and December 31, 2015, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

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(1)	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 $2 million and $1 million as of December 31, 2016 and December 31, 2015, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

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(1)	Excludes short-term cash investments: FirstEnergy - $61 million; FES - $44 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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•	FE and the Utilities entered into a new $4 billion revolving credit facility, which represents an increase of $500 million over the existing $3.5 billion facility it replaced,

•	FET and its subsidiaries entered into a $1 billion revolving credit facility, which replaced their existing $1 billion facility, and

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FES and AE Supply terminated their unsecured $1.5 billion credit facility (commitments of $900 million and $600 million for FES and AE Supply, respectively) and FES entered into a new, two-year secured credit facility with FE in which FE provided a committed line of credit to FES of up to $500 million and additional credit support of up to $200 million to cover a $169 million surety bond for the benefit of the PA DEP with respect to LBR, and other bonds as designated in writing to FE. In connection with the cancellation of the prior FES/AE Supply facility and entry into the new FES secured facility with FE, certain commitments and amendments associated with shared services and operational matters were made including, without limitation, as follows: (i) FE reaffirmed its obligations under the Intercompany Tax Allocation Agreement, and (ii) amendments to the Service Agreement by and among FESC, FES, FG and NG, to prevent termination until the earlier of December 31, 2018, or a change in control of FES or its subsidiaries.

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(1)	FE and the Utilities.

(2)	Includes FET, ATSI and TrAIL.

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(1)	No limitations.

(2)	Excluding amounts which may be borrowed under the regulated companies' money pool.

(3)	Pending regulatory approval, as discussed under "FERC Matters" below.

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•	Bath County Hydro (713 MWs pumped-storage hydro) in Warm Springs, Va. (represents AE Supply’s indirect interest)

•	Springdale Generating Facility Units 1-5 (638 MWs natural gas) in Springdale Township, Pa.

•	Chambersburg Generating Facility Units 12-13 (88 MWs natural gas) in Guildford Township, Pa.

•	Gans Generating Facility Units 8-9 (88 MWs natural gas) in Springhill Township, Pa.

•	Hunlock Creek (45 MWs natural gas) in Hunlock Creek, Pa.

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

ITEM 9A.	CONTROLS AND PROCEDURES

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ITEM 9B.	OTHER INFORMATION

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

ITEM 11.	EXECUTIVE COMPENSATION

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

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ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

(1)	Professional services rendered for the audits of the registrants' annual financial statements and reviews of unaudited financial statements included in the registrants' Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters, agreed upon procedures and consents for financings and filings made with the SEC.

(2)	Professional services rendered in 2016 and 2015 related to SEC Regulation AB. Also, in 2016, professional services rendered related to additional agreed upon procedures for the audit of PE's cost allocation manual and the attestation of Penn Power's Net Earnings Certificate.

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ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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(1)	Represents recoveries and reinstatements of accounts previously written off.

(2)	Represents the write-off of accounts considered to be uncollectible.

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(1)	Represents recoveries and reinstatements of accounts previously written off.

(2)	Represents the write-off of accounts considered to be uncollectible.

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ITEM 16.	FORM 10-K SUMMARY

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