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ITEM 1.	BUSINESS

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(1)	FE and the Utilities. Available liquidity includes impact of $10 million of LOCs issued under various terms.

(2)	Includes FET, ATSI, MAIT and TrAIL.

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•	On January 5, 2017, UWUA Local 180, which represents approximately 123 employees in PN, ratified a new agreement that will expire August 31, 2022.

•	On March 2, 2017, IBEW Local 777, which represents approximately 497 employees in ME, ratified a contract that will expire on April 30, 2022.

•	On May 18, 2017, IBEW Local 272, which represents approximately 214 employees at the Bruce Mansfield Plant, ratified a new agreement that will expire on February 15, 2020.

•	On October 10, 2017, UWUA Local 304, which represents approximately 164 employees at the Harrison Plant, ratified a new agreement that will expire March 1, 2022.

•	On October 27, 2017, UWUA Local 270, which represents approximately 786 employees at CEI, the Perry nuclear plant and the Eastlake synchronous condenser plant, ratified a new agreement that will expire on April 30, 2022.

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ITEM 1A.	RISK FACTORS

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

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•	requests to post additional collateral or accelerate payments, including prepayments to certain trade creditors; and

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

•	the risk that we may not be able to, or may no longer desire to, complete our planned disposition of our generating assets;

•	the risk that FirstEnergy could be required to satisfy or otherwise elect to guarantee significant financial obligations of FES or its subsidiaries, which could adversely affect the financial condition and cash flows of FirstEnergy;

•	the risk that creditors of FES may attempt to assert claims, including those that arise out of litigation or other commercial disputes, against FirstEnergy that may require significant effort and money to defend and could adversely affect the business, financial condition, results of operations and cash flows of FirstEnergy; and

•	the risk that certain triggering events could constitute events of default under certain of FirstEnergy’s obligations.

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

•	the unlikelihood of FG and NG being able to refinance debt maturities of $515 million and $323 million in 2018 and 2019, respectively;

•	additional postings of collateral or acceleration of payments;

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

•	reducing the availability of FES cash flow to fund other corporate purposes; and

•	reducing the ability of FES to enter into transactions with counterparties due to demands for additional collateral or credit support due to FES' creditworthiness.

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

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

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

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

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

(7)	On July 22, 2016, FirstEnergy and FES announced its intent to exit operations of the Bay Shore Unit 1 generating station by October 1, 2020, through either sale or deactivation and to deactivate Units 1-4 of the W. H. Sammis generating station by May 31, 2020.

(8)	Subject to an asset purchase agreement with a subsidiary of LS Power, expected to close in the first half of 2018.

(9)	On February 16, 2018, AE Supply announced its intent to sell or deactivate the Pleasants Power Station by January 1, 2019.

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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 and the effectiveness of our strategy to transition to a fully regulated business profile.

•	The accomplishment of our regulatory and operational goals in connection with our transmission and distribution investment plans, including, but not limited to, our planned transition to forward-looking formula rates.

•	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.

•	Success of legislative and regulatory solutions for generation assets that recognize their environmental or energy security benefits.

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The risks and uncertainties associated with the lack of viable alternative strategies regarding the CES segment, thereby causing FES to restructure its substantial debt and other financial obligations with its creditors or seek protection under U.S. bankruptcy laws (which filing would include FENOC) 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, its subsidiaries, and FENOC, related to wholesale energy and capacity markets, and the viability and/or success of strategic business alternatives, such as pending and potential CES generating unit asset sales or the potential need to deactivate additional generating units, which could result in further substantial write-downs and impairments of assets.

•	The substantial uncertainty as to FES’ ability to continue as a going concern and substantial risk that it may be necessary for FES and 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 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, margins and operations 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.

•	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.

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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, including the federal administration's required review and potential revision of 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).

•	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, including the Tax Act, 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 FES and its subsidiaries.

•	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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•	Reduction of the corporate federal income tax rate from 35% to 21%, effective in 2018;

•	Full expensing of qualified property, excluding rate regulated utilities, through 2022 with a phase down beginning in 2023;

•	Limitations on interest deductions with an exception for rate regulated utilities;

•	Limitation of the utilization of federal NOLs arising after December 31, 2017 to 80% of taxable income with an indefinite carryforward;

•	Repeal of the corporate AMT and allowing taxpayers to claim a refund on any AMT credit carryovers.

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•	Impairment charges of $9,218 million resulting from management's plans to exit its commodity-exposed generation at CES and the anticipated cash flows over the shortened period.

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

•	Impairment charges totaling $647 million 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.

•	Charges of $2,045 million associated with FES' nuclear generating assets, as discussed above in "Executive Summary."

•	Impairment charges of $193 million as a result of the amended asset purchase agreement between AE Supply, AGC, BU Energy and a subsidiary of LS Power.

•	Impairment charge of $120 million resulting from AE Supply's announced intent to exit operations of the Pleasants Power Station, through either sale or deactivation by January 1, 2019.

•	Impairment charges totaling $41 million associated with formula-rate settlement agreements filed with FERC by MAIT and JCP&L.

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•	The decrease in revenues at CES resulted from a 10 million MWH decline in contract sales at lower prices, as well as lower capacity auction prices and lower net gains on financially settled contracts, partially offset by an increase in short-term (net hourly position) transactions.

•	The increase in revenues at Regulated Transmission resulted primarily from recovery of incremental operating expenses and a higher rate base at ATSI and TrAIL.

•	The increase in revenues at Regulated Distribution resulted from the implementation of new rates in January 2017, partially offset by lower weather-related distribution deliveries and higher customer shopping.

•	Purchased power decreased $649 million mainly due to lower volumes at CES and Regulated Distribution as well as lower capacity expense at CES.

•	Fuel expense decreased $283 million, mainly due to 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.

•	Depreciation expense decreased $175 million, mainly from a lower asset base at CES resulting from asset impairments recognized in 2016.

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Other operating expenses increased $381 million, reflecting an increase of $251 million at CES, primarily associated with estimated losses on long-term coal and coal transportation contract disputes recognized in 2017 and higher non-cash mark-to-market losses on commodity contract positions. Operating expenses at Regulated Distribution increased $88 million, resulting primarily from higher operating and maintenance expenses, including increased expenses in Pennsylvania recovered through the new base distribution rates, effective January 27, 2017, and increased storm restoration costs.

•	The decrease in revenue at CES resulted from a 15 million MWH decline in contract sales, as the segment aligned 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.

•	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.

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The increase in revenue at Regulated Transmission primarily resulted from the 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 formula rate.

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•	Purchased power decreased $580 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 $111 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, 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.

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•	Fuel expense decreased $74 million in 2017, as compared to 2016, primarily related to lower unit costs.

•	Purchased power costs decreased $379 million in 2017, as compared to 2016, primarily due to decreased volumes, as described above, as well as lower default service auction prices.

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•	Other operating expenses increased $88 million primarily due to:

•	Higher network transmission expenses of $35 million. 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 expenses of $64 million, including increased expenses in Pennsylvania recovered through the new base distribution rates, effective January 27, 2017, and increased storm restoration costs, which were deferred for future recovery, resulting in no material impact on current period earnings;

•	Higher energy efficiency program expenses of $45 million in Ohio, which were recovered through higher distribution rider revenues; partially offset by,

•	Lower regulatory costs of $51 million resulting from the absence of economic development and energy efficiency obligations recognized in 2016 in accordance with the PUCO's March 31, 2016 Opinion and Order adopting and approving, with modifications, the Ohio Companies' ESP IV.

•	Depreciation expenses increased $48 million due to a higher asset base as well as increased rates in Pennsylvania.

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•	Fuel costs decreased $209 million, primarily due to the absence of approximately $58 million in settlement and termination costs on coal contracts recognized in 2016, as well as lower generation associated with outages and economic dispatch of fossil units resulting from low wholesale spot market energy prices, as discussed above, partially offset by higher unit costs.

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Purchased power costs decreased $363 million primarily due to lower capacity expenses ($271 million) and lower unit costs ($126 million), partially offset by higher volumes ($34 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 unit costs primarily resulted from lower wholesale spot market prices, as discussed above.

•	Charges of $318 million associated with estimated losses on long-term coal and coal transportation contract disputes was recognized in 2017, as discussed in "Outlook - Environmental Matters" below.

•	Fossil operating and maintenance expenses decreased $18 million, primarily due to lower outage costs.

•	Nuclear operating and maintenance expenses increased $14 million, primarily as a result of higher employee benefit costs, partially offset by lower refueling outage costs.

•	Retirement benefit costs decreased $14 million.

•	Transmission expenses decreased $60 million, primarily due to lower contract sales volumes.

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•	Other operating expenses increased $11 million, primarily due to higher non-cash mark-to-market losses on commodity contract positions, partially offset by the absence of a termination charge recognized in 2016 associated with an FES Governmental Aggregation customer contract and lower lease expense as a result of the expiration of a nuclear sale-leaseback agreement.

•	Depreciation expense decreased $269 million, primarily due to a lower asset base resulting from asset impairments recognized in 2016, partially offset by the absence of an out-of-period adjustment to reduce the depreciation of a hydroelectric generating station in the third quarter of 2016.

•	General taxes decreased $35 million, primarily due to lower property taxes and reduced gross receipts taxes associated with lower retail sales volumes.

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Impairment of assets and related charges decreased $8,300 million, primarily due to the absence of impairments recognized in 2016 related to goodwill and the competitive generation assets primarily resulting from the strategic review announced in November 2016, partially offset by the impairments recognized in 2017 related to the nuclear generating assets and the Pleasants Power Station, as discussed further in "Executive Summary," above.

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

•	Purchased power costs decreased $350 million, in 2016 as compared to 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 $198 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 $125 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)

•	The recovery of previously deferred energy and fuel costs ($75 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.

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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.

•	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 $39 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.

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

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(1)	FE and the Utilities. Available liquidity includes impact of $10 million of LOCs issued under various terms.

(2)	Includes FET, ATSI, MAIT and TrAIL.

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(1)	No limitations.

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

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•	the absence of $382 million in cash contributions to the qualified pension plan in 2016;

•	higher transmission revenue, reflecting recovery of incremental operating expenses, a higher rate base at ATSI and TrAIL, and the implementation of new rates at MAIT and JCP&L;

•	higher distribution services retail receipts reflecting implementation of approved rates in Ohio, Pennsylvania and New Jersey, as further described above; partially offset by

•	lower receipts from a decrease in capacity revenue and contract sales at CES.

•	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;

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

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•	a decrease of $302 million at CES, resulting from lower capital investments associated with outages, MATS compliance and the Mansfield dewatering facility,

•	a decrease of $71 million at Regulated Transmission due to timing of capital investments associated with its Energizing the Future investment program; partially offset by,

•	an increase of $128 million at Regulated Distribution due to an increase in storm restoration work and smart meter investments in Pennsylvania.

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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, 2017.

(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, 2017.

(6)	In January 2018, FirstEnergy satisfied its minimum required funding obligations of $500 million and addressed funding obligations through 2020 to its qualified pension plan with additional contributions of $750 million. The impact of the contributions is reflected in the table above.

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

(2)	CES related portion is $149 million, including $58 million and $91 million at FES and FENOC, respectively.

(3)	As a condition to closing the sale of the natural gas generating plants, FE provided the purchaser two limited three-year guarantees totaling $555 million of certain obligations of AE Supply and AGC arising under the amended and restated purchase agreement.

(4)	FE is the guarantor of the remaining payments due to CSX/BNSF in connection with the definitive settlement on a transportation agreement.

(5)	Includes guarantees of $4 million for various leases.

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

(7)	FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR and the Hatfield's Ferry disposal site, respectively.

(8)	FE provides credit support for $23 million of surety bonds held by AE Supply.

(9)	Includes $10 million issued for various terms pursuant to LOC capacity available under FirstEnergy's revolving credit facilities.

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

(2)	Includes $(79) 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 changes in market values do not impact earnings.

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•	Reduction of the corporate federal income tax rate from 35% to 21%, effective in 2018;

•	Full expensing of qualified property, excluding rate regulated utilities, through 2022 with a phase down beginning in 2023;

•	Limitations on interest deductions with an exception for rate regulated utilities;

•	Limitation of the utilization of federal NOLs arising after December 31, 2017 to 80% of taxable income with an indefinite carryforward;

•	Repeal of the corporate AMT and allowing taxpayers to claim a refund on any AMT credit carryovers.

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•	Charges of $225 million associated with estimated losses on long-term coal transportation contract disputes was recognized in 2017, as discussed in the "Outlook - Environmental Matters" above.

•	Nuclear operating and maintenance expenses increased $14 million, primarily as a result of higher employee benefit costs, partially offset by lower refueling outage costs.

•	Retirement benefit costs decreased $12 million.

•	Transmission expenses decreased $62 million, primarily due to lower contract sales volumes.

•	Other operating expenses increased $72 million, primarily due to higher non-cash mark-to-market losses on commodity contract positions, partially offset by the absence of a termination charge associated with an FES Governmental Aggregation customer contract.

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•	a $138 million cash contribution to the qualified pension plan;

•	higher cash collateral postings primarily associated with higher margin requirements by counterparties due to FES' credit downgrading in 2016; partially offset by,

•	increased capacity revenues.

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(1)	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 $390 million, $406 million and $416 million in 2017, 2016 and 2015, respectively.

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*	Includes excise tax collections of $20 million, $28 million and $44 million in 2017, 2016 and 2015, respectively.

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(1)	For the years ended December 31, 2017, 2016 and 2015, approximately three million, three million and one million shares were excluded from the calculation of diluted shares outstanding, respectively, as their inclusion would be antidilutive, and in the case of 2016 and 2017, a result of the net loss for the period.

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

•	restructuring FES' debt with its creditors,

•	seeking protection under U.S. bankruptcy laws for FES and likely FENOC, and/or

•	asset sales and/or plant deactivations.

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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 $(10) million as of December 31, 2017, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

(2)	Net asset value used as a practical expedient to approximate fair value.

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(1)	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.

(2)	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.

(3)	Net asset value used as a practical expedient to approximate fair value.

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(1)	Excludes $(2) million as of December 31, 2017, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

(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.

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•	Reduction of the corporate federal income tax rate from 35% to 21%, effective in 2018;

•	Full expensing of qualified property, excluding rate regulated utilities, through 2022 with a phase down beginning in 2023;

•	Limitations on interest deductions with an exception for rate regulated utilities;

•	Limitation of the utilization of federal NOLs arising after December 31, 2017 to 80% of taxable income with an indefinite carryforward;

•	Repeal of the corporate AMT and allowing taxpayers to claim a refund on any AMT credit carryovers.

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(1)	NUG contracts are subject to regulatory accounting and their amortization does not impact earnings.

(2)	The coal contracts were recorded with a regulatory offset and their amortization does not impact earnings.

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Ohio Securitization - In September 2012, the Ohio Companies created separate, wholly-owned limited liability company 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, 2017 and December 31, 2016, $315 million and $339 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, which were paid in full at maturity on June 5, 2017. Additionally, 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 II and are collateralized by its equity and assets, which consist primarily of bondable transition property. As of December 31, 2017 and December 31, 2016, $56 million and $85 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 limited liability company SPEs 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 limited liability company SPEs, have no recourse to any assets or revenues of the special purpose limited liability companies. As of December 31, 2017 and December 31, 2016, $383 million and $406 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. In 2015, FirstEnergy fully impaired the value of its investment in Global Holding.

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PATH WV - PATH, a proposed transmission line from West Virginia through Virginia into Maryland which PJM cancelled in 2012, 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. As of December 31, 2017, the carrying value of the equity method investment was $17 million.

•	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 - FES has obligations that are not included on its Consolidated Balance Sheet related to the 2007 Bruce Mansfield Unit 1 sale and leaseback arrangement, 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.

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(1)	NUG contracts are subject to regulatory accounting treatment and changes in market values 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 $(3) million as of December 31, 2017 and December 31, 2016, 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 $3 million and $2 million as of December 31, 2017 and December 31, 2016, 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 - $87 million; FES - $76 million.

(2)	Excludes short-term cash investments: FirstEnergy - $61 million; FES - $44 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 changes in market values do not impact earnings.

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(1)	FE and the Utilities. Available liquidity includes impact of $10 million of LOCs issued under various terms.

(2)	Includes FET, ATSI, MAIT and TrAIL.

(1)	No limitations.

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

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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

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ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

ITEM 11.	EXECUTIVE COMPENSATION

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

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 2017 and 2016 related to SEC Regulation AB. Also, in 2017, professional services rendered related to restructuring and 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's Net Earnings Certificate.

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ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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ITEM 16.	FORM 10-K SUMMARY

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

(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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