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•	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, including the NOPR released by the Secretary of Energy and action by FERC.

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The risks and uncertainties associated with the lack of viable alternative strategies regarding the CES segment, thereby causing FES, and likely FENOC, to restructure its substantial 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 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, 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, 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 likely 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.

•	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

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•	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 new 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 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 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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•	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

•	additional asset sales and/or plant deactivations.

•	The outcome of efforts related to the NOPR released by the Secretary of Energy and action by FERC to address critical issues central to protecting the long-term reliability and resiliency of the electric grid provided by traditional baseload resources, such as coal and nuclear generation;

•	The resolution of legislation before the Ohio General Assembly that would create a zero-emission nuclear (ZEN) program that would provide compensation to nuclear power plants for their fuel diversity, environmental and other benefits and the potential for similar legislative action in Pennsylvania; and/or

•	The inability to finalize and consummate a settlement agreement with BNSF and NS regarding a previously disclosed long-term coal transportation contract dispute as discussed in Note 11, "Commitments, Guarantees and Contingencies - Environmental Matters" below, whereby FG could be subject to materially higher damages.

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(1)

For both the three and nine months ended September 30, 2017, and the three months ended September 30, 2016, one million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. For the nine months ended September 30, 2016, three million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive as a result of the net loss.

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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 September 30, 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 September 30, 2017 and December 31, 2016, $60 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 September 30, 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.

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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.

•	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. As of September 30, 2017, FES' leasehold interest was 93.83% of Bruce Mansfield Unit 1.

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

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

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

(4)	Excludes $(13) million and $(3) million as of September 30, 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)	NUG contracts are subject to regulatory accounting treatment and do not impact earnings.

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

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

(3)	Excludes $(8) million and $2 million as of September 30, 2017 and December 31, 2016, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

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(1)	Excludes short-term cash investments: FirstEnergy - $100 million; FES - $89 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 do not impact earnings.

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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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•	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

•	additional asset sales and/or plant deactivations.

•	The outcome of efforts related to the NOPR released by the Secretary of Energy and action by FERC to address critical issues central to protecting the long-term reliability and resiliency of the electric grid provided by traditional baseload resources, such as coal and nuclear generation;

•	The resolution of legislation before the Ohio General Assembly that would create a zero-emission nuclear (ZEN) program that would provide compensation to nuclear power plants for their fuel diversity, environmental and other benefits and the potential for similar legislative action in Pennsylvania; and/or

•	The inability to finalize and consummate a settlement agreement with BNSF and NS regarding a previously disclosed long-term coal transportation contract dispute as discussed in "Outlook - Environmental Matters" below, whereby FG could be subject to materially higher damages.

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•	The decrease in revenue at CES was primarily due to lower contract sales volumes and lower retail prices partially offset by higher wholesale sales.

•	The decrease in revenue at Regulated Distribution was primarily due to the impact of lower weather-related usage and higher customer shopping partially offset by higher distribution revenues reflecting the implementation of new rates in January 2017.

•	The increase in revenue at Regulated Transmission resulted from a higher rate base at ATSI, JCP&L and TrAIL as well as recovery of incremental operating expenses.

•	Purchased power decreased $118 million, primarily at Regulated Distribution as a result of lower volumes from increased customer shopping and lower weather-related usage as well as lower default service auction prices. The decline in purchased power at CES was due to lower capacity expenses and market prices.

•	Fuel expense decreased $87 million, primarily at CES due to lower generation associated with outages and economic dispatch of fossil units resulting from low wholesale spot market energy prices. The decline in fuel expense at Regulated Distribution resulted from lower unit costs.

•	Depreciation expense decreased $22 million, primarily due to a lower asset base at CES resulting from asset impairments recognized in 2016.

•	Other operating expenses decreased $11 million, primarily due to the absence of a termination charge associated with an FES Governmental Aggregation customer contract.

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•	Impairment of assets increased $31 million, resulting primarily from purchase price adjustments pursuant to the terms of the amended and restated asset purchase agreement between AE Supply, AGC, BU Energy and a subsidiary of LS Power.

•	Non-cash pre-tax impairment charges of $800 million associated with goodwill at CES;

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

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

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

•	The decrease in revenue at CES was primarily due to lower contract sales volumes at lower prices and lower capacity revenues, partially offset by an increase in wholesale sales.

•	The decrease in revenue at Regulated Distribution primarily resulted from lower weather-related usage and higher customer shopping partially offset by new rates implemented in January 2017.

•	The increase in revenue at Regulated Transmission resulted from a higher rate base at ATSI, JCP&L and TrAIL as well as recovery of incremental operating expenses.

•	Fuel expense decreased $195 million, primarily due to the absence of approximately $58 million in settlement and termination costs on coal contracts in 2016 and lower generation associated with outages and economic dispatch of fossil units resulting from low wholesale spot market energy prices.

•	Purchased power decreased $533 million, primarily at CES, due to lower capacity expense as a result of lower contract sales and lower unit costs. At Regulated Distribution, the decline in purchased power was the result of lower volumes from increased customer shopping and lower weather-related usage as well as lower default service auction prices.

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Other operating expenses increased $206 million, reflecting an increase of $117 million at CES, primarily associated with estimated losses on long-term coal transportation contract disputes recognized in the first quarter of 2017 and higher non-cash mark-to-market losses on commodity contract positions. Operating expenses increased $31 million at Regulated Distribution resulting primarily from higher operating and maintenance expenses, including increased storm restoration costs.

•	Depreciation expense decreased $129 million, primarily due to a lower asset base at CES resulting from asset impairments recognized in 2016.

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•	Fuel expense decreased $30 million in the third quarter of 2017, as compared to the same period in 2016, primarily related to lower unit costs.

•	Purchased power costs were $105 million lower in the third quarter of 2017, as compared to the same period in 2016, primarily due to lower default service auction prices as well as decreased volumes resulting from increased customer shopping and lower weather-related usage, as described above.

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•	Depreciation expense increased $14 million primarily due to a higher asset base as well as increased rates in Pennsylvania.

•	Amortization expense decreased $13 million primarily due to lower amortization of transition costs and non-utility generation costs, partially offset by lower deferral of storm costs.

(1)	Revenues in 2016 represent transmission revenues under stated rates at ME and PN.

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•	Fuel costs decreased $57 million, primarily due to lower generation associated with outages and economic dispatch of fossil units resulting from low wholesale spot market energy prices, as described above.

•	Purchased power costs decreased $37 million due to lower capacity expense ($20 million) and lower unit costs ($25 million), partially offset by higher volumes ($8 million). The decrease in capacity expense, which is a component of CES' retail price, was primarily the result of lower contract sales.

•	Transmission expenses decreased $25 million, primarily due to lower contract sales volumes.

•	Other operating expenses decreased $18 million, primarily due to the absence of a termination charge associated with an FES Governmental Aggregation customer contract, partially offset by higher non-cash mark-to-market losses on commodity contract positions.

•	Depreciation expense decreased $49 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 $16 million, primarily due to lower property taxes and reduced gross receipts taxes associated with lower retail sales volumes.

•	Impairment of assets were $18 million in the third quarter of 2017, primarily resulting from adjustments pursuant to the terms of the amended and restated asset purchase agreement between AE Supply, AGC, BU Energy and a subsidiary of LS Power as further discussed under "Outlook - Asset Impairment - Competitive Generation Asset Sale" below.

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•	Fuel expense decreased $48 million in the first nine months of 2017, as compared to the same period in 2016, primarily related to lower unit costs.

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Purchased power costs decreased $282 million during the first nine months of 2017, as compared to the same period of 2016, primarily due to decreased volumes resulting from increased customer shopping and lower weather-related usage, as described above, as well as lower default service auction prices. These lower costs were partially offset by recovery of previously deferred energy and fuel costs.

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•	Other operating expenses increased $31 million primarily due to:

•	Higher network transmission expenses of $14 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 $68 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.

•	Lower regulatory costs of $51 million resulting from the recognition in 2016 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.

•	Depreciation expense increased $36 million primarily due to a higher rate base as well as increased rates in Pennsylvania.

•	Amortization expense decreased $14 million primarily due to lower amortization of transition costs and non-utility generation costs, as well as higher deferral of storm restoration costs, partially offset by a lower deferral of transmission costs in Ohio.

(1)	Revenues in 2016 represent transmission revenues under stated rates at ME and PN.

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•	Fuel costs decreased $147 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 described above, partially offset by higher unit costs.

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Purchased power costs decreased $332 million, primarily due to lower capacity expenses ($254 million) and lower unit costs ($91 million), partially offset by higher volumes ($13 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.

•	A $164 million charge associated with estimated losses on long-term coal transportation contract disputes was recognized in the first quarter of 2017, as discussed in "Outlook - Environmental Matters" below.

•	Fossil operating and maintenance expenses decreased $42 million, primarily due to lower outage costs and the absence of plant demolition costs recognized in 2016.

•	Nuclear operating and maintenance expenses increased $18 million, primarily as a result of higher refueling outage costs, partially offset by lower non-outage maintenance costs. There were two refueling outages during the first nine months of 2017, as compared to one refueling outage during the same period of 2016.

•	Transmission expenses decreased $51 million, primarily due to lower contract sales volumes.

•	Other operating expenses increased $28 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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•	Depreciation expense decreased $197 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 $27 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 decreased $1,298 million primarily due to the absence of an $800 million impairment of goodwill and a $647 million impairment of Units 1-4 of the W.H. Sammis generating station and the Bay Shore Unit 1 generating station in 2016, partially offset by impairment charges recognized in 2017 resulting from the amended and restated asset purchase agreement between AE Supply, AGC, BU Energy and a subsidiary of LS Power as further discussed under "Outlook - Asset Impairment - Competitive Generation Asset Sale" below.

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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, TrAIL and MAIT.

(3)	As disclosed in "Long-term Debt Capacity" below, debt capacity is subject to the consolidated debt to total capitalization limits of each borrower as defined under each of the Facilities. As of September 30, 2017, FE and its subsidiaries could issue additional debt of approximately $4.8 billion and remain within the limitations of the financial covenants required by the FE Facility.

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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 $297 million contribution to the qualified pension plan in 2016;

•	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 retail sales at CES.

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•	a decrease of $259 million at CES, resulting from lower capital investments associated with outages, MATS compliance and the Mansfield dewatering facility,

•	a decrease of $107 million at Regulated Transmission due to timing of capital investments associated with its Energizing the Future investment program; partially offset by,

•	an increase of $45 million at Regulated Distribution due to an increase in storm restoration work and smart meter investments in Pennsylvania.

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

(2)	CES-related portion is $143 million, including $56 million and $87 million at FES and FENOC, respectively.

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

(4)	Includes guarantees of $1 million for railcar leases and $3 million for various leases.

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

(6)	FE provides credit support for $169 million of FG surety bonds for the benefit of the PA DEP with respect to LBR. As of September 30, 2017, an additional $31 million of surety credit support remains available to FES from FE under this facility.

(7)	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 $(92) 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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•	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

•	additional asset sales and/or plant deactivations.

•	The outcome of efforts related to the NOPR released by the Secretary of Energy and action by FERC to address critical issues central to protecting the long-term reliability and resiliency of the electric grid provided by traditional baseload resources, such as coal and nuclear generation;

•	The resolution of legislation before the Ohio General Assembly that would create a zero-emission nuclear (ZEN) program that would provide compensation to nuclear power plants for their fuel diversity, environmental and other benefits and the potential for similar legislative action in Pennsylvania; and/or

•	The inability to finalize and consummate a settlement agreement with BNSF and NS regarding a previously disclosed long-term coal transportation contract dispute as discussed in "Outlook - Environmental Matters" above, whereby FG could be subject to materially higher damages.

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•	A $164 million charge associated with estimated losses on long-term coal transportation contract disputes was recognized in the first quarter of 2017, as discussed in "Outlook - Environmental Matters" above.

•	Fossil operating and maintenance expenses decreased $33 million, primarily due to lower outage costs and the absence of plant demolition costs recognized in 2016.

•	Nuclear operating and maintenance expenses increased $18 million, primarily as a result of higher refueling outage costs, partially offset by lower non-outage maintenance costs. There were two refueling outages during the first nine months of 2017, as compared to one refueling outage during the same period of 2016.

•	Transmission expenses decreased $49 million, primarily due to lower contract sales volumes.

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•	Other operating expenses increased $70 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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(1)	Primarily represents contracts based on broker and ICE quotes.

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ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4.	CONTROLS AND PROCEDURES

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(1)

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

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

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