On September 28, 2017, the Secretary of Energy released a NOPR requesting FERC to issue rules directing RTOs, including PJM, to incorporate pricing for defined “eligible grid reliability and resiliency resources” into wholesale energy markets. FERC established a docket requesting comments, and issued an order on January 8, 2018 terminating the NOPR proceeding, finding that the NOPR did not satisfy the statutory threshold requirements under the FPA for requiring changes to RTO/ISO tariffs to address resilience concerns. FERC in its order instituted a new administrative proceeding to gather additional information regarding resilience issues, and on March 9, 2018, each RTO/ISO responded to a provided list of questions. In the event FERC orders resiliency payments in wholesale energy markets, such charges may be levied against LSEs in the PJM Region, including the Utilities. There is no deadline or requirement for FERC to act in this new proceeding and as such the outcome of the proceeding and its impact on the Utilities, if any, cannot be predicted at this time.

PJM Markets: Capacity Pricing Reform

On April 10, 2018, as amended on April 16, 2018, PJM filed with FERC two alternative proposals to modify the PJM Tariff to address concerns that state-authorized subsidies to certain generators within PJM may affect market prices. Under one approach, PJM would establish a two-stage capacity auction to enable subsidized generators to participate in the auction, but to prevent the subsidies from affecting the market clearing price. Under the alternative approach, the MOPR would be expanded to cover all generators in PJM, including vertically-integrated utility generation owners such as MP and JCP&L. PJM requested FERC action on the filing by June 29, 2018, and to make the proposed tariff revisions effective as of January 4, 2019. Comments on PJM’s proposals are due May 1, 2018. The outcome of the proceeding and its impact on MP and JCP&L, if any, cannot be predicted at this time.

ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Pursuant to a March 28, 2017 executive order, the EPA and other federal agencies are to review existing regulations that potentially burden the development or use of domestically produced energy resources and appropriately suspend, revise or rescind those that unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof, in particular with respect to existing environmental regulations, may impact its business, results of operations, cash flows and financial condition.

Compliance with environmental regulations could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations.

Clean Air Act

FirstEnergy complies with SO₂ and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls ~~generating more electricity from lower or non-emitting plants~~ and/or using emission allowances.

CSAPR requires reductions of NOx and SO₂ emissions in two phases (2015 and 2017), ultimately capping SO₂ emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO₂ emission allowances between power plants located in the same state and interstate trading of NOx and SO₂ emission allowances with some restrictions. The ~~U.S. Court of Appeals for the~~ D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO₂ emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR, but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR update rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. On September 6, 2017, the D.C. Circuit rejected the industry's bid for a lengthy pause in the litigation and set a briefing schedule. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the EPA and the states ultimately implement CSAPR, the future cost of compliance may be material and changes to FirstEnergy's ~~and FES'~~ operations may result.

The EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of 75 PPB to 70 PPB on October 1, 2015. The EPA stated the vast majority of U.S. counties will meet the new 70 PPB standard by 2025 due to other federal and state rules and programs but the EPA will designate those counties that fail to attain the new 2015 ozone NAAQS by October 1, 2017. The EPA missed the October 1, 2017, deadline and has not yet promulgated the attainment designations. States will then have roughly three years to develop implementation plans to attain the new 2015 ozone NAAQS. On December 5, 2017, fourteen states and the District of Columbia filed complaints in the U.S. District Court of Northern California seeking an order that the EPA promulgate the attainment designations for the new 2015 ozone NAAQS. Depending on how the EPA and the states implement the new 2015 ozone NAAQS, the future cost of compliance may be material and changes to FirstEnergy’s ~~and FES’~~ operations may result.

In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating facility's NOx emissions significantly contribute to Delaware's inability to attain the ozone NAAQS. The petition seeks a short-term NOx emission rate limit of 0.125 lb/mmBTU over an averaging period of no more than 24 hours. On September27, 2016, the EPA extended the time frame for acting on the State of Delaware's CAA Section 126 petition by six months to April7, 2017, but has not taken any further action. On January 2, 2018, the State of Delaware provided the EPA a notice required at least 60 days prior to filing a suit seeking to compel the EPA to either approve or deny the August 2016 CAA Section 126 petition.In November 2016, the State of Maryland filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3 ~~Mansfield Unit 1~~ and Pleasants Units 1 and 2, significantly contribute to Maryland's inability to attain the ozone NAAQS. The petition seeks NOx emission rate limits for the 36 EGUs by May1, 2017. On January3, 2017, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to July15, 2017, but has not taken any further action. On September 27, 2017, and October 4, 2017, the State of Maryland and various environmental organizations filed complaints in the U.S. District Court for the District of Maryland seeking an order that the EPA either approve or deny the CAA Section 126 petition of November 16, 2016. In March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including Ohio, Pennsylvania and West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition seeks suitable emission rate limits for large stationary sources that are affecting New York’s air quality within the three years allowed by CAA Section 126. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss.

MATS imposed emission limits for mercury, PM, and HCl for all existing and new fossil fuel fired ~~electric generating units~~EGUs effective in April 2015 with averaging of emissions from multiple units located at a single plant. The majority of FirstEnergy's MATS compliance program and related costs have been completed.

On August 3, 2015, FG, a wholly owned subsidiary of FES, submitted to the AAA office in New York, N.Y., a demand for arbitration and statement of claim against BNSF and CSX seeking a declaration that MATS constituted a force majeure event that excuses FG’s performance under its coal transportation contract with these parties. Specifically, the dispute arose from a contract for the transportation by BNSF and CSX of a minimum of 3.5 million tons of coal annually through 2025 to certain coal-fired power plants owned by FG that are located in Ohio. As a result of and in compliance with MATS, all plants covered by this contract were deactivated by April 16, 2015. Separately, on August 4, 2015, BNSF and CSX submitted to the AAA office in Washington, D.C., a demand for arbitration and statement of claim against FG alleging that FG breached the contract and that FG’s declaration of a force majeure under the contract is not valid and seeking damages under the contract through 2025. On May 31, 2016, the parties agreed to a

stipulation that if FG’s force majeure defense is determined to be wholly or partially invalid, liquidated damages are the sole remedy available to BNSF and CSX. The arbitration panel consolidated the claims and held a hearing in November and December 2016. On April 12, 2017, the arbitration panel ruled on liability in favor of BNSF and CSX. In the liability award, the panel found, among other things, that FG’s demand for declaratory judgment that force majeure excused FG’s performance was denied, that FG breached and repudiated the coal transportation contract and that the panel retains jurisdiction of claims for liquidated damages for the years 2015-2025. On May 1, 2017, FE and FG and CSX and BNSF entered into a definitive settlement agreement, which resolved all claims related to ~~this consolidated proceeding~~a coal transportation contract dispute as a result of MATS on the terms and conditions set forth below. Pursuant to the settlement agreement, FG ~~will~~agreed to pay CSX and BNSF an aggregate amount equal to $109 million, ~~which is~~ payable in three annual installments, the first of which was made on May 1, 2017. FE agreed to unconditionally and continually guarantee the settlement payments due by FG pursuant to the terms of the settlement agreement. The settlement agreement further ~~provides~~provided that in the event of the initiation of bankruptcy proceedings or failure to make timely settlement payments, the unpaid settlement amount will immediately accelerate and become due and payable in full. ~~Further,~~On April 6, 2018, FE ~~and FG, and CSX and BNSF, agreed to release, waive and discharge each other from any further obligations~~paid the remaining $72 million under the ~~claims covered by the~~ settlement agreement upon payment in full of the settlement amount. Until such time, CSX and BNSF will retain the claims covered by the settlement agreement and in the event of a bankruptcy proceeding with respect to FG, to the extent the remaining settlement payments are not paid in full by FG or FE, CSX and BNSF shall be entitled to seek damages for such claims in an amount to be determined by the arbitration panel or otherwise agreed by the parties.

On December 22, 2016, FG, a wholly owned subsidiary of FES, received a demand for arbitration and statement of claim from BNSF and NS, which are the counterparties to the coal transportation contract covering the delivery of 2.5 million tons annually through 2025, for FG’s coal-fired Bay Shore Units 2-4, deactivated on September 1, 2012, as a result of the EPA’s MATS and for FG’s W.H. Sammis generating station. The demand for arbitration was submitted to the AAA office in Washington, D.C. against FG alleging, among other things, that FG breached the agreement in 2015 and 2016 and repudiated the agreement for 2017-2025. The counterparties are seeking, among other things, damages, including lost profits through 2025, and a declaratory judgment that FG's claim of force majeure is invalid. The arbitration hearing is scheduled for June 2018. The parties have exchanged settlement proposals to resolve all claims related to this proceeding and all remaining claims. FirstEnergy and FES ~~recorded a pre-tax charge of~~$55 million in the first quarter of 2017 based on an estimated settlement. If the dispute with BNSF and NS is not settled, the amount of damages owed to BNSF and NS could be materially higher and may cause FES to seek protection under U.S. bankruptcy laws. Absent a settlement, FG intends to vigorously assert its position in this arbitration proceeding, and if it were ultimately determined that the force majeure provisions or other defenses do not excuse the delivery shortfalls, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted.Bankruptcy.

As to a specific coal supply agreement, AE Supply, the party thereto, asserted termination rights effective in 2015 as a result of MATS. In response to notification of the termination, on January15, 2015, Tunnel Ridge, LLC, the coal supplier, commenced litigation in the Court of Common Pleas of Allegheny County, Pennsylvania, alleging AE Supply did not have sufficient justification to terminate the agreement and seeking damages for the difference between the market and contract price of the coal, or lost profits plus incidental damages. On February 18, 2018, the parties reached an agreement in principle settling all claims in dispute. The agreement in principle includes, among other matters, a $93 million payment by AE Supply, filed an answer denying any liability related to the termination. On May 1, 2017, the complaint was amended to add FE, FES and FG, although not parties to the underlying contract, as defendants and to seek additional damages based on new claims of fraud, unjust enrichment, promissory estoppel and alter ego. On June 27, 2017, after oral argument, defendants' preliminary objections to the amended complaint were denied. FE, FES, FG and AE Supply believe the merits of this case are distinguishable from the rail arbitration proceedings above based on the contract terms and other elements of the case. There were approximately 5.5 million tons remaining under the contract for delivery. This matter is in the discovery phase of litigation and no trial date has been established. FE, FES, FG and AE Supply dispute the allegations and intend to vigorously defend the merits of the lawsuit. At this time, FE, FES, FG and AE Supply cannot estimate the loss or range of loss regarding the ongoing litigation with respect to this agreement. Damages, if any, are yet to be determined, but an adverse outcome could be material.

~~In September 2007, AE received an NOV from the EPA alleging NSR and PSD violations under the CAA,~~ as well as ~~Pennsylvania and West Virginia state laws at~~certain coal supply commitments for Pleasants Power Station during its remaining operation by AE Supply. Certain aspects of the ~~coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania~~final settlement agreement are guaranteed by FE, including the $93 million payment. The parties executed the final settlement agreement on March 9, 2018 and the ~~coal-fired Fort Martin and Willow Island plants in West Virginia. The EPA's NOV alleges equipment replacements during maintenance outages triggered~~plaintiff dismissed the ~~pre-construction permitting requirements under the NSR and PSD programs. On June 29, 2012, January 31, 2013,~~matter with prejudice on March 27, 2013 and October 18, 2016, EPA issued CAA section 114 requests for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007. On December 12, 2014, EPA issued a CAA section 114 request for the Fort Martin coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2009. FirstEnergy intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the loss or range of loss.

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15, 2018.

Climate Change

FirstEnergy has established a goal to reduce CO₂ emissions by 90% below 2005 levels by 2045.There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.

The EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air ~~Act”~~Act,” in December 2009, concluding that concentrations of several key GHGs constitutes an "endangerment" and may be regulated as "air pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. On June23, 2014, the U.S. Supreme Court decided that CO₂ or other GHG emissions alone cannot trigger permitting requirements under the CAA, but that air emission sources that need PSD permits due to other regulated air pollutants can be required by the EPA to install GHG control technologies. The EPA released its final CPP regulations in August 2015 (which have been stayed by the U.S. Supreme Court), to reduce CO₂ emissions from existing fossil ~~fuel fired electric generating units that would require each state to develop SIPs by September 6, 2016, to meet the EPA’s state specific CO~~₂ emission rate goals. The EPA’s CPP allows states to request a two-year extension to finalize SIPs by September 6, 2018. If states fail to develop SIPs, the EPA also proposed a federal implementation plan that can be implemented by the EPA that included model emissions trading rules which states can also adopt in their SIPs.fuel-fired EGUs. The EPA also finalized separate regulations imposing CO₂ emission limits for new, modified, and reconstructed fossil fuel fired ~~electric generating units.~~EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the ~~U.S. Court of Appeals for the~~ D.C. Circuit in October 2015. On January21, 2016, a panel of the D.C. Circuit denied the motions for stay and set an expedited schedule for briefing and argument. On February9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On October16, 2017, the EPA issued a proposed rule to repeal the CPP. Depending on the outcomes of the review pursuant to the executive order, of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material.

At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020. The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide GHG emissions by 26 to 28 percent below 2005 levels by 2025, and in September 2016, joined in adopting the agreement reached on December 12, 2015, at the United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement was ratified by the requisite number of countries (i.e., at least 55 countries representing at least 55% of global GHG emissions) in October 2016 and its non-binding obligations to limit global warming to well below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO₂ emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations. ~~The CO~~₂ ~~emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO~~₂ ~~emitting gas-fired and nuclear generators.~~

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations.

The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore plant's cooling water intake channel to divert fish away from the plant's cooling water intake system. Depending on ~~the results of such studies and~~ any final action taken by the states ~~based on those studies,~~with respect to impingement and entrainment, the future capital costs of compliance with these standards may be material.

On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations phase-in as permits are renewed on a five-year cycle from 2018 to 2023. The final rule also allows plants to commit to more stringent effluent limits for wet scrubber systems based on evaporative technology and in return have until the end of 2023 to meet the more stringent limits. On April 13, 2017, the EPA granted a Petition for Reconsideration and administratively stayed (effective upon publication in the Federal Register) all deadlines in the effluent limits rule pending a new rulemaking. Also, on September 18, 2017, the EPA postponed certain compliance deadlines for two years. Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's ~~and FES'~~ operations may result.

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In October 2009, the WVDEP issued an NPDES water discharge permit for the Fort Martin plant, which imposes TDS, sulfate concentrations and other effluent limitations for heavy metals, as well as temperature limitations. Concurrent with the issuance of the Fort Martin NPDES permit, WVDEP also issued an administrative order setting deadlines for MP to meet certain of the effluent limits that were effective immediately under the terms of the NPDES permit. MP appealed, and a stay of certain conditions of the NPDES permit and order have been granted pending a final decision on the appeal and subject to WVDEP moving to dissolve the stay. The Fort Martin NPDES permit could require an initial capital investment ranging from $150 million to $300 million in order to install technology to meet the TDS and sulfate limits, which technology may also meet certain of the other effluent limits. Additional technology may be needed to meet certain other limits in the Fort Martin NPDES permit. MP intends to vigorously pursue these issues but cannot predict the outcome of the appeal or estimate the possible loss or range of loss.

FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the loss or range of loss.

Regulation of Waste Disposal

Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain ~~coal combustion residuals,~~CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation.

In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards ~~regarding~~for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing ~~of spend~~ had no significant impact on FirstEnergy's ~~or FES'~~ existing AROs associated with CCRs. Although not currently expected, ~~any~~ changes in timing and closure plan requirements in the future ~~including changes resulting from the strategic review at CES,~~ could materially and adversely impact FirstEnergy's ~~and FES'~~ AROs.

Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit for the Little Blue Run CCR impoundment requiring the Bruce Mansfield plant to cease disposal of CCRs by December 31, 2016, and FG to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizing FG to seek a permit modification based on "unexpected site conditions that have or will slow closure progress." The permit does not require active dewatering of the CCRs,

but does require a groundwater assessment for arsenic and abatement if certain conditions in the permit are met. The CCRs from the Bruce Mansfield plant are being beneficially reused with the majority used for reclamation of a site owned by the Marshall County Coal Company in Moundsville, W. Va., and the remainder recycled into drywall by National Gypsum. These beneficial reuse options ~~should~~are expected to be sufficient for ongoing plant operations, however, the Bruce Mansfield plant is pursuing other options. On May 22, 2015 and September 21, 2015, the PA DEP reissued a permit for the Hatfield's Ferry CCR disposal facility and then modified that permit to allow disposal of Bruce Mansfield plant CCR. ~~On September 14, 2017, the~~The Sierra Club's Notices of Appeal before the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit for the Hatfield’s Ferry CCR disposal facility were resolved through a Consent Adjudication between FG, PA DEP and the Sierra Club requiring operational changes ~~which is subject~~that became effective November 3, 2017. As noted above, FE provides credit support for FG surety bonds of $169 million and $31 million for the benefit of the PA DEP with respect to ~~a thirty-day comment period with final approval expected in November 2017~~.LBR and the Hatfield's Ferry disposal site, respectively.

FirstEnergy or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of ~~September 30, 2017~~March 31, 2018, based on estimates of the total costs of cleanup, ~~FE's and its subsidiaries'~~FirstEnergy's proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately ~~$131~~$125 million have been accrued through ~~September 30, 2017.~~March 31, 2018. Included in the total are accrued liabilities of approximately ~~$84~~$85 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. ~~FirstEnergy~~FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.

OTHER LEGAL PROCEEDINGS

Nuclear Plant Matters

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its retired nuclear ~~facilities.~~facility, TMI-2. As of ~~September 30, 2017,~~March 31, 2018, FirstEnergy had approximately ~~$2.6~~$0.8 billion~~(FES $1.8 billion)~~ invested in external trusts to be used for the decommissioning and environmental remediation of its retired TMI-2 nuclear generating ~~facilities.~~facility. The values of FirstEnergy's NDTs also fluctuate based on market conditions. If the ~~value~~values of the trusts decline by a material amount, FirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs.

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FES Bankruptcy

~~As part of routine inspections~~On March 31, 2018, FES, including its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage L.L.C. and FirstEnergy Generation Mansfield Unit 1 Corp, and FENOC filed voluntary petitions for bankruptcy protection under Chapter 11 of the concrete shield building at Davis-Besse in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 2011. These inspections revealed that the cracking condition had propagated a small amount in select areas. FENOC's analysis confirms that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions. In a May 28, 2015, Inspection Report regarding the apparent cause evaluation on crack propagation, the NRC issued a non-cited violation for FENOC’s failure to request and obtain a license amendment for its method of evaluating the significance of the shield building cracking. The NRC also concluded that the shield building remained capable of performing its design safety functions despite the identified laminar cracking and that this issue was of very low safety significance. FENOC plans to submit a license amendment application to the NRC related to the laminar crackingUnited States Bankruptcy Code in the ~~Shield Building.~~

On March 12, 2012, the NRC issued orders requiring safety enhancements at U.S. reactors based on recommendations from the lessons learned Task Force review of the accident at Japan's Fukushima Daiichi nuclear power plant. These orders requireBankruptcy Court. See Note 3, "Discontinued Operations," for additional mitigation strategies for beyond-design-basis external events, and enhanced equipment for monitoring water levels in spent fuel pools. The NRC also requested that licensees including FENOC: re-analyze earthquake and flooding risks using the latest information available; conduct earthquake and flooding hazard walkdowns at their nuclear plants; assess the ability of current communications systems and equipment to perform under a prolonged loss of onsite and offsite electrical power; and assess plant staffing levels needed to fill emergency positions. Although a majority of the necessary modifications and evaluations at FirstEnergy’s nuclear facilities have been completed, some still remain subject to regulatory review or approval.

FES provides a parental support agreement to NG of up to $400 million. The NRC typically relies on such parental support agreements to provide additional assurance that U.S. merchant nuclear plants, including NG's nuclear units, have the necessary financial resources to maintain safe operations, particularly in the event of extraordinary circumstances. So long as FES remains in the unregulated companies’ money pool, the $500 million secured line of credit with FE discussed in Note 1, "Organization and Basis of Presentation - Going Concern at FES" above provides FES the needed liquidity in order for FES to satisfy its nuclear support obligations to NG.information.

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against ~~FirstEnergy and~~FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to ~~FirstEnergy~~FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note ~~10,~~13, "Regulatory ~~Matters" of the Combined Notes to Consolidated Financial Statements.~~Matters."

FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that ~~FirstEnergy~~FE or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on ~~FirstEnergy's~~FE's or its subsidiaries' financial condition, results of operations and cash flows.

~~ASSET IMPAIRMENT~~

~~Competitive Generation Asset Sale~~

FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset purchase agreement (which was subsequently amended and restated as described below) to sell four of AE Supply’s natural gas generating plants and approximately 59% of AGC’s interest in the Bath County pumped hydro facility (1,572 MWs of combined capacity) to a subsidiary of LS Power for an all-cash purchase price of $925 million, subject to customary and other closing conditions, including receipt of regulatory approvals from FERC and the VSCC, as applicable, and various third-party consents. On February 17, 2017, AE Supply and AGC submitted a filing with FERC and on June 13, 2017, FERC issued an order authorizing such transaction as described in the January 2017 asset purchase agreement. On September 29, 2017, the parties filed a request with FERC for authorization to transfer the related hydroelectric license for Bath County under Part I of the FPA. Additional filings have been submitted to FERC for the purpose of amending affected FERC-jurisdictional rates and implementing the transaction once all regulatory approvals are obtained. Additionally, the consent of VEPCO is needed for the sale of AGC’s interest in the Bath County pumped hydro facility, as well as agreement among AGC, LS Power and VEPCO with respect to certain amendments to the Bath County project agreements.

On August 30, 2017, the parties, along with AE Supply's subsidiary BU Energy, executed an amended and restated asset purchase agreement to (1) reduce the purchase price to $825 million, subject to adjustments, (2) add BU Energy’s 50% interest in a joint venture that owns the Buchanan Generating Facility (43 MWs) to the transaction and (3) provide that each component of the transaction (~~i.e.~~, the AE Supply natural gas facilities, AGC’s interest in the Bath County hydroelectric power station and BU Energy’s interest in the Buchanan Generating Facility) may close independently. The sale of the AE Supply natural gas generating plants is expected to close in the fourth quarter of 2017 and the sale of approximately 59% of AGC’s interests in the Bath County hydroelectric power station and BU Energy’s 50% interest in the Buchanan Generating Facility are expected to close in the first quarter of 2018, subject in each case to various customary and other closing conditions including, without limitation, receipt of regulatory approvals and third-party consents, including the consent of VEPCO as discussed above. Under the amended and restated purchase agreement, AE Supply has agreed to satisfy and discharge all of its approximately $305 million of currently outstanding senior

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notes, which is expected to require the payment of a “make-whole” premium currently estimated to be approximately $100 million based on current interest rates, upon both (i) the consummation of the sale of the natural gas generating plants and (ii) either (a) the consummation of the sale of approximately 59% of AGC's interest in the Bath County hydroelectric power station or (b) the consummation of the pending sale of the Pleasants Power Station by AE Supply to its affiliate, MP. As a further condition to closing, FE will provide the purchaser two limited three-year guarantees of certain obligations of AE Supply and AGC arising under the amended and restated purchase agreement. On September 29, 2017, the parties filed an application with FERC for authorization to complete the Buchanan Generating Facility sale. On October 20, 2017, the parties filed an application with the VSCC for approval of the sale of approximately 59% of AGC's interest in the Bath County hydroelectric power station. There can be no assurance that all regulatory approvals will be obtained and/or all closing conditions will be satisfied or that any of the transactions will be consummated.

~~As a result of the amended asset purchase agreement, CES recorded non-cash pre-tax impairment charges of $158 million in the nine-month period ended September 30, 2017.~~

NEW ACCOUNTING PRONOUNCEMENTS

Recently Adopted Pronouncements

ASU ~~2016-09, "Improvements~~2014-09, "Revenue from Contracts with Customers" (Issued May 2014 and subsequently updated to ~~Employee Share-Based Payment Accounting" (Issued March 2016)~~address implementation questions): ~~ASU 2016-09 simplifies several aspects of the accounting for employee share-based payments.~~ The new revenue recognition guidance ~~requires all income tax effects of awards~~establishes a new control-based revenue recognition model, changes the basis for deciding when revenue is recognized over time or at a point in time, provides new and more detailed guidance on specific topics and expands and improves disclosures about revenue. FirstEnergy evaluated its revenues and the new guidance had immaterial impacts to be recognized in the income statement when the awards vest or are settled. It also does not require liability accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. FirstEnergy adopted ASU 2016-09recognition practices upon adoption on January 1, ~~2017. Upon~~2018. As part of the adoption, FirstEnergy elected to ~~account for forfeitures as they occur. The change was applied~~apply the new guidance on a modified retrospective ~~basis~~basis. FirstEnergy did not record a cumulative effect adjustment to retained earnings for initially applying the new guidance as no revenue recognition differences were identified in the timing or amount of revenue. In

addition, upon adoption, certain immaterial financial statement presentation changes were implemented. See Note 2, " Revenue," for additional information on FirstEnergy revenues.

ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities" (Issued January 2016 and subsequently updated in 2018): ASU 2016-01 primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. FirstEnergy adopted this standard on January 1, 2018, and recognizes all gains and losses for equity securities in income with the exception of those that are accounted for under the equity method of accounting. The NDT equity portfolios of JCP&L, ME and PN will not be impacted as unrealized gains and losses will continue to be offset against regulatory assets or liabilities. As a result of adopting this standard, FirstEnergy recorded a cumulative effect adjustment to retained earnings of ~~approximately $6~~$115 million (pre-tax) on January 1, 2018, representing unrealized gains on equity securities with FES NDTs that were previously recorded to AOCI. Following deconsolidation of FES and FENOC, the adoption of this standard is not expected to have a material impact on FirstEnergy's financial statements as the majority of its equity securities are offset against a regulatory asset or liability.

ASU 2016-18, "Restricted Cash" (Issued November 2016): ASU 2016-18 addresses the presentation of changes in restricted cash and restricted cash equivalents in the statement of cash flows. The guidance is required to be applied retrospectively. As a result of adopting this standard, FirstEnergy's statement of cash flows report changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents. Prior periods have been recasted to conform to the current year presentation.

ASU 2017-01, "Business Combinations: Clarifying the Definition of a Business" (Issued January 2017): ASU 2017-01 assists entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. FirstEnergy adopted ASU 2017-01 on January 1, 2018. The ASU will be applied prospectively to future transactions.

ASU 2017-04, "Goodwill Impairment" (Issued January 2017): Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. FirstEnergy has elected to early adopt ASU 2017-04 as of January 1, ~~2017. Additionally, FirstEnergy~~2018, and will apply this standard on a prospective basis.

ASU 2017-07, "Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost" (Issued March 2017): ASU 2017-07 requires entities to retrospectively ~~applied~~(1) disaggregate the ~~cash flow presentation requirement to~~current-service-cost component from the other components of net benefit cost (the “other components”) and present cash paid to tax authorities when shares are withheld to satisfy statutory tax withholding obligations as financing activities by reclassifying $12 million from operating activities to financing activitiesit with other current compensation costs for related employees in the ~~2016 Consolidated Statement~~income statement and (2) present the other components elsewhere in the income statement and outside of ~~Cash Flow.~~income from operations if such a subtotal is presented. In addition, only service costs are eligible for capitalization on a prospective basis. FirstEnergy adopted ASU 2017-07 on January 1, 2018. Because the non-service cost components of net benefit cost are no longer eligible for capitalization after December 31, 2017, FirstEnergy has recognized these components in income as a result of adopting this standard. FirstEnergy reclassified approximately $8 million of non-service costs from Other operating expense to Miscellaneous income for the three months ended March 31, 2017.

ASU ~~2016-15, "Classification~~2018-02, "Reclassification of Certain ~~Cash Receipts and Cash Payments"~~Tax Effects from Accumulated Other Comprehensive Income" (Issued ~~August 2016)~~February 2018): ~~The standard is intended~~ ASU 2018-02 allows entities to ~~eliminate diversity in practice in how certain cash receipts and cash payments are presented and classified in~~reclassify from AOCI to retained earnings stranded tax effects resulting from the Consolidated Statements of Cash Flows, including the presentation of debt prepayment or debt extinguishment costs, all of which will be classified as financing activities. ASU 2016-15 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017.Tax Act. FirstEnergy early adopted this standard during the first quarter of 2018 and has elected to present the change in the period of adoption. Upon adoption, FirstEnergy recorded a $22 million cumulative effect adjustment for stranded tax effects, such as pension and OPEB prior service costs and losses on derivative hedges, to retained earnings on January 1, 2018, of which $8 million was related to FES and FENOC.

ASU 2018-05, "Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118" (Issued March 2018): ASU 2018-05, effective 2018, expands income tax accounting and disclosure guidance to include SAB 118 issued by the SEC in December 2017. SAB 118 provides guidance on accounting for the income tax effects of the Tax Act and among other things allows for a measurement period not to exceed one year for companies to finalize the provisional amounts recorded as of ~~January 1,~~December 31, 2017. ~~There was no impact to prior periods.~~See Note 7, "Income taxes," for additional information on FirstEnergy's accounting for the Tax Act.

Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below or in the ~~2016~~2017 Annual Report on Form 10-K based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting. Below is an update to the discussion of pronouncements contained in the ~~2016~~2017 Annual Report on Form 10-K.

ASU ~~2014-09, "Revenue from Contracts with Customers" (Issued May 2014 and subsequently updated to address implementation questions):~~2016-02, For public business entities, the new revenue recognition guidance will be effective for annual and interim reporting periods beginning after December 15, 2017. FirstEnergy will not early adopt the standard. FirstEnergy has evaluated its revenues and expects limited impacts to current revenue recognition practices. FirstEnergy expects to apply the new guidance on a modified retrospective basis and continues to assess the impact on its financial statements and disclosures.

~~ASU 2016-02,~~"Leases (Topic 842)" ~~(Issued~~(Issued February 2016)and ASU 2018-01,"Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842" (Issued January 2018): ASU 2016-02 will require organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets. In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash flows arising

from leases will be required. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. ASU 2018-01 (same effective date and transition requirements as ASU 2016-02) provides an optional transition practical expedient that, if elected, would not require an entity to reconsider its accounting for existing land easements that are not currently accounted for under the old leases standard. FirstEnergy does not plan to adopt these standards early. Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment.

~~ASU 2017-01, "Business Combinations: Clarifying~~ FirstEnergy expects an increase in assets and liabilities; however, it is currently assessing the ~~Definition~~impact on its Consolidated Financial Statements, including monitoring utility industry implementation guidance. FirstEnergy is in the process of developing a ~~Business" (Issued January 2017): ASU 2017-01 assists entities~~complete lease inventory, as well as identifying, assessing and documenting technical accounting issues, policy considerations and financial reporting implications. In addition, FirstEnergy is implementing a third-party software tool that will assist with ~~evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is effective for fiscal years,~~the initial adoption and for interim periods within those fiscal years, beginning after December 15, 2017. The ASU will be applied prospectively to any transactions occurring within the period of adoption. Early adoption is permitted, including for interim or annual periods in which the financial statements have not been issued or made available for issuance.

~~ASU 2017-07, "Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost" (Issued March 2017):~~ ASU 2017-07 requires entities to retrospectively (1) disaggregate the current-service-cost component from the other components of net benefit cost (the “other components”) and present it with other currentongoing compliance.

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compensation costs for related employees in the income statement and (2) present the other components elsewhere in the income statement and outside of income from operations if such a subtotal is presented. In addition, only service costs are eligible for capitalization on a prospective basis. Because the non-service cost components of net benefit cost will no longer be eligible for capitalization after December 31, 2017, FirstEnergy will recognize these components in income as a result of adopting the standard. FirstEnergy is currently evaluating presentation of the Statement of Income and the impact on disclosures as a result of adopting ASU 2017-07. The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years.

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~~FIRSTENERGY SOLUTIONS CORP.~~

~~MANAGEMENT’S NARRATIVE~~

~~ANALYSIS OF RESULTS OF OPERATIONS~~

FES, a subsidiary of FE, was organized under the laws of the State of Ohio in 1997. FES provides energy-related products and services to retail and wholesale customers. FES also owns and operates, through its FG subsidiary, fossil generating facilities and owns, through its NG subsidiary, nuclear generating facilities, which are operated by FENOC. FES purchases the entire output of the generation facilities owned by FG and NG. Prior to April 1, 2016, FES financially purchased the uncommitted output of AE Supply's generation facilities under a PSA. On December 21, 2015, FES agreed, under a PSA, to physically purchase all the output of AE Supply's generation facilities effective April 1, 2016. FES and AE Supply terminated the PSA effective April 1, 2017.

FES' revenues are derived primarily from sales to individual retail customers, sales to customers in the form of governmental aggregation programs, and participation in affiliated and non-affiliated POLR auctions. FES' sales are primarily concentrated in Ohio, Pennsylvania, Illinois, Michigan, New Jersey, and Maryland. The demand for electricity produced and sold by FES, along with the price of that electricity, is principally impacted by conditions in competitive power markets, global economic activity as well as economic activity and weather conditions in the Midwest and Mid-Atlantic regions of the United States.

FES is exposed to various market and financial risks, including the risk of price fluctuations in the wholesale power markets. Wholesale power prices may be impacted by the prices of other commodities, including coal and natural gas, and energy efficiency and DR programs, as well as regulatory and legislative actions, such as MATS among other factors. FES attempts to mitigate the market risk inherent in its energy position by economically hedging its exposure and continuously monitoring various risk measurement metrics to ensure compliance with its risk management policies.

Today, FES' competitive generation portfolio is comprised of more than 10,000 MWs of generation, primarily from coal, nuclear and natural gas and oil fuel sources. The assets generate approximately 60-65 million MWHs annually, with up to an additional five million MWHs available from purchased power agreements for wind, solar, and FES' entitlement in OVEC.

Over the past several years, FES has been impacted by a decrease in demand and excess generation supply in the PJM Region, which has resulted in low power and capacity prices, as well as significant environmental compliance costs. To address this, FES sold or deactivated approximately 2,700 MWs of competitive generation from 2012 to 2015 and announced in 2016 plans to exit and/or deactivate an additional 856 MWs by 2020 related to the Bay Shore Unit 1 generating station and Units 1-4 of the W.H. Sammis generating station. Additionally, FES has continued to focus on cost reductions, including those identified as part of FirstEnergy’s previously disclosed cash flow improvement plan.

However, the energy and capacity markets remain weak with significantly low capacity clearing prices and current forward pricing as well as the long-term fundamental view on energy and capacity prices. In order to focus on stable and predictable cash flow from its regulated business units, in November of 2016, FirstEnergy announced a strategic review of its competitive operations with a target to implement its exit from competitive operations by mid-2018.

~~The strategic options to exit the competitive operations are still uncertain, but could include one or more of the following:~~

~~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.~~

~~Furthermore, the implementation of various strategic options, and the timing thereof, could be impacted by various events, including, but not limited to the following:~~

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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FES continues to be managed conservatively due to the stress of weak energy prices, insufficient results from recent capacity auctions and anemic demand forecasts. Furthermore, the credit quality of FES, specifically the unsecured debt rating of Caa1 at Moody’s, CCC- at S&P and C at Fitch and a negative outlook from Moody's and S&P, has challenged its ability to hedge generation with retail and forward wholesale sales due to significant collateral requirements. As a result, FES' contract sales are expected to decline from 52 million MWHs in 2016 to 40-45 million MWHs in 2017 and to 30-35 million MWHs in 2018. While the reduced contract sales will decrease potential collateral requirements, market price volatility may significantly impact FES' financial results due to the increased exposure to the wholesale spot market.

Although FES has access to a $500 million secured line of credit with FE, all of which was available as of September 30, 2017, its current credit rating and the current forward wholesale pricing environment present significant challenges to FES. Furthermore, an inability to develop and execute upon viable alternative strategies for its competitive portfolio would continue to further stress the liquidity and financial condition of FES.

Cash flow from operations at FES is expected to be sufficient to fund capital expenditures, nuclear fuel purchases, and repay money pool borrowings through March 2018. However, as previously disclosed, FES has $515 million of maturing debt in 2018, beginning in the second quarter. Additionally, FES has $48 million of interest and lease payments in December 2017 and $38 million of interest payments in the first quarter of 2018. Based on FES' current senior unsecured debt rating, capital structure and the forecasted decline in wholesale forward market prices over the next few years, the debt maturities are likely to be difficult to refinance. Furthermore, lack of clarity regarding the timing and viability of alternative strategies, including additional asset sales or deactivations and/or converting generation from competitive operations to a regulated or regulated-like construct in a way that provides FES with the means to satisfy its obligations over the long-term, may also require FES to restructure debt and other financial obligations with its creditors and/or seek protection under U.S. bankruptcy laws. In the event FES seeks protection under U.S. bankruptcy laws, FENOC will likely seek such protection. Although management is exploring capital and other cost reductions, asset sales, and other options to improve cash flow as well as continuing with efforts to explore legislative or regulatory solutions, these obligations and their impact to liquidity raise substantial doubt about FES’ ability to meet its obligations as they come due over the next twelve months and, as such, its ability to continue as a going concern.

~~For additional information with respect to FES, please see the information contained under "Risk Factors" in Part II, Item 1A of this Form 10-Q and in "FirstEnergy~~’~~s Management~~’s Discussion and Analysis of Financial Condition and Results of Operations" under the following subheadings, which information is incorporated by reference herein: "FirstEnergy's Business," "Executive Summary," "Capital Resources and Liquidity," "Guarantees and Other Assurances," "Off-Balance Sheet Arrangements," "Market Risk Information," "Credit Risk," "New Accounting Pronouncements," and "Outlook."

~~Results of Operations~~

Operating results increased $282 million in the first nine months of 2017, compared to the same period of 2016, primarily due to the absence of asset impairment and plant exit costs recognized in 2016, as discussed below, and lower depreciation expense, partially offset by a pre-tax charge of $164 million associated with estimated losses on long-term coal transportation contract disputes, as discussed in "Outlook - Environmental Matters" above, higher non-cash mark-to-market losses on commodity contract positions and lower capacity revenue.

~~Revenues -~~

Total revenues decreased $1,003 million in the first nine months of 2017, compared to the same period of 2016, primarily due to lower contract sales volumes at lower rates, lower capacity revenues from lower capacity auction prices, and lower net gains on financially settled contracts, partially offset by an increase in short-term (net hourly position) transactions, as further described below.

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~~The change in total revenues resulted from the following sources:~~

For the Nine Months Ended September 30
Revenues by Type of Service 2017 2016 Decrease
(In millions)
Contract Sales:
Direct $ 560
$ 610
$ (50 )
Governmental Aggregation 303
666
(363 )
Mass Market 97
133
(36 )
POLR 389
447
(58 )
Structured 246
353
(107 )
Total Contract Sales 1,595
2,209
(614 )
Wholesale 710
1,015
(305 )
Transmission 30
53
(23 )
Other 63
124
(61 )
Total Revenues $ 2,398
$ 3,401
$ (1,003 )

For the Nine Months Ended September 30 Increase
MWH Sales by Channel 2017 2016 (Decrease)
(In thousands)
Contract Sales:
Direct 11,504
11,391
1.0 %
Governmental Aggregation 5,686
10,798
(47.3 )%
Mass Market 1,425
1,912
(25.5 )%
POLR 6,983
7,526
(7.2 )%
Structured 6,398
8,863
(27.8 )%
Total Contract Sales 31,996
40,490
(21.0 )%
Wholesale 11,134
8,461
31.6 %
Total MWH Sales 43,130
48,951
(11.9 )%

~~The following table summarizes the price and volume factors contributing to changes in revenues in the first nine months of 2017, compared with the same period of 2016:~~

Source of Change in Revenues
Increase (Decrease)
MWH Sales Channel: Sales Volumes Prices Gain on Settled Contracts Capacity Revenue Total
(In millions)
Direct $ 6
$ (56 ) $ —
$ —
$ (50 )
Governmental Aggregation (315 ) (48 ) —
—
(363 )
Mass Market (34 ) (2 ) —
—
(36 )
POLR (32 ) (26 ) —
—
(58 )
Structured (100 ) (7 ) —
—
(107 )
Wholesale 73
(4 ) (114 ) (260 ) (305 )

Lower sales volumes in the Governmental Aggregation channel primarily reflects the termination of an FES customer contract in 2016. The Direct, Governmental Aggregation and Mass Market customer base was approximately 842,000 as of September 30, 2017, compared to 1.4 million as of September 30, 2016. Although unit pricing in Direct, Governmental Aggregation and Mass

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~~Market was lower year-over-year, the decrease was primarily attributable to lower capacity expense as discussed below, which is a component of the retail price.~~

The decrease in POLR revenue of $58 million was primarily due to lower volumes and lower unit prices. Structured revenue decreased $107 million, primarily due to the impact of lower transaction volumes.

Wholesale revenues decreased $305 million, primarily due to a decrease in capacity revenue from lower capacity auction prices and lower net gains on financially settled contracts, partially offset by an increase in short-term (net hourly position) transactions at slightly lower market prices.

~~Transmission revenue decreased $23 million, primarily due to lower congestion revenues.~~

Other revenues decreased $61 million, primarily due to lower lease revenues from the expiration of a nuclear sale-leaseback agreement. FES earned lease revenue associated with the lessor equity interests it has purchased in sale-leaseback transactions, one of which expired in June 2017 and another in May 2016.

~~Operating Expenses -~~

~~Total operating expenses decreased $1,293 million in the first nine months of 2017, compared to the same period of 2016.~~

~~The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first nine months of 2017, compared with the same period of 2016:~~

Source of Change
Increase (Decrease)
Operating Expenses Volumes Unit Costs Loss on Settled Contracts Capacity Expense Total
(In millions)
Fossil Fuel $ (88 ) $ 9
$ (58 ) $ —
$ (137 )
Nuclear Fuel 3
2
—
—
5
Affiliated Purchased Power (92 ) 23
(169 ) —
(238 )
Non-affiliated Purchased Power (34 ) 17
(91 ) (253 ) (361 )

Fossil and nuclear fuel costs decreased $132 million, primarily due to the absence of $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.

Affiliated purchased power costs decreased $238 million, primarily resulting from the termination of the AE Supply PSA, effective April 1, 2017, and the expiration of a nuclear sale-leaseback agreement.

Non-affiliated purchased power costs decreased $361 million due to lower capacity expenses ($253 million), reduced net losses on financially settled contracts ($91 million), and lower volumes ($34 million), partially offset by higher unit costs ($17 million). The decrease in capacity expense, which is a component of FES' retail price, was primarily the result of lower contract sales and lower capacity rates associated with FES' retail sales obligation. Lower volumes primarily resulted from lower contract sales as discussed above, partially offset by economic purchases resulting from the low wholesale spot market price environment.

~~Other operating expenses increased $170 million in the first nine months of 2017, compared to the same period of 2016, due to the following:~~

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 $49million, 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.

~~Depreciation expense decreased $170 million, primarily due to a lower asset base resulting from asset impairments recognized in 2016.~~

~~General taxes decreased $22 million, primarily due to lower property taxes and reduced gross receipts taxes associated with lower retail sales volumes.~~

Impairment of assets decreased $540 million, primarily due to the absence of an impairment of goodwill and a $517 million impairment of Units 1-4 of the W.H. Sammis generating station and the Bay Shore Unit 1 generating station recognized in 2016.

~~Other Expense —~~

~~Total other expense decreased $11 million in the first nine months of 2017, as compared to the same period of 2016, primarily due to higher investment income on NDT investments.~~

~~Income Tax Benefits —~~

FES' effective tax rate for the nine months ended September 30, 2017 and 2016 was 48.3% on pre-tax income and 1.8% on pre-tax losses, respectively. The change in the effective tax rate was primarily due to a $65 million of valuation allowance recognized in 2016 against state and local NOL carryforwards and the impairment of goodwill also recognized in 2016, of which $23 million was non-deductible for tax purposes.

~~Changes in Cash Position~~

FES expects to rely on its current access to the unregulated companies' money pool and a two-year secured line of credit from FE of up to $500 million, as further described above. Additionally, FES subsidiaries have debt maturities of $515 million in 2018, beginning in the second quarter. The inability to refinance the debt maturities could cause FES to take one or more of the following actions: (i) restructuring of debt and other financial obligations, (ii) additional borrowings under its credit facility with FE, (iii) further asset sales or plant deactivations, and/or (iv) seeking protection under U.S. bankruptcy laws. In the event FES seeks such protection, FENOC will likely seek protection under U.S. bankruptcy laws.

FES continues to be managed conservatively due to the stress of weak power prices, insufficient proceeds from recent capacity auctions and anemic demand forecasts that have lowered the value of the business. Furthermore, the credit quality of FES, specifically its unsecured debt rating of Caa1 at Moody’s, CCC- at S&P and C at Fitch and a negative outlook from Moody's and S&P, has challenged its ability to hedge generation with retail and forward wholesale sales without collateral obligations, which reduce the business units available liquidity. A lack of viable alternative strategies for its competitive portfolio would continue to further stress the liquidity and financial condition of FES.

As discussed above, FES currently maintains access to the unregulated companies' money pool in lieu of borrowing under its $500 million secured line of credit. FE expects to provide ongoing access to FES to the unregulated companies' money pool to allow time to evaluate its strategic alternatives including, among other things, the results of legislative and regulatory solutions, including the NOPR released by the Secretary of Energy and action by FERC. As of September 30, 2017, FES, and its subsidiaries, and FENOC had $67 million of net borrowings in the aggregate under the unregulated companies' money pool. Cash flow from operations at FES is expected to be sufficient to fund capital expenditures, nuclear fuel purchases, and repay money pool borrowings through March 2018.

~~Cash Flows From Operating Activities~~

FES' most significant sources of cash are derived from electric service provided by the sales of energy and related products and services. The most significant use of cash from operating activities is to buy electricity in the wholesale market and pay fuel suppliers, employees, tax authorities, lenders, and others for a wide range of material and services.

Net cash provided from operating activities was $458 million during the first nine months of 2017 compared with $605 million provided from operating activities during the first nine months of 2016. Cash flows from operations decreased $147 million in the first nine months of 2017, compared with the same period of 2016 primarily due to lower receipts from a decrease in capacity revenues and retail sales, as discussed above in "Results of Operations" and timing of working capital.

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~~Cash Flows From Financing Activities~~

For the first nine months of 2017, cash used for financing activities was $83 million, compared to cash provided from financing activities of $61 million in same period of 2016. The following table summarizes new debt financing, redemptions, repayments and short-term borrowings:

For the Nine Months Ended September 30
Securities Issued or Redeemed / Repaid 2017 2016
(In millions)
New Issues
PCRBs $ —
$ 471

Redemptions / Repayments

Senior secured notes $ (5 ) $ (20 )
PCRBs (158 ) (483 )
$ (163 ) $ (503 )

Short-term borrowings, net $ 85
$ 101

~~Cash Flows From Investing Activities~~

Cash used for investing activities for the first nine months of 2017 principally represented cash used for property additions and nuclear fuel. The following table summarizes investing activities for the first nine months of 2017 and comparable period of 2016.

For the Nine Months Ended September 30
Cash Used for Investing Activities 2017 2016
(In millions)
Property Additions $ 201
$ 432
Nuclear fuel 156
195
Loans to affiliated companies, net (29 ) 15
Investments 44
43
Other 3
(19 )
$ 375
$ 666

Cash used for investing activity for the first nine months of 2017 decreased $291 million, compared to the same period of 2016, primarily due to lower property additions. Property additions decreased due to lower capital expenditures related to outages and the Mansfield dewatering facility, which was substantially completed in 2016.

~~Market Risk Information~~

FES uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.

~~Commodity Price Risk~~

FES is exposed to financial risks resulting from fluctuating commodity prices, including prices for electricity, natural gas, coal and energy transmission. FirstEnergy's Risk Management Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FES uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.

~~Sources of information for the valuation of commodity derivative assets and liabilities as of September 30, 2017 are summarized by year in the following table:~~

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Source of Information-
Fair Value by Contract Year
2017 2018 2019 2020 2021 Thereafter Total
(In millions)
Other external sources⁽¹⁾
$ 10
$ 15
$ —
$ —
$ —
$ —
$ 25
Prices based on models (2 ) —
—
—
—
—
(2 )
Total $ 8
$ 15
$ —
$ —
$ —
$ —
$ 23


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

FES performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of September 30, 2017, an increase in commodity prices of 10% would decrease net income by approximately $6 million during the next twelve months.

~~Interest Rate Risk~~

~~FES’ exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates.~~

~~Equity Price Risk~~

NDT funds have been established to satisfy NG’s nuclear decommissioning obligations. Included in NG's NDT are fixed income, equities and short-term investments carried at market values of approximately $969 million, $765 million and $96 million, respectively, as of September 30, 2017, excluding $(7) million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $76 million reduction in fair value as of September 30, 2017. NG recognizes in earnings the unrealized losses on AFS securities held in its NDT as OTTI. A decline in the value of NG's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements by NG.

~~Credit Risk~~

Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. FES evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. FES may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. FES monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.

~~Wholesale Credit Risk~~

FES measures wholesale credit risk as the replacement cost for derivatives in power, natural gas, coal and emission allowances, adjusted for amounts owed to, or due from, counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where FES has a legally enforceable right of offset. FES monitors and manages the credit risk of wholesale marketing, risk management and energy transacting operations through credit policies and procedures, which include an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such as margin, collateral and the use of master netting agreements. The majority of FES' energy contract counterparties maintain investment-grade credit ratings.

~~Retail Credit Risk~~

FES' principal retail credit risk exposure relates to its competitive electricity activities, which serve residential, commercial and industrial companies. Retail credit risk results when customers default on contractual obligations or fail to pay for service rendered. This risk represents the loss that may be incurred due to the nonpayment of customer accounts receivable balances, as well as the loss from the resale of energy previously committed to serve customers.

Retail credit risk is managed through established credit approval policies, monitoring customer exposures and the use of credit mitigation measures such as deposits in the form of LOCs, cash or prepayment arrangements.

Retail credit quality is affected by the economy and the ability of customers to manage through unfavorable economic cycles and other market changes. If the business environment were to be negatively affected by changes in economic or other market conditions, FES' retail credit risk may be adversely impacted.

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ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “First Energy Corp. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Information” ~~and "FirstEnergy Solutions Corp. Management's Narrative Analysis of Results of Operations - Market Risk Information"~~ in Item 2 above.


ITEM 4.	CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

The management of FirstEnergy, ~~and FES,~~ with the participation of ~~each registrant's principal executive officer~~the Chief Executive Officer and ~~principal financial officer,~~Chief Financial Officer, have reviewed and evaluated the effectiveness of ~~their registrant's~~its disclosure controls and procedures, as defined inunder the Securities Exchange Act of 1934, as amended, in Rules 13a-15(e) and 15d-15(e), as of the end of the period covered by this report. Based on that evaluation, the ~~principal executive officer~~Chief Executive Officer and ~~principal financial officer~~Chief Financial Officer of FirstEnergy ~~and FES~~ have concluded that ~~their respective registrant's~~its disclosure controls and procedures were effective as of the end of the period covered by this report.

(b) Changes in Internal Control over Financial Reporting

During the quarter ended ~~September 30, 2017,~~March 31, 2018, there were no changes in internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) that have materially affected, or are reasonably likely to materially affect, FirstEnergy's ~~and FES'~~ internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Note ~~10,~~13, "Regulatory Matters," and Note ~~11,~~14, "Commitments, Guarantees and Contingencies," of the ~~Combined~~ Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A. RISK FACTORS

~~You should carefully consider~~We operate in a business environment that involves significant risks, many of which are beyond our control. Management of FirstEnergy regularly evaluates the most significant risks of its businesses and reviews those risks with the Board of Directors or appropriate Committees of such Board. The following risk factors ~~discussed~~and all other information contained in ~~Part I,~~this report should be considered carefully when evaluating FirstEnergy. These risk factors could affect our financial results and cause such results to differ materially from those expressed in any forward-looking statements made by or on behalf of us. Below, we have identified risks we consider material. Additional information on risk factors is included in “Item ~~1A.~~2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and in other sections of this Form 10-Q that include forward-looking and other statements involving risks and uncertainties that could impact our business and financial results. The Risk ~~Factors”~~Factors set forth in this Quarterly Report on Form 10-Q supersede in their entirety the ~~Registrants’~~Risk Factors contained in our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2016,~~2017, filed with the SEC on February 20, 2018.

Risks Related to the FES Bankruptcy and ~~Part II, "Item 1A. Risk Factors"~~Remaining Competitive Generation

We Are Subject to Risks Relating to the FES Bankruptcy

As previously disclosed, FES and FENOC (collectively, the Filing Entities) filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code to facilitate an orderly restructuring. It is possible that as part of the restructuring process, claims may be asserted by or on behalf of the Filing Entities against non-debtor affiliates of the Filing Entities. Any assertions of claims by creditors of the Filing Entities against FirstEnergy may require significant effort, resources, and money to defend or could result in material losses to FirstEnergy. We can provide no assurance that any such claims, if asserted, will be resolved in an efficient manner or a manner that is satisfactory to FirstEnergy.

There Is Substantial Uncertainty Regarding the FES Bankruptcy, Which Could Have a Material Adverse Impact on FirstEnergy’s Business, Financial Condition, Results of Operations and Cash Flows

Management of FirstEnergy may be required to spend a significant amount of time and effort dealing with the FES Bankruptcy instead of focusing on FirstEnergy’s business operations, which could have an adverse impact on our ability to execute our business plan and operations. Additionally, FirstEnergy’s relationship with its employees, suppliers, customers and other parties may be adversely impacted by negative publicity related to the FES Bankruptcy or otherwise and FirstEnergy’s operations could be materially and adversely affected. The FES Bankruptcy also may make it more difficult to retain, attract or replace management and other key personnel.

In addition, the FES Bankruptcy creates substantial uncertainty regarding certain significant commercial and other relationships among FE, the Filing Entities and other FE subsidiaries, including, but not limited to, AE Supply. These relationships include a

shared services agreement, cash management, intercompany loans, tax sharing and energy-related purchases and sales, among others, which may be subject to review and possible challenge in the ~~Registrants' Quarterly Report~~FES Bankruptcy. FirstEnergy is unable to estimate the outcome of such challenges or other claims arising out of the FES Bankruptcy, any resulting material losses, obligations or other liabilities of FirstEnergy or their possible material adverse effect on ~~Form 10-Q for~~ the ~~quarter ended June 30, 2017, which~~business, results of operations and financial condition of FirstEnergy.

The costs of potential liabilities resulting from the FES Bankruptcy could ~~materially affect the Registrants’~~have a material and adverse impact on FirstEnergy’s business, financial condition, results of operations and cash flows.

The FES Bankruptcy Could Negatively Impact FirstEnergy’s Right to Repayment under the Intercompany Loans and Other Financial Arrangements

FE has loaned $500 million to FES, has provided additional credit support to FES of up to $200 million and has guaranteed certain material financial obligations of the Filing Entities. Additionally, AE Supply has separately loaned $102 million to FES. There can be no assurance that the loans made by FirstEnergy will be repaid or ~~future results.~~that FirstEnergy will be reimbursed for any guaranteed obligations it satisfies. Any of these matters could adversely affect the financial condition, cash flows and ability to satisfy obligations of FirstEnergy. In addition, ~~you should carefully consider~~ the ~~information set forth in this report,~~uncertainty associated with these matters could adversely affect FirstEnergy’s ability to access the capital or credit markets and ability to finance its business.

Adverse Developments Related to the Filing Entities Could Trigger Events of Default under Certain FirstEnergy Obligations

FirstEnergy's credit facilities contain various events of default, including ~~without limitation,~~with respect to the ~~updated disclosures throughout and the risk factor presented below, which update, and should be read in conjunction with, the above-referenced risk factors and information disclosed~~borrowers or significant subsidiaries (each as defined in the ~~Registrants’ documents previously filed with~~credit agreements), a bankruptcy or insolvency of FirstEnergy, the ~~SEC.~~

failure to pay any principal of or premium or interest on any indebtedness in excess of $100 million, or the failure to satisfy any judgment or order for the payment of money exceeding any applicable insurance coverage by more than $100 million. Although the Filing Entities are not “significant subsidiaries” for these purposes, it is possible that an adverse development related to the Filing Entities could otherwise trigger an event of default under the FirstEnergy credit facilities if creditors of the Filing Entities asserted successful claims against FE or our significant subsidiaries.

In the ~~event of a foreclosure, liquidation, bankruptcy or similar proceeding involving~~ FES ~~FG or NG,~~Bankruptcy, the ~~value~~Value of the Collateral Securing the Secured Indebtedness of the Filing Entities May Not Be Sufficient to Ensure Repayment of Such Indebtedness and, the Ability of Holders of Such Indebtedness, Including FE, to Realize Any Such Value May Be Delayed or Otherwise Limited

The FES Bankruptcy will affect the Filing Entities’ respective properties and assets that serve as collateral securing certain of the Filing Entities’ secured ~~indebtedness of FG and NG may not be sufficient to ensure repayment of such indebtedness and, in the case of~~indebtedness. As a ~~bankruptcy proceeding, the ability of holders of such indebtedness, including FE, to realize any such value may be delayed or otherwise limited~~

FG and NG have secured pollution control notes outstanding of $612.2 million (FG - $327.6 million of FMBs; NG - $284.6 million of FMBs) and secured obligations supporting FES’ $500 million revolving line of credit and $200 million additional credit support with FE (FG - $250 million of FMBs; NG - $450 million of FMBs). In the event of a foreclosure, liquidation, bankruptcy or similar proceeding affecting FES, FG or NG or any of their respective properties or assets,result, the value of the collateral securing such indebtedness or the net proceeds from any sale or liquidation of such collateral, as applicable, may not be sufficient to pay the obligations under such secured ~~indebtedness.~~indebtedness, including amounts owed to FE under the FES secured credit agreement. If the value of the collateral or the net proceeds of any sale of such collateral, as applicable, are not sufficient to repay all amounts due with respect to such secured indebtedness, the holders of the secured indebtedness would have an unsecured claim for the deficiency in value or proceeds against the applicable obligors alongside all other unsecured creditors of such obligor. None of ~~FG, NG or FES~~the Filing Entities can assure holders of their respective secured debt that, if a sale process were to be pursued, the collateral will be saleable or, if saleable, that there will not be substantial delays in its ~~liquidation~~sale due to, among other things, the need for regulatory authorization from the FERC, NRC or other governmental authorities, as applicable.

Additionally, ~~in the context of a bankruptcy case by or against FES, FG or NG,~~ the holders of the secured indebtedness, including FE, may not be able or entitled to receive payment of interest, fees (including attorney’s fees), costs or charges related to such secured obligations, and may be required to repay any such amounts received by such holders during the FES Bankruptcy.

Regardless of the Viability or Success of the Sale of Certain AE Supply Generation Assets, Certain Events May Significantly Increase Cash Flow and Liquidity Risks and Have a Material Adverse Effect on Results of Operations and the Financial Condition of FirstEnergy

Any developments that negatively impact the viability or success of the sale of the remaining AE Supply generation assets could have adverse consequences, including:

the risk that we may not be able to complete our planned disposition of our competitive generation assets;

the risk that FirstEnergy could be required to satisfy or otherwise elect to guarantee significant financial obligations related to such ~~bankruptcy case.~~sales, which could adversely affect the financial condition and cash flows of FirstEnergy; and

the risk that AE Supply is unable to adequately address the capacity coverage risk for shutting Pleasants Power Station down early.

Further, as part of AE Supply’s recent sale of gas generation assets to a subsidiary of LS Power, FE provided two limited three-year guarantees totaling $555 million of certain obligations of AE Supply and AGC arising under the purchase agreement. Liabilities incurred under these guarantees could have an adverse impact on the financial condition of FE.

Risks Related to Business Operations Generally

Temperature Variations as well as Weather Conditions or other Natural Disasters Could Have an Adverse Impact on Our Results of Operations and Financial Condition, and Demand Significantly Below or Above Our Forecasts Could Adversely Affect Our Energy Margins and Have an Adverse Effect on our Financial Condition and Results of Operations

Weather conditions directly influence the demand for electric power. Demand for power generally peaks during the summer and winter months, with market prices also typically peaking at that time. Overall operating results may fluctuate based on weather conditions. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Severe weather, such as tornadoes, hurricanes, ice or snowstorms, or droughts or other natural disasters, may cause outages and property damage that may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned under these conditions would be particularly burdensome during a peak demand period and could have an adverse effect on our financial condition and results of operations.

We Are Subject to Financial Performance Risks Related to Regional and General Economic Cycles and also Related to Heavy Industries such as Shale Gas, Automotive and Steel

Our business follows economic cycles. Economic conditions impact the demand for electricity and declines in the demand for electricity will reduce our revenues. The regional economy in which our Utilities operate is influenced by conditions in industries in our business territories, e.g. shale gas, automotive, chemical, steel and other heavy industries, and as these conditions change, our revenues will be impacted.

Certain FirstEnergy Companies May Not Be Able to Meet Their Obligations to or on Behalf of Other FirstEnergy Companies or Their Affiliates, Which Could Have a Material Adverse Effect on the Results of Operations, Financial Condition or Liquidity of One or More FirstEnergy Entities

Certain of the FirstEnergy companies have obligations to other FirstEnergy companies pursuant to transactions involving credit, energy, coal, services and hedging transactions. If one FirstEnergy entity failed to perform under any of these arrangements, other FirstEnergy entities could incur losses. Their results of operations, financial position, or liquidity could be adversely affected, and such non-performance could result in the non-defaulting FirstEnergy entity being unable to meet its obligations to unrelated third parties. Certain FirstEnergy companies also provide guarantees to third-party creditors on behalf of other FirstEnergy affiliate companies under transactions of the types described above, legal settlements or under financing transactions. Any failure to perform under such guarantees by such FirstEnergy guarantor company or under the underlying transaction by the FirstEnergy company on whose behalf the guarantee was issued could have similar adverse impacts on one or both FirstEnergy companies or their affiliates.

We Are Subject to Risks Arising from the Operation of Our Power Plants and Transmission and Distribution Equipment Which Could Reduce Revenues, Increase Expenses and Have a Material Adverse Effect on Our Business, Financial Condition and Results of Operations

Operation of generation, transmission and distribution facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, human error in operations or maintenance, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental requirements and governmental interventions, and performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution delivery systems. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.

Operation of our power plants below expected capacity could result in lost revenues and increased expenses, including higher operation and maintenance costs, purchased power costs and capital requirements. Unplanned outages of generating units and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses or may require us to incur significant costs as a result of operating our higher cost units or obtaining replacement power from third parties in the open market to satisfy our sales obligations. Moreover, if we were unable to perform under contractual obligations, including, but not limited to, our coal and coal transportation contracts, penalties or liability for damages could result, which could have a material adverse effect on our business, financial condition and results of operations.

Failure to Provide Safe and Reliable Service and Equipment Could Result in Serious Injury or Loss of Life That May Harm Our Business Reputation and Adversely Affect Our Operating Results

We are obligated to provide safe and reliable service and equipment in our franchised service territories. Meeting this commitment requires the expenditure of significant capital resources. However, our employees, contractors and the general public may be exposed to dangerous environments due to the nature of our operations. Failure to provide safe and reliable service and equipment

due to various factors, including equipment failure, accidents and weather, could result in serious injury or loss of life that may harm our business reputation and adversely affect our operating results through reduced revenues, increased capital and operating costs, litigation or the imposition of penalties/fines or other adverse regulatory outcomes.

Our Use of Non-Derivative and Derivative Contracts to Mitigate Risks Could Result in Financial Losses That May Negatively Impact Our Financial Results

We use a variety of non-derivative and derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of these derivative instruments involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. Also, we could recognize financial losses as a result of volatility in the market value of these contracts if a counterparty fails to perform or if there is limited liquidity of these contracts in the market.

The Outcome of Litigation, Arbitration, Mediation, and Similar Proceedings Involving Our Business, or That of One or More of Our Operating Subsidiaries, Is Unpredictable and an Adverse Decision in Any Material Proceeding Could Have a Material Adverse Effect on Our Financial Condition and Results of Operations

We are involved in a number of litigation, arbitration, mediation, and similar proceedings. These and other matters may divert financial and management resources that would otherwise be used to benefit our operations. Further, no assurances can be given that the resolution of these matters will be favorable to us. If certain matters were ultimately resolved unfavorably to us, the results of operations and financial condition of FirstEnergy could be materially adversely impacted.

In addition, we are sometimes subject to investigations and inquiries by various state and federal regulators due to the heavily regulated nature of our industry. Any material inquiry or investigation could potentially result in an adverse ruling against us, which could have a material adverse impact on our financial condition and operating results.

Capital Market Performance and Other Changes May Decrease the Value of Pension Fund Assets and Other Trust Funds, Which Could Require Significant Additional Funding and Negatively Impact Our Results of Operations and Financial Condition

Our financial statements reflect the values of the assets held in trust to satisfy our obligations to decommission our retired nuclear generating facility and under pension and other postemployment benefit plans. Certain of the assets held in these trusts do not have readily determinable market values. Changes in the estimates and assumptions inherent in the value of these assets could affect the value of the ~~collateral securing FG’s and NG’s secured obligations is~~trusts. If the value of the assets held by the trusts declines by a material amount, our funding obligation to the trusts could materially increase. These assets are subject to ~~fluctuation~~market fluctuations and will ~~depend on market~~yield uncertain returns, which may fall below our projected return rates. Forecasting investment earnings and costs to decommission FirstEnergy's retired nuclear generating facility, to pay future pension and other ~~economic~~obligations, requires significant judgment and actual results may differ significantly from current estimates. Capital market conditions that generate investment losses or that negatively impact the discount rate and increase the present value of liabilities may have significant impacts on the value of the decommissioning, pension and other trust funds, which could require significant additional funding and negatively impact our results of operations and financial position.

We Could be Subject to Higher Costs and/or Penalties Related to Mandatory Reliability Standards Set by NERC/FERC or Changes in the Rules of Organized Markets

Owners, operators, and users of the bulk electric system are subject to mandatory reliability standards promulgated by NERC and approved by FERC. The standards are based on the functions that need to be performed to ensure that the bulk electric system operates reliably. NERC, RFC and FERC can be expected to continue to refine existing reliability standards as well as develop and adopt new reliability standards. Compliance with modified or new reliability standards may subject us to higher operating costs and/or increased capital expenditures. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties. FERC has authority to impose penalties up to and including $1 million per day for failure to comply with these mandatory electric reliability standards.

In addition to direct regulation by FERC, we are also subject to rules and terms of participation imposed and administered by various RTOs and ISOs. Although these entities are themselves ultimately regulated by FERC, they can impose rules, restrictions and terms of service that are quasi-regulatory in nature and can have a material adverse impact on our business. For example, the independent market monitors of ISOs and RTOs may impose bidding and scheduling rules to curb the perceived potential for exercise of market power and to ensure the markets function appropriately. Such actions may materially affect our ability to sell, and the price we receive for, our energy and capacity. In addition, PJM may direct our transmission-owning affiliates to build new transmission facilities to meet PJM's reliability requirements or to provide new or expanded transmission service under the PJM Tariff.

We incur fees and costs to participate in RTOs. Administrative costs imposed by RTOs, including the ~~availability~~cost of ~~any suitable buyers for~~administering energy markets, may increase. To the ~~collateral, which~~degree we incur significant additional fees and increased costs to participate in an RTO, and are

limited with respect to recovery of such costs from retail customers, our results of operations and cash flows could be ~~impacted~~significantly impacted.

We may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. We may be required to expand our transmission system according to decisions made by an RTO rather than our own internal planning processes. Various proposals and proceedings before FERC may cause transmission rates to change from time to time. In addition, RTOs have been developing rules associated with the ~~risks~~allocation and methodology of assigning costs associated with ~~operating nuclear generation facilities~~improved transmission reliability, reduced transmission congestion and firm transmission rights that may have a financial impact on us.

As a member of an RTO, we are subject to certain additional risks, including those associated with the allocation among members of losses caused by unreimbursed defaults of other participants in that RTO’s market and those associated with complaint cases filed against the RTO that may seek refunds of revenues previously earned by its members.

We Face Certain Human Resource Risks Associated with Potential Labor Disruptions and/or With the Availability of Trained and Qualified Labor to Meet Our Future Staffing Requirements

We are continually challenged to find ways to balance the retention of our aging skilled workforce while recruiting new talent to mitigate losses in critical knowledge and skills due to retirements. Additionally, a significant number of our physical workforce are represented by unions. While we believe that our relations with our employees are generally fair, we cannot provide assurances that the company will be completely free of labor disruptions such as work stoppages, work slowdowns, union organizing campaigns, strikes, lockouts or that any labor disruption will be favorably resolved. Mitigating these risks could require additional financial commitments and the failure to prevent labor disruptions and retain and/or attract trained and qualified labor could have an adverse effect on our business.

Significant Increases in Our Operation and Maintenance Expenses, Including Our Health Care and Pension Costs, Could Adversely Affect Our Future Earnings and Liquidity

We continually focus on limiting, and reducing where possible, our operation and maintenance expenses. However, we expect to continue to face increased cost pressures related to operation and maintenance expenses, including in the ~~case~~areas of ~~NG’s properties~~health care and pension costs. We have experienced health care cost inflation in recent years, and we expect our cash outlay for health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken requiring employees and retirees to bear a higher portion of the ~~risks~~costs of their health care benefits. The measurement of our expected future health care and pension obligations and costs is highly dependent on a variety of ~~operating coal~~assumptions, many of which relate to factors beyond our control. These assumptions include investment returns, interest rates, discount rates, health care cost trends, benefit design changes, salary increases, the demographics of plan participants and regulatory requirements. While we anticipate that our operation and maintenance expenses will continue to increase, if actual results differ materially from our assumptions, our costs could be significantly higher than expected which could adversely affect our future earnings and liquidity.

Our Results May be Adversely Affected by the Volatility in Pension and OPEB Expenses

FirstEnergy recognizes in income the change in the fair value of plan assets and net actuarial gains and losses for its defined Pension and OPEB plans. This adjustment is recognized in the fourth quarter of each year and whenever a plan is determined to qualify for a remeasurement, which could result in greater volatility in pension and OPEB expenses and may materially impact our results of operations.

FirstEnergy recognizes as a pension and OPEB mark-to-market adjustment the change in the fair value of plan assets and net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement.

Cyber-Attacks, Data Security Breaches and Other Disruptions to Our Information Technology Systems Could Compromise Our Business Operations, Critical and Proprietary Information and Employee and Customer Data, Which Could Have a Material Adverse Effect on Our Business, Financial Condition and Reputation

In the ordinary course of our business, we depend on information technology systems that utilize sophisticated operational systems and network infrastructure to run all facets of our generation, transmission and distribution services. Additionally, we store sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers, suppliers, business partners and other ~~fossil-fueled generation facilities~~individuals in our data centers and on our networks. The secure maintenance of information and information technology systems is critical to our operations.

Over the last several years, there has been an increase in the ~~case~~frequency of ~~FG’s properties,~~cyber-attacks by terrorists, hackers, international activist organizations, countries and individuals. These and other unauthorized parties may attempt to gain access to our network systems or facilities, or those of third parties with whom we do business in many ways, including directly through our network infrastructure or through fraud, trickery, or other forms of deceiving our employees, contractors and temporary staff. Additionally, our information

and information technology systems may be increasingly vulnerable to data security breaches, damage and/or interruption due to viruses, human error, malfeasance, faulty password management or other malfunctions and disruptions. Further, hardware, software, or applications we develop or procure from third parties may contain defects in ~~each case,~~design or manufacture or other problems that could unexpectedly compromise information and/or security.

Despite security measures and safeguards we have employed, including certain measures implemented pursuant to mandatory NERC Critical Infrastructure Protection standards, our infrastructure may be increasingly vulnerable to such attacks as a result of the rapidly evolving and increasingly sophisticated means by which attempts to defeat our security measures and gain access to our information technology systems may be made. Also, we may be at an increased risk of a cyber-attack and/or data security breach due to the nature of our business.

Any such cyber-attack, data security breach, damage, interruption and/or defect could: (i) disable our generation, transmission (including our interconnected regional transmission grid) and/or distribution services for a significant period of time; (ii) delay development and construction of new facilities or capital improvement projects; (iii) adversely affect our customer operations; (iv) corrupt data; and/or (v) result in unauthorized access to the information stored in our data centers and on our networks, including, company proprietary information, supplier information, employee data, and personal customer data, causing the information to be publicly disclosed, lost or stolen or result in incidents that could result in economic loss and liability and harmful effects on the environment and human health, including loss of life. Additionally, because our generation, transmission and distribution services are part of an interconnected system, disruption caused by a cybersecurity incident at another utility, electric generator, RTO, or commodity supplier could also adversely affect our operations.

Although we maintain cyber insurance and property and casualty insurance, there can be no assurance that liabilities or losses we may incur, including as a result of cybersecurity-related litigation, will be covered under such policies or that the amount of insurance will be adequate. Further, as cyber threats become more difficult to detect and successfully defend against, there can be no assurance that we can implement adequate preventive measures, accurately assess the likelihood of a cyber-incident or quantify potential liabilities or losses. Also, we may not discover any data security breach and loss of information for a significant period of time after the data security breach occurs.

For all of these reasons, any such cyber incident could result in significant lost revenue, the inability to conduct critical business functions and serve customers for a significant period of time, the use of significant management resources, legal claims or proceedings, regulatory penalties, significant remediation costs, increased regulation, increased capital costs, increased protection costs for enhanced cybersecurity systems or personnel, damage to our reputation and/or the rendering of our internal controls ineffective, all of which could materially adversely affect our business and financial condition.

Our Risk Management Policies Relating to Energy and Fuel Prices, and Counterparty Credit, Are by Their Very Nature Subject to Uncertainties, and We Could Suffer Economic Losses Resulting in an Adverse Effect on Results of Operations Despite Our Efforts to Manage and Mitigate Our Risks

We attempt to mitigate the market risk inherent in our energy, fuel and debt positions. Procedures have been implemented to enhance and monitor compliance with our risk management policies, including validation of transaction and market prices, verification of risk and transaction limits, sensitivity analysis and daily portfolio reporting of various risk measurement metrics. Nonetheless, we cannot economically hedge all of our exposure in these areas and our risk management program may not operate as planned. As a result, actual events may lead to greater losses or costs than our risk management positions were intended to hedge.

We Have Coal-Fired Generation Capacity, Which Exposes Us to Risk from Regulations Relating to Coal, GHGs and CCRs

Approximately 76% of FirstEnergy's generation fleet capacity is coal-fired, totaling 3,093 MWs at MP and 1,367 MWs at AE Supply. Historically, coal-fired generating plants have greater exposure to the costs of complying with federal, state and local environmental statutes, rules and regulations ~~associated~~relating to air emissions, including GHGs and CCR disposal, than other types of electric generation facilities. These legal requirements and any future initiatives could impose substantial additional costs and, in the case of GHG requirements, could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities and could require our coal-fired generation plants to curtail generation or cease to generate. Failure to comply with ~~public~~any such existing or future legal requirements may also result in the assessment of fines and penalties. Significant resources also may be expended to defend against allegations of violations of any such requirements.

Physical Acts of War, Terrorism or Other Attacks on any of Our Facilities or Other Infrastructure Could Have an Adverse Effect on Our Business, Results of Operations and Financial Condition

As a result of the continued threat of physical acts of war, terrorism, or other attacks in the United States, our electric generation, fuel storage, transmission and distribution facilities and other infrastructure, including power plants, transformer and high voltage lines and substations, or the facilities or other infrastructure of an interconnected company, could be direct targets of, or indirect casualties of, an act of war, terrorism, or other attack, which could result in disruption of our ability to generate, purchase, transmit or distribute electricity for a significant period of time, otherwise disrupt our customer operations and/or result in incidents that could result in harmful effects on the environment and human health, ~~and safety and the environment.~~including loss of life. Any such disruption or incident could result in

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a significant decrease in revenue, significant additional capital and operating costs, including costs to implement additional security systems or personnel to purchase electricity and to replace or repair our assets over and above any available insurance reimbursement, higher insurance deductibles, higher premiums and more restrictive insurance policies, legal claims or proceedings, greater regulation with higher attendant costs, generally, and significant damage to our reputation, which could have a material adverse effect on our business, results of operations and financial condition.

Capital Improvements and Construction Projects May Not be Completed Within Forecasted Budget, Schedule or Scope Parameters or Could be Canceled Which Could Adversely Affect Our Business and Results of Operations

Our business plan calls for execution of extensive capital investments in electric generation, transmission and distribution, including but not limited to our Energizing the Future transmission expansion program, which has been extended to include $4.0 to $4.8 billion in investments from 2018 through 2021. We may be exposed to the risk of substantial price increases in, or the adequacy or availability of, the costs of labor and materials used in construction, nonperformance of equipment and increased costs due to delays, including delays relating to the procurement of permits or approvals, adverse weather or environmental matters. We engage numerous contractors and enter into a large number of construction agreements to acquire the necessary materials and/or obtain the required construction-related services. As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us. Such risk could include our contractors’ inabilities to procure sufficient skilled labor as well as potential work stoppages by that labor force. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, with resulting delays in those and other projects. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. Also, because we enter into construction agreements for the necessary materials and to obtain the required construction related services, any cancellation by FirstEnergy of a construction agreement could result in significant termination payments or penalties. Any delays, increased costs or losses or cancellation of a construction project could adversely affect our business and results of operations, particularly if we are not permitted to recover any such costs in rates.

Changes in Technology and Regulatory Policies May Make Our Facilities Significantly Less Competitive and Adversely Affect Our Results of Operations

Traditionally, electricity is generated at large central station generation facilities. This method results in economies of scale and lower unit costs than newer generation technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in newer generation technologies will make newer generation technologies more cost-effective, or that changes in regulatory policy will create benefits that otherwise make these newer generation technologies even more competitive with central station electricity production. To the extent that newer generation technologies are connected directly to load, bypassing the transmission and distribution systems, potential impacts could include decreased transmission and distribution revenues, stranded assets and increased uncertainty in load forecasting and integrated resource planning and could adversely affect our business and results of operations.

Certain FirstEnergy Companies Have Guaranteed the Performance of Third Parties, Which May Result in Substantial Costs or the Incurrence of Additional Debt

Certain FirstEnergy companies have issued guarantees of the performance of others, which obligates such FirstEnergy companies to perform in the event that the third parties do not perform. For instance, FE is a guarantor under a syndicated senior secured term loan facility, under which Global Holding's outstanding principal balance is $255 million. In the event of non-performance by the third parties, FirstEnergy could incur substantial cost to fulfill this obligation and other obligations under such guarantees. Such performance guarantees could have a material adverse impact on our financial position and operating results.

Additionally, with respect to FEV's investment in Global Holding, it could require additional capital from its owners, including FEV, to fund operations and meet its obligations under its term loan facility. These capital requirements could be significant and if other partners do not fund the additional capital, resulting in FEV increasing its equity ownership and obtaining the ability to direct the significant activities of Global Holding, FEV may be required to consolidate Global Holding, increasing FirstEnergy's long-term debt by $255 million.

Energy Companies are Subject to Adverse Publicity Causing Less Favorable Regulatory and Legislative Outcomes Which Could have an Adverse Impact on Our Business

Energy companies, including FirstEnergy's utility subsidiaries, have been the subject of criticism on matters including the reliability of their distribution services and the speed with which they are able to respond to power outages, such as those caused by storm damage. Adverse publicity of this nature, as well as negative publicity associated with the operation or bankruptcy of nuclear and/or coal-fired facilities or proceedings seeking regulatory recoveries may cause less favorable legislative and regulatory outcomes and damage our reputation, which could have an adverse impact on our business.

Risks Associated with Regulation

We Have Taken a Series of Actions to Focus on Growing Our Regulated Operations, Particularly Within the Regulated Transmission Segment. Whether This Investment Strategy Will Deliver the Desired Result Is Subject to Certain Risks Which Could Adversely Affect Our Results of Operations and Financial Condition in the Future

We focus on capitalizing on investment opportunities available to our regulated operations - particularly within our Regulated Transmission segment - as we focus on delivering enhanced customer service and reliability. The success of these efforts will depend, in part, on successful recovery of our transmission investments. Factors that may affect rate recovery of our transmission investments include: (1) FERC’s timely approval of rates to recover such investments; (2) whether the investments are included in PJM's RTEP; (3) FERC's evolving policies with respect to incentive rates for transmission assets; (4) FERC's evolving policies with respect to the calculation of the base ROE component of transmission rates, as articulated in FERC's Opinion No. 531 and related orders; (5) consideration of the objections of those who oppose such investments and their recovery; and (6) timely development, construction, and operation of the new facilities.

The success of these efforts will also depend, in part, on any future distribution rate cases or other filings seeking cost recovery for distribution system enhancements in the states where our Utilities operate and transmission rate filings at FERC. Any denial of, or delay in, the approval of any future distribution or transmission rate requests could restrict us from fully recovering our cost of service, may impose risks on the Regulated Transmission and Regulated Distribution operations, and could have a material adverse effect on our regulatory strategy and results of operations.

Our efforts also could be impacted by our ability to finance the proposed expansion projects while maintaining adequate liquidity. There can be no assurance that our efforts to reflect a more regulated business profile will deliver the desired result which could adversely affect our future results of operations and financial condition.

Any Subsequent Modifications to, Denial of, or Delay in the Effectiveness of the PUCO’s Approval of the DMR Could Impose Significant Risks on FirstEnergy’s Operations and Materially and Adversely Impact the Credit Ratings, Results of Operations and Financial Condition of FirstEnergy

On October 12, 2016, the PUCO denied the Ohio Companies’ modified Rider RRS and, in accordance with the PUCO Staff’s recommendation, approved a new DMR providing for the collection of $132.5 million annually for three years with a possible extension for an additional two years. Rider DMR will be grossed up for federal income taxes, resulting in an approved amount of approximately $168 million annually in 2018 and 2019. Various parties have appealed the PUCO’s denial of subsequent applications for rehearing to the Ohio Supreme Court. Any subsequent modification to, denial of, or delay in the effectiveness of, the PUCO’s order approving the DMR could impose risks on our operations and materially and adversely impact the credit ratings, results of operations and financial condition of FirstEnergy.

Complex and Changing Government Regulations, Including Those Associated with Rates and Rate Cases and Restrictions and Prohibitions on Certain Business Dealings Could Have a Negative Impact on Our Business, Financial Condition, Results of Operations and Cash Flows

We are subject to comprehensive regulation by various federal, state and local regulatory agencies that significantly influence our operating environment. Changes in, or reinterpretations of, existing laws or regulations, or the imposition of new laws or regulations, could require us to incur additional costs or change the way we conduct our business, and therefore could have a material adverse impact on our results of operations.

Our transmission and operating utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. Thus, the rates a utility is allowed to charge may be decreased as a result of actions taken by FERC or by a state regulatory commission in which the Utilities operate. Also, these rates may not be set to recover such utility's expenses at any given time. Additionally, there may also be a delay between the timing of when costs are incurred and when costs are recovered. For example, we may be unable to timely recover the costs for our energy efficiency investments or expenses and additional capital or lost revenues resulting from the implementation of aggressive energy efficiency programs. While rate regulation is premised on providing an opportunity to earn a reasonable return on invested capital and recovery of operating expenses, there can be no assurance that the applicable regulatory commission will determine that all of our costs have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs in a timely manner. Further, there can be no assurance that we will retain the expected recovery in future rate cases.

In addition, as a U.S. corporation, we are subject to U.S. laws, Executive Orders, and regulations administered and enforced by the U.S. Department of Treasury and the Department of Justice restricting or prohibiting business dealings in or with certain nations and with certain specially designated nationals (individuals and legal entities). If any of our existing or future operations or investments, including our joint venture investment in Signal Peak or our continued procurement of uranium from existing suppliers, are subsequently determined to involve such prohibited parties we could be in violation of certain covenants in our financing documents and unless we cease or modify such dealings, we could also be in violation of such U.S. laws, Executive Orders and

sanctions regulations, each of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

State Rate Regulation May Delay or Deny Full Recovery of Costs and Impose Risks on Our Operations. Any Denial of or Delay in, Cost Recovery Could Have an Adverse Effect on Our Business, Results of Operations, Cash Flows and Financial Condition

Each of the Utilities' retail rates are set by its respective regulatory agency for utilities in the state in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC - through traditional, cost-based regulated utility ratemaking. As a result, any of the Utilities may not be permitted to recover its costs and, even if it is able to do so, there may be a significant delay between the time it incurs such costs and the time it is allowed to recover them. Factors that may affect outcomes in the distribution rate cases include: (i) the value of plant in service; (ii) authorized rate of return; (iii) capital structure (including hypothetical capital structures); (iv) depreciation rates; (v) the allocation of shared costs, including consolidated deferred income taxes and income taxes payable across the FirstEnergy utilities; (vi) regulatory approval of rate recovery mechanisms for capital spending programs (including for example accelerated deployment of smart meters); and (vii) the accuracy of forecasts used for ratemaking purposes in "future test year"cases.

FirstEnergy can provide no assurance that any base rate request filed by any of the Utilities will be granted in whole or in part. Any denial of, or delay in, any base rate request could restrict the applicable Utility from fully recovering its costs of service, may impose risks on its operations, and may negatively impact its results of operations, cash flows and financial condition. In addition, to the extent that any of the Utilities seeks rate increases after an extended period of frozen or capped rates, pressure may be exerted on the applicable legislators and regulators to take steps to control rate increases, including through some form of rate increase moderation, reduction or freeze. Any related public discourse and debate can increase uncertainty associated with the regulatory process, the level of rates and revenues that are ultimately obtained, and the ability of the Utility to recover costs. Such uncertainty may restrict operational flexibility and resources, and reduce liquidity and increase financing costs.

Federal Rate Regulation May Delay or Deny Full Recovery of Costs and Impose Risks on Our Operations. Any Denial or Reduction of, or Delay in Cost Recovery Could Have an Adverse Effect on Our Business, Results of Operations, Cash Flows and Financial Condition

FERC policy currently permits recovery of prudently-incurred costs associated with wholesale power rates and the expansion and updating of transmission infrastructure within its jurisdiction. If FERC were to adopt a different policy regarding recovery of transmission costs or if transmission needs do not continue or develop as projected, or if there is any resulting delay in cost recovery, our strategy of investing in transmission could be affected. If FERC were to lower the rate of return it has authorized for FirstEnergy's cost-based wholesale power rates or transmission investments and facilities, it could reduce future earnings and cash flows, and impact our financial condition.

There are multiple matters pending before FERC. There can be no assurance as to the outcome of these proceedings and an adverse result could have an adverse impact on FirstEnergy’s results of operations and business conditions.

The Business Operations of Our Subsidiaries That Sell Wholesale Power Are Subject to Regulation by FERC and Could be Adversely Affected by Such Regulation

FERC granted the Utilities authority to sell electric energy, capacity and ancillary services at market-based rates. These orders also granted waivers of certain FERC accounting, record-keeping and reporting requirements, as well as, for certain of these subsidiaries, waivers of the requirements to obtain FERC approval for issuances of securities. FERC’s orders that grant this market-based rate authority reserve with FERC the right to revoke or revise that authority if FERC subsequently determines that these companies can exercise market power in transmission or generation, or create barriers to entry, or have engaged in prohibited affiliate transactions. In the event that one or more of FirstEnergy's market-based rate authorizations were to be revoked or adversely revised, the affected FirstEnergy subsidiaries may be subject to sanctions and penalties, and would be required to file with FERC for authorization of individual wholesale sales transactions, which could involve costly and possibly lengthy regulatory proceedings and the loss of flexibility afforded by the waivers associated with the current market-based rate authorizations.

Energy Efficiency and Peak Demand Reduction Mandates and Energy Price Increases Could Negatively Impact Our Financial Results

A number of regulatory and legislative bodies have introduced requirements and/or incentives to reduce peak demand and energy consumption. Such conservation programs could result in load reduction and adversely impact our financial results in different ways. We currently have energy efficiency riders in place to recover the cost of these programs either at or near a current recovery time frame in the states where we operate.

Currently, only our Ohio Companies recover lost distribution revenues that result between distribution rate cases. In our regulated operations, conservation could negatively impact us depending on the regulatory treatment of the associated impacts. Should we be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting

rates for the impact of these measures could have a negative financial impact. We have already been adversely impacted by reduced electric usage due in part to energy conservation efforts such as the use of efficient lighting products such as CFLs, halogens and LEDs. We could also be adversely impacted if any future energy price increases result in a decrease in customer usage. We are unable to determine what impact, if any, conservation and increases in energy prices will have on our financial condition or results of operations.

Additionally, failure to meet regulatory or legislative requirements to reduce energy consumption or otherwise increase energy efficiency could result in penalties that could adversely affect our financial results.

Mandatory Renewable Portfolio Requirements Could Negatively Affect Our Costs and Have an Adverse Effect on Our Financial Condition and Results of Operations

Where federal or state legislation mandates the use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal and such legislation does not also provide for adequate cost recovery, it could result in significant changes in our business, including material increases in REC purchase costs, purchased power costs and capital expenditures. Such mandatory renewable portfolio requirements may have an adverse effect on our financial condition and results of operations.

Changes in Local, State or Federal Tax Laws Applicable to Us or Adverse Audit Results or Tax Rulings, and Any Resulting Increases in Taxes and Fees, May Adversely Affect Our Results of Operations, Financial Condition and Cash Flows

FirstEnergy is subject to various local, state and federal taxes, including income, franchise, real estate, sales and use and employment-related taxes. We exercise significant judgment in calculating such tax obligations, booking reserves as necessary to reflect potential adverse outcomes regarding tax positions we have taken and utilizing tax benefits, such as carryforwards and credits. Additionally, various tax rate and fee increases may be proposed or considered in connection with such changes in local, state or federal tax law. We cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, or whether any such legislation or regulation will be passed by legislatures or regulatory bodies. Any such changes, or any adverse tax audit results or adverse tax rulings on positions taken by FirstEnergy or its subsidiaries could have a negative impact on its results of operations, financial condition and cash flows.

In addition, in December 2017, Congress passed the Tax Act. Various state regulatory proceedings have been initiated to investigate the impact of the Tax Act on the Utilities’ rates and charges, and FERC recently took action to address the impact of the Tax Act on FERC-jurisdictional rates, including transmission and electric wholesale rates. FirstEnergy continues to work with state regulatory commissions to determine appropriate changes to customer rates and, beginning in the first quarter of 2018, began to track and apply regulatory accounting treatment for the expected rate impact of changes in current taxes resulting from the Tax Act. FirstEnergy has also reflected the impact of changes to current taxes in its normal update to FERC-jurisdictional transmission rates and will continue to work with the commission regarding whether and how FERC should address possible changes to transmission and wholesale rates resulting from the Tax Act.

We cannot predict whether, when or to what extent new tax regulations, interpretations or rulings will be issued, nor is the short-term or long-term impact of proposed tax reform clear. Any future reform of U.S. tax laws may be enacted in a manner that negatively impacts our results of operations, financial condition, business operations, earnings and is adverse to FE's shareholders. Furthermore, with respect to the Utilities and our transmission-owning affiliates, FirstEnergy cannot predict what, if any, response state regulatory commissions or FERC may have and the potential response of such authorities regarding the rates and charges of the Utilities and our transmission-owning affiliates.

The EPA is Conducting NSR Investigations at Generating Plants that We Currently or Formerly Owned, the Results of Which Could Negatively Impact Our Results of Operations and Financial Condition

We may be subject to risks from changing or conflicting interpretations of existing laws and regulations, including, for example, the applicability of the EPA's NSR programs. Under the CAA, modification of our generation facilities in a manner that results in increased emissions could subject our existing generation facilities to the far more stringent new source standards applicable to new generation facilities.

The EPA has taken the view that many companies, including many energy producers, have been modifying emissions sources in violation of NSR standards during work considered by the companies to be routine maintenance. The EPA has investigated alleged violations of the NSR standards at certain of our existing and former generating facilities. We intend to vigorously pursue and defend our position, but we are unable to predict their outcomes. If NSR and similar requirements are imposed on our generation facilities, in addition to the possible imposition of fines, compliance could entail significant capital investments in pollution control technology, which could have an adverse impact on our business, results of operations, cash flows and financial condition.

Costs of Compliance with Environmental Laws are Significant, and the Cost of Compliance with New Environmental Laws, Including Limitations on GHG Emissions, Could Adversely Affect Cash Flow and Profitability

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations. Compliance with these legal requirements requires us to incur costs for, among other things, installation and operation of pollution control equipment, emissions monitoring and fees, remediation and permitting at our facilities. These expenditures have been significant in the past and may increase in the future. We may be forced to shut down other facilities or change their operating status, either temporarily or permanently, if we are unable to comply with these or other existing or new environmental requirements, or if the expenditures required to comply with such requirements are unreasonable.

Moreover, new environmental laws or regulations including, but not limited to CWA effluent limitations imposing more stringent water discharge regulations, or changes to existing environmental laws or regulations may materially increase our costs of compliance or accelerate the timing of capital expenditures. Our compliance strategy, including but not limited to, our assumptions regarding estimated compliance costs, although reasonably based on available information, may not successfully address future relevant standards and interpretations. If we fail to comply with environmental laws and regulations or new interpretations of longstanding requirements, even if caused by factors beyond our control, that failure could result in the assessment of civil or criminal liability and fines. In addition, any alleged violation of environmental laws and regulations may require us to expend significant resources to defend against any such alleged violations.

At the international level, the Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide greenhouse gas emissions by 26 to 28 percent below 2005 levels by 2025 and in September 2016, joined in adopting the agreement reached on December 12, 2015 at the United Nations Framework Convention on Climate Change meetings in Paris. However, on June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the 2015 Paris Agreement. Due to the uncertainty of control technologies available to reduce GHG emissions, any other legal obligation that requires substantial reductions of GHG emissions could result in substantial additional costs, adversely affecting cash flow and profitability, and raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities.

We Could be Exposed to Private Rights of Action Relating to Environmental Matters Seeking Damages Under Various State and Federal Law Theories Which Could Have an Adverse Impact on Our Results of Operations, Financial Condition and Business Operations

Private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other relief. For example, claims have been made against certain energy companies alleging that CO₂ emissions from power generating facilities constitute a public nuisance under federal and/or state common law. While FirstEnergy is not a party to this litigation, it, and/or one of its subsidiaries, could be named in other actions making similar allegations. An unfavorable ruling in any such case could result in the need to make modifications to our coal-fired plants or reduce emissions, suspend operations or pay money damages or penalties. Adverse rulings in these or other types of actions could have an adverse impact on our results of operations and financial condition and could significantly impact our business operations.

We Are or May Be Subject to Environmental Liabilities, Including Costs of Remediation of Environmental Contamination at Current or Formerly Owned Facilities, Which Could Have a Material Adverse effect on Our Results of Operations and Financial Condition

We may be subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned or operated by us and of property contaminated by hazardous substances that we may have generated regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. We are currently involved in a number of proceedings relating to sites where hazardous substances have been released and we may be subject to additional proceedings in the future. We also have current or previous ownership interests in sites associated with the production of gas and the production and delivery of electricity for which we may be liable for additional costs related to investigation, remediation and monitoring of these sites. Remediation activities associated with our former MGP operations are one source of such costs. Citizen groups or others may bring litigation over environmental issues including claims of various types, such as property damage, personal injury, and citizen challenges to compliance decisions on the enforcement of environmental requirements, such as opacity and other air quality standards, which could subject us to penalties, injunctive relief and the cost of litigation. We cannot predict the amount and timing of all future expenditures (including the potential or magnitude of fines or penalties) related to such environmental matters, although we expect that they could be material.

In some cases, a third party who has acquired assets from us has assumed the liability we may otherwise have for environmental matters related to the transferred property. If the transferee fails to discharge the assumed liability or disputes its responsibility, a regulatory authority or injured person could attempt to hold us responsible, and our remedies against the transferee may be limited by the financial resources of the transferee.

We Are and May Become Subject to Legal Claims Arising from the Presence of Asbestos or Other Regulated Substances at Some of Our Facilities

We have been named as a defendant in pending asbestos litigations involving multiple plaintiffs and multiple defendants, in several states. The majority of these claims arise out of alleged past exposures by contractors (and in Pennsylvania, former employees) at both currently and formerly owned electric generation plants. In addition, asbestos and other regulated substances are, and may continue to be, present at currently owned facilities where suitable alternative materials are not available. We believe that any remaining asbestos at our facilities is contained and properly identified in accordance with applicable governmental regulations, including OSHA. The continued presence of asbestos and other regulated substances at these facilities, however, could result in additional actions being brought against us. This is further complicated by the fact that many diseases, such as mesothelioma and cancer, have long latency periods in which the disease process develops, thus making it impossible to accurately predict the types and numbers of such claims in the near future. While insurance coverages exist for many of these pending asbestos litigations, others have no such coverages, resulting in FirstEnergy being responsible for all defense expenditures, as well as any settlements or verdict payouts.

The Risks Associated with Climate Change May Have an Adverse Impact on Our Business Operations, Operating Results and Cash Flows

Physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, and other related phenomena, could affect some, or all, of our operations. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Utilities' service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Further, as extreme weather conditions increase system stress, we may incur costs relating to additional system backup or service interruptions, and in some instances, we may be unable to recover such costs. For all of these reasons, these physical risks could have an adverse financial impact on our business operations, operating results and cash flows. Climate change poses other financial risks as well. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes. Increased energy use due to weather changes may require us to invest in additional system assets and purchase additional power. Additionally, decreased energy use due to weather changes may affect our financial condition through decreased rates, revenues, margins or earnings.

Future Changes in Accounting Standards May Affect Our Reported Financial Results

The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be difficult to predict and could materially impact how we report our financial condition and results of operations. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial position.

Risks Associated with Financing and Capital Structure

In the Event of Volatility or Unfavorable Conditions in the Capital and Credit Markets, Our Business, Including the Immediate Availability and Cost of Short-Term Funds for Liquidity Requirements, Our Ability to Meet Long-Term Commitments and the Competitiveness and Liquidity of Energy Markets May be Adversely Affected, Which Could Negatively Impact Our Results of Operations, Cash Flows and Financial Condition

We rely on the capital markets to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use letters of credit provided by various financial institutions to support our hedging operations. We also deposit cash in short-term investments. In the event of volatility in the capital and credit markets, our ability to draw on our credit facilities and cash may be adversely affected. Our access to funds under those credit facilities is dependent on the ability of the financial institutions that are parties to the facilities to meet their funding commitments. Those institutions may not be able to meet their funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. Any delay in our ability to access those funds, even for a short period of time, could have a material adverse effect on our results of operations and financial condition.

Should there be fluctuations in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant foreign or domestic financial institutions or foreign governments, our access to liquidity needed for our business could be adversely affected. Unfavorable conditions could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures, changing hedging strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash.

Energy markets depend heavily on active participation by multiple counterparties, which could be adversely affected should there be disruptions in the capital and credit markets. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to our business.

Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace those market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on our results of operations and cash flows.

Interest Rates and/or a Credit Rating Downgrade Could Negatively Affect Our or Our Subsidiaries' Financing Costs, Ability to Access Capital and Requirement to Post Collateral

We have near-term exposure to interest rates from outstanding indebtedness indexed to variable interest rates, and we have exposure to future interest rates to the extent we seek to raise debt in the capital markets to meet maturing debt obligations and fund construction or other investment opportunities. Past disruptions in capital and credit markets have resulted in higher interest rates on new publicly issued debt securities, increased costs for certain of our variable interest rate debt securities and failed remarketing of variable interest rate tax-exempt debt issued to finance certain of our facilities. Similar future disruptions could increase our financing costs and adversely affect our results of operations. Also, interest rates could change as a result of economic or other events that are beyond our risk management processes. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs that our risk management positions were intended to hedge. Although we employ risk management techniques to hedge against interest rate volatility, significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results of operations.

We rely on access to bank and capital markets as sources of liquidity for cash requirements not satisfied by cash from operations. A downgrade in our or our subsidiaries' credit ratings from the nationally recognized credit rating agencies, particularly to a level below investment grade, could negatively affect our ability to access the bank and capital markets, especially in a time of uncertainty in either of those markets, and may require us to post cash collateral to support outstanding commodity positions in the wholesale market, as well as available letters of credit and other guarantees. Furthermore, a downgrade could increase the cost of such capital by causing us to incur higher interest rates and fees associated with such capital. A rating downgrade would increase our interest expense on certain of FirstEnergy's long-term debt obligations and would also increase the fees we pay on our various existing credit facilities, thus increasing the cost of our working capital. A rating downgrade could also impact our ability to grow our regulated businesses by substantially increasing the cost of, or limiting access to, capital.

Any Default by Customers or Other Counterparties Could Have a Material Adverse Effect on Our results of Operations and Financial Condition

We are exposed to the risk that counterparties that owe us money, power, fuel or other commodities could breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, which would cause our financial results to be diminished and we might incur losses. Some of our agreements contain provisions that require the counterparties to provide credit support to secure all or part of their obligations to FirstEnergy or its subsidiaries. If the counterparties to these arrangements fail to perform, we may have a right to receive the proceeds from the credit support provided, however the credit support may not always be adequate to cover the related obligations. In such event, we may incur losses in addition to amounts, if any, already paid to the counterparties, including by being forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices. Although our estimates take into account the expected probability of default by a counterparty, our actual exposure to a default by customers or other counterparties may be greater than the estimates predict, which could have a material adverse effect on our results of operations and financial condition.

We Must Rely on Cash from Our Subsidiaries and Any Restrictions on Our Utility Subsidiaries' Ability to Pay Dividends or Make Cash Payments to Us May Adversely Affect Our Cash Flows and Financial Condition

We are a holding company and our investments in our subsidiaries are our primary assets. Substantially all of our business is conducted by our subsidiaries. Consequently, our cash flow, including our ability to pay dividends and service debt, is dependent on the operating cash flows of our subsidiaries and their ability to upstream cash to the holding company. Any inability of our subsidiaries to pay dividends or make cash payments to us may adversely affect our cash flows and financial condition.

Additionally, our utility and transmission subsidiaries are regulated by various state utility and federal commissions that generally possess broad powers to ensure that the needs of utility customers are being met. Those state and federal commissions could attempt to impose restrictions on the ability of our utility and transmission subsidiaries to pay dividends or otherwise restrict cash payments to us.

Our Mandatorily Convertible Preferred Stock Will be Converted into Common Stock, at the Latest, in Two Years from the Date of Issuance and the Holders Thereof Have Registration Rights. Upon Conversion of the Preferred Shares, the Number of Common Shares Eligible for Future Resale in the Public Market Will Increase and May Result in Dilution to Common Shareholders. This May Have an Adverse Effect on the Market Price of Common Stock.

On January 22, 2018, FE issued $2.5 billion of equity, which included $1.62 billion of mandatorily convertible preferred equity with an initial conversion price of $27.42 per share and $850 million of common equity issued at $28.22 per share. The issuance of

common equity created some dilution to existing common holders. The new preferred shares contain an optional conversion for holders beginning in July 2018, and will mandatorily convert in 18 months from issuance, subject to limited exceptions.

Upon the conversion of the mandatorily convertible preferred stock additional shares of our common stock will be issued, which results in dilution to our stockholders, and will increase the number of shares eligible for resale in the public market. Sales of substantial numbers of such shares in the public market could adversely affect the market price of our common stock.

We Cannot Assure Common and Preferred Shareholders that Future Dividend Payments Will be Made, or if Made, in What Amounts They May be Paid

Our Board of Directors will continue to regularly evaluate our common stock dividend and determine an appropriate dividend each quarter taking into account such factors as, among other things, our earnings, financial condition and cash flows from subsidiaries, as well as general economic and competitive conditions. We cannot assure common or preferred shareholders that dividends will be paid in the future, or that, if paid, dividends will be at the same amount or with the same frequency as in the past. Further, the terms of the outstanding preferred stock require that preferred shareholders receive dividends alongside the common shareholders on an as-converted, pro rata basis.

The Recognition of Impairments of Goodwill and Long-Lived Assets Has Adversely Affected Our Results of Operations and Additional Impairments Could Have a Material Adverse Effect on FirstEnergy’s Business, Financial Condition, Results of Operations, Liquidity and the Trading Price of FirstEnergy's Securities

We have approximately $5.6 billion of goodwill on our consolidated balance sheet as of March 31, 2018. Goodwill is tested for impairment annually as of July 31 or whenever events or changes in circumstances indicate impairment may have occurred. Key assumptions incorporated in the estimated cash flows used for the impairment analysis requiring significant management judgment include: discount rates, growth rates, future energy and capacity pricing, projected operating income, changes in working capital, projected capital expenditures, projected funding of pension plans, expected results of future rate proceedings, the impact of pending carbon and other environmental legislation and terminal multiples.

We are unable to predict whether further impairments of one or more of our long-lived assets or investments may occur in the future. The actual timing and amounts of any impairments to goodwill, or long-lived assets in the future depends on many factors, including the outcome of the strategic review, interest rates, sector market performance, our capital structure, natural gas or other commodity prices, market prices for power, results of future rate proceedings, operating and capital expenditure requirements, the value of comparable acquisitions, environmental regulations and other factors. A determination that goodwill, a long-lived asset, or other investments are impaired would result in a non-cash charge that could materially adversely affect our results of operations and capitalization.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The table below sets forth information on a monthly basis regarding FirstEnergy's purchases of its common stock during the ~~third~~first quarter of ~~2017:~~2018:

Period
Total Number of Shares Purchased⁽¹⁾
Average Price Paid per Share
Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs⁽²⁾

Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs⁽²⁾

July 1-31, 2017 —
—
—
—
August 1-31, 2017 2,318
$ 32.62
—
—
September 1-30, 2017 —
—
—
—

Third Quarter 2,318
$ 32.62
—
—



Period	Total Number of Shares Purchased⁽¹⁾	Average Price Paid per Share		Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs⁽²⁾	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs⁽²⁾

January 1-31, 2018	—	—		—	—
February 1-28, 2018	1,118	$	33.01	—	—
March 1-31, 2018	—	—		—	—

First Quarter of 2018	1,118	$	33.01	—	—

⁽¹⁾

Share amounts reflect shares that were surrendered to FirstEnergy by a participant under our ~~2007~~2015 Incentive Compensation 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.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

~~None.~~The FES Bankruptcy constituted an event of default, or otherwise triggered repayment obligations, under the terms of the following debt instruments of the following entities (collectively, the “Debt Documents”):

FG:

Air Quality Facilities Loan Agreement, dated as of December 1, 2006, between the Ohio Air Quality Development Authority (“OAQDA”) and FG, relating to $234.5 million of pollution control refunding bonds (“PCRBs”) due 2023;

Exempt Facilities Loan Agreement, dated as of November 1, 2006, between the Pennsylvania Economic Development Financing Authority (“PEDFA”) and FG, relating to $26 million of PCRBs due 2041;

Exempt Facilities Loan Agreement, dated as of December 1, 2005, between PEDFA and FG, relating to $43 million of PCRBs due 2040;

Exempt Facilities Loan Agreement, dated as of July 1, 2002, as amended, between PEDFA and FG, relating to $15 million of PCRBs due 2028 and certain related first mortgage bonds (“FMBs”) issued and outstanding under the FG Mortgage (as defined below);

Pollution Control Facilities Loan Agreement, dated as of November 1, 2008, as amended, between the Beaver County Industrial Development Authority (“BCIDA”) and FG, relating to $25 million of PCRBs due 2028 and certain related FMBs issued and outstanding under the FG Mortgage;

Waste Water Facilities Loan Agreement, dated as of April 1, 2006, between the Ohio Water Development Authority (“OWDA”) and FG, relating to $90.1 million of PCRBs due 2019;

Pollution Control Facilities Loan Agreement, dated as of September 1, 2008, between BCIDA and FG, relating to $46.3 million of PCRBs due 2047 and certain related FMBs issued and outstanding under the FG Mortgage;

Pollution Control Facilities Loan Agreement, dated as of April 1, 2006 between BCIDA and FG, relating to $56.6 million of PCRBs due 2041;

Air Quality Facilities Loan Agreement, dated as of August 1, 2009, between OAQDA and FG, relating to $177 million of PCRBs due 2020;

Air Quality Facilities Loan Agreement, dated as of March 1, 2009, between OAQDA and FG, relating to $50 million of PCRBs due 2023;

Air Quality Facilities Loan Agreement, dated as of June 1, 2009, between OAQDA and FG, relating to $100 million of PCRBs due 2029 and certain related FMBs issued and outstanding under the FG Mortgage;

Air Quality Facilities Loan Agreement dated as of June 1, 2009, between OAQDA and FG, relating to $141.3 million of PCRBs due 2018 and certain related FMBs issued and outstanding under the FG Mortgage;

Guaranty, dated as of March 26, 2007, of FG relating to indebtedness of FirstEnergy Solutions Corp.; and

Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008, as amended and supplemented (the “FG Mortgage”), by and between FG and UMB Bank, National Association, as successor trustee under which FG’s FMBs are issued and outstanding, including but not limited to $250 million of FMBs supporting the Parent Credit Facility (as defined below).

NG:

Pollution Control Facilities Loan Agreement, dated as of December 1, 2005, between BCIDA and NG, relating to $72.7 million of PCRBs due 2035;

Air Quality Facilities Loan Agreement, dated as of December 1, 2005, between OAQDA and NG, relating to $7.2 million of PCRBs due 2034;

Air Quality Facilities Loan Agreement, dated as of November 1, 2008, between OAQDA and NG, relating to $23 million of PCRBs due 2032;

Air Quality Facilities Loan Agreement, dated as of September 15, 2010, between OAQDA and NG, relating to $8 million of PCRBs due 2033;

Waste Water Facilities and Solid Waste Facilities Loan Agreement, dated as of December 1, 2005, between OWDA and NG, relating to $82.8 million of PCRBs due 2034;

Waste Water Facilities and Solid Waste Facilities Loan Agreement, dated as of November 1, 2008, between OWDA and NG, relating to $33 million of PCRBs due 2032;

Waste Water Facilities and Solid Waste Facilities Loan Agreement, dated as of September 15, 2010, between OWDA and NG, relating to $99.1 million of PCRBs due 2033;

Waste Water Facilities and Solid Waste Facilities Loan Agreement, dated as of June 1, 2009, between OWDA and NG, relating to $107.5 million of PCRBs due 2033 and certain related FMBs issued and outstanding under the NG Mortgage (as defined below);

Pollution Control Facilities Loan Agreement, dated as of December 1, 2006, between BCIDA and NG, relating to $164 million of PCRBs due 2035;

Air Quality Facilities Loan Agreement, dated as of December 1, 2006, between OAQDA and NG, relating to $15.5 million of PCRBs due 2033;

Air Quality Facilities Loan Agreement, dated as of November 15, 2010, between OAQDA and NG, relating to $26 million of PCRBs due 2033;

Waste Water Facilities and Solid Waste Facilities Loan Agreement, dated as of December 1, 2006, between OWDA and NG, relating to $135.6 million of PCRBs due 2033;

Waste Water Facilities and Solid Waste Facilities Loan Agreement, dated as of September 1, 2008, between OWDA and NG, relating to $20.5 million of PCRBs due 2033;

Waste Water Facilities and Solid Waste Facilities Loan Agreement, dated as of November 15, 2010, between OWDA and NG, relating to $46.5 million of PCRBs due 2033;

Waste Water Facilities and Solid Waste Facilities Loan Agreement, dated as of November 15, 2010, between OWDA and NG, relating to $54.6 million of PCRBs due 2033 and certain related FMBs issued and outstanding under the NG Mortgage;

Air Quality Facilities Loan Agreement, dated as of September 1, 2008, between OAQDA and NG, relating to $9.1 million of PCRBs due 2033;

Air Quality Facilities Loan Agreement, dated as of April 1, 2009, between the Company and the OAQDA and NG (as amended or supplemented from time to time) relating to $62.5 million of PCRBs due 2033 and certain related FMBs issued and outstanding under the NG Mortgage;

Pollution Control Facilities Loan Agreement, dated as of April 1, 2006, as amended, between BCIDA and NG, relating to $60 million of PCRBs due 2035 and certain related FMBs issued and outstanding under the NG Mortgage;

Pollution Control Facilities Loan Agreement, dated as of June 1, 2008, as amended, between BCIDA and NG, relating to $98.9 million of PCRBs due 2035;

Guaranty, dated as of March 26, 2007, of NG relating to indebtedness of FirstEnergy Solutions Corp.; and

Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009, as amended and supplemented (the “NG Mortgage”), by and between NG and UMB Bank, National Association, as successor trustee under which NG’s FMBs are issued and outstanding, including but not limited to $450 million of FMBs supporting the Parent Credit Facility;

FirstEnergy Solutions Corp.:

Indenture, dated as of August 1, 2009, and the First Supplemental Indenture thereto, dated as of August 1, 2009, between FirstEnergy Solutions Corp. and The Bank of New York Mellon Trust Company, N.A., as trustee, under which $332 million and $363 million, respectively, of FirstEnergy Solutions Corp. 6.05% senior notes due 2021 and 6.80% senior notes due 2039 are issued and outstanding;

U.S. $700 million Credit Agreement, dated as of December 6, 2016, among FirstEnergy Solutions Corp., as borrower, FG and NG, as guarantors, and FE, as lender under which $700 million is currently utilized (the “Parent Credit Facility”);

Revolving Credit Note, dated June 29, 2016, issued by FirstEnergy Solutions Corp. to Allegheny Energy Supply Company, LLC, under which $102 million is currently outstanding;

Guaranty, dated as of March 26, 2007, of FirstEnergy Solutions Corp. relating to indebtedness of FG;

Guaranty, dated as of March 26, 2007, of FirstEnergy Solutions Corp. relating to indebtedness of NG; and

Guaranty, dated as of July 1, 2007, of FirstEnergy Solutions Corp. relating to the FG Leases.

As a result of such an event of default or triggering event, all obligations under the Debt Documents, by the terms of the Debt Documents, have become due and payable, subject to the provisions of Chapter 11 of the United States Bankruptcy Code. The aggregate indebtedness subject to events of default under the Debt Documents is approximately $3.6 billion. FirstEnergy believes that any efforts to enforce such payment obligations against the above entities are stayed as a result of the filing of the FES Bankruptcy, and the creditors’ rights of enforcement are subject to the applicable provisions of Chapter 11 of the United States Bankruptcy Code.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

~~None.~~On March 28, 2018, FES amended and restated its outstanding 2018 Annual Incentive Program, in which FirstEnergy Solutions Corp. President Donald Schneider, who is deemed a named executive officer, participates to distinguish the impact of a voluntary resignation as opposed to death or retirement, clarify the authority of the FES Board of Directors with respect to the program and awards thereunder, and to clarify the portion of awards that correlate to FES' prior short term incentive program. The foregoing description does not purport to be complete and is qualified in its entirety by reference to the full text of the Amended and Restated FES 2018 Annual Incentive Plan, a copy of which is included as Exhibit 10.14 and incorporated by reference herein.

~~114~~86

ITEM 6. EXHIBITS



Exhibit Number		Description
~~FirstEnergy~~
	4	Amendment to the Amended Articles of Incorporation of FirstEnergy Corp., effective January 22, 2018 (incorporated by reference to FE's Form 8-K filed January 22, 2018, Exhibit 3.1, File No. 333-21011).
	10.1	Preferred Stock Purchase Agreement, dated January 22, 2018, among FirstEnergy Corp. and the Preferred Investors (incorporated by reference to FE’s Form 8-K filed January 22, 2018, Exhibit 10.1, File No. 333-21011).
	10.2	Common Stock Purchase Agreement, dated January 22, 2018, among FirstEnergy Corp. and ZP Master Utility Fund, Ltd., P Zimmer, Ltd., ZP Energy Fund, L.P. and ZP Master Energy Fund, L.P. (incorporated by reference to FE’s Form 8-K filed January 22, 2018, Exhibit 10.2, File No. 333-21011).
(A) (B)	10.3	FirstEnergy Solutions Corp. 2016 Key Employee Retention Plan, effective December 1, 2016.
(A) (B)	10.4	Amendment to FirstEnergy Solutions Corp. 2016 Key Employee Retention Plan, effective March 23, 2017.
(A) (B)	10.5	Second Amendment to FirstEnergy Solutions Corp. 2016 Key Employee Retention Plan, effective December 1, 2017.
(A) (B)	10.6	Form of FirstEnergy Solutions Corp. Retention Agreement.
(A) (B)	10.7	FirstEnergy Nuclear Operating Company 2016 Key Employee Retention Plan, effective December 1, 2016.
(A) (B)	10.8	Amendment to FirstEnergy Nuclear Operating Company 2016 Key Employee Retention Plan, effective March 23, 2017.
(A) (B)	10.9	Second Amendment to FirstEnergy Nuclear Operating Company 2016 Key Employee Retention Plan, effective December 1, 2017.
(A) (B)	10.10	Form of FirstEnergy Nuclear Operating Company Retention Agreement.
(A) (B)	10.11	FirstEnergy Nuclear Operating Company Replacement 2017 Long-Term Incentive Program (LTIP), effective March 6, 2017.
(A) (B)	10.12	Form of 2018-2019 Stock-Based Performance-Adjusted Restricted Stock Unit Award Agreement.
(A) (B)	10.13	FirstEnergy Solutions Corp. 2018 Annual Incentive Program, effective February 19, 2018.
(A) (B)	10.14	FirstEnergy Solutions Corp. Amended and Restated 2018 Annual Incentive Program (AIP), effective March 28, 2018.
(A)	12	~~Fixed charge ratio~~Consolidated ratios of earnings to fixed charges.
(A)	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a).
(A)	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a).
(A)	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section ~~1350~~1350.
	101	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended ~~September 30, 2017,~~March 31, 2018, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Statements of Income ~~(Loss)~~ and Consolidated Statements of Comprehensive Income, ~~(Loss),~~ (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements and (v) document and entity information.
~~FES~~
~~(A)~~	~~31.1~~	~~Certification of principal executive officer, as adopted pursuant to Rule 13a-14(a)~~
~~(A)~~	~~31.2~~	~~Certification of principal financial officer, as adopted pursuant to Rule 13a-14(a)~~
~~(A)~~	32	~~Certification of principal executive officer and principal financial officer, pursuant to 18 U.S.C. Section 1350~~
	~~101~~	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Solutions Corp. for the period ended September 30, 2017, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Statements of Income (Loss) and Comprehensive Income (Loss), (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements and (v) document and entity information.

(A) Provided herein in electronic format as an exhibit.

(B) Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, except as set forth above ~~neither~~ FirstEnergy ~~nor FES have~~has not filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but ~~each~~ hereby agrees to furnish to the SEC on request any such documents.

~~115~~87

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, ~~each~~the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

~~October 26, 2017~~April 23, 2018



	FIRSTENERGY CORP.
	Registrant

	/s/ ~~K. Jon Taylor~~Jason J. Lisowski
	~~K. Jon Taylor~~Jason J. Lisowski
	Vice President, Controller and Chief Accounting Officer

	~~FIRSTENERGY SOLUTIONS CORP.~~
	~~Registrant~~

	~~/s/ Jason J. Lisowski~~
	~~Jason J. Lisowski~~
	~~Controller and Treasurer~~
	~~(Principal Financial Officer)~~

~~116~~88



Commission	Registrant; State of Incorporation;	I.R.S. Employer
File Number	Address; and Telephone Number	Identification No.

333-21011	FIRSTENERGY CORP.	34-1843785
	(An Ohio Corporation)
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

~~000-53742~~	~~FIRSTENERGY SOLUTIONS CORP.~~	~~31-1560186~~
	~~(An Ohio Corporation)~~
	~~c/o FirstEnergy Corp.~~
	~~76 South Main Street~~
	~~Akron, OH 44308~~
	~~Telephone (800)736-3402~~



Large Accelerated Filer þ	~~FirstEnergy Corp.~~

Accelerated Filer o	~~N/A~~

Non-accelerated Filer (Do not check if a smaller reporting company) þo	~~FirstEnergy Solutions Corp.~~

Smaller Reporting Company o	~~N/A~~

Emerging Growth Company o	~~N/A~~



		OUTSTANDING
CLASS		AS OF ~~SEPTEMBER 30, 2017~~MARCH 31, 2018
FirstEnergy Corp., $0.10 par value		~~444,858,003~~
~~FirstEnergy Solutions Corp., no par value~~		7476,909,318

TABLE OF CONTENTS

	Page

Part I. Financial Information

Glossary of Terms	ii

Item 1. Financial Statements

FirstEnergy Corp.
Consolidated Statements of Income ~~(Loss)~~	1
Consolidated Statements of Comprehensive Income ~~(Loss)~~	2
Consolidated Balance Sheets	3
Consolidated Statements of Cash Flows	4

~~FirstEnergy Solutions Corp.~~
~~Consolidated Statements of Income (Loss) and Comprehensive Income (Loss)~~	5
~~Consolidated Balance Sheets~~	6
~~Consolidated Statements of Cash Flows~~	7

~~Combined~~ Notes To Consolidated Financial Statements	85

Item 2. Management's Discussion and Analysis of ~~Registrant and Subsidiaries~~	60
~~FirstEnergy Corp.~~ ~~Management's Discussion and Analysis of~~ Financial Condition and Results of Operations	60

~~Management's Narrative Analysis of Results of Operations~~
~~FirstEnergy Solutions Corp.~~	~~106~~40

Item 3. Quantitative and Qualitative Disclosures About Market Risk	~~113~~71

Item 4. Controls and Procedures	~~113~~71

Part II. Other Information

Item 1. Legal Proceedings	~~113~~71

Item 1A. Risk Factors	~~113~~71

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	~~114~~84

Item 3. Defaults Upon Senior Securities	~~114~~85

Item 4. Mine Safety Disclosures	~~114~~86

Item 5. Other Information	~~114~~86

Item 6. Exhibits	~~115~~87



AE	Allegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy on February 25, ~~2011. As of January 1, 2014, AE~~2011, which subsequently merged with and into ~~FirstEnergy Corp.~~FE on January 1, 2014
AESC	Allegheny Energy Service Corporation, a subsidiary of FirstEnergy Corp.
AE Supply	Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary of FE
AGC	Allegheny Generating Company, a generation subsidiary of AE Supply and equity method investee of MP
ATSI	American Transmission Systems, Incorporated, formerly a direct subsidiary of FE that became a subsidiary of FET in April 2012, which owns and operates transmission facilities
BU Energy	Buchanan Energy Company of Virginia, LLC, a subsidiary of AE Supply, and formerly a 50% owner in a joint venture that owns the Buchanan Generating Facility
Buchanan Energy	Buchanan Generation, LLC, formerly a joint venture between AE Supply and CNX Gas Corporation
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
CES	Competitive Energy Services, formerly a reportable operating segment of FirstEnergy
FE	FirstEnergy Corp., a public utility holding company
FENOC	FirstEnergy Nuclear Operating Company, a subsidiary of FE, which operates NG's nuclear generating facilities
FES	FirstEnergy Solutions Corp., together with its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage L.L.C. and FGMUC, which provides unregulated energy-related products and services
FESC	FirstEnergy Service Company, which provides legal, financial and other corporate support services
FET	FirstEnergy Transmission, LLC, formerly known as Allegheny Energy Transmission, LLC, which is the parent of ATSI, TrAIL and MAIT, and has a joint venture in PATH
FEV	FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures
FG	FirstEnergy Generation, LLC, a wholly owned subsidiary of FES, which owns and operates non-nuclear generating facilities
FGMUC	FirstEnergy Generation Mansfield Unit 1 Corp., a wholly owned subsidiary of FG, which has certain leasehold interests in a portion of Unit 1 at the Bruce Mansfield plant
FirstEnergy	FirstEnergy Corp., together with its consolidated subsidiaries
Global Holding	Global Mining Holding Company, LLC, a joint venture between FEV, WMB Marketing Ventures, LLC and Pinesdale LLC
Global Rail	Global Rail Group, LLC, a subsidiary of Global Holding that owns coal transportation operations near Roundup, Montana
GPU	GPU, Inc., former parent of JCP&L, ME and PN, that merged with FE on November 7, 2001
JCP&L	Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
MAIT	Mid-Atlantic Interstate Transmission, LLC, a subsidiary of FET, which owns and operates transmission facilities
ME	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
MP	Monongahela Power Company, a West Virginia electric utility operating subsidiary
NG	FirstEnergy Nuclear Generation, LLC, a wholly owned subsidiary of FES, which owns nuclear generating facilities
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies	CEI, OE and TE
PATH	Potomac-Appalachian Transmission Highline, LLC, a joint venture between FE and a subsidiary of AEP
PATH-Allegheny	PATH Allegheny Transmission Company, LLC
PATH-WV	PATH West Virginia Transmission Company, LLC
PE	The Potomac Edison Company, a Maryland and West Virginia electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies	ME, PN, Penn and WP
PN	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Signal Peak	Signal Peak Energy, LLC, an indirect subsidiary of Global Holding that owns mining operations near Roundup, Montana
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
TrAIL	Trans-Allegheny Interstate Line Company, a subsidiary of FET, which owns and operates transmission facilities
Utilities	OE, CEI, TE, Penn, JCP&L, ME, PN, MP, PE and WP
WP	West Penn Power Company, a Pennsylvania electric utility operating subsidiary

The following abbreviations and acronyms are used to identify frequently used terms in this report:
AAA	American Arbitration Association
ADIT	Accumulated Deferred Income Taxes
~~AEP~~	~~American Electric Power Company, Inc.~~
~~AFS~~	~~Available-for-sale~~
~~AFUDC~~	~~Allowance for Funds Used During Construction~~



Yes þ No o		~~FirstEnergy Corp. and FirstEnergy Solutions Corp.~~



Yes o No þ		~~FirstEnergy Corp. and FirstEnergy Solutions Corp.~~

GLOSSARY OF TERMS, Continued

AEP	American Electric Power Company, Inc.
AFS	Available-for-sale
AFUDC	Allowance for Funds Used During Construction
ALJ	Administrative Law Judge
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement Obligation
ARP	Alternative Revenue Program
ARR	Auction Revenue Right
ASC	Accounting Standard Codification
ASU	Accounting Standards Update
Bankruptcy Court	U.S. Bankruptcy Court in the Northern District of Ohio in Akron
BGS	Basic Generation Service
BNSF	BNSF Railway Company
BRA	PJM RPM Base Residual Auction
BSPC	Bay Shore Power Company
CAA	Clean Air Act
CCR	Coal Combustion Residuals
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980
CFR	Code of Federal Regulations
CO₂	Carbon Dioxide
CPP	EPA's Clean Power Plan
CSAPR	Cross-State Air Pollution Rule
CSX	CSX Transportation, Inc.
CTA	Consolidated Tax Adjustment
CWA	Clean Water Act
DCR	Delivery Capital Recovery
DMR	Distribution Modernization Rider
DOE	United States Department of Energy
DPM	Distribution Platform Modernization
DR	Demand Response
DSIC	Distribution System Improvement Charge
DSP	Default Service Plan
EDC	Electric Distribution Company
EDCP	Executive Deferred Compensation Plan
EE&C	Energy Efficiency and Conservation
EGS	Electric Generation Supplier
ELPC	Environmental Law & Policy Center
EmPOWER Maryland	EmPOWER Maryland Energy Efficiency Act
ENEC	Expanded Net Energy Cost
EPA	United States Environmental Protection Agency
EPS	Earnings per Share
ERO	Electric Reliability Organization
ESP IV	Electric Security Plan IV
ESP IV PPA	Unit Power Agreement entered into on April 1, 2016 by and between the Ohio Companies and FES
Facebook®	Facebook is a registered trademark of Facebook, Inc.
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
FMB	First Mortgage Bond
FPA	Federal Power Act
FTR	Financial Transmission Right
GAAP	Accounting Principles Generally Accepted in the United States of America
~~GHG~~	~~Greenhouse Gases~~
~~HCl~~	~~Hydrochloric Acid~~
~~ICE~~	~~Intercontinental Exchange, Inc.~~
~~IRP~~	~~Integrated Resource Plan~~
~~IRS~~	~~Internal Revenue Service~~
kV	~~Kilovolt~~
~~KWH~~	~~Kilowatt-hour~~
~~LOC~~	~~Letter of Credit~~
~~LS Power~~	~~LS Power Equity Partners III, LP~~
~~LTIIPs~~	~~Long-Term Infrastructure Improvement Plans~~
~~MATS~~	~~Mercury and Air Toxics Standards~~

GLOSSARY OF TERMS, Continued

GHG	Greenhouse Gases
HCl	Hydrochloric Acid
ICE	Intercontinental Exchange, Inc.
IIP	Infrastructure Investment Program
IRP	Integrated Resource Plan
IRS	Internal Revenue Service
kV	Kilovolt
KWH	Kilowatt-hour
LBR	Little Blue Run
LOC	Letter of Credit
LS Power	LS Power Equity Partners III, LP
LSE	Load Serving Entity
LTIIPs	Long-Term Infrastructure Improvement Plans
MATS	Mercury and Air Toxics Standards
MDPSC	Maryland Public Service Commission
MISO	Midcontinent Independent System Operator, Inc.
MLP	Master Limited Partnership
mmBTU	~~One~~ Million British Thermal Units
Moody’s	Moody’s Investors Service, Inc.
MOPR	Minimum Offer Price Rule
MVP	Multi-Value Project
MW	Megawatt
MWH	Megawatt-hour
NAAQS	National Ambient Air Quality Standards
NDT	Nuclear Decommissioning Trust
NERC	North American Electric Reliability Corporation
NJAPA	New Jersey Administrative Procedure Act
NJBPU	New Jersey Board of Public Utilities
NOL	Net Operating Loss
NOPR	Notice of Proposed Rulemaking
NOV	Notice of Violation
NOx	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
NRC	Nuclear Regulatory Commission
NS	Norfolk Southern Corporation
NSR	New Source Review
NUG	Non-Utility Generation
NYPSC	New York State Public Service Commission
OCA	Office of Consumer Advocate
OCC	Ohio Consumers' Counsel
OPEB	Other Post-Employment Benefits
OPIC	Other Paid-in Capital
ORC	Ohio Revised Code
OTTI	Other Than Temporary Impairments
OVEC	Ohio Valley Electric Corporation
PA DEP	Pennsylvania Department of Environmental Protection
PCB	Polychlorinated Biphenyl
PCRB	Pollution Control Revenue Bond
PJM	PJM Interconnection, L.L.C.
PJM Region	The aggregate of the zones within PJM
PJM Tariff	PJM Open Access Transmission Tariff
PM	Particulate Matter

GLOSSARY OF TERMS, Continued

POLR	Provider of Last Resort
POR	Purchase of Receivables
PPA	Purchase Power Agreement
PPB	Parts Per Billion
PPUC	Pennsylvania Public Utility Commission
PSA	Power Supply Agreement
PSD	Prevention of Significant Deterioration
PUCO	Public Utilities Commission of Ohio
PURPA	Public Utility Regulatory Policies Act of 1978
RCRA	Resource Conservation and Recovery Act
REC	Renewable Energy Credit
Regulation FD	Regulation Fair Disclosure promulgated by the SEC
REIT	Real Estate Investment Trust
RFC	ReliabilityFirst Corporation
RFP	Request for Proposal
RGGI	Regional Greenhouse Gas Initiative
ROE	Return on Equity

~~GLOSSARY OF TERMS,~~ ~~Continued~~

RRS	Retail Rate Stability
RSS	Rich Site Summary
RTEP	Regional Transmission Expansion Plan
RTO	Regional Transmission Organization
RWG	Restructuring Working Group
S&P	Standard & Poor’s Ratings Service
SB310	Substitute Ohio Senate Bill No. 310
SBC	Societal Benefits Charge
SEC	United States Securities and Exchange Commission
Seventh Circuit	United States Court of Appeals for the Seventh Circuit
SIP	State Implementation Plan(s) Under the Clean Air Act
SO₂	Sulfur Dioxide
Sixth Circuit	United States Court of Appeals for the Sixth Circuit
SOS	Standard Offer Service
SPE	Special Purpose Entity
SREC	Solar Renewable Energy Credit
SSO	Standard Service Offer
Tax Act	Tax Cuts and Jobs Act, adopted December 22, 2017
TDS	Total Dissolved Solid
TMI-2	Three Mile Island Unit 2
TO	Transmission Owner
Twitter®	Twitter is a registered trademark of Twitter, Inc.
U.S. Court of Appeals for the D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
VEPCO	Virginia Electric and Power Company
VIE	Variable Interest Entity
VMP	Vegetation Management Plan
VMS	Vegetation Management Surcharge
VSCC	Virginia State Corporation Commission
WVDEP	West Virginia Department of Environmental Protection
WVPSC	Public Service Commission of West Virginia


	For the Three Months Ended September 30						For the Nine Months Ended September 30						For the Three Months Ended March 31,
(In millions, except per share amounts)	2017			2016			2017			2016			2018			2017

REVENUES:
Regulated Distribution	$	2,610		$	2,691		$	7,362		$	7,390		$	2,576		$	2,500
Regulated Transmission	342			294			982			851			323			313
Unregulated businesses	762			932			2,231			2,946
Other													77			42
Total revenues*	3,714			3,917			10,575			11,187			2,976			2,855

OPERATING EXPENSES:
Fuel	363			450			1,074			1,269			187			204
Purchased power	861			979			2,459			2,992			825			791
Other operating expenses	942			953			3,041			2,835			962			657
Provision for depreciation	289			311			845			974			294			250
Amortization of regulatory assets, net	91			98			215			222
Amortization (deferral) of regulatory assets, net													(148		)	83
General taxes	253			265			777			786			259			242
Impairment of assets (Note 14)	31			—			162			1,447
Total operating expenses	2,830			3,056			8,573			10,525			2,379			2,227

OPERATING INCOME	884			861			2,002			662			597			628

OTHER INCOME (EXPENSE):
Investment income	37			28			78			75
Miscellaneous income													67			14
Interest expense	(305		)	(286		)	(882		)	(863		)	(250		)	(245		)
Capitalized financing costs	19			28			59			79			15			12
Total other expense	(249		)	(230		)	(745		)	(709		)	(168		)	(219		)

INCOME (LOSS) BEFORE INCOME TAXES	635			631			1,257			(47		)
INCOME BEFORE INCOME TAXES													429			409

INCOME TAXES	239			251			482			334			252			152

NET INCOME (LOSS)	$	396		$	380		$	775		$	(381	)
INCOME FROM CONTINUING OPERATIONS													177			257

EARNINGS (LOSS) PER SHARE OF COMMON STOCK:
Basic	$	0.89		$	0.89		$	1.75		$	(0.90	)
Diluted	$	0.89		$	0.89		$	1.74		$	(0.90	)
Discontinued operations (net of income tax benefits of $890 and $26) (Note 3)													1,192			(52		)

NET INCOME													$	1,369		$	205

INCOME ALLOCATED TO PREFERRED STOCKHOLDERS (Note 4)													156			—

NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS													$	1,213		$	205

EARNINGS PER SHARE OF COMMON STOCK (Note 4):
Basic - Continuing Operations													$	0.04		$	0.58
Basic - Discontinued Operations													2.51			(0.12		)
Basic - Net Income Attributable to Common Stockholders													$	2.55		$	0.46

Diluted - Continuing Operations													$	0.04		$	0.58
Diluted - Discontinued Operations													2.50			(0.12		)
Diluted - Net Income Attributable to Common Stockholders													$	2.54		$	0.46

WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic	444			425			444			425			476			443
Diluted	446			427			445			425			478			444

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	0.72		$	0.72		$	1.44		$	1.44		$	0.72		$	0.72


(In millions, except share amounts)	September 30, 2017			December 31, 2016			March 31, 2018			December 31, 2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	399		$	199		$	248		$	588
Restricted cash							51			51
Receivables-
Customers, net of allowance for uncollectible accounts of $52 in 2017 and $53 in 2016	1,370			1,440
Other, net of allowance for uncollectible accounts of $1 in 2017 and 2016	172			175
Materials and supplies	543			564
Prepaid taxes	123			98
Derivatives	35			140
Collateral	146			176
Other	143			158
Customers, net of allowance for uncollectible accounts of $50 in 2018 and $49 in 2017							1,279			1,282
Affiliated companies, net of allowance for uncollectible accounts of $624							44			—
Other, net of allowance for uncollectible accounts of $1 in 2018 and 2017							159			170
Materials and supplies, at average cost							273			262
Prepaid taxes and other							254			151
Current assets - discontinued operations							2			606
	2,931			2,950			2,310			3,110
PROPERTY, PLANT AND EQUIPMENT:
In service	44,229			43,767			37,717			37,270
Less — Accumulated provision for depreciation	16,086			15,731			10,267			10,098
	28,143			28,036			27,450			27,172
Construction work in progress	1,355			1,351			1,120			1,004
	29,498			29,387			28,570			28,176

PROPERTY, PLANT AND EQUIPMENT, NET - DISCONTINUED OPERATIONS							353			1,057

INVESTMENTS:
Nuclear plant decommissioning trusts	2,632			2,514			800			822
Nuclear fuel disposal trust							251			251
Other	511			512			252			255
	3,143			3,026

ASSETS HELD FOR SALE (Note 14)	788			—
Investments - discontinued operations							—			1,875
							1,303			3,203
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	5,618			5,618			5,618			5,618
Regulatory assets	929			1,014			49			40
Other	742			1,153			592			697
Deferred charges and other assets - discontinued operations							—			356
	7,289			7,785			6,259			6,711
	$	43,649		$	43,148		$	38,795		$	42,257
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,076		$	1,685		$	1,157		$	558
Short-term borrowings	500			2,675			1,200			300
Accounts payable	924			1,043			1,005			827
Accrued taxes	520			580			530			533
Accrued compensation and benefits	337			363			254			257
Collateral	31			42			37			39
Other	867			738			882			626
Current liabilities - discontinued operations							—			973
	4,255			7,126			5,065			4,113
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 700,000,000 shares - 444,858,003 and 442,344,218 shares outstanding as of September 30, 2017 and December 31, 2016, respectively	44			44
Stockholders’ equity-
Common stock, $0.10 par value, authorized 700,000,000 shares - 476,909,318 and 445,334,111 shares outstanding as of March 31, 2018 and December 31, 2017, respectively							48			44
Mandatorily convertible preferred stock, $100 par value, authorized 5,000,000 shares - 1,616,000 shares issued and outstanding as of March 31, 2018							162			—
Other paid-in capital	9,974			10,555			11,937			10,001
Accumulated other comprehensive income	151			174			86			142
Accumulated deficit	(3,763		)	(4,532		)	(4,858		)	(6,262		)
Total common stockholders’ equity	6,406			6,241
Total stockholders’ equity							7,375			3,925
Long-term debt and other long-term obligations	21,089			18,192			16,740			18,816
	27,495			24,433			24,115			22,741
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	4,225			3,765			2,505			3,171
Retirement benefits	3,814			3,719			2,717			3,975
Regulatory liabilities							2,632			2,720
Asset retirement obligations	1,550			1,482			580			570
Deferred gain on sale and leaseback transaction	732			757
Adverse power contract liability	143			162			124			130
Other	1,435			1,704			1,057			1,438
Noncurrent liabilities - discontinued operations							—			3,399
	11,899			11,589			9,615			15,403
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 11)
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 14)
	$	43,649		$	43,148		$	38,795		$	42,257


	For the Nine Months Ended September 30						For the Three Months Ended March 31,
(In millions)	2017			2016			2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	775		$	(381	)
Adjustments to reconcile net income (loss) to net cash from operating activities-
Net income							$	1,369		$	205
Adjustments to reconcile net income to net cash from operating activities-
Gain on deconsolidation, net of tax (Note 3)							(1,239		)	—
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs	1,248			1,477			280			416
Deferred purchased power and other costs	55			(34		)
Deferred income taxes and investment tax credits, net	453			318			278			114
Impairment of assets (Note 14)	162			1,447
Investment impairments	10			13
Deferred costs on sale leaseback transaction, net	37			36
Retirement benefits, net of payments	28			45			(46		)	10
Pension trust contributions	—			(297		)	(1,250		)	—
Unrealized (gain) loss on derivative transactions (Note 8)	64			(10		)
Lease payments on sale and leaseback transaction	(47		)	(94		)
Unrealized (gain) loss on derivative transactions							(10		)	47
Changes in current assets and liabilities-
Receivables	73			(34		)	32			68
Materials and supplies	(6		)	45			36			11
Prepaid taxes and other current assets	(41		)	(28		)
Prepaid taxes and other							(144		)	(111		)
Accounts payable	(22		)	(17		)	96			45
Accrued taxes	(161		)	(81		)	(145		)	(131		)
Accrued compensation and benefits	(54		)	2			(108		)	(137		)
Other current liabilities	13			53			(15		)	20
Collateral, net	19			25			(7		)	58
Other	156			107			(7		)	170
Net cash provided from operating activities	2,762			2,592
Net cash provided from (used for) operating activities							(880		)	785

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	4,050			521			—			250
Short-term borrowings, net	—			1,275			900			75
Preferred stock issuance							1,616			—
Common stock issuance							850			—
Redemptions and Repayments-
Long-term debt	(1,711		)	(1,017		)	(1,476		)	(211		)
Short-term borrowings, net	(2,175		)	—
Preferred stock dividend payments							(21		)	—
Common stock dividend payments	(478		)	(458		)	(171		)	(159		)
Other	(67		)	(17		)	(19		)	(13		)
Net cash (used for) provided from financing activities	(381		)	304
Net cash provided from (used for) financing activities							1,679			(58		)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,847		)	(2,156		)	(583		)	(588		)
Nuclear fuel	(156		)	(195		)	—			(132		)
Proceeds from asset sales							20			—
Sales of investment securities held in trusts	1,923			1,361			300			738
Purchases of investment securities held in trusts	(1,995		)	(1,437		)	(322		)	(761		)
Notes receivable from affiliated companies							(500		)	—
Asset removal costs	(130		)	(101		)	(57		)	(35		)
Other	24			52			(1		)	(1		)
Net cash used for investing activities	(2,181		)	(2,476		)
Net cash used for investing activites							(1,143		)	(779		)

Net change in cash and cash equivalents	200			420
Cash and cash equivalents at beginning of period	199			131
Cash and cash equivalents at end of period	$	399		$	551
Net change in cash and cash equivalents and restricted cash							(344		)	(52		)
Cash and cash equivalents and restricted cash at beginning of period							643			260
Cash and cash equivalents and restricted cash at end of period							$	299		$	208

SUPPLEMENTAL CASH FLOW INFORMATION:
Non-cash transaction, beneficial conversion feature (Note 4)							$	296		$	—
Non-cash transaction, deemed dividend preferred stock (Note 4)							$	(113	)	$	—



Note Number		Page Number

1	Organization and Basis of Presentation	6

2	Revenue	8

3	Discontinued Operations	10

4	Earnings Per Share of Common Stock	14

5	Pension and Other Postemployment Benefits	15

6	Accumulated Other Comprehensive Income	17

7	Income Taxes	18

8	Variable Interest Entities	18

9	Fair Value Measurements	20

10	Derivative Instruments	23

11	Capitalization	24

12	Asset Retirement Obligations	25

13	Regulatory Matters	26

14	Commitments, Guarantees and Contingencies	33

15	Segment Information	37

16	Subsequent Events	39



	For the Three Months Ended March 31, 2018
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments ⁽¹⁾			Total
	(In millions)
Distribution services ⁽²⁾	$	1,281	$	—	$	(12	)	$	1,269
Retail generation	1,040		—		(14		)	1,026
Wholesale sales	123		—		120			243
Transmission ⁽²⁾	—		319		—			319
Other	35		—		—			35
Total revenues from contracts with customers	$	2,479	$	319	$	94		$	2,892
ARP	64		—		—			64
Other non-customer revenue	33		4		(17		)	20
Total revenues	$	2,576	$	323	$	77		$	2,976



	For the Three Months Ended March 31, 2018
Revenues by Customer Class	For the Three Months Ended March 31, 2018
	(In millions)
Residential	$	1,463
Commercial	580
Industrial	254
Other	24
Total Revenues	$	2,321



	For the Three Months Ended March 31, 2018
Revenues by Transmission Asset Owner	For the Three Months Ended March 31, 2018
	(In millions)
ATSI	$	159
TrAIL	62
MAIT	31
Other	71
Total Revenues	$	323



(In millions)
Removal of investment in FES and FENOC	$	2,193
Assumption of benefit obligations retained at FE (including Pension, OPEB and EDCP)	(820		)
Guarantees and credit support provided by FE	(139		)
Reserve on receivables and allocated Pension/OPEB mark-to-market	(914		)
Gain on deconsolidation of FES and FENOC, before tax	320
Income tax benefit including estimated worthless stock deduction	919
Gain on deconsolidation of FES and FENOC	$	1,239



(In millions)	March 31, 2018		December 31, 2017

Carrying amount of the major classes of assets included in discontinued operations:
Cash	$	—	$	1
Restricted cash	—		3
Receivables	—		202
Materials and supplies	2		201
Collateral	—		130
Other current assets	—		69
Total current assets	2		606

Property, plant and equipment	353		1,057
Investments	—		1,875
Other non-current assets	—		356
Total non-current assets	353		3,288
Total assets included in discontinued operations	$	355	$	3,894

Carrying amount of the major classes of liabilities included in discontinued operations:
Currently payable long-term debt	$	—	$	524
Accounts payable	—		200
Accrued taxes	—		38
Accrued compensation and benefits	—		79
Other current liabilities	—		132
Total current liabilities	—		973

Long-term debt and other long-term obligations	—		2,299
Accumulated deferred income taxes ⁽¹⁾	—		(1,812		)
Asset retirement obligations	—		1,945
Deferred gain on sale and leaseback transaction	—		723
Other non-current liabilities	—		244
Total noncurrent liabilities	—		3,399
Total liabilities included in discontinued operations	$	—	$	4,372



(In millions, except per share amounts)	For the Three Months Ended March 31,
Reconciliation of Basic and Diluted Earnings per Share of Common Stock	2018			2017


Earnings Per Share of Common Stock
Income from continuing operations	$	177		$	257
Less: Preferred dividends	(43		)	—
Less: Amortization of beneficial conversion feature	(113		)	—
Less: Undistributed earnings allocated to preferred stockholders ⁽¹⁾	—			—
Income from continuing operations available to common stockholders	21			257
Discontinued operations, net of tax	1,192			(52		)
Less: Undistributed earnings allocated to preferred stockholders ⁽¹⁾	—			—
Income (loss) from discontinued operations available to common stockholders	1,192			(52		)

Income available to common stockholders, basic and diluted	$	1,213		$	205

Share Count information:
Weighted average number of basic shares outstanding	476			443
Assumed exercise of dilutive stock options and awards	2			1
Assumed conversion of preferred stock	—			—
Weighted average number of diluted shares outstanding	478			444

Income available to common stockholders, per common share:
Income from continuing operations, basic	$	0.04		$	0.58
Discontinued operations, basic	2.51			(0.12		)
Income available to common stockholders, basic	$	2.55		$	0.46

Income from continuing operations, diluted	$	0.04		$	0.58
Discontinued operations, diluted	2.50			(0.12		)
Income available to common stockholders, diluted	$	2.54		$	0.46



Components of Net Periodic Benefit Costs (Credits)	Pension						OPEB
For the Three Months Ended September 30	2017			2016			2017			2016
	(In millions)
Service costs	$	52		$	48		$	1		$	2
Interest costs	97			99			7			7
Expected return on plan assets	(112		)	(100		)	(7		)	(7		)
Amortization of prior service costs (credits)	2			2			(20		)	(20		)
Net periodic costs (credits)	$	39		$	49		$	(19	)	$	(18	)



Net Periodic Benefit Expense (Credit)	Pension				OPEB
For the Three Months Ended September 30	2017		2016		2017			2016
	(In millions)
FirstEnergy	$	30	$	35	$	(14	)	$	(11	)
FES	3		5		(4		)	(4		)



FirstEnergy	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance as of July 1, 2017	$	(26	)	$	61		$	128		$	163

Other comprehensive income before reclassifications	—			27			—			27
Amounts reclassified from AOCI	4			(33		)	(19		)	(48		)
Other comprehensive income (loss)	4			(6		)	(19		)	(21		)
Income taxes (benefits) on other comprehensive income (loss)	1			(3		)	(7		)	(9		)
Other comprehensive income (loss), net of tax	3			(3		)	(12		)	(12		)

AOCI Balance as of September 30, 2017	$	(23	)	$	58		$	116		$	151

AOCI Balance as of July 1, 2016	$	(31	)	$	58		$	164		$	191

Other comprehensive income before reclassifications	—			21			—			21
Amounts reclassified from AOCI	2			(17		)	(18		)	(33		)
Other comprehensive income (loss)	2			4			(18		)	(12		)
Income taxes (benefits) on other comprehensive income (loss)	—			2			(7		)	(5		)
Other comprehensive income (loss), net of tax	2			2			(11		)	(7		)

AOCI Balance as of September 30, 2016	$	(29	)	$	60		$	153		$	184

	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance as of January 1, 2017	$	(28	)	$	52		$	150		$	174

Other comprehensive income before reclassifications	—			63			—			63
Amounts reclassified from AOCI	8			(55		)	(55		)	(102		)
Other comprehensive income (loss)	8			8			(55		)	(39		)
Income taxes (benefits) on other comprehensive income (loss)	3			2			(21		)	(16		)
Other comprehensive income (loss), net of tax	5			6			(34		)	(23		)

AOCI Balance as of September 30, 2017	$	(23	)	$	58		$	116		$	151

AOCI Balance as of January 1, 2016	$	(33	)	$	18		$	186		$	171

Other comprehensive income before reclassifications	—			109			—			109
Amounts reclassified from AOCI	6			(42		)	(54		)	(90		)
Other comprehensive income (loss)	6			67			(54		)	19
Income taxes (benefits) on other comprehensive income (loss)	2			25			(21		)	6
Other comprehensive income (loss), net of tax	4			42			(33		)	13

AOCI Balance as of September 30, 2016	$	(29	)	$	60		$	153		$	184



	For the Three Months Ended September 30						For the Nine Months Ended September 30						Affected Line Item in the Consolidated Statements of Income (Loss)
Reclassifications from AOCI⁽²⁾	2017			2016			2017			2016
	(In millions)
Gains & losses on cash flow hedges
Long-term debt	$	4		$	2		$	8		$	6		Interest expense
	(1		)	—			(3		)	(2		)	Income taxes
	$	3		$	2		$	5		$	4		Net of tax

Unrealized gains on AFS securities
Realized gains on sales of securities	$	(33	)	$	(17	)	$	(55	)	$	(42	)	Investment income
	12			7			20			16			Income taxes
	$	(21	)	$	(10	)	$	(35	)	$	(26	)	Net of tax

Defined benefit pension and OPEB plans
Prior-service costs	$	(19	)	$	(18	)	$	(55	)	$	(54	)	⁽¹⁾
	7			7			21			21			Income taxes
	$	(12	)	$	(11	)	$	(34	)	$	(33	)	Net of tax

⁽¹⁾ These AOCI components are included in the computation of net periodic pension cost. See Note 3, "Pension and Other Postemployment Benefits," for additional details.
⁽²⁾Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.



	Maximum Exposure		Discounted Lease Payments, net		Net Exposure
	(In millions)
FirstEnergy⁽¹⁾	$	1,095	$	873	$	222

⁽¹⁾ All amounts are associated with FES.



Level 1	-	Quoted prices for identical instruments in active market

Level 2	-	Quoted prices for similar instruments in active market
	-	Quoted prices for identical or similar instruments in markets that are not active
	-	Model-derived valuations for which all significant inputs are observable market data



Level 3	-	Valuation inputs are unobservable and significant to the fair value measurement


FirstEnergy

Recurring Fair Value Measurements	September 30, 2017											December 31, 2016												March 31, 2018										December 31, 2017
	Level 1		Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total			Level 1		Level 2		Level 3			Total			Level 1		Level 2			Level 3			Total
Assets	(In millions)																							(In millions)
Corporate debt securities	$	—	$	1,201		$	—		$	1,201		$	—		$	1,247		$	—		$	1,247		$	—	$	468	$	—		$	468		$	—	$	476		$	—		$	476
Derivative assets - commodity contracts	—		35			—			35			10			200			—			210
Derivative assets - FTRs	—		—			5			5			—			—			7			7			—		—		1			1			—		—			3			3
Derivative assets - NUG contracts⁽¹⁾	—		—			—			—			—			—			1			1
Equity securities⁽²⁾	1,045		—			—			1,045			925			—			—			925			288		—		—			288			297		—			—			297
Foreign government debt securities	—		92			—			92			—			78			—			78			—		24		—			24			—		23			—			23
U.S. government debt securities	—		152			—			152			—			161			—			161			—		28		—			28			—		21			—			21
U.S. state debt securities	—		274			—			274			—			246			—			246			—		245		—			245			—		247			—			247
Other⁽³⁾	399		152			—			551			199			123			—			322			248		30		—			278			588		38			—			626
Total assets	$	1,444	$	1,906		$	5		$	3,355		$	1,134		$	2,055		$	8		$	3,197		$	536	$	795	$	1		$	1,332		$	885	$	805		$	3		$	1,693

Liabilities
Derivative liabilities - commodity contracts	$	—	$	(12	)	$	—		$	(12	)	$	(6	)	$	(118	)	$	—		$	(124	)	$	—	$	—	$	—		$	—		$	—	$	(4	)	$	—		$	(4	)
Derivative liabilities - FTRs	—		—			(2		)	(2		)	—			—			(6		)	(6		)
Derivative liabilities - NUG contracts⁽¹⁾	—		—			(92		)	(92		)	—			—			(108		)	(108		)	—		—		(74		)	(74		)	—		—			(79		)	(79		)
Total liabilities	$	—	$	(12	)	$	(94	)	$	(106	)	$	(6	)	$	(118	)	$	(114	)	$	(238	)	$	—	$	—	$	(74	)	$	(74	)	$	—	$	(4	)	$	(79	)	$	(83	)

Net assets (liabilities)⁽⁴⁾	$	1,444	$	1,894		$	(89	)	$	3,249		$	1,128		$	1,937		$	(106	)	$	2,959		$	536	$	795	$	(73	)	$	1,258		$	885	$	801		$	(76	)	$	1,610


⁽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.


⁽⁴⁾	Excludes ~~$(13)~~$(15) million and ~~$(3)~~$(11) million as of ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016,~~2017, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.


	NUG Contracts⁽¹⁾									FTRs									NUG Contracts⁽¹⁾									FTRs
	Derivative Assets			Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
	(In millions)																		(In millions)
January 1, 2016 Balance	$	1		$	(137	)	$	(136	)	$	8		$	(13	)	$	(5	)
January 1, 2017 Balance																			$	1		$	(108	)	$	(107	)	$	3		$	(1	)	$	2
Unrealized gain (loss)	2			(17		)	(15		)	(6		)	(4		)	(10		)	—			(10		)	(10		)	1			(1		)	—
Purchases	—			—			—			16			(7		)	9			—			—			—			3			—			3
Settlements	(2		)	46			44			(11		)	18			7			(1		)	39			38			(4		)	2			(2		)
December 31, 2016 Balance	$	1		$	(108	)	$	(107	)	$	7		$	(6	)	$	1
Unrealized loss	—			(14		)	(14		)	—			(2		)	(2		)
Purchases	—			—			—			5			(2		)	3
December 31, 2017 Balance																			$	—		$	(79	)	$	(79	)	$	3		$	—		$	3
Unrealized gain (loss)																			—			(2		)	(2		)	1			—			1
Settlements	(1		)	30			29			(7		)	8			1			—			7			7			(3		)	—			(3		)
September 30, 2017 Balance	$	—		$	(92	)	$	(92	)	$	5		$	(2	)	$	3
March 31, 2018 Balance																			$	—		$	(74	)	$	(74	)	$	1		$	—		$	1


⁽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.~~