FE will ~~pay certain pre-petition FES and FENOC employee-related obligations, which include unfunded pension obligations and other employee benefits, and provides for the waiver of~~waive all pre-petition claims (other than those claims under the Tax Allocation Agreement for the 2018 tax year) and certain post-petition claims, against the FES Debtors related to the FES Debtors and their businesses, including the full borrowings by FES under the $500 million secured credit facility, the $200 million credit agreement being used to

support surety bonds, the ~~BNSF/~~BNSF Railway Company/CSX Transportation, Inc. rail settlement guarantee, and the FES ~~Debtors'~~Debtors’ unfunded pension ~~obligations, all of which were previously accounted for in the first quarter of 2018 gain on deconsolidation.~~obligations.


•	A nonconsensual release of all claims against FirstEnergy by the FES Debtors’ creditors, which was subsequently waived pursuant to the Waiver Agreement, discussed below.


•	A $225 million cash payment from FirstEnergy.


•	A $628 million aggregate principal amount note issuance by FirstEnergy to the FES Debtors, which may be decreased by the amount, if any, of cash paid by FirstEnergy to the FES Debtors under the Intercompany Income Tax Allocation Agreement for the tax benefits related to the sale or deactivation of certain plants.

~~The full release of all claims against FirstEnergy by the FES Debtors and their creditors.~~

~~A $225 million cash payment from FirstEnergy.~~

A $628 million aggregate principal amount note issuance by FirstEnergy to the FES Debtors, which may be decreased by the amount, if any, of cash paid by FirstEnergy to the FES Debtors under the Intercompany Income Tax Allocation Agreement for the tax benefits related to the sale or deactivation of certain plants.

Transfer of the Pleasants Power Station and related assets, ~~to FES or its designee for~~including the ~~benefit~~economic interests therein as of ~~FES’ creditors, which resulted in a pre-tax charge of $43 million in the third quarter of 2018,~~January 1, 2019, and a requirement that FE continue to provide ~~FES~~ access to the ~~McElroy's~~McElroy’s Run CCR Impoundment Facility, which is not being transferred. ~~Prior to transfer and beginning no later than January 1, 2019, FES will acquire the economic interests in Pleasants and AE Supply will operate Pleasants until the transfer.~~ FE will provide ~~certain~~ guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility.

FirstEnergy agrees to waive all pre-petition claims related to shared services and credit nine-months of the FES Debtors' shared service costs beginning as of April 1, 2018, in an amount not to exceed $112.5 million, and FirstEnergy agrees to extend the availability of shared services until no later than June 30, 2020.


•	FirstEnergy agrees to waive all pre-petition claims related to shared services and credit for nine months of the FES Debtors’ shared service costs beginning as of April 1, 2018 through December 31, 2018, in an amount not to exceed $112.5 million, and FirstEnergy agrees to extend the availability of shared services until no later than June 30, 2020.

Subject to a cap, FirstEnergy has agreed to fund a pension enhancement through its pension plan, ~~a pension enhancement, subject to a cap, should FES offer a~~for voluntary enhanced retirement ~~package in 2019 and~~packages offered to certain FES employees, as well as offer certain other employee ~~benefits.~~

benefits (approximately $14 million recognized in the first nine months of 2019).

FirstEnergy agrees to perform under the ~~Intracompany~~Intercompany Tax Allocation Agreement through the FES Debtors’ emergence from bankruptcy, at which time FirstEnergy will waive a 2017 overpayment for NOLs of approximately $71 million, reverse 2018 estimated payments for NOLs of approximately $88 million and pay the FES Debtors for the use of NOLs in an amount no less than $66 million ~~(of which approximately $20 million has been paid through~~for 2018. Based on the 2018 federal tax return filed in September ~~30, 2018).~~

2019, FirstEnergy ~~has determined a loss is probable with respect to~~owes the FES ~~Bankruptcy and recorded a pre-tax charge in the third quarter of~~debtors approximately $31 million associated with 2018, ~~of $1.2 billion within Discontinued Operations,~~ which ~~reflects the current estimate of the commitments and payments under the settlement agreement.~~ will be paid upon emergence.

The FES Bankruptcy settlement agreement remains subject to satisfaction of the conditions set forth therein, most notably the issuance of a final order by the Bankruptcy Court approving the plan or plans of reorganization for the FES Debtors that are acceptable to FirstEnergy consistent with the requirements of the settlement agreement.certain conditions. There can be no assurance that such conditions will be satisfied or the FES Bankruptcy settlement agreement will be otherwise consummated, and the actual outcome of this matter may differ materially from the terms of the agreement described herein. FirstEnergy will continue to evaluate the impact of any new factors on the settlement and their relative impact on the financial statements.

In connection with the FES Bankruptcy settlement agreement, FirstEnergy entered into a separation agreement with the FES Debtors to implement the separation of the FES Debtors and their businesses from FirstEnergy. A business separation committee ~~has been~~was established between FirstEnergy and the FES Debtors to review and determine issues that arise in the context of the separation of the FES Debtors’ businesses from those of FirstEnergy.

As contemplated under the FES Bankruptcy settlement agreement, AE Supply entered into an agreement on December 31, 2018, to transfer the 1,300 MW Pleasants Power Station and related assets to FG, while retaining certain specified liabilities. Under the terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply will operate Pleasants until the transfer is completed. After closing, AE Supply will continue to provide access to the McElroy’s Run CCR Impoundment Facility, which is not being transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. The transfer of the Pleasants Power Station is subject to various customary and other closing conditions, including the effectiveness of a plan of reorganization for the FES Debtors in connection with the FES Bankruptcy. There can be no assurance that all closing conditions will be satisfied or that the transfer will be consummated.

On April 11, 2019, the Bankruptcy Court entered an order denying the FES Debtors’ disclosure statement approval motion. The Bankruptcy Court concluded that the nonconsensual third-party releases proposed under the plan of reorganization, which were a condition under the FES Bankruptcy settlement agreement for FirstEnergy’s benefit, were legally impermissible and rendered the plan unconfirmable.On April 18, 2019, FirstEnergy consented to the waiver of the condition. Additionally, the FES Debtors agreed to provide FirstEnergy with the same third-party release provided in favor of certain other parties in any plan of reorganization and to pay FirstEnergy approximately $60 million in cash (paid during the second quarter of 2019) to resolve certain outstanding pension and service charges totaling $87 million, which resulted in FirstEnergy recognizing a $27 million pre-tax charge to income in the first quarter of 2019 ($17 million of which was recognized in continuing operations). Further, the FES Debtors agreed to initiate negotiations with the EPA, OEPA, PA DEP and the NRC to obtain those parties’ cooperation with the FES Debtors’ revised plan of reorganization. FirstEnergy may choose to participate in those negotiations at its option. On May 20, 2019, the Bankruptcy Court approved the waiver and a revised disclosure statement.

In August 2019, the Bankruptcy Court held hearings to consider whether to confirm the FES Debtors’ plan of reorganization. Upon the conclusion of the hearing, the Bankruptcy Court ruled against the objections of several parties, including FERC and OVEC. However, the Bankruptcy Court ruled in favor of the objections made by certain of the FES Debtors’ unions regarding their collective bargaining agreements. The Bankruptcy Court adjourned the hearing without ruling on confirmation and explained that the only issue to be resolved was the acceptance or rejection by the FES Debtors of the collective bargaining agreements at issue.

United States District Court for the Northern District of Ohio appealing the Bankruptcy Court’s final order approving FES Debtors’ plan of reorganization. The emergence of the FES Debtors from bankruptcy pursuant to the confirmed plan of reorganization is subject to the satisfaction of certain conditions, including approvals from the FERC and NRC.

Capitalized Financing Costs

For each of the three months ended September 30, ~~2018~~2019 and ~~2017,~~2018, capitalized financing costs on ~~FirstEnergy's~~FirstEnergy’s Consolidated Statements of Income (Loss) include ~~$11~~$12 million and $8$11 million, respectively, of allowance for equity funds used during construction and $7 million and $5 million, respectively, of capitalized interest. For each of the nine months ended September 30, ~~2018~~2019 and ~~2017,~~2018, capitalized financing costs on ~~FirstEnergy's~~FirstEnergy’s Consolidated Statements of Income (Loss) include ~~$33~~$34 million and ~~$25~~$33 million, respectively, of allowance for equity funds used during construction and $19 million and $14 million, respectively, of capitalized interest.

Restricted Cash

Restricted cash primarily relates to the consolidated ~~VIE's~~VIE’s discussed in Note ~~8, "Variable~~10, “Variable Interest Entities."” The cash collected from JCP&L, MP, PE and the Ohio ~~Companies'~~Companies’ customers is used to service debt of their respective funding companies.

~~Goodwill~~

FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise. For 2018, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission reporting units' goodwill, assessing economic, industry and market considerations in addition to the reporting units' overall financial performance. Key factors used in the assessment include: growth rates, interest rates, expected capital expenditures, utility sector market performance and other market considerations. It was determined that the fair value of these reporting units was, more likely than not, greater than their carrying value and a quantitative analysis was not necessary.

New Accounting Pronouncements

Recently Adopted Pronouncements

ASU ~~2014-09,~~ 2016-02, "~~Revenue from Contracts with Customers"~~Leases (Topic 842)" (Issued ~~May 2014~~February 2016 and subsequently updated to address implementation questions): The new ~~revenue recognition~~ guidance ~~establishes~~requires 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, as well as new qualitative and quantitative disclosures. FirstEnergy implemented a ~~new control-based revenue recognition model, changes~~third-party software tool that assisted with the ~~basis for deciding when revenue is recognized over time or at a point~~initial adoption and will assist with ongoing compliance. FirstEnergy chose to apply the requirements of the standard 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 recognition practices upon~~period of adoption (January 1, 2019) with no restatement of prior periods. Upon adoption, on January 1, ~~2018. As part~~2019, FirstEnergy increased assets and liabilities by $186 million, with no impact to results of the adoption, FirstEnergy elected to apply the new guidance on a modified retrospective 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 timingoperations or ~~amount of revenue. In addition, upon adoption, certain immaterial financial statement presentation changes were implemented.~~cash flows. See Note ~~2, "Revenue,~~8, "Leases," for additional information on FirstEnergy's ~~revenues.~~leases.

~~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 pre-tax cumulative effect adjustment to retained earnings of $115 million on January 1, 2018, representing unrealized gains on equity securities with FES NDTs that were previously recorded to AOCI. Following deconsolidation of the FES Debtors, 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 reports changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents. Prior periods have been recast 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): ASU 2017-04 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, 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 (1) disaggregate the current-service-cost component from the other components of net benefit cost (the other components) and present it with other current 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. 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 $7 million and $23 million of non-service costs from Other operating expenses to Miscellaneous income, net, for the three and nine months ended September 30, 2017, respectively.

~~ASU 2018-02, "Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income~~" (Issued February 2018): ASU 2018-02 allows entities to reclassify from AOCI to retained earnings stranded tax effects resulting from the 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 the FES Debtors.

~~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 December 31, 2017. 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 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~~

ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of ~~pronouncements contained in the 2017 Annual Report~~Credit Losses on ~~Form 10-K.~~

~~ASU 2016-02,~~ ~~"Leases (Topic 842)~~"Financial Instruments” (Issued ~~February~~June 2016 and subsequently ~~updated to address implementation questions)~~updated): ~~The new guidance~~ASU 2016-13 removes all recognition thresholds and will require ~~organizations that lease assets with lease terms of more than 12 months~~companies to recognize ~~assets and liabilities~~an allowance for credit losses for the ~~rights~~difference between the amortized cost basis of a financial instrument and obligations created by those leases on their balance sheets as well as new qualitative and quantitative disclosures. FirstEnergy expects an increase in assets and liabilities; however, it is currently assessing the ~~impact, including monitoring utility industry implementation guidance, but expects no impact to results~~amount of operations or cash flows. FirstEnergy has developed its complete lease inventory and continues to identify, assess and document technical accounting issues, policy considerations, financial reporting implications and changes to internal controls and processes. In addition, FirstEnergy is inamortized cost that the process of implementing a third-party software tool that will assist with the initial adoption and ongoing compliance. The standard provides a number of transition practical expedients that entities may elect. These include a "package of three" expedients that must be taken together and allow entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. A separate practical expedient allows entities to not evaluate land easements under the new guidance at adoption if they were not previously accounted for as leases. Additionally, entities have the option to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. FirstEnergycompany expects to ~~elect all of these practical expedients.~~collect over the instrument’s contractual life. The ~~guidance will be~~ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, ~~2018,~~2019, with early adoption permitted. FirstEnergy has analyzed its financial instruments within the scope of this guidance, primarily trade receivables and AFS debt securities, and does not expect a material impact to ~~adopt this standard early.~~its financial statements upon adoption in 2020.

ASU 2018-15, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract" (Issued August 2018): ASU 2018-15 requires implementation costs incurred by customers in cloud computing arrangements to be deferred and recognized over the term of the arrangement, if those costs would be capitalized by the customers in a software licensing arrangement. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted.

~~ASU 2018-14, "Compensation-Retirement Benefits-Defined Benefit Plans-General (Subtopic 715-20): Disclosure Framework-Changes~~ FirstEnergy does not expect a material impact to ~~the Disclosure Requirements for Defined Benefit Plans~~" (Issued August 2018): ASU 2018-14 amends ASC 715 to add, remove, and clarify disclosure requirements related to defined benefit pension and other postretirement plans. The guidance is required to be applied on a retrospective basis and will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020, with earlyits financial statements upon adoption ~~permitted.~~

~~ASU 2018-13, "Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement~~" (Issued August 2018): ASU 2018-14 eliminates, adds and modifies certain disclosure requirements for fair value measurements as part of the FASB's disclosure framework project. Entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, but public companies will be required to disclose the range and weighted average used to develop significant unobservable inputs for Level 3 fair value measurements. The guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, but entities are permitted to early adopt either the entire standard or only the provisions that eliminate or modify the requirements.

in 2020.

2. REVENUE

FirstEnergy accounts for revenues from contracts with customers under ASC 606, “Revenue from Contracts with Customers, which became effective January 1, 2018. As part of the adoption of ASC 606, FirstEnergy applied the new standard on a modified retrospective basis analyzing open contracts as of January 1, 2018. However, no cumulative effect adjustment to retained earnings was necessary as no revenue recognition differences were identified when comparing the revenue recognition criteria under ASC 606 to previous requirements.

Customers.” Revenue from leases, financial instruments, other contractual rights or obligations and other revenues that are not from contracts with customers are outside the scope of the new standard and accounted for under other existing GAAP. FirstEnergy has elected to exclude sales taxes and other similar taxes collected on behalf of third parties from revenue as prescribed in the new standard. As a result, tax collections and remittances ~~within the scope of this election~~ are excluded from recognition in the income statement and instead recorded through the balance ~~sheet, consistent with FirstEnergy’s accounting process prior to the adoption of ASC 606.~~sheet. Excise and gross receipts taxes that are assessed on FirstEnergy are not subject to the election and are included in revenue. FirstEnergy has elected the optional invoice practical expedient for most of its revenues and, with the exception of JCP&L transmission, utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations. ~~For a qualitative overview of FirstEnergy's performance obligations, see below.~~

FirstEnergy’s revenues are primarily derived from electric service provided by ~~its~~the Utilities and ~~transmission (ATSI, TrAIL and MAIT) subsidiaries.~~Transmission Companies.

The following tables represent a disaggregation of revenue from contracts with customers for the three ~~and nine~~ months ended September 30, 2019 and 2018, by type of service from each reportable segment:


	For the Three Months Ended September 30, 2018									For the Three Months Ended September 30, 2019
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments ⁽¹⁾			Total		Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments ⁽¹⁾			Total
	(In millions)									(In millions)
Distribution services⁽²⁾	$	1,440	$	—	$	(22	)	$	1,418	$	1,457	$	—	$	(21	)	$	1,436
Retail generation	1,059		—		(14		)	1,045		989		—		(14		)	975
Wholesale sales⁽²⁾	133		—		6			139		100		—		2			102
Transmission⁽²⁾	—		341		—			341		—		371		—			371
Other	43		—		—			43		42		—		—			42
Total revenues from contracts with customers	$	2,675	$	341	$	(30	)	$	2,986	$	2,588	$	371	$	(33	)	$	2,926
ARP	66		—		—			66		25		—		—			25
Other non-customer revenue	25		5		(18		)	12		23		4		(15		)	12
Total revenues	$	2,766	$	346	$	(48	)	$	3,064	$	2,636	$	375	$	(48	)	$	2,963

⁽¹⁾ Includes eliminations and reconciling adjustments of inter-segment revenues.

⁽²⁾Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($4 million at Regulated Distribution and $4 million at Regulated Transmission) and Rider DMR as discussed in Note 12, “Regulatory Matters” (approximately $31 million at Regulated Distribution).



	For the Three Months Ended September 30, 2018
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments ⁽¹⁾			Total
	(In millions)
Distribution services⁽²⁾	$	1,440	$	—	$	(22	)	$	1,418
Retail generation	1,059		—		(14		)	1,045
Wholesale sales	133		—		6			139
Transmission⁽²⁾	—		341		—			341
Other	43		—		—			43
Total revenues from contracts with customers	$	2,675	$	341	$	(30	)	$	2,986
ARP	66		—		—			66
Other non-customer revenue	25		5		(18		)	12
Total revenues	$	2,766	$	346	$	(48	)	$	3,064

⁽¹⁾ Includes eliminations and reconciling adjustments of inter-segment revenues.

⁽²⁾Includes $29 million in net reductions to revenue related to amounts subject to refund resulting from the Tax Act ($27 million at Regulated Distribution and $2 million at Regulated Transmission).

Other non-customer revenue includes revenue from late payment charges of $9 million for both the three months ended September 30, 2019 and 2018, as well as revenue from derivatives of $2 million and $4 million, for the three months ended September 30, 2019 and 2018, respectively.

The following tables represent a disaggregation of revenue from contracts with customers for the nine months ended September 30, 2019 and 2018, by type of service from each reportable segment:


	For the Nine Months Ended September 30, 2018									For the Nine Months Ended September 30, 2019
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments⁽¹⁾			Total		Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments ⁽¹⁾			Total
	(In millions)									(In millions)
Distribution services⁽²⁾	$	3,949	$	—	$	(81	)	$	3,868	$	3,903	$	—	$	(63	)	$	3,840
Retail generation	2,981		—		(42		)	2,939		2,853		—		(42		)	2,811
Wholesale sales⁽²⁾	377		—		16			393		316		—		9			325
Transmission⁽²⁾	—		996		—			996		—		1,090		—			1,090
Other	113		—		4			117		113		—		1			114
Total revenues from contracts with customers	$	7,420	$	996	$	(103	)	$	8,313	$	7,185	$	1,090	$	(95	)	$	8,180
ARP	190		—		—			190		142		—		—			142
Other non-customer revenue	84		14		(50		)	48		74		13		(47		)	40
Total revenues	$	7,694	$	1,010	$	(153	)	$	8,551	$	7,401	$	1,103	$	(142	)	$	8,362

~~economic performance. FEV's ownership interest is subject to the equity method of accounting. In 2015, FirstEnergy fully impaired the value of its investment in Global Holding.~~

•

Global Holding - FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint ventures economic performance. FEV’s ownership interest is subject to the equity method of accounting. As of September 30, 2019, the carrying value of the equity method investment was $19 million.

As discussed in Note ~~14, "Commitments,~~13, “Commitments, Guarantees and Contingencies,"” FE is the guarantor under Global ~~Holding's~~Holding’s $300 million term loan facility, which matures in March 2020, and has an outstanding principal balance of ~~$220~~$145 million as of September 30, ~~2018.~~2019. Failure by Global Holding to meet the terms and conditions under its term loan facility could require FE to ~~be obligated~~perform its obligations under the provisions of its guarantee, resulting in consolidation of Global Holding by FE.

~~PATH WV~~ - PATH, a proposed transmission line from West Virginia through Virginia into Maryland which PJM cancelled in 2012, is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of FE owns 100% of the Allegheny Series (PATH-Allegheny) and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of PATH-WV. FirstEnergy's ownership interest in PATH-WV is subject to the equity method of accounting. As of September 30, 2018, the carrying value of the equity method investment was $17 million.

~~Purchase Power Agreements~~ - FirstEnergy evaluated its PPAs and determined that certain NUG entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production.

•

PATH WV - PATH, a proposed transmission line from West Virginia through Virginia into Maryland, which PJM cancelled in 2012, is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of FE owns 100% of the Allegheny Series (PATH-Allegheny) and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of PATH-WV. FirstEnergy’s ownership interest in PATH-WV is subject to the equity method of accounting. As of September 30, 2019, the carrying value of the equity method investment was $18 million.


•	Purchase Power Agreements - FirstEnergy evaluated its PPAs and determined that certain NUG entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production.

FirstEnergy maintains 1211 long-term PPAs with NUG entities that were entered into pursuant to PURPA. FirstEnergy was not involved in the creation of, and has no0 equity or debt invested in, any of these entities. FirstEnergy has determined that, for all but ~~one~~1 of these NUG entities, it does not have a variable interest or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold a variable interest in the remaining ~~one~~1 entity; however, it applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.

Because FirstEnergy has no0 equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred at its Regulated Distribution segment to be recovered from customers. Purchased power costs related to the contract that may contain a variable interest during the three months ended September 30, 2019 and 2018, ~~and 2017,~~ were ~~$27~~$30 million and ~~$29~~$27 million, respectively, and ~~$85~~$91 million and ~~$82~~$85 million during the nine months ended September 30, 2019 and 2018, ~~and 2017,~~ respectively.

~~FES and FENOC -~~ As a result of the Chapter 11 bankruptcy filing discussed in Note 3, "Discontinued Operations," FE evaluated its investments in FES and FENOC and determined they are VIEs. FE is not the primary beneficiary because it lacks a controlling interest in FES and FENOC, which are subject to the jurisdiction of the Bankruptcy Court as of March 31, 2018. The carrying values of the equity investments in FES and FENOC were zero at September 30, 2018.

•

FES and FENOC - As a result of the Chapter 11 bankruptcy filing discussed in Note 3, “Discontinued Operations,” FE evaluated its investments in FES and FENOC and determined they are VIEs. FE is not the primary beneficiary because it lacks a controlling interest in FES and FENOC, which are subject to the jurisdiction of the Bankruptcy Court. The carrying values of the equity investments in FES and FENOC were 0 at September 30, 2019.

9.11. FAIR VALUE MEASUREMENTS

RECURRING FAIR VALUE MEASUREMENTS

Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows:



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

Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.



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

FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast ~~which has been reviewed and approved by FirstEnergy's Risk Policy Committee,~~ are used to measure fair value.

FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term PJM auctions and are initially recorded using the auction clearing price less cost. After initial recognition, ~~FTRs'~~FTRs’ carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent PJM auction clearing prices and the ~~FTRs'~~FTRs’ remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. ~~Generally, significant~~Significant increases or decreases in inputs in isolation ~~could result~~may have resulted in a higher or lower fair value measurement. ~~See Note 10, "Derivative Instruments," for additional information regarding FirstEnergy's FTRs.~~

NUG contracts represent PPAs with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value and adjusted periodically using a mark-to-model methodology, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. Pricing for the NUG contracts is a combination of market prices for the current year and next two years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on ~~ICE~~Intercontinental Exchange, Inc. quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. ~~Generally, significant~~Significant increases or decreases in inputs in isolation ~~could result~~may have resulted in a higher or lower fair value measurement.

FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of September 30, ~~2018,~~2019, from those used as of December 31, ~~2017.~~2018. The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk was not significant to the fair value measurements.

2326

~~Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the nine months ended September 30, 2018.~~ The following tables set forth ~~FirstEnergy's~~the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy:



	September 30, 2018										December 31, 2017										September 30, 2019										December 31, 2018
	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	$	—	$	405	$	—		$	405		$	—	$	476	$	—		$	476		$	—	$	446	$	—		$	446		$	—	$	405	$	—		$	405
Derivative assets - FTRs	—		—		10			10			—		—		3			3
Equity securities⁽¹⁾	329		—		—			329			297		—		—			297
Derivative assets FTRs⁽¹⁾																					—		—		6			6			—		—		10			10
Equity securities⁽²⁾																					362		—		—			362			339		—		—			339
Foreign government debt securities	—		12		—			12			—		23		—			23			—		17		—			17			—		13		—			13
U.S. government debt securities	—		22		—			22			—		21		—			21			—		18		—			18			—		20		—			20
U.S. state debt securities	—		251		—			251			—		247		—			247			—		266		—			266			—		250		—			250
Other⁽²⁾	436		106		—			542			588		38		—			626
Other⁽³⁾																					716		71		—			787			367		34		—			401
Total assets	$	765	$	796	$	10		$	1,571		$	885	$	805	$	3		$	1,693		$	1,078	$	818	$	6		$	1,902		$	706	$	722	$	10		$	1,438

Liabilities
Derivative liabilities - FTRs	$	—	$	—	$	(1	)	$	(1	)	$	—	$	—	$	—		$	—
Derivative liabilities - NUG contracts⁽³⁾	—		—		(52		)	(52		)	—		—		(79		)	(79		)
Derivative liabilities FTRs⁽¹⁾																					$	—	$	—	$	(3	)	$	(3	)	$	—	$	—	$	(1	)	$	(1	)
Derivative liabilities NUG contracts⁽¹⁾																					—		—		(24		)	(24		)	—		—		(44		)	(44		)
Total liabilities	$	—	$	—	$	(53	)	$	(53	)	$	—	$	—	$	(79	)	$	(79	)	$	—	$	—	$	(27	)	$	(27	)	$	—	$	—	$	(45	)	$	(45	)

Net assets (liabilities)⁽⁴⁾	$	765	$	796	$	(43	)	$	1,518		$	885	$	805	$	(76	)	$	1,614		$	1,078	$	818	$	(21	)	$	1,875		$	706	$	722	$	(35	)	$	1,393


⁽¹⁾	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 S&P 500 Low Volatility High Dividend Index, S&P 500 Index, MSCI World Index and MSCI AC World IMI Index.


⁽²⁾⁽³⁾	Primarily consists of short-term cash investments.


⁽³⁾	~~NUG contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings.~~


⁽⁴⁾	Excludes ~~$(33)~~$(15) million and ~~$(11)~~$4 million as of September 30, ~~2018~~2019 and December 31, ~~2017,~~2018, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended September 30, ~~2018,~~2019, and December 31, ~~2017:~~

2018:

NUG Contracts⁽¹⁾
FTRs
Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net
(In millions)
January 1, 2017 Balance $ 1
$ (108 ) $ (107 ) $ 3
$ (1 ) $ 2
Unrealized gain (loss) —
(10 ) (10 ) 1
(1 ) —
Purchases —
—
—
3
—
3
Settlements (1 ) 39
38
(4 ) 2
(2 )
December 31, 2017 Balance $ —
$ (79 ) $ (79 ) $ 3
$ —
$ 3
Unrealized gain (loss) —
2
2
7
2
9
Purchases —
—
—
5
(5 ) —
Settlements —
25
25
(5 ) 2
(3 )
September 30, 2018 Balance $ —
$ (52 ) $ (52 ) $ 10
$ (1 ) $ 9



	NUG Contracts⁽¹⁾								FTRs⁽¹⁾
	Derivative Assets		Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
	(In millions)
January 1, 2018 Balance	$	—	$	(79	)	$	(79	)	$	3		$	—		$	3
Unrealized gain	—		2			2			8			1			9
Purchases	—		—			—			5			(5		)	—
Settlements	—		33			33			(6		)	3			(3		)
December 31, 2018 Balance	$	—	$	(44	)	$	(44	)	$	10		$	(1	)	$	9
Unrealized loss	—		(8		)	(8		)	—			(1		)	(1		)
Purchases	—		—			—			6			(4		)	2
Settlements	—		28			28			(10		)	3			(7		)
September 30, 2019 Balance	$	—	$	(24	)	$	(24	)	$	6		$	(3	)	$	3

(1)~~NUG contracts~~Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings.

Level 3 Quantitative Information

The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended September 30, ~~2018:~~

2019:

Fair Value, Net (In millions)

Valuation
Technique

Significant Input

Range

Weighted Average

Units

FTRs

Model

RTO auction clearing prices

$0.60 to $3.60

$1.20

Dollars/MWH

NUG Contracts

(24

)

Model

Generation

400 to 553,000

115,000

MWH

Regional electricity prices

$26.20 to $28.30

$27.20

Dollars/MWH

Fair Value, Net (In millions) Valuation
Technique Significant Input Range Weighted Average Units
FTRs $ 9
Model RTO auction clearing prices $(0.40) to $8.60 $1.40 Dollars/MWH

NUG Contracts $ (52 ) Model Generation 400 to 1,437,000 293,000
MWH
Regional electricity prices $30.60 to $32.70 $31.60 Dollars/MWH

INVESTMENTS

All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include equity securities, AFS debt securities and other investments. FirstEnergy has no debt securities held for trading purposes.

Generally, unrealized gains and losses on equity securities are recognized in income whereas unrealized gains and losses on AFS debt securities are recognized in AOCI. However, the NDTs and nuclear fuel disposal trusts of JCP&L, ME and PN are subject to regulatory accounting with all gains and losses on equity and AFS debt securities offset against regulatory assets.

The investment policy for the NDT funds restricts or limits the ~~trusts'~~trusts’ ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, securities convertible into common stock and securities of the trust ~~funds'~~funds’ custodian or managers and their parents or subsidiaries.

Nuclear Decommissioning and Nuclear Fuel Disposal Trusts

JCP&L, ME and PN hold debt and equity securities within their respective NDT and nuclear fuel disposal trusts. The debt securities are classified as AFS securities, recognized at fair market value.

The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in NDT and nuclear fuel disposal trusts as of September 30, ~~2018,~~2019, and December 31, ~~2017:~~2018:



	September 30, 2019⁽¹⁾									December 31, 2018⁽¹⁾
	Cost Basis		Unrealized Gains		Unrealized Losses			Fair Value		Cost Basis		Unrealized Gains		Unrealized Losses			Fair Value
	(In millions)

Debt securities	$	736	$	27	$	(14	)	$	749	$	714	$	2	$	(28	)	$	688
Equity securities	$	312	$	50	$	(2	)	$	360	$	339	$	15	$	(16	)	$	338

September 30, 2018⁽¹⁾

December 31, 2017⁽¹⁾
Cost Basis Unrealized Gains Unrealized Losses Fair Value Cost Basis Unrealized Gains Unrealized Losses Fair Value
(In millions)

Debt securities $ 712
$ 2
$ (23 ) $ 691
$ 774
$ 11

$ (17 ) $ 768
Equity securities $ 286
$ 42
$ (1 ) $ 327
$ 254
$ 40
$ —
$ 294

⁽¹⁾ Excludes $33 million and $20 million as of September 30, 2019 and December 31, 2018, respectively, of short-term cash investments, ~~of $57 million~~taxes, receivables, payables and ~~$11 million in 2018 and 2017, respectively~~accrued income.

Proceeds from the sale of investments in equity and AFS debt securities, realized gains and losses on those sales and interest and dividend income for the three and nine months ended September 30, ~~2018~~2019 and ~~2017,~~2018, were as follows:



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2019			2018			2019			2018
	(In millions)
Sale proceeds	$	204		$	261		$	506		$	627
Realized gains	8			3			20			31
Realized losses	(7		)	(7		)	(18		)	(34		)
Interest and dividend income	10			11			30			31

On October 15, 2019, JCP&L, ME, PN and GPUN executed an asset purchase and sale agreement with TMI-2 Solutions, LLC, a subsidiary of EnergySolutions, LLC, concerning the transfer and dismantlement of TMI-2. This transfer of TMI-2 to TMI-2 Solutions, LLC will include the transfer of: (i) the ownership and operating NRC licenses for TMI-2; (ii) the external trusts for the decommissioning and environmental remediation of TMI-2; and (iii) related liabilities of approximately $900 million as of September 30, 2019. There can be no assurance that the transfer will receive the required regulatory approvals and, even if approved, whether the conditions to the closing of the transfer will be satisfied.

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2018 2017 2018 2017
(In millions)
Sale Proceeds $ 261
$ 269
$ 627
$ 1,089
Realized Gains 3
20
31
70
Realized Losses (7 ) (11 ) (34 ) (55 )
Interest and Dividend Income 11
9
31
28

Other Investments

Other investments include employee benefit trusts, which are primarily invested in corporate-owned life insurance policies and equity method investments. Other investments were ~~$254~~$283 millionand$~~255~~253 million as of September 30, ~~2018,~~2019, and December 31, ~~2017,~~2018, respectively, and are excluded from the amounts reported above.

LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS

All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate their fair market value. The following table provides the approximate fair value and related carrying amounts of ~~FirstEnergy's~~ long-term debt, which excludes ~~capital~~finance lease obligations and net unamortized debt issuance costs, premiums and discounts as of September 30, ~~2018~~2019 and December 31, ~~2017:~~2018:



	September 30, 2019		December 31, 2018
	(In millions)
Carrying value ⁽¹⁾	$	19,880	$	18,315
Fair value	$	22,910	$	19,266

September 30, 2018 December 31, 2017
(In millions)
Carrying Value $ 17,796
$ 19,296
Fair Value $ 18,761
$ 21,412

⁽¹⁾The carrying value as of September 30, 2019, includes $2.1 billion of debt issuances and $784 million of redemptions that occurred in the first nine months of 2019.

The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of September 30, ~~2018,~~2019, and December 31, ~~2017.~~2018.

~~10. DERIVATIVE INSTRUMENTS~~

FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, coal and energy transmission. To manage the volatility related to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy 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. FirstEnergy also uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.

~~FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value (unless they meet the normal purchases and normal sales criteria) as follows:~~

Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings.

Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings.

~~Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted.~~

Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance.

~~FirstEnergy has contractual derivative agreements through 2020.~~

~~Cash Flow Hedges~~

FirstEnergy has used forward starting interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were designated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. Total pre-tax unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $16 million and $22 million as of September 30, 2018 and December 31, 2017, respectively. Based on current estimates, approximately $3 million of these unamortized losses are expected to be amortized to interest expense during the next twelve months.

~~Refer to Note 6, "Accumulated Other Comprehensive Income," for reclassifications from AOCI during the three and nine months ended September 30, 2018 and 2017.~~

~~As of September 30, 2018, and December 31, 2017, no commodity or interest rate derivatives were designated as cash flow hedges.~~

~~Fair Value Hedges~~

FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. As of September 30, 2018, and December 31, 2017, no fixed-for-floating interest rate swap agreements were outstanding.

Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $2 million and $3 million as of September 30, 2018 and December 31, 2017, respectively.

~~NUGs~~

As of September 30, 2018, and December 31, 2017, FirstEnergy's net liability position under NUG contracts was $52 million and $79 million, respectively, representing contracts held at JCP&L and PN. NUG contracts are classified as an adverse power contract liability on the Consolidated Balance Sheets. During the three and nine months ended September 30, 2018, there were settlements of $9 million and $25 million, and unrealized gains of $4 million and $2 million, respectively. Changes in the fair value of NUG contracts are subject to regulatory accounting treatment and do not impact earnings.

~~FTRs~~

As of September 30, 2018, and December 31, 2017, FirstEnergy's net asset position associated with FTRs was $9 million and $3 million, respectively. FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of PJM that have load serving obligations. For the three months ended September 30, 2018, there were no settlements and there were unrealized gains of $9 million. During the nine months ended September 30, 2018, there were settlements of $3 million and unrealized gains of $9 million.

~~11. CAPITALIZATION~~

~~Stock Issuance~~

On January 22, 2018, FirstEnergy entered into agreements for the private placement of its equity securities representing an approximately $2.5 billion investment in FE. FE entered into a Preferred Stock Purchase Agreement (the Preferred SPA) for the private placement of 1,616,000 shares of mandatorily convertible preferred stock, designated as the Series A Convertible Preferred

Stock, par value $100 per share, representing an investment of nearly $1.62 billion ($162 million of mandatorily convertible preferred stock and $1.46 billion of OPIC). FE also entered into a Common Stock Purchase Agreement for the private placement of 30,120,482 shares of FE’s common stock, par value $0.10 per share, representing an investment of $850 million ($3 million of Common Stock and $847 million of OPIC).

The Preferred Stock participates in dividends on the Common Stock on an as-converted basis based on the number of shares of Common Stock a holder of Preferred Stock would receive if its shares of Preferred Stock were converted on the dividend record date at the conversion price in effect at that time. Such dividends are paid at the same time that the dividends on Common Stock are paid.

Each share of Preferred Stock is convertible at the option of the holders into a number of shares of Common Stock equal to the $1,000 liquidation preference, divided by the Conversion Price then in effect. As of September 30, 2018, the Conversion Price in effect remained $27.42 per share. The Conversion Price is subject to anti-dilution adjustments and adjustments for subdivisions and combinations of the Common Stock, as well as dividends on the Common Stock paid in Common Stock and for certain equity issuances below the Conversion Price then in effect. As of September 30, 2018, 911,411 preferred shares have been converted into 33,238,910 common shares at the option of the holders.

In general, any shares of Preferred Stock outstanding on July 22, 2019, will be automatically converted. Further, the Preferred Stock will automatically convert to Common Stock upon certain events of bankruptcy or liquidation of FE. FE may elect to convert the Preferred Stock if, at any time, fewer than 323,200 shares of Preferred Stock are outstanding. However, no shares of Preferred Stock will be converted prior to January 22, 2020, if such conversion will cause a converting holder to be deemed to beneficially own, together with its affiliates whose holdings would be aggregated with such holder for purposes of Section 13(d) under the Exchange Act, more than 4.9% of the then-outstanding Common Stock. Furthermore, in no event shall the Company issue more than 58,964,222 shares of Common Stock (the Share Cap) in the aggregate upon conversion of the convertible Preferred Stock. From and after the time at which the aggregate number of shares of Common Stock issued upon conversion of the Preferred Stock equals the Share Cap, each holder electing to convert convertible Preferred Stock will be entitled to receive a cash payment equal to the market value of the Common Stock such holder does not receive upon conversion.

The holders of Preferred Stock have limited class voting rights related to the creation of additional securities that are senior or equal with the Preferred Stock, as well as certain reclassifications and amendments that would affect the rights of the holders of Preferred Stock. The holders of Preferred Stock also have the right to approve issuances of securities convertible or exchangeable for Common Stock, subject to certain exceptions for compensation arrangements and bona fide dividend reinvestment or share purchase plans.

Pursuant to the Preferred SPA, FirstEnergy formed an RWG composed of three employees of FirstEnergy and two outside members identified in the Preferred SPA to advise FirstEnergy management regarding FES' restructuring. On September 20, 2018, pursuant to the Preferred SPA, the RWG was terminated in light of the substantial completion of the RWG’s role.

12. ~~ASSET RETIREMENT OBLIGATIONS~~

FirstEnergy has recognized applicable legal obligations for AROs and their associated cost, primarily for the decommissioning of the TMI-2 nuclear generating facility and environmental remediation, including reclamation of sludge disposal ponds, closure of coal ash disposal sites, underground and above-ground storage tanks and wastewater treatment lagoons. In addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remediation.

FirstEnergy uses an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation AROs, considering the expected timing of settlement of the ARO based on the expected economic useful life of the plants. Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of settlement.

~~The aggregate ARO liabilities for FirstEnergy are approximately $630 million and $570 million as of September 30, 2018 and December 31, 2017, respectively.~~

In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards 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. On July 17, 2018, the EPA Administrator signed a final rule extending the deadline for certain CCR facilities to cease disposal and commence closure activities, as well as, establishing less stringent groundwater monitoring and protection requirements. On August 21, 2018, the D.C. Circuit remanded sections of the CCR Rule to the EPA to provide additional safeguards for unlined CCR impoundments that are more protective of human health and the environment, effective October 12, 2018. AE Supply assessed the changes in timing and closure plan requirements associated with the McElroy's Run impoundment site and increased the ARO by approximately $43 million in the third quarter of 2018.

~~13.~~ REGULATORY MATTERS

STATE REGULATION

Each of the ~~Utilities'~~Utilities’ retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in ~~Ohio by the PUCO, in~~ New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. ~~In addition,~~Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility.

Following the adoption of the Tax Act, various state regulatory proceedings have been initiated to investigate the impact of the Tax Act on the Utilities’ rates and charges. State proceedings that have arisen are discussed below. The Utilities continue to monitor and investigate the impact of state regulatory proceedings resulting from the Tax Act.

MARYLAND

PE operates under MDPSC approved base rates that were effective as of March 23, 2019. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.

The ~~Maryland legislature adopted a statute in 2008 codifying the~~ EmPOWER Maryland ~~goals to reduce electric consumption and demand and requiring~~program requires each electric utility to file a plan ~~every three years. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017~~to reduce electric consumption and ~~beyond, beginning with the goal of 0.97% savings achieved under PE's plan for 2016, and increasing~~demand 0.2% per year, ~~thereafter to reach 2%. The Maryland legislature in April 2017 adopted a statute requiring the same 0.2% per year increase,~~ up to the ultimate goal of 2% annual savings, for the duration of the 2018-2020 and 2021-2023 EmPOWER Maryland program cycles, to the extent the MDPSC determines that cost-effective programs and services are available. ~~PE's~~PE’s approved 2018-2020 EmPOWER Maryland plan continues and expands upon prior ~~years'~~years’ programs, and adds new programs, for a projected total cost of $116 million over the three-year period. ~~On December 22, 2017, the MDPSC issued an order approving the 2018-2020 plan with various modifications.~~ PE recovers program costs subject to a five-year amortization. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding, and to date, such recovery has not been sought or obtained by PE.

On ~~February 27, 2013,~~January 19, 2018, PE filed a joint petition along with other utility companies, work group stakeholders and the MDPSC ~~issued an order requiring the Maryland~~ electric ~~utilities~~vehicle work group leader to ~~submit analyses relating to the costs and benefits of making further system and staffing enhancements~~implement a statewide electric vehicle portfolio in order to attempt to reduce storm outage durations. PE's responsive filings discussed the steps needed to harden the utility's system in order to attempt to achieve various levels of storm response speed described in the February 2013 Order, and projected that it would require approximately $2.7 billion in infrastructure investments over 15 years to attempt to achieve the quickest level of response for the largest storm projected in the February 2013 Order. On July 1, 2014, the Staff of theconnection with a 2016 MDPSC issued a set of reports that recommended the imposition of extensive additional requirements in the areas of storm response, feeder performance, estimates of restoration times, and regulatory reporting, as well as the imposition of penalties, including customer rebates, for a utility's failure or inability to comply with the escalating standards of storm restoration speed proposed by the Staff of the MDPSC. In addition, the Staff of the MDPSC proposed that Maryland utilities be required to develop and implement system hardening plans, up to a rate impact cap on cost. The MDPSC conducted a hearing September 15-18, 2014, to consider certain of these matters, and has not yet issued a ruling on any of those matters.

~~On September 26, 2016, the MDPSC initiated a new~~ proceeding to consider an array of issues relating to electric distribution system design, including matters relating to electric vehicles, distributed energy resources, advanced metering infrastructure, energy storage, system planning, rate design, and impacts on low-income customers. Comments were filed, and a hearing was held in late 2016. On January 31, 2017, the MDPSC issued a notice establishing five working groups to address these issues over the following eighteen months, and also directed the retention of an outside consultant to prepare a report on costs and benefits of distributed solar generation in Maryland. On January 19, 2018, PE filed a joint petition, along with other utility companies, work group stakeholders, and the MDPSC electric vehicle work group leader, to implement a statewide electric vehicle portfolio. If approved, PE will launchproposed an electric vehicle charging infrastructure program ~~on January 1, 2019, offering up to 2,000 rebates for electric vehicle charging equipment to residential customers, and deploying up to 259 chargers at non-residential customer service locations~~ at a projected total cost of $12 ~~million. PE is proposing~~million, to ~~recover program costs subject to~~be recovered over a five-year amortization. On ~~February 6, 2018,~~January 14, 2019, the MDPSC ~~opened a new proceeding to consider~~approved the petition ~~and numerous parties filed comments on~~subject to certain reductions in the ~~petition on March 27, 2018. The MDPSC held hearings on the petition in May and September, 2018, after which parties filed final comments.~~scope

On January 12, 2018, the MDPSC instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of Maryland utilities. PE was required to track and apply regulatory accounting treatment for the impacts beginning January 1, 2018, and submitted a report to the MDPSC on February 15, 2018, estimating that the Tax Act impacts would be approximately $7 million to $8 million annually for PE’s customers. On August 17, 2018, the Staff of the MDPSC filed a reply to PE's February 15, 2018 filing,

inof the program. The MDPSC approved PE’s compliance filing, which ~~reply~~implements the Staff recommended that the MDPSC direct PE to reduce base rates by $6.5 million to reflect reduced federal tax costs pending resolution of PE's upcoming rate case, and that PE further be directed to pay customers a one-time credit for what the Staff estimated were the tax savings to PE through the end ofpilot program, with minor modifications, on July 2018. On October 5, 2018, the MDPSC issued an order requiring PE to pay a one-time credit for tax savings through September 30, 2018, which PE estimates will be approximately $5 million, and reserved all other Tax Act impacts to be resolved in the pending rate case.3, 2019.

On August 24, 2018, PE filed a base rate case with the MDPSC, which it supplemented on October 22, 2018, to update the partially forecasted test year with a full twelve months of actual data. The rate case ~~requests~~requested an annual increase in base distribution rates of $19.7 million, plus creation of an ~~Electric Distribution Investment surcharge~~EDIS to fund four enhanced service reliability programs. In responding to discovery, PE revised its request for an annual increase in base rates to $17.6 million. The proposed rate increase isreflected $7.3 million ~~less than it otherwise would have been due to~~in annual savings for customers resulting from the recent federal tax law changes. ~~The evidentiary hearing will commence on January~~On March 22, 2019, ~~and~~the MDPSC issued a final order ~~is expected by March 23, 2019.~~that approved a rate increase of $6.2 million, approved three of the four EDIS programs for four years, directed PE to file a new depreciation study within 18 months, and ordered the filing of a new base rate case in four years to correspond to the ending of the approved EDIS programs.

NEW JERSEY

JCP&L ~~currently~~operates under NJBPU approved rates that were effective as of January 1, 2017. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third-party EGSs that fail to provide the contracted service. The supply for BGS is comprised of two components, procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU. One BGS component reflects hourly real time energy prices and is available for larger commercial and industrial customers. The second BGS component provides a fixed price service and is intended for smaller commercial and residential customers. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates.

~~JCP&L currently operates under rates that were approved by~~On April 18, 2019, pursuant to the ~~NJBPU on December 12, 2016, effective as~~May 2018 New Jersey enacted legislation establishing a ZEC program to provide ratepayer funded subsidies of January 1, 2017. These rates provide an annual increase in operating revenues of approximately $80 million from those previously in place and are intended to improve service and benefit customers by supporting equipment maintenance, tree trimming, and inspections of lines, poles and substations, while also compensating for other business and operating expenses. In addition, on January 25, 2017,New Jersey nuclear energy supply, the NJBPU approved the ~~acceleration~~implementation of ~~the amortization of~~a non-bypassable, irrevocable ZEC charge for all New Jersey electric utility customers, including JCP&L’s ~~2012 major storm expenses that are recovered through the SRC in order for~~customers. Once collected from customers by JCP&L, these funds will be remitted to ~~achieve full recovery by~~eligible nuclear energy generators.

In December ~~31, 2019.~~

~~Pursuant to the NJBPU's March 26, 2015, final order in JCP&L's 2012 rate case proceeding directing that certain studies be completed, on July 22, 2015,~~2017, the NJBPU ~~approved the NJBPU staff's recommendation~~issued proposed rules to implement such studies, which included operational and financial components. The independent consultant conducting the review issued a final report on July 27, 2016, recognizing that JCP&L is meeting the NJBPU requirements and making various operational and financial recommendations. The NJBPU issued an Order on August 24, 2016, that accepted the independent consultant’s final report and directed JCP&L, the Division of Rate Counsel and other interested parties to address the recommendations.

~~In an Order issued October 22, 2014, in a generic proceeding to review its policies with respect to the use of a CTA in base rate cases, the NJBPU stated that it would continue to apply~~modify its current CTA policy in base rate cases ~~subject to incorporating the following modifications:~~to: (i) ~~calculating~~calculate savings using a five-year look back from the beginning of the test year; (ii) ~~allocating~~allocate savings with 75% retained by the company and 25% allocated to ~~rate payers;~~ratepayers; and (iii) ~~excluding~~exclude transmission assets of electric distribution companies in the savings calculation. On November 5, 2014, the Division of Rate Counsel appealed the NJBPU Order regarding the generic CTA proceeding to the Superior Court of New Jersey Appellate Division and JCP&L filed to participate as a respondent in that proceeding supporting the order. On September 18, 2017, the Superior Court of New Jersey Appellate Division reversed the NJBPU's Order on the basis that the NJBPU's modification of its CTA methodology did not comply with the procedures of the NJAPA. JCP&L's existing rates are not expected to be impacted by this order. On December 19, 2017, the NJBPU approved the issuance of proposed rules to modify the CTA methodology consistent with its October 22, 2014, Generic Order,calculation, which were published in the NJ Register ~~on January 16, 2018, and republished on February 6, 2018, to correct an error.~~in the first quarter of 2018.JCP&L filed comments supporting the proposed ~~rulemaking on April 6, 2018.~~rulemaking. On January 17, 2019, the NJBPU approved the proposed CTA rules with no changes. On May 17, 2019, the Rate Counsel filed an appeal with the Appellate Division of the Superior Court of New Jersey. JCP&L is contesting this appeal but is unable to predict the outcome of this matter.

~~At the~~Also in December ~~19,~~ 2017, ~~NJBPU public meeting,~~ the NJBPU approved its IIP rulemaking. The IIP creates a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing components that enhance reliability, resiliency, and/or safety. On July 13, 2018, JCP&L filed an infrastructure plan, JCP&L Reliability Plus, which proposed to accelerate $386.8 million of electric distribution infrastructure investment over four years to enhance the reliability and resiliency of its distribution system and reduce the frequency and duration of power outages. ~~JCP&L requested that~~On January 23, 2019, the NJBPU ~~issue~~granted JCP&L’s request to temporarily suspend the procedural schedule in the matter pending settlement discussions. On April 23, 2019, JCP&L filed a ~~final order in December 2018. On August 29, 2018,~~Stipulation of Settlement with the NJBPU ~~retained~~on behalf of the JCP&L, Rate Counsel, NJBPU Staff and New Jersey Large Energy Users Coalition, which provides that JCP&L will invest up to approximately $97 million in capital investments beginning on June 1, 2019 through December 31, 2020. JCP&L shall seek recovery of the capital investment through an accelerated cost recovery mechanism, provided for in the rules, that includes a revenue adjustment calculation and a process for two rate adjustments. On May 8, 2019, the NJBPU issued an order approving the Stipulation of Settlement without modifications. Pursuant to the Stipulation, JCP&L filed a petition on September 16, 2019, to seek approval of rate adjustments to provide for ~~hearing.~~cost recovery established with JCP&L Reliability Plus.

On January 31, 2018, the NJBPU instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of New Jersey utilities. The NJBPU ordered New Jersey utilities to: (1) defer on their books the impacts of the Tax Act effective January 1, 2018; (2) to file tariffs effective April 1, 2018, reflecting the rate impacts of changes in current taxes; and (3) to file tariffs effective July 1, 2018, reflecting the rate impacts of changes in deferred taxes. On March 2, 2018, JCP&L filed a petition with the NJBPU, which included proposed tariffs for a base rate reduction of $28.6 million effective April 1, 2018, and a rider to reflect $1.3 million in rate impacts of changes in deferred taxes. On March 26, 2018, the NJBPU approved JCP&L’s rate reduction effective April 1, 2018, on an interim basis subject to refund, pending the outcome of this proceeding. On April 23, 2019, JCP&L filed a Stipulation of Settlement on behalf of the Rate Counsel, NJBPU Staff, and the New Jersey Large Energy Users Coalition with the NJBPU. The terms of the Stipulation of Settlement provide that between January 1, 2018 and March 31, 2018, JCP&L’s refund obligation is estimated to be approximately $7 million, which will be refunded to customers. The Stipulation of Settlement also provides for a base rate reduction of $28.6 million, which was reflected in rates on April 1, 2018, and a Rider Tax Act Adjustment for certain items over a five-year period. On May 8, 2019, the NJBPU ~~however, did not address refunds and other proposed rider tariffs at such time, but may be addressed at a later date.~~issued an order approving the Stipulation of Settlement without modification.

OHIO

The Ohio Companies currently operate under ESP IV ~~which commenced~~effective June 1, 2016, and expires May 31, 2024. The material terms of ESP IV, as approved in the PUCO’s Opinion and Order issued on March 31, 2016 and Fifth Entry on Rehearing on October 12, 2016, include Rider DMR, which provides for the Ohio Companies to collect $132.5 million annually for three years, with the possibility of a two-year extension. Rider DMR will be grossed up for federal income taxes, resulting in an approved amount of approximately $168 million annually in 2018 and 2019. Revenues from Rider DMR will be excluded from the significantly excessive earnings test for the initial three-year term but the exclusion will be reconsidered upon application for a potential two-year extension. The PUCO set three conditions for continued recovery under Rider DMR: (1) retention of the corporate headquarters and nexus of operations in Akron, Ohio; (2) no change in control of the Ohio Companies; and (3) a demonstration of sufficient progress in the implementation of grid modernization programs approved by the PUCO. ESP IV also continues a base distribution rate freezecontinuing through May 31, ~~2024. In addition, ESP IV~~2024, that continues the supply of power to non-shopping customers at a market-based price set through an auction process.

ESP IV ~~also~~continues a base distribution rate freeze through May 31, 2024 and continues Rider DCR, which supports continued investment related to the

distribution system for the benefit of customers, with increased revenue caps of ~~$30 million per year from June 1, 2016 through May 31, 2019;~~ $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024. ~~Other material terms of~~ ESP IV ~~include:~~also includes: (1) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (2) ~~an agreement to file a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016, and remains pending); (3)~~ a goal across FirstEnergy to reduce CO₂ emissions by 90% below 2005 levels by 2045; ~~(4)~~and (3) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory ~~Agency~~Council to ensure preservation and growth of the competitive market in ~~Ohio; and (5) an agreement to file an application to transition to a straight fixed variable cost recovery mechanism~~Ohio.

In addition, ESP IV provided for ~~residential customers' base distribution rates, which filing was made on April 3, 2017, and which the PUCO denied on June 13, 2018.~~

~~Several parties, including~~ the Ohio Companies ~~filed applications for rehearing regarding the Ohio Companies’ ESP IV with the PUCO. The Ohio Companies’ application for rehearing challenged, among other things, the PUCO’s failure~~ to ~~adopt the Ohio Companies’ suggested modifications to Rider DMR. The Ohio Companies had previously suggested that a properly designed~~collect through Rider DMR ~~would be valued at $558~~$132.5 million annually for ~~eight~~three years beginning in 2017, grossed up for federal income taxes, resulting in an approved amount of approximately $168 million annually in 2018 and ~~include an additional amount that recognizes~~2019. Revenues from Rider DMR are excluded from the ~~value of~~significantly excessive earnings test. On appeal, the ~~economic impact of FirstEnergy maintaining its headquarters in Ohio. Other parties’ applications for rehearing argued, among other things, that~~SCOH, on June 19, 2019, reversed the PUCO’s ~~adoption of~~determination that Rider DMR is ~~not supported by law or sufficient evidence.~~lawful, and remanded the matter to the PUCO with instructions to remove Rider DMR from ESP IV. On August ~~16, 2017,~~20, 2019, the ~~PUCO denied all remaining intervenor applications for rehearing,~~SCOH denied the Ohio Companies’ ~~challenges~~motion for reconsideration. The PUCO entered an Order directing the Ohio Companies to ~~the modifications to~~cease further collection through Rider DMR, ~~and added~~credit back to customers a ~~third-party monitor to ensure that~~refund of Rider DMR funds ~~are spent appropriately.~~collected since July 2, 2019, and remove Rider DMR from ESP IV. The Ohio Companies filed revised tariffs to implement the refund of Rider DMR funds collected since July 2, 2019. On ~~September 15, 2017,~~October 1, 2019, the Ohio Companies implemented PUCO approved tariffs to refund approximately $28 million to customers, including Rider DMR revenues billed from July 2, 2019 through August 31, 2019.

On July 15, 2019, OCC filed ~~an application for rehearing~~a Notice of Appeal with the SCOH, challenging the PUCO’s exclusion of Rider DMR revenues from the determination of the ~~PUCO’s August 16,~~existence of significantly excessive earnings under ESP IV for calendar year 2017 ~~ruling on the issues of the third-party monitor~~ and the ROE calculation for advanced metering infrastructure. On October 11, 2017, the PUCO denied the Ohio Companies' application for rehearing on both issues. On October 16, 2017, the Sierra Club and the OMAEG filed notices of appeal with the Supreme Court of Ohio appealing various PUCO entries on their applications for rehearing. On November 16, 2017, theclaiming a $42 million refund is due to OE customers. The Ohio Companies ~~intervened in~~intend to contest this appeal but are unable to predict the ~~appeal. Additional parties subsequently filed notices~~outcome of ~~appeal with the Supreme Court of~~this matter.

Under Ohio challenging various PUCO entries on their applications for rehearing. On February 26, 2018, appellants filed their briefs. Briefs of the PUCO and the Ohio Companies were filed on May 29, 2018. On July 9, 2018, appellants filed their reply briefs. On September 26, 2018, the Supreme Court of Ohio denied a July 30, 2018 joint motion filed by the OCC, the NOAC, and the OMAEG to stay the portions of the PUCO's orders and entries under appeal that authorized Rider DMR. Oral argument on the appeals is scheduled for January 9, 2019.

~~Under ORC 4928.66,~~law, the Ohio Companies are required to implement energy efficiency programs that achieve certain annual energy savings and total peak demand reductions. Starting in 2017, ORC 4928.66 requires the energy savings benchmark to increase by 1% and the peak demand reduction benchmark to increase by 0.75% annually thereafter through 2020 and the energy savings benchmark to increase by 2% annually from 2021 through 2027, with a cumulative benchmark of 22.2% by 2027. On April 15, 2016, theThe Ohio Companies filed an application for approval of their three-year energy efficiency portfolio plans for the period from January 1, 2017 through December 31, 2019. The plans as proposed comply with benchmarks contemplated by ORC 4928.66 and provisions of the ESP IV, and includeCompanies’ 2017-2019 plan includes a portfolio of energy efficiency programs targeted to a variety of customer segments, including residential customers, low income customers, small commercial customers, large commercial and industrial customers and governmental entities. On December 9, 2016, the Ohio Companies filed a Stipulation and Recommendation with several parties that contained changes to the plan and a decrease in the plan costs.segments. The Ohio Companies anticipate the cost of the ~~plans~~plan will be approximately $268 million over the life of the ~~portfolio plans~~plan and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms. On November 21, 2017, the PUCO issued an order that approved the ~~filed Stipulation and Recommendation~~proposed plan with several modifications, including a cap on the Ohio Companies’ collection of program costs and shared savings set at4% of the Ohio Companies’ total sales to ~~customers~~customers. On October 15, 2019, the SCOH reversed the PUCO’s decision to impose the 4% cost-recovery cap and remanded the matter to the PUCO for approval of the portfolio plans without the cost-recovery cap.

On July 23, 2019, Ohio enacted legislation establishing support for nuclear energy supply in Ohio. In addition to the provisions supporting nuclear energy, the legislation included a provision implementing a decoupling mechanism for Ohio electric utilities. The legislation also is ending current energy efficiency program mandates on December 31, 2020, provided statewide energy efficiency mandates are achieved as ~~reported~~determined by the PUCO. On October 23, 2019, the PUCO solicited comments on ~~2015 FERC Form 1. On December 21, 2017,~~whether the PUCO should terminate the energy efficiency programs once the statewide energy efficiency mandates are achieved. The Ohio Companies plan to apply to the PUCO for approval of the decoupling mechanism later this year, which would set residential and commercial base distribution related revenues at the levels collected in 2018. As such, those base distribution revenues would no longer be based on electric consumption, which allows continued support of energy efficiency initiatives while also providing revenue certainty to the Ohio ~~Companies~~Companies. Opponents to the legislation are petitioning to submit the legislation to a statewide referendum on the November 2020 ballot, and stay its effect unless and until approved by a majority of Ohio voters. On September 4, 2019, a lawsuit was filed ~~an application for rehearing~~with the SCOH, challenging the ~~PUCO’s modification~~referendum on the grounds that the provisions supporting nuclear energy are a new tax and taxes cannot be overturned by referendum. On October 7, 2019, petitioners filed a lawsuit in the U.S. District Court for the Southern District of Ohio challenging various Ohio legal requirements for a referendum, and seeking additional time to gather signatures in support of a referendum. Petitioners did not meet the ~~Stipulation~~October 21, 2019 deadline to file the necessary number of petition signatures. On October 23, 2019, legislation went into effect. The U.S. District Court denied petitioners’ request for more time, and ~~Recommendation~~certified questions of state law to ~~include~~ the ~~4% cost cap, which was denied by the PUCO on January 10, 2018. On March 12, 2018,~~SCOH to answer.

In February 2016, the Ohio Companies filed a ~~Notice~~Grid Modernization Business Plan for PUCO consideration and approval, as required by the terms of Appeal with the Supreme Court of Ohio challenging the PUCO’s imposition of a 4% cost cap. Various other parties also filed Notices of Appeal challenging various PUCO entries on their applications for rehearing. The Ohio Companies filed their brief on May 21, 2018. The PUCO filed its brief on July 30, 2018, and the Ohio Companies filed their reply brief on September 10, 2018. Oral argument on the appeals is scheduled for February 20, 2019.

Ohio law requires electric utilities and electric service companies in Ohio to serve part of their load from renewable energy resources measured by an annually increasing percentage amount through 2026, except that in 2014 SB310 froze 2015 and 2016 requirements at the 2014 level (2.5%), pushing back scheduled increases, which resumed in 2017 (3.5%), and increases 1% each year through 2026 (to 12.5%) and shall remain at 12.5% in 2027 and each year thereafter. The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet these renewable energy requirements. In September 2011, the PUCO opened a docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies recover the costs of acquiring these RECs. The PUCO issued an Opinion and Order on August 7, 2013, approving the Ohio Companies' acquisition process and their purchases of RECs to meet statutory mandates in all instances except for certain purchases arising from one auction and directed the Ohio Companies to credit non-shopping customers in the amount of $43.4 million, plus interest, on the basis that the Ohio Companies did not prove such purchases were prudent. On December 24, 2013, following the denial of their application for rehearing, the Ohio Companies filed a Notice of Appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio, which was granted. The OCC and the ELPC also filed appeals of the PUCO's order. On January 24, 2018, the Supreme Court of Ohio reversed the PUCO order finding that the order violated the rule against retroactive ratemaking. On February 5, 2018, the OCC and ELPC filed a motion for reconsideration, to which the Ohio Companies responded in opposition on February 15, 2018. On April 25, 2018, the Supreme Court of Ohio denied the motion for reconsideration. As a result, in the second quarter of 2018, the Ohio Companies recognized a pre-tax benefit to earnings (within the Amortization (deferral) of regulatory assets, net line on the Consolidated Statement of Income (Loss)) of approximately $72 million to reverse the liability associated with the PUCO opinion and order.

ESP IV. On December 1, 2017, the Ohio Companies filed an application with the PUCO for approval of a DPM ~~Plan. The DPM~~ Plan, is a portfolio of ~~approximately $450 million in~~ distribution platform investment projects, which are designed to modernize the Ohio Companies’ distribution grid, prepare it for further grid modernization projects, and provide customers with immediate reliability benefits. The Ohio Companies have requested that the PUCO issue an order approving the DPM Plan and associated cost recovery so that the Ohio Companies can expeditiously commence the DPM Plan and customers can begin to realize the associated benefits.

OnAlso, on January 10, 2018, the PUCO opened a case to consider the impacts of the Tax Act on Ohio utilities’ rates and determine the appropriate course of action to pass benefits on to customers. On November 9, 2018, the Ohio Companies filed a settlement agreement that provides for the implementation of the first phase of grid modernization plans, including the investment of $516 million over three years to modernize the Ohio Companies’ electric distribution system, and for all tax savings associated with the Tax Act to flow back to customers. As part of the agreement, the Ohio Companies also filed an application for approval of a rider to return the remaining tax savings to customers following PUCO approval of the settlement. On January 25, 2019, the Ohio Companies filed a supplemental settlement agreement that keeps intact the provisions of the settlement described above and adds further customer benefits and protections, which broadened support for the settlement. The settlement has broad support, including PUCO Staff, the OCC, representatives of industrial and commercial customers, a low-income advocate, environmental advocates, hospitals, competitive generation suppliers and other parties. On July 17, 2019, the PUCO approved the settlement agreement with no material

modifications. On August 16, 2019, environmental advocates who were not parties to the settlement filed an application for rehearing challenging the PUCO’s approval of the settlement. On September 11, 2019, the PUCO denied the application for rehearing.

The Ohio Companies’ Rider NMB is designed to recover NMB transmission-related costs imposed on or charged to the Ohio Companies by FERC or PJM. On December 14, 2018, the Ohio Companies filed an application for a review of their 2019 Rider NMB, including recovery of future Legacy RTEP costs and previously absorbed Legacy RTEP costs, net of refunds received from PJM. On February 27, 2018, the PUCO issued an order directing the Ohio Companies to file revised final tariffs recovering Legacy RTEP costs incurred since May 31, 2018, but excluding recovery of approximately $95 million in Legacy RTEP costs incurred prior to May 31, 2018, net of refunds received from PJM. The PUCO solicited comments on whether the Ohio Companies should be permitted to recover the Legacy RTEP charges incurred prior to May 31, 2018. The Ohio Companies, ~~effective January 1, 2018, were required to establish a regulatory liability for the estimated reduction in federal income tax resulting from the Tax Act,~~OCC and OMAEG filed comments on February 15, 2018, explaining that customers will save nearly $40 million annually as a result of updating tariff riders for the tax rate changes and that the Ohio Companies’ base distribution rates are not impacted by the Tax Act changes because they are frozen through May 2024.March 29, 2019. The Ohio Companies filed reply comments on ~~March 7, 2018.~~April 15, 2019. On October ~~24, 2018,~~9, 2019, the PUCO ~~entered an Order in its investigation into~~approved the ~~impacts~~recovery of the ~~Tax Act on Ohio's utilities directing that~~$95 million of previously excluded Legacy RTEP charges.

PENNSYLVANIA

The Pennsylvania Companies operate under rates approved by the PPUC, effective as of January ~~1, 2019, all Ohio rate-regulated utility companies, unless ordered otherwise, file applications not~~27, 2017. These rates were adjusted for ~~an increase in rates to reflect~~ the net impact of the Tax Act, ~~on each specific utility's current rates.~~

~~PENNSYLVANIA~~

effective March 15, 2018. The net impact of the Tax Act for the period January 1, 2018 through March 14, 2018 must also be separately tracked for treatment in a future rate proceeding. The Pennsylvania Companies operate under DSPs for the June 1, ~~2017~~2019 through May 31, ~~2019~~2023 delivery period, which provide for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. Under the DSPs, the supply will be provided by wholesale suppliers through a mix of 12 and 24-month energy contracts, as well as one RFP for 2-year SREC contracts for ME, PN and Penn. The DSPs include modifications to the Pennsylvania Companies’ POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated with alternative EGS charges.

~~On December 11, 2017, the Pennsylvania Companies filed DSPs for the June 1, 2019 through May 31, 2023 delivery period.~~ Under the 2019-2023 DSPs, ~~the~~ supply ~~is proposed to~~will be provided by wholesale suppliers through a mix of 3, 12 and 24-month energy contracts, as well as two RFPs for 2-year SREC contracts for ME, PN and Penn. The 2019-2023 DSPs ~~as proposed~~ also include modifications to the Pennsylvania Companies’ POR programs in order to continue their clawback pilot program as a long-term, permanent ~~program. The 2019-2023 DSPs also introduce a retail market enhancement rate mechanism designed to stimulate residential customer shopping, and~~program term, modifications to the Pennsylvania Companies’ customer class definitions to allow for the introduction of hourly priced default service to customers at or above 100kW. A hearing was held on April 10, 2018, and the ALJ issued a recommended decision dated May 31, 2018. The decision recommended approval of the Pennsylvania Companies' DSPs as originally proposed with two exceptions: it recommended rejecting the proposed retail market enhancement rate mechanism, and establishing limitations on customer assistance program customers' shopping. Exceptions were filed by two parties on June 28, 2018, to which the Pennsylvania Companies filed reply exceptions on July 9, 2018. On September 4, 2018, the PPUC issued an order approving the Pennsylvania Companies' DSPs and directed a working group to further discuss the implementation of100kW, customer assistance program shopping limitations, and ~~appropriate scripting for~~script modifications related to the Pennsylvania ~~Companies'~~Companies’ customer referral programs. The Pennsylvania Companies and two other parties filed petitions for reconsideration to that order on the limited issue of timing and scope of the working group discussion related to customer assistance program shopping limitations, which are pending PPUC review at this time.programs.

The Pennsylvania Companies operate under rates that were approved by the PPUC on January 19, 2017, effective as of January 27, 2017. These rates provide annual increases in operating revenues of approximately $96 million at ME, $100 million at PN, $29 million at Penn, and $66 million at WP, and are intended to benefit customers by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements.

Pursuant to ~~Pennsylvania's EE&C legislation in~~Pennsylvania Act 129 of 2008 and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. ~~On June 19, 2015, the PPUC issued a Phase III Final Implementation Order setting: demand reduction targets, relative to each Pennsylvania Companies' 2007-2008 peak demand (in MW), at 1.8%for ME, 1.7% for Penn, 1.8% for WP, and 0% for PN; and energy consumption reduction targets, as a percentage of each Pennsylvania Companies’ historic 2010 forecasts (in MWH), at 4.0% for ME, 3.9%for PN, 3.3% for Penn, and 2.6% for WP.~~ The Pennsylvania ~~Companies'~~Companies’ Phase III EE&C plans for the June 2016 through May 2021 period, which were approved in March 2016, with expected costs up to $390 million, are designed to achieve the targets established in the ~~PPUC's~~PPUC’s Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders.

~~Pursuant to Act 11 of 2012,~~ Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. ~~Pennsylvania EDCs must file~~ LTIIPs outlining infrastructure improvement plans for PPUC review and approval must be filed prior to approval of a DSIC. ~~On February 11, 2016, the PPUC approved LTIIPs for each of the Pennsylvania Companies.~~ On June 14, 2017, the PPUC approved modified LTIIPs for ME, PN and Penn for the remaining years of 2017 through 2020 to provide additional support for reliability and infrastructure investments. ~~The LTIIPs estimated costs for the remaining period of~~On September 20, 2018, ~~to 2020 are: WP $50.1 million; PN $44.8 million; Penn $33.2 million; and ME $51.3 million. On April 10, 2018, the PPUC notified each of the Pennsylvania Companies that the PPUC was initiating~~following a periodic review of the LTIIPs as required by regulation once every five years, and soliciting comments from interested parties. On May 10, 2018, the Pennsylvania Companies each filed comments explaining that their LTIIPs are effective and that changes to the respective LTIIPs are not necessary. No parties other than the Pennsylvania Companies filed comments. On September 20, 2018, the PPUC entered an Order concluding that the Pennsylvania Companies have substantially adhered to the schedules and expenditures outlined in their LTIIPs, but that changes to the LTIIPs as designed are necessary to maintain and improve ~~reliability. The PPUC~~reliability and directed the Pennsylvania Companies to file modified or new ~~LTIIPs within 60 days of the Order; however, on October 17, 2018, the Pennsylvania Companies requested a 60-day extension to file the new or modified~~ LTIIPs.

On ~~February 16, 2016,~~January 18, 2019, the Pennsylvania Companies filed ~~riders~~modifications to their current LTIIPs that would terminate those LTIIPs at the end of 2019, and proposed revised LTIIP spending in 2019 of approximately $45 million by ME, $25 million by PN, $26 million by Penn and $51 million by WP. The Pennsylvania Companies also committed to making filings later in 2019, which would propose new LTIIPs for the 2020 through 2024 period. On May 23, 2019, the PPUC issued an order approving the Pennsylvania Companies’ Modified LTIIPs as filed. On August 30, 2019, the Pennsylvania Companies filed individual Petitions for approval of proposed LTIIPs for the five-year period beginning January 1, 2020 and ending December 31, 2024 for a total capital investment of approximately $572 million for certain infrastructure improvement initiatives. On September 30, 2019, the Pennsylvania OCA submitted comments on the Pennsylvania Companies’ LTIIPs. A PPUC decision is expected by year-end.

The Pennsylvania Companies’ approved DSIC riders for quarterly cost recovery ~~which were approved by the PPUC on June 9, 2016, and~~ went into effect July 1, 2016, subject to hearings and refund or reallocation among customer classes. OnIn the January 19, 2017 ~~in the PPUC’s~~ order approving the Pennsylvania Companies’ general rate cases, the PPUC added an additional issue to the DSIC proceeding to include whether ADIT should be included in DSIC calculations. On February 2, 2017, the parties to the DSIC proceeding submitted a Joint Settlement to the ALJ that resolved the issues that were pending from the order issued on June 9, 2016. On August 31, 2017, the ALJ issued a decision recommending that the complaint of the Pennsylvania OCA be granted by the PPUC such that the Pennsylvania Companies reflect all federal and state income tax deductions related to DSIC-eligible property in the currently effective DSIC rates. On April 19, 2018, the PPUC approved the Joint Settlement without modification and reversed the ~~ALJ's~~ALJ’s previous decision that would have required the Pennsylvania Companies to reflect all federal and state income tax deductions related to DSIC-eligible property in currently effective DSIC rates. On May 21, 2018, the Pennsylvania OCA filed an appeal with the Pennsylvania Commonwealth Court of the ~~PPUC's~~PPUC’s decision of April 19, 2018. On June 11, 2018, the Pennsylvania Companies filed a Notice of Intervention in the Pennsylvania ~~OCA's~~OCA’s appeal to the Commonwealth Court.

On ~~February 12,~~July 11, 2019, the Commonwealth Court issued an opinion and order reversing the PPUC’s decision of April 19, 2018 and remanding the matter to the PPUC ~~initiated a proceeding~~ to ~~determine the effects of the Tax Act on the tax liability of utilities and the feasibility of reflecting such impacts in rates charged to customers. On March 9, 2018,~~require the Pennsylvania Companies ~~submitted~~to revise their ~~calculation of the net annual effect of the Tax Act on~~tariffs and DSIC calculations to include ADIT and state income tax expense and rate base to be $37 million for ME, $40 million for PN, $9 million for Penn, and $30 million for WP. The Pennsylvania Companies also filed comments proposing that rates be adjusted to reflect the tax rate changes prospectively from the date of a final PPUC order via a reconcilable rider, with the amount that would otherwise accrue between January 1, 2018 and the date of a final order being used to invest in the Pennsylvania Companies’ infrastructure.taxes. On ~~March 15, 2018,~~July 25, 2019, the PPUC ~~issued a Temporary Rates Order making the Pennsylvania Companies’ rates temporary~~ and ~~subject to refund for six months. On May 17, 2018, the PPUC issued orders directing that~~ the Pennsylvania Companies ~~implement a reconcilable negative surcharge mechanism in order to refund to customers the net effect~~filed separate Applications for Reargument of the ~~Tax Act for~~Commonwealth Court’s July 11, 2019 Opinion and Order. The Applications were denied by the ~~period July 1, 2018, through December 31, 2018, to be prospectively updated for new rates effective January 1,~~Commonwealth Court by Orders entered September 4, 2019. ~~The Pennsylvania Companies were also directed to establish a regulatory liability for the net impact of the Tax Act for the period of January 1, 2018 through June 30, 2018.~~ On ~~June 14, 2018,~~October 7, 2019, the PPUC ~~issued an order revising this directive such that~~and the Pennsylvania Companies ~~must instead establish accounts~~filed separate Petitions for Allowance of Appeal of the Commonwealth Court’s Opinion and Order to ~~track tax savings~~the Pennsylvania Supreme Court. On August

30, 2019, Penn filed a Petition seeking approval of a waiver of the statutory DSIC cap of 5% of distribution rate revenue and approval to increase the maximum allowable DSIC to 11.81% of distribution rate revenue for the five-year period ~~January 1, 2018, through March 14, 2018, and record regulatory liabilities associated with tax savings for only the period March 15, 2018 through June 30, 2018.~~of its proposed LTIIP. The ~~cumulative value~~Pennsylvania Office of ~~the tracked amounts~~Small Business Advocate and the ~~regulatory liability is expected to amount to $12 million for ME, $13 million for PN, $3 million for~~Pennsylvania OCA have opposed Penn’s Petition. On September 20, 2019, Penn ~~and $10 million for WP. These amounts are expected to be addressed~~filed its direct testimony in the Pennsylvania Companies' next available rate proceedings, or independent filings to be made within three years, whichever comes sooner. The Pennsylvania Companies filed voluntary surcharges on June1, 2018, to adjust rates for the reduced tax rate, which were effective for bills rendered starting July 1, 2018. For the first six-month period, the surcharge is expected to return to customers $19 million for ME, $20 million for PN, $5 million for Penn, and $15 million for WP.support of its Petition.

WEST VIRGINIA

MP and PE provide electric service to all customers through traditional cost-based, regulated utility ~~ratemaking.~~ratemaking and operates under rates approved by the WVPSC effective February 2015. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. ~~MP's~~MP’s and ~~PE's~~PE’s ENEC rate is updated annually.

On August ~~31, 2018,~~21, 2019, MP and PE filed with the WVPSC their annual ENEC case requesting a ~~$100.9 million~~ decrease in ~~their~~ ENEC rates ~~proposed to be effective~~of $6.1 million beginning January 1, ~~2019, which includes~~2020, representing a $25.6 million annual decrease impact associated with the settlement regarding the impact of the Tax Act on West Virginia rates, as noted below. Additionally, the August 31, 2018 filing includes an elimination of the Energy Efficiency Cost Rate Surcharge effective January 1, 2019, equating to an additional $2.1 million decrease. The rate decreases represent an approximate 7.2% annual0.4% decrease in rates versus those in effect on August ~~31, 2018. Hearings before the WVPSC are scheduled for November 27 and 28, 2018.~~

21, 2019. On January 3, 2018, the WVPSC initiated a proceeding to investigate the effects of the Tax Act on the revenue requirements of utilities. MP and PE must track the tax savings resulting from the Tax Act on a monthly basis, effective January 1, 2018. On January 26, 2018, the WVPSC issued an order clarifying that regulatory accounting should be implemented as of January 1, 2018, including the recording of any regulatory liabilities resulting from the Tax Act.October 11, 2019, MP and PE filed ~~written testimony on May 30, 2018, explaining the impact~~a supplement requesting approval of the ~~Tax Act~~termination of the 50 MW PPA with Morgantown Energy Associates, a NUG entity. A settlement between MP, PE, and the majority of the intervenors fully resolving the ENEC case, which maintains 2019 ENEC rates into 2020, and supports the termination of the Morgantown Energy Associates PPA was filed with the WVPSC on ~~federal income tax~~October 18, 2019. A hearing has been set for December 11, 2019 to consider the settlement, and ~~revenue requirements and showing~~ an ~~annual rate impact of $26.2 million.~~order is expected in December 2019 for rates effective January 1, 2020.

On August 21, 2019, MP and PE ~~the Staff of~~filed with the WVPSC ~~the WV Consumer Advocate,~~for a reconciliation of their VMS and a ~~coalition~~periodic review of ~~industrial customers entered into~~its vegetation management program requesting an increase in VMS rates of $7.6 million beginning January 1, 2020. The increase is due to moving from a ~~settlement agreement~~5-year maintenance cycle to a 4-year cycle and performing more operation and maintenance work and less capital work on the rights of way. The increase is a 0.5% increase in rates versus those in effect on August ~~23, 2018,~~21, 2019. The hearing in this matter has been set for December 11, 2019.

FERC REGULATORY MATTERS

Under the FPA, FERC regulates rates for interstate wholesale sales, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. With respect to ~~have $25.6 million in rate reductions flow through to customers beginning September 1, 2018,~~their wholesale services and ~~to defer to~~rates, the ~~next base rate case (or a separate proceeding if a base rate case is not filed by August 31, 2020) the amount and classification of the excess ADITs resulting from the Tax Act~~Utilities, AE Supply, AGC, and the ~~issue~~Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE, WP and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of ~~whether~~JCP&L, MP, PE, WP and ~~PE should be required~~the Transmission Companies are subject to ~~credit~~functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff.

FERC regulates the sale of power for resale in interstate commerce in part by granting authority to ~~customers any of~~public utilities to sell wholesale power at market-based rates upon showing that the ~~reduced income tax expense occurring between January 1, 2018~~seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Utilities and ~~August 31, 2018. The WVPSC approved~~AE Supply each have been authorized by FERC to sell wholesale power in interstate commerce at market-based rates and have a market-based rate tariff on file with FERC, although major wholesale purchases remain subject to regulation by the ~~settlement on August 24, 2018.~~relevant state commissions.

~~FERC MATTERS~~

~~Reliability Matters~~

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, AE Supply, ~~ATSI, MAIT~~ and ~~TrAIL.~~the Transmission Companies. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to ~~eight~~six regional entities, including RFC. All of ~~FirstEnergy's~~the facilities that FirstEnergy operates are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC.

FirstEnergy believes that it is in material compliance with all ~~currently-effective~~currently effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on ~~FirstEnergy's~~FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities that could have a material adverse effect on its financial condition, results of operations and cash flows.

~~PJM Transmission Rates~~

PJM and its stakeholders have been debating the proper method to allocate costs for a certain class of new transmission facilities since 2005. While FirstEnergy and other parties advocate for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costs on a load-ratio share basis, where each customer in the zone would pay based on its total usage of energy within PJM. This question has been the subject of extensive litigation before FERC and the appellate courts, including before the Seventh Circuit. On June 25, 2014, a divided three-judge panel of the Seventh Circuit ruled that FERC had not quantified the benefits that western PJM utilities would derive from certain new 500 kV or higher lines and thus had not adequately supported its decision to socialize the costs of these lines. The majority found that eastern PJM utilities are the primary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries, and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from the lines, and not on load-ratio share in PJM as a whole. The court remanded the case to FERC, which issued an order setting the issue of cost allocation for hearing and settlement proceedings. On June 15, 2016, various parties, including ATSI and the Utilities, filed a settlement agreement at FERC agreeing to apply a combined usage based/socialization approach to cost allocation for charges to transmission customers in the PJM Region for transmission projects operating at or above 500 kV. For historical transmission costs prior to January 1, 2016, the settlement agreement provides a “black-box” schedule of credits to and payments from customers across PJM’s transmission zones. From January 1, 2016 forward, PJM will collect a charge for the revenue requirement associated with each transmission enhancement through a “50/50” calculation, with 50% based on a load-ratio share and the other 50% solution-based distribution factor (DFAX) hybrid method. On May 31, 2018, FERC approved the settlement agreement as filed, without conditions. As a result of the settlement, FirstEnergy recorded a pre-tax benefit of approximately $73 million and $42 million during the second and third quarters, respectively (within the Other operating expenses line on the Consolidated Statement of Income), relating to the amount of refund the Ohio Companies will receive and retain from PJM for the period prior to January 1, 2016. PJM implemented the settlement for transmission service purchased in July 2018 in customer bills beginning in August 2018. FirstEnergy does not expect a material impact from implementation of the settlement agreement going forward. Requests for rehearing or clarification of FERC's May 31, 2018, orders and related responses remain pending before FERC.

RTO Realignment

On June 1, 2011, ATSI and the ATSI zone transferred from MISO to PJM. While many of the matters involved with the move have been resolved, FERC denied recovery under ~~ATSI's~~ATSI’s transmission rate for certain charges that collectively can be described as ~~"exit fees"~~“exit fees” and certain other transmission cost allocation charges totaling approximately $78.8 million until such time as ATSI submits a cost/benefit analysis demonstrating net benefits to customers from the transfer to PJM. Subsequently, FERC rejected a proposed

settlement agreement to resolve the exit fee and transmission cost allocation issues, stating that its action is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges. ~~On March 17, 2016,~~In a subsequent order, FERC ~~denied FirstEnergy's request for rehearing of FERC's earlier order rejecting the settlement agreement and~~ affirmed its prior ruling that ATSI must submit the cost/benefit analysis. ATSI is evaluating the cost/benefit approach.

Separately, FirstEnergy joined certain other PJM TOs in a protest of MISO's proposal to allocate MVP costs to energy transactions that cross MISO's borders into the PJM Region. On July 13, 2016, FERC issued its order finding it appropriate for MISO to assess an MVP usage charge for power withdrawals from MISO to PJM. Various parties, including FirstEnergy and the PJM TOs, requested rehearing or clarification of FERC’s order. On September 20, 2018, FERC issued an order denying rehearing and affirming and clarifying its prior decision that MISO may allocate MVP costs to PJM customers for power withdrawals from MISO to PJM as such exports occur.

~~The outcome of the proceedings that address the remaining open issues related to MVP costs cannot be predicted at this time.~~

~~PATH Transmission Project~~

In 2012, the PJM Board of Managers canceled the PATH project, a proposed transmission line from West Virginia through Virginia and into Maryland. As a result of PJM canceling the project, approximately $62 million and approximately $59 million in costs incurred by PATH-Allegheny and PATH-WV, respectively, were reclassified from net property, plant and equipment to a regulatory asset for future recovery. PATH-Allegheny and PATH-WV requested authorization from FERC to recover the costs with a proposed ROE of 10.9% (10.4% base plus 0.5% for RTO membership) from PJM customers over five years. FERC issued an order denying the 0.5% ROE adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012, subject to hearing and settlement procedures. On January 19, 2017, FERC issued an order reducing the PATH formula rate ROE from 10.4% to 8.11% effective January 19, 2017 and allowing recovery of certain related costs. On February 21, 2017, PATH filed a request for rehearing with FERC seeking recovery of disallowed costs and requesting that the ROE be reset to 10.4% for the entire amortization period. ~~The Edison Electric Institute submitted an~~ ~~amicus curiae~~ request for reconsideration in support of PATH. On March 20, 2017, PATH also submitted a compliance filing implementing the January 19, 2017 order. Certain affected ratepayers challenged the compliance filing, and FERC Staff requested additional information on, and edits to, the compliance filing, as directed by the January 19, 2017 order. PATH responded to comments and Staff’s request. ~~FERC orders on PATH's requests for rehearing and compliance filing remain pending.~~

FERC Actions on Tax Act

On March 15, 2018, FERC took action to address the impact of the Tax Act on FERC-jurisdictional rates, including transmission and electric wholesale rates. FERC directed MP, PE and WP to either submit a joint filing to adjust the transmission rate for the Allegheny Power transmission zone in the PJM Region to address the impact of the Tax Act changes in effective tax rate, or to “show cause” as to why such action is not required. FERC established a refund effective date of March 21, 2018 for any refunds as a result of the change in tax rate. On May 14, 2018, MP, PE and WP submitted revisions to their joint stated transmission rate to reflect the reduction in the federal corporate income tax rate. The revisions reduce the rate by 6.70%. There were no comments submitted in response to the proposed revisions, and the matter is now before FERC for further action. FERC is not at this time requiring other FirstEnergy FERC-jurisdictional companies to make changes to their transmission or wholesale rates. However, these rates may be affected by a related FERC "Notice of Inquiry" assessing the impact of the Tax Act on certain rate components.

~~Also, on~~ March 15, 2018, FERC issued a ~~Notice of Inquiry~~NOI seeking information regarding whether and how FERC should address possible changes to ~~accumulated deferred income taxes~~ADIT and bonus depreciation as a result of the Tax Act. Such possible changes could impact FERC-jurisdictional rates, including ~~wholesale~~transmission rates. ~~Various entities submitted responses~~On November 15, 2018, FERC issued a NOPR suggesting mechanisms to revise transmission rates to address the ~~Notice~~Tax Act’s effect on ADIT. Specifically, FERC proposed utilities with transmission formula rates would include mechanisms to (i) deduct any excess ADIT from or add any deficient ADIT to their rate bases; (ii) raise or lower their income tax allowances by any amortized excess or deficient ADIT; and (iii) incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT. Utilities with transmission stated rates would determine the amount of ~~Inquiry.~~excess and deferred income tax caused by the reduced federal corporate income tax rate and return or recover this amount to or from customers. To assist with implementation of the proposed rule, FERC also issued on November 15, 2018, a policy statement providing accounting and ratemaking guidance for treatment of ADIT for all FERC-jurisdictional public utilities. The policy statement also addresses the accounting and ratemaking treatment of ADIT following the sale or retirement of an asset after December 31, 2017. FESC, on behalf of its ~~transmission-owning affiliates, participated in the development of separate~~affiliated transmission owners, supported comments submitted by ~~Edison Electric Institute~~EEI requesting additional clarification on the ratemaking and ~~certain PJM TOs. The~~accounting treatment for ADIT in formula and stated transmission rates. FERC’s final rule remains pending.

Transmission ROE Methodology

In June 2014, FERC issued Opinion No. 531 revising its approach for calculating the discounted cash flow element of FERC’s ROE methodology and announcing the potential for a qualitative adjustment to the ROE methodology results. Parties appealed to the D.C. Circuit, and on April 14, 2017, that court issued a decision vacating FERC’s order and remanding the matter ~~is now before~~to FERC for further ~~action.~~

~~PJM Markets: Grid Reliability and Resiliency~~

review. 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. Each RTO/ISO responded to a provided list of questions and various entities submitted comments. The matter is now before FERC for further action. 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~~

In March 2016, a number of generation owners filed with FERC a complaint against PJM requesting that FERC expand the MOPR in the PJM Tariff to prevent the alleged artificial suppression of prices in PJM capacity markets by state-subsidized generation. However, FERC took no action at that time. In April 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.

~~On June 29,~~October 16, 2018, FERC issued its order on remand, in which it proposed a revised ROE methodology. Specifically, in complaint proceedings alleging that an ~~order granting in part~~existing ROE is not just and ~~denying in part~~reasonable, FERC proposes to rely on three financial models-discounted cash flow, capital-asset pricing, and expected earnings - to establish a composite zone of reasonableness to identify a range of just and reasonable ROEs. FERC then will utilize the ~~March 2016 complaint and rejecting both~~transmission utility’s risk relative to other utilities within that zone of ~~PJM's April 2018 proposals, agreeing with~~reasonableness to assign the ~~complaint that PJM's current MOPR is~~transmission utility to one of three quartiles within the zone. FERC would take no further action (i.e., dismiss the complaint) if the existing ROE falls within the identified quartile. However, if the replacement ROE falls outside the quartile, FERC would deem the existing ROE presumptively unjust and unreasonable and ~~finding that none~~would determine the replacement ROE. FERC would add a fourth financial model risk premium to the analysis to calculate a ROE based on the average point of central tendency for each of the ~~proposed solutions to MOPR reform were just and reasonable and not unduly discriminatory.~~four financial models. On March 21, 2019, FERC established ~~a new FPA Section 206 proceeding~~NOIs to ~~develop a solution to~~collect industry and stakeholder comments on the ~~MOPR construct. FERC's directives~~revised ROE methodology that is described in the ~~new proceeding are~~October 16, 2018 decision, and also whether to ~~revise the MOPR so that it (i) applies~~make changes to ~~both~~FERC’s existing policies and ~~new resources that receive out-of-market subsidies with very limited exemptions;~~practices for awarding transmission rates incentives. Any changes to FERC’s transmission rate ROE and ~~(ii) accommodates state~~incentive policies ~~by allowing~~would be applied on a new FRR-like alternative that would remove resources that receive out-of-market subsidies from the capacity market if the unit could be paired with a commensurate amount of load. Resources receiving out-of-market revenues could opt to stayprospective basis. FirstEnergy currently is participating through various trade groups in the ~~capacity market but would be subject to the revised MOPR, or under the FRR-like alternative they could exit the market. FERC established a timeline for~~NOI comments, and ~~expects~~any subsequent rulemaking and other proceedings.

JCP&L Transmission Formula Rate

On October 30, 2019, JCP&L filed tariff amendments with FERC to ~~issue an order by January 4, 2019, so~~convert JCP&L’s existing stated transmission rate to a forward-looking formula transmission rate. JCP&L requested that the ~~reformed MOPR can be implemented for the 2019 BRA. FERC instituted a refund~~tariff amendments become effective date of July 11, 2018, for the new Section 206 proceeding. On July 30, 2018 FESC, on behalf of the Utilities, submitted a request for clarification or, in the alternative, rehearing of FERC's June 29, 2018 order. Specifically, FESC requested clarification regarding the applicability of FERC's directed MOPR reform to vertically-integrated resources. Various other parties also submitted requests for rehearing or clarification. FERC's order on rehearing remains pending. On October 2, 2018, FESC on behalf of the Utilities submitted comments demonstrating that while MOPR reform may be an interim step, FERC needs to address fundamental flaws in the PJM capacity market.January 1, 2020.

~~On August 13, 2018~~, PJM filed a request for a waiver of certain provisions of the PJM Tariff to delay the 2019 BRA for the 2022/2023 Delivery Year from May 2019 to August 14, 2019 if FERC delays its order in the above Section 206 proceeding as requested by certain parties. PJM also requested waiver of certain deadlines associated with the 2019 BRA, including the posting of planning parameters and submission of a preliminary exception request for deactivating generation resources. FERC issued an order on August 30, 2018 granting the waiver as requested.

Separately, on May 31, 2018, certain merchant generators filed a complaint with FERC against PJM seeking an order finding that PJM's existing MOPR mechanism is unjust and unreasonable, and implementing instead a so-called "Clean" MOPR that would apply to existing and new generation resources of all fuel types and all ownership arrangements, including regulated generation resources such as MP's and JCP&L's existing generation, that receive or have any form of "out-of-market" support, including recovery of generation costs in retail rates. The complainants request a FERC order by May 2019, so that the proposed "Clean" MOPR could be implemented in PJM's 2019 BRA. FESC, on behalf of its affiliates and jointly with EKPC, submitted a protest of the complaint. FESC and EKPC requested FERC reject PJM's proposals, maintain the existing PJM market rules, and direct PJM to develop a holistic solution to the fundamental issues facing its market. Various other entities also submitted protests and comments. FERC did not address the Clean MOPR Complaint in its June 29, 2018 order, which remains pending before FERC. The outcome of FERC's Section 206 proceeding and the Clean MOPR Complaint, and their impact on the Utilities and FirstEnergy's regulated generation sources, if any, cannot be predicted at this time but are not expected to be material.

~~14.~~13. COMMITMENTS, GUARANTEES AND CONTINGENCIES

GUARANTEES AND OTHER ASSURANCES

FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party.

As of September 30, ~~2018, FirstEnergy's~~2019, outstanding guarantees and other assurances aggregated approximately ~~$1.7~~$1.6 billion, consisting of guarantees ~~and assurances~~ on behalf of FES and FENOC ($~~352~~343 million), parental guarantees on behalf of its consolidated subsidiaries ($1 billion), and other guarantees ~~($220 million)~~ and ~~other~~ assurances ($~~141~~301 million). FirstEnergy has also committed to provide ~~certain~~ additional guarantees to the FES Debtors for certain retained environmental liabilities of AE Supply related to the Pleasants Power Station and ~~McElroy's~~McElroy’s Run CCR disposal facility as part of the settlement agreement in connection with the FES Bankruptcy.

COLLATERAL AND CONTINGENT-RELATED FEATURES

In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel, and emission allowances. Certain bilateral agreements ~~and derivative instruments~~ contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit

support with thresholds contingent upon ~~FE's~~FE’s or its ~~subsidiaries'~~subsidiaries’ credit ratings from each of the major

credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements.

Bilateral agreements ~~and derivative instruments~~ entered into by FE and its subsidiaries have margining provisions that require posting of collateral. ~~Based on AE Supply's power portfolio exposure as of September 30, 2018, AE Supply has posted collateral of$1 million.~~ The Utilities ~~and FET's subsidiaries~~ have posted collateral ~~of $10~~totaling $2 million.

These credit-risk-related contingent features, or the margining provisions within bilateral agreements, stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining, which is the ability to secure additional collateral when needed, could be required. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of September 30, ~~2018.~~2019:



Potential Collateral Obligations		AE Supply		Utilities and FET		FE		Total
	(In millions)
Contractual Obligations for Additional Collateral
At current credit rating		$	1	$	—	$	—	$	1
Upon further downgrade		—		40		—		40
Surety Bonds (collateralized amount)⁽¹⁾		1		63		246		310
Total Exposure from Contractual Obligations		$	2	$	103	$	246	$	351

Potential Collateral Obligations AE Supply Utilities and FET FE Total
(In millions)
Contractual Obligations for Additional Collateral
At Current Credit Rating $ 1
$ —
$ —
$ 1
Upon Further Downgrade —
54
—
54
Surety Bonds (Collateralized Amount) 1
60
246
307
Total Exposure from Contractual Obligations $ 2
$ 114
$ 246
$ 362


⁽¹⁾	Surety Bonds are not tied to a credit rating. Surety Bonds’ impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield’s Ferry CCR disposal site, respectively.

Surety Bonds are not tied to a credit rating. Surety Bonds' impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for FG surety bonds of $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield's Ferry CCR disposal site, respectively.

OTHER COMMITMENTS AND CONTINGENCIES

FE is a guarantor under a $300 million syndicated senior secured term loan facility due March 3, 2020, under which Global ~~Holding's~~Holding’s outstanding principal balance is ~~approximately $220~~$145 million as of September 30, ~~2018.~~2019. In addition to FE, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, continue to provide their joint and several ~~guarantees~~guaranties of the obligations of Global Holding under the facility.

In connection with the facility, 69.99% of Global ~~Holding's~~Holding’s direct and indirect membership interests in Signal Peak, Global Rail and their affiliates along with ~~FEV's~~FEV’s and WMB Marketing Ventures, ~~LLC's~~LLC’s respective 33-1/3% membership interests in Global Holding, are pledged to the lenders under the current facility as collateral.

ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. ~~Pursuant~~While FirstEnergy’s environmental policies and procedures are designed to ~~a March 28, 2017 executive order,~~achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by 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.implementing agencies. 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 materially impact its business, results of operations, cash flows and financial condition.

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 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 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~~industry’s bid for a lengthy pause in the litigation and set a briefing schedule. On September 13, 2019, the D.C. Circuit remanded the CSAPR update rule to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable

attainment deadlines. 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~~materially impact FirstEnergy’s operations, cash flows and financial condition.

In February 2019, the EPA announced its final decision to retain without changes ~~to FirstEnergy's operations may result.~~

~~The EPA tightened~~ the ~~primary and secondary~~ NAAQS for ~~ozone from~~SO₂, specifically retaining the ~~2008~~2010 primary (health-based) 1-hour standard ~~levels~~ of 75 ~~PPB to 70 PPB on October 1, 2015. The EPA stated the vast majority~~PPB. As of ~~U.S. counties will meet the new 70 PPB standard by 2025 due to other federal and state rules and programs but on April~~September 30, ~~2018, the EPA designated fifty-one areas in twenty-two states as non-attainment; however,~~2019, FirstEnergy has no power plants operating in ~~those areas. States have roughly threeyears to develop implementation plans to attain~~areas designated as non-attainment by 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 operations may result.~~ EPA.

In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating ~~facility's~~facility’s NOx emissions significantly contribute to ~~Delaware's~~Delaware’s inability to attain the ozone NAAQS. The petition sought a short-term NOx emission rate limit of 0.125 lb/mmBTU over an averaging period of no more than 24 hours. 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 and Pleasants Units 1 and 2, significantly contribute to ~~Maryland's~~Maryland’s inability to attain the ozone NAAQS. The petition sought NOx emission rate limits for the 36 EGUs by May1, 2017. On September 14, 2018, the EPA denied both the States of Delaware and ~~Maryland~~Maryland’s petitions under CAA Section 126. In October 2018, Delaware and Maryland appealed the denials of their petitions to the D.C. Circuit. In March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from ~~nine~~9 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. On May 3, 2018, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to November 9, 2018. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss.

Climate Change

~~FirstEnergy has established a goal to reduce CO~~₂ ~~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,” 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 June~~23, 2014, the U.S. Supreme Court decided that CO~~₂ 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 EGUs. The EPA also finalized separate regulations imposing CO~~₂ emission limits for new, modified, and reconstructed fossil fuel-fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On January~~21, 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 March~~28, 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. To replace the CPP, the EPA proposed the ACE rule on August 21, 2018, which would establish emission guidelines for states to develop plans to address GHG emissions from existing coal-fired power plants. 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~~2025. In 2015, FirstEnergy set a goal of reducing company-wide CO₂ emissions by at least 90 percent below 2005 levels by 2045. As of December 31, 2018, FirstEnergy has reduced its CO₂emissions by approximately 62 percent. In September 2016, the U.S. 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~~Agreement’s 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.

In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHG under the Clean Air Act” 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. The EPA released its final CPP regulations in August 2015 to reduce CO₂ emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO₂ emission limits for new, modified, and reconstructed fossil fuel fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On February 9, 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. To replace the CPP, the EPA proposed the ACE rule on August 21, 2018, which would establish emission guidelines for states to develop plans to address GHG emissions from existing coal-fired power plants. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that establishes guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired power plants. Depending on the outcomes of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material.

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~~FirstEnergy’s facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to ~~FirstEnergy's~~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~~facility’s cooling water system. Depending on any final action taken by the states 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~~FirstEnergy’s operations may result.

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. In March 2018, the WVDEP issued a draft NPDES Permit Renewal that, if finalized as proposed, would moot the appeal and reduce the estimated capital investment requirements. 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 CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the ~~EPA's~~EPA’s evaluation of the need for future regulation.

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, ~~2018,~~2019, based on estimates of the total costs of cleanup, ~~FirstEnergy's~~FirstEnergy’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately ~~$115~~$119 million have been accrued through September 30, ~~2018.~~2019. Included in the total are accrued liabilities of approximately ~~$78~~$83 million for environmental remediation of former ~~manufactured gas plants~~MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. 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, JCP&L, ME and PN must ensure that adequate funds will be available to decommission their retired nuclear facility, TMI-2. As of September 30, ~~2018,~~2019, JCP&L, ME and PN had in total approximately ~~$0.8 billion~~$871 million invested in external trusts to be used for the decommissioning and environmental remediation of their retired TMI-2 nuclear generating facility. The values of these NDTs also fluctuate based on market conditions. If the values of the trusts decline by a material amount, the obligation ofto JCP&L, ME and PN 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.

FES Bankruptcy

On March 31, 2018, FES, including its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage L.L.C. and FGMUC, and FENOC filed voluntary petitions for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court. See Note 3, ~~"Discontinued~~“Discontinued Operations,"” for additional information.

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to ~~FirstEnergy's~~FirstEnergy’s normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE

or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note ~~13, "Regulatory~~12, “Regulatory 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 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 ~~FE's~~FE’s or its ~~subsidiaries'~~subsidiaries’ financial condition, results of operations and cash flows.

~~15.~~

14. SEGMENT INFORMATION

~~FirstEnergy's reportable segments are as follows:~~ Regulated Distribution and Regulated ~~Transmission.~~Transmission are FirstEnergy’s reportable segments.

On March 31, 2018, as discussed in Note 3,, “Discontinued Operations,,” FirstEnergy deconsolidated FES and FENOC and presented FES, FENOC, BSPC and a portion of AE Supply, representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, as discontinued operations in FirstEnergy’s consolidated financial statements resulting from actions taken as part of the strategic review to exit commodity-exposed generation. During the third quarter of 2018, the Pleasants Power Station was also reclassified to discontinued operations following its inclusion in the definitive settlement agreement for the benefit of FES' creditors. The financial information for all periods has been revised to present the discontinued operations within Reconciling Adjustments. The remaining business activities that previously comprised the CES reportable operating segment were not material and, as such, have been combined into Corporate/Other for reporting purposes.

The Regulated Distribution segment distributes electricity through FirstEnergy’s ~~ten~~10 utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The ~~segment's~~segment’s results reflect the ~~commodity~~ costs of securing and delivering electric generation ~~and~~from transmission facilities to customers, including the deferral and amortization of certain ~~fuel~~related costs.

The Regulated Transmission segment provides transmission infrastructure owned and operated by ~~ATSI, TrAIL, MAIT~~the Transmission Companies and certain of ~~FirstEnergy's~~FirstEnergy’s utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The ~~segment's~~segment’s revenues are primarily derived from forward-looking formula rates at ~~ATSI, TrAIL, and MAIT~~the Transmission Companies as well as stated transmission rates at JCP&L, MP, PE and WP. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. The ~~segment's~~segment’s results also reflect the net transmission expenses related to the delivery of electricity on ~~FirstEnergy's~~FirstEnergy’s transmission facilities.

4039

Financial information for each of ~~FirstEnergy's~~FirstEnergy’s reportable segments is presented in the tables ~~below.~~below:

Segment Financial Information



For the Three Months Ended	Regulated Distribution			Regulated Transmission		Corporate/ Other			Reconciling Adjustments			Consolidated
	(In millions)

September 30, 2019
External revenues	$	2,590		$	371	$	2		$	—		$	2,963
Internal revenues	46			4		—			(50		)	—
Total revenues	$	2,636		$	375	$	2		$	(50	)	$	2,963
Depreciation	215			71		—			18			304
Amortization of regulatory assets, net	42			1		—			—			43
Miscellaneous income (expense), net	36			4		24			(7		)	57
Interest expense	124			49		95			(7		)	261
Income taxes (benefits)	103			26		(22		)	—			107
Income (loss) from continuing operations	370			113		(94		)	—			389
Property additions	365			304		15			—			684

September 30, 2018
External revenues	$	2,717		$	341	$	6		$	—		$	3,064
Internal revenues	49			5		—			(54		)	—
Total revenues	$	2,766		$	346	$	6		$	(54	)	$	3,064
Depreciation	202			64		1			16			283
Amortization of regulatory assets, net	65			2		—			—			67
Miscellaneous income (expense), net	34			4		19			(8		)	49
Interest expense	127			43		93			(8		)	255
Income taxes (benefits)	126			34		(39		)	—			121
Income (loss) from continuing operations	416			99		(116		)	—			399
Property additions	356			262		5			12			635

For the Nine Months Ended

September 30, 2019
External revenues	$	7,261		$	1,091	$	10		$	—		$	8,362
Internal revenues	140			12		—			(152		)	—
Total revenues	$	7,401		$	1,103	$	10		$	(152	)	$	8,362
Depreciation	644			211		3			52			910
Amortization of regulatory assets, net	79			6		—			—			85
Miscellaneous income (expense), net	128			12		73			(22		)	191
Interest expense	370			142		283			(22		)	773
Income taxes (benefits)	259			87		(65		)	—			281
Income (loss) from continuing operations	957			333		(205		)	—			1,085
Property additions	1,037			835		40			—			1,912

September 30, 2018
External revenues	$	7,540		$	996	$	15		$	—		$	8,551
Internal revenues	154			14		13			(181		)	—
Total revenues	$	7,694		$	1,010	$	28		$	(181	)	$	8,551
Depreciation	598			187		6			52			843
Amortization (deferral) of regulatory assets, net	(194		)	6		—			—			(188		)
Miscellaneous income (expense), net	146			11		34			(27		)	164
Interest expense	384			124		377			(27		)	858
Income taxes (benefits)	357			104		(6		)	—			455
Income (loss) from continuing operations	1,115			302		(529		)	—			888
Property additions	1,011			836		68			27			1,942

As of September 30, 2019
Total assets	$	29,428		$	11,255	$	790		$	33		$	41,506
Total goodwill	5,004			614		—			—			5,618

As of December 31, 2018
Total assets	$	28,690		$	10,404	$	944		$	25		$	40,063
Total goodwill	5,004			614		—			—			5,618

For the Three Months Ended Regulated Distribution Regulated Transmission Corporate/ Other Reconciling Adjustments Consolidated
(In millions)

September 30, 2018
Revenues $ 2,766
$ 346
$ 6
$ (54 ) $ 3,064
Depreciation 202
64
1
16
283
Amortization of regulatory assets, net 65
2
—
—
67
Miscellaneous income (expense), net 34
4
19
(8 ) 49
Interest expense 127
43
93
(8 ) 255
Income taxes (benefits) 126
34
(27 ) —
133
Income (loss) from continuing operations 416
99
(128 ) —
387
Total assets 28,530
10,017
896
—
39,443
Total goodwill 5,004
614
—
—
5,618
Property additions 356
262
5
12
635

September 30, 2017
Revenues $ 2,609
$ 341
$ 10
$ (50 ) $ 2,910
Depreciation 183
59
2
17
261
Amortization of regulatory assets, net 107
6
—
—
113
Impairment of assets —
13
—
—
13
Miscellaneous income (expense), net 16
1
15
(13 ) 19
Interest expense 133
38
104
(13 ) 262
Income taxes (benefits) 183
49
(30 ) —
202
Income (loss) from continuing operations 314
84
(97 ) —
301
Total assets 27,866
9,356
938
5,489
43,649
Total goodwill 5,004
614
—
—
5,618
Property additions 286
248
14
45
593

For the Nine Months Ended

September 30, 2018
Revenues $ 7,694
$ 1,010
$ 28
$ (181 ) $ 8,551
Depreciation 598
187
6
52
843
Amortization (deferral) of regulatory assets, net (194 ) 6
—
—
(188 )
Miscellaneous income (expense), net 146
11
34
(27 ) 164
Interest expense 384
124
377
(27 ) 858
Income taxes 357
104
42
—
503
Income (loss) from continuing operations 1,115
302
(577 ) —
840
Property additions 1,011
836
68
27
1,942

September 30, 2017
Revenues $ 7,380
$ 981
$ 37
$ (151 ) $ 8,247
Depreciation 540
164
9
52
765
Amortization of regulatory assets, net 263
11
—
—
274
Impairment of assets —
13
—
—
13
Miscellaneous income (expense), net 45
1
31
(33 ) 44
Interest expense 405
116
263
(33 ) 751
Income taxes (benefits) 442
154
(113 ) —
483
Income (loss) from continuing operations 756
264
(248 ) —
772
Property additions 854
717
43
233
1,847

4140

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRSTENERGY’S BUSINESS

FE and its subsidiaries are principally involved in the transmission, distribution and generation of ~~electricity. Its~~electricity through its reportable segments, ~~are as follows:~~ Regulated Distribution and Regulated Transmission.

On March 31, 2018, ~~as discussed below,~~ FirstEnergy deconsolidated FES and FENOC and presented FES, FENOC, BSPC and a portion of AE Supply, representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, as discontinued operations in FirstEnergy’s consolidated financial statements resulting from actions taken as part of the strategic review to exit commodity-exposed generation. During the third quarter of 2018, the Pleasants Power Station was also reclassified to discontinued operations following its inclusion in the definitive settlement agreement for the benefit of FES' creditors. The financial information for all periods has been revised to present the discontinued operations within Reconciling Adjustments. The remaining business activities that previously comprised the CES reportable operating segment were not material and, as such, have been combined into Corporate/Other for reporting purposes.

The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The ~~segment's~~segment’s results reflect the ~~commodity~~ costs of securing and delivering electric generation ~~and~~from transmission facilities to customers, including the deferral and amortization of certain ~~fuel~~related costs.

The Regulated Transmission segment provides transmission infrastructure owned and operated by ~~ATSI, TrAIL, MAIT~~the Transmission Companies and certain of ~~FirstEnergy's~~FirstEnergy’s utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The ~~segment's~~segment’s revenues are primarily derived from forward-looking formula rates at ~~ATSI, TrAIL, and MAIT~~the Transmission Companies as well as stated transmission rates at ~~certain of~~ JCP&L, MP, PE and WP. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. The ~~segment's~~segment’s results also reflect the net transmission expenses related to the delivery of electricity on ~~FirstEnergy's~~FirstEnergy’s transmission facilities.

~~Corporate~~The Corporate/Other segment reflects corporate support not charged to ~~FE's~~FE’s subsidiaries, interest expense on ~~stand-alone~~FE’s holding company debt ~~corporate income taxes~~ and other businesses that do not constitute an operating ~~segment are categorized as Corporate/Other for reportable business segment purposes.~~segment. Additionally, reconciling adjustments for the elimination of inter-segment transactions and discontinued operations are included in Corporate/Other. As of September 30, ~~2018, 1,367~~2019, 67 MWs of electric generating capacity, representing ~~the Pleasants Power Station (1,300 MWs) and~~ AE ~~Supply's~~Supply’s OVEC capacity entitlement, ~~(67 MWs),~~ was included in continuing operations of the Corporate/~~Other.~~Other reportable segment. As of September 30, ~~2018,~~2019, Corporate/Other had ~~$5.35~~approximately $7.1 billion of FE holding company long-term debt and $1.7 billion in borrowings under its revolving credit facility. On October 19, 2018, FE and the Utilities and FET and certain of its subsidiaries amended their respective five-year syndicated revolving credit facilities, which provide for aggregate commitments of $3.5 billion and are available through December 6, 2022. Also on October 19, 2018, FE entered into two separate syndicated term loan credit facilities, the first being a $1.25 billion 364-day facility, and the second being a $500 million two-year facility, the proceeds of which were used to reduce short-term debt.

4241

EXECUTIVE SUMMARY

FirstEnergy’s strategy is to be a fully regulated utility company, focusing on stable and predictable earnings and cash flow from its regulated business units - Regulated Distribution and Regulated Transmission - ~~which focus on~~through delivering enhanced customer service and reliability. Together, the Regulated Distribution and Regulated Transmission businesses are expected to provide stable, predictable earnings and cash flows that support FE’s dividend.

The scale and diversity of the ten Utilities that comprise the Regulated Distribution business uniquely position this business for growth through opportunities for additional investment. ~~Since 2015,~~Over the past several years, Regulated Distribution has experienced ~~significant~~rate base growth through investments that have improved reliability and added operating flexibility to the distribution infrastructure, which provide benefits to the customers and communities those Utilities serve. Based on its current capital plan, which includes ~~$5.7~~$6.2 to $6.7 billion in forecasted capital investments from 2018 through 2021, Regulated Distribution’s rate base growth rate is expected to be approximately 5% from 2018 through 2021. Additionally, this business is exploring other opportunities for growth, including investments in electric system improvement and modernization projects to increase reliability and improve service to customers, as well as exploring opportunities in customer engagement that focus on the electrification of ~~customers'~~customers’ homes and businesses by providing a full range of products and services.

With approximately 24,500 miles in operations, the Regulated Transmission business is the centerpiece of FirstEnergy’s regulated investment strategy with approximately 80% of its capital investments recovered under the forward-looking formula rates ~~including~~at ATSI, TrAIL and MAIT. Regulated Transmission has also experienced significant growth as part of its Energizing the Future transmission plan with plans to invest ~~$4.0~~up to $4.8 billion in capital from 2018 to 2021, which is expected to result in Regulated Transmission rate base growth of approximately 11% through 2021.

As part of the Energizing the Future initiative, a Center for Advanced Technology was opened in Akron, Ohio in April 2019. The 88,000 square feet facility was designed to be a hands-on environment where engineers and technicians can develop and evaluate new technology and grid solutions and simulate a variety of real-world conditions.

FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of ~~approximately~~over $20 billion beyond those identified through 2021, which are expected to strengthen grid and cyber-security and make the transmission system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility.

On December 22, 2017, the President signed the Tax Act into law. Substantially all of the provisions of the Tax Act are effective for taxable years beginning after December 31, 2017. As discussed below, various state regulatory proceedings have been initiated to investigate the impact of the Tax Act on the Utilities’ rates and charges. FirstEnergy continues to work with various state regulatory commissions to determine appropriate changes to customer rates resulting from the Tax Act. Several states have since implemented rate reductions to reflect the impact of the Tax Act, while in the remaining states, FirstEnergy continues to track and apply regulatory accounting treatment for the expected rate impact of changes resulting from the Tax Act. FERC also recently took action to address the impact of the Tax Act on FERC-jurisdictional rates, including transmission and electric wholesale rates. FirstEnergy has reflected the impact of changes to current taxes in its normal update to FERC-jurisdictional transmission rates and will continue to work with FERC regarding whether and how it should address possible changes to transmission and wholesale rates resulting from the Tax Act.

As previously disclosed, on January 22, 2018, FirstEnergy announced a $2.5 billion equity issuance, which included $1.62 billion in 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 equity investment strengthened the Company’s balance sheet, supports the ~~company's~~company’s transition to a fully regulated utility company and ~~is expected to position~~positions FirstEnergy for sustained investment-grade credit metrics. The shares of preferred ~~shares participate~~stock participated in the dividend paid on common stock on an as-converted basis and ~~are~~were non-voting except in certain limited circumstances. The preferred shares contain an optional conversion right for holders as of July 22, 2018, and will mandatorily convert in July 2019, subject to limited exceptions. Proceeds from the investment were used to reduce holding company debt by $1.45 billion and fund the company’s pension plan by $750 million, with the remainder used for general corporate purposes. Because of this investment, FirstEnergy does not currently anticipate the need to issue additional equity through at least 2021 outside of its regular stock investment and employee benefit plans. On July 22, 2019, 28,302 shares of preferred stock automatically converted into 1,032,165 shares of common stock, and 181,520 shares of preferred stock remained unconverted as the holder reached the 4.9% cap as outlined in the terms of the preferred stock. The remaining 181,520 preferred stock shares were converted on August 1, 2019, into 6,619,985 shares of common stock. As of September 30, ~~2018, 911,411~~2019, there are no preferred shares outstanding and 1,616,000 shares of preferred stock ~~have been~~were converted ~~to 33,238,910~~ into 58,935,078shares of common ~~stock at the option of the holders.~~stock.

On March 31, 2018, FirstEnergy’s competitive subsidiary FES and FENOC voluntarily filed petitions under Chapter 11 of the Federal Bankruptcy Code with the U.S. Bankruptcy Court. FirstEnergy and its other subsidiaries - including its Utilities and AE Supply - are not part of the filing and are not subject to the Chapter 11 process. The voluntary bankruptcy filings by the FES ~~and FENOC~~Debtors represented a significant event in FirstEnergy’s previously announced strategy to exit the competitive generation business and become a fully regulated utility company with a stronger balance sheet, solid cash flows and more predictable earnings. As a result of the bankruptcy filings, as of March 31, 2018, the FES ~~and FENOC~~Debtors were deconsolidated from FirstEnergy’s financial statements. Additionally, the operating results of the FES ~~and FENOC,~~Debtors, as well as BSPC and a portion of AE Supply (including the Pleasants Power Station) that were subject to completed or pending asset sales, collectively representing substantially all of FirstEnergy’s operations that comprised the CES reportable segment, are presented as discontinued operations. Prior periods have been reclassified to conform with such presentation as discontinued operations.

On April 23, 2018, FirstEnergy and the FES Key Creditor Groups reached an agreement in principle to resolve certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and their creditors against FirstEnergy. ~~The~~On September 26, 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement dated August 26, 2018, by and among FirstEnergy, two groups of key FES creditors (collectively, the FES Key Creditor Groups), the FES Debtors and the ~~UCC subsequently joined~~UCC. The FES Bankruptcy settlement ~~discussions with~~agreement resolves certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and the FES Key Creditor ~~Groups. On August 26, 2018,~~Groups against FirstEnergy, ~~the FES Key Creditor Groups, the FES Debtors~~ and ~~the UCC entered into a definitive settlement agreement which~~

~~was approved by order of the Bankruptcy Court on September 26, 2018. The settlement agreement~~ includes the following terms, among others:


•	FE will pay certain pre-petition FES Debtors employee-related obligations, which include unfunded pension obligations and other employee benefits.


•	A nonconsensual release of all claims against FirstEnergy by the FES Debtors’ creditors, which was subsequently waived pursuant to the Waiver Agreement, discussed below.


•	A $225 million cash payment from FirstEnergy.


•	A $628 million aggregate principal amount note issuance by FirstEnergy to the FES Debtors, which may be decreased by the amount, if any, of cash paid by FirstEnergy to the FES Debtors under the Intercompany Income Tax Allocation Agreement for the tax benefits related to the sale or deactivation of certain plants.

FE will pay certain pre-petition FES and FENOC employee-related obligations, which include unfunded pension obligations and other employee benefits, and provides for the waiver of all pre-petition claims (other than those claims under the Tax Allocation Agreement for the 2018 tax year) against the FES Debtors related to the FES Debtors and their businesses, including the full borrowings by FES under the $500 million secured credit facility, the $200 million credit agreement being used to support surety bonds, the BNSF/CSX rail settlement guarantee, and the FES Debtors' unfunded pension obligations, all of which were previously accounted for in the first quarter of 2018 gain on deconsolidation.

~~The full release of all claims against FirstEnergy by the FES Debtors and their creditors.~~

~~A $225 million cash payment from FirstEnergy.~~


•	FirstEnergy agrees to waive all pre-petition claims related to shared services and credit for nine months of the FES Debtors’ shared service costs beginning as of April 1, 2018 through December 31, 2018, in an amount not to exceed $112.5 million, and FirstEnergy agrees to extend the availability of shared services until no later than June 30, 2020.

•

FirstEnergy agrees to perform under the Intercompany Tax Allocation Agreement through the FES Debtors’ emergence from bankruptcy, at which time FirstEnergy will waive a 2017 overpayment for NOLs of approximately $71 million, reverse 2018 estimated payments for NOLs of approximately $88 million and pay the FES Debtors for the use of NOLs in an amount no less than $66 million for 2018. Based on the 2018 federal tax return filed in September 2019, FirstEnergy owes the FES debtors approximately $31 million associated with 2018, which will be paid upon emergence.

FirstEnergy agrees to perform under the Intracompany Tax Allocation Agreement through the FES Debtors’ emergence from bankruptcy, at which time FirstEnergy will waive a 2017 overpayment for NOLs of approximately $71 million, reverse 2018 estimated payments for NOLs of approximately $88 million and pay the FES Debtors for the use of NOLs in an amount no less than $66 million (of which approximately $20 million has been paid through September 30, 2018).

~~FirstEnergy has determined a loss is probable with respect to the~~The FES Bankruptcy and recorded a pre-tax charge in the third quarter of 2018 of $1.2 billion within Discontinued Operations, which reflects the current estimate of the commitments and payments under the settlement agreement.

~~The~~ settlement agreement remains subject to satisfaction of the conditions set forth therein, most notably the issuance of a final order by the Bankruptcy Court approving the plan or plans of reorganization for the FES Debtors that are acceptable to FirstEnergy consistent with the requirements of the settlement agreement.certain conditions. There can be no assurance that such conditions will be satisfied or the FES Bankruptcy settlement agreement will be otherwise consummated, and the actual outcome of this matter may differ materially from the terms of the agreement described herein. FirstEnergy will continue to evaluate the impact of any new factors on the settlement and their relative impact on the financial statements.

In October 2019, the FES Debtors and the unions objecting to confirmation of the plan of reorganization reached an agreement framework and the unions agreed to withdraw their objections to the plan of reorganization. On October 15, 2019, the Bankruptcy Court held a hearing to confirm the FES Debtors’ plan of reorganization, and on October 16, 2019, entered a final order confirming the FES Debtors' plan of reorganization. On October 29, 2019, several parties, including FERC, filed notices of appeal with the United States District Court for the Northern District of Ohio appealing the Bankruptcy Court’s final order approving FES Debtors’ plan of reorganization. The emergence of the FES Debtors from bankruptcy pursuant to the confirmed plan of reorganization is subject to the satisfaction of certain conditions, including approvals from the FERC and NRC.

With the bankruptcy filings of FES and FENOC, and the completed sale of the previously announced competitive Bath hydroelectric station, FirstEnergy’s electric generation fleet is now made up of 3,790 MW of regulated generation, including four plants in West Virginia, Virginia and New Jersey. This excludes AE Supply’s remaining competitive generation assets - the 1,300 MW Pleasants Power Station, which will be transferred to ~~FES' creditors under~~FG pursuant to the settlement agreement, and its 67 MW OVEC capacity entitlement.

In support of the strategic review to exit competitive generation, management launched the FE Tomorrow initiative to define FirstEnergy's future organization to support its regulated business. FE Tomorrow is intended to align corporate services to efficiently support the regulated operations by ensuring that FirstEnergy has the right talent, organizational and cost structure to achieve our earnings growth targets. In support of the FE Tomorrow initiative, in June and early July 2018, nearly 500 employees in the shared services and utility services and sustainability organizations, which was more than 80% of eligible employees, accepted a voluntary enhanced retirement package, which included severance compensation and a temporary pension enhancement, with most employees expected to depart by December 31, 2018. Management expects the cost savings resulting from the FE Tomorrow initiative to support the company's growth targets.

FINANCIAL OVERVIEW AND RESULTS OF OPERATIONS


(In millions, except per share amounts)	For the Three Months Ended September 30,											For the Nine Months Ended September 30,
(In millions)																						For the Three Months Ended September 30,											For the Nine Months Ended September 30,
	2018			2017			Change					2018			2017			Change				2019			2018			Change					2019			2018			Change

Revenues	$	3,064		$	2,910		$	154		5	%	$	8,551		$	8,247		$	304	4	%	$	2,963		$	3,064		$	(101	)	(3	)%	$	8,362		$	8,551		$	(189	)	(2	)%

Operating expenses	2,354			2,177			177			8	%	6,561			6,324			237		4	%	2,282			2,354			(72		)	(3	)%	6,467			6,561			(94		)	(1	)%

Operating income	710			733			(23		)	(3	)%	1,990			1,923			67		3	%	681			710			(29		)	(4	)%	1,895			1,990			(95		)	(5	)%

Other expenses, net	(190		)	(230		)	40			(17	)%	(647		)	(668		)	21		(3	)%	(185		)	(190		)	5			3	%	(529		)	(647		)	118			18	%

Income before income taxes	520			503			17			3	%	1,343			1,255			88		7	%	496			520			(24		)	(5	)%	1,366			1,343			23			2	%

Income taxes	133			202			(69		)	(34	)%	503			483			20		4	%	107			121			(14		)	(12	)%	281			455			(174		)	(38	)%

Income from continuing operations	387			301			86			29	%	840			772			68		9	%	389			399			(10		)	(3	)%	1,085			888			197			22	%

Discontinued operations	(845		)	95			(940		)	NM		370			3			367		NM
Discontinued operations, net of tax																						2			(857		)	859			NM		(62		)	322			(384		)	NM

Net income (loss)	$	(458	)	$	396		$	(854	)	(216	)%	$	1,210		$	775		$	435	56	%	$	391		$	(458	)	$	849		185	%	$	1,023		$	1,210		$	(187	)	(15	)%

* NM = not meaningful

The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note ~~15, "Segment~~14, “Segment Information,"” of the Notes to Consolidated Financial Statements.

~~On March 31, 2018, as discussed above~~, FirstEnergy deconsolidated FES and FENOC and presented FES, FENOC, BSPC and a portion of AE Supply representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, as discontinued operations in FirstEnergy’s consolidated financial statements resulting from the FES Bankruptcy and actions taken as part of the strategic review to exit commodity-exposed generation. During the third quarter of 2018, the Pleasants Power Station was reclassified to discontinued operations following its inclusion in the definitive settlement agreement for the benefit of FES' creditors. The financial information for all periods has been revised to present the discontinued operations. The remaining business activities that previously comprised the CES reportable operating segment were not material and, as such, have been combined into Corporate/Other for reporting purposes.

Certain prior year amounts have been reclassified to conform to the current year presentation.

4544

Summary of Results of Operations — Third Quarter ~~2018~~2019 Compared with Third Quarter ~~2017~~2018

Financial results for FirstEnergy’s business segments in the third quarter of ~~2018~~2019 and ~~2017~~2018 were as follows:



Third Quarter 2019 Financial Results	Regulated Distribution			Regulated Transmission			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
Electric	$	2,571		$	371		$	(33	)	$	2,909
Other	65			4			(15		)	54
Total Revenues	2,636			375			(48		)	2,963

Operating Expenses:
Fuel	122			—			—			122
Purchased power	794			—			4			798
Other operating expenses	715			75			(32		)	758
Provision for depreciation	215			71			18			304
Amortization of regulatory assets, net	42			1			—			43
General taxes	197			53			7			257
Total Operating Expenses	2,085			200			(3		)	2,282

Operating Income (Loss)	551			175			(45		)	681

Other Income (Expense):
Miscellaneous income, net	36			4			17			57
Interest expense	(124		)	(49		)	(88		)	(261		)
Capitalized financing costs	10			9			—			19
Total Other Expense	(78		)	(36		)	(71		)	(185		)

Income (Loss) Before Income Taxes (Benefits)	473			139			(116		)	496
Income taxes (benefits)	103			26			(22		)	107
Income (Loss) From Continuing Operations	370			113			(94		)	389
Discontinued operations, net of tax	—			—			2			2
Net Income (Loss)	$	370		$	113		$	(92	)	$	391


Third Quarter 2018 Financial Results	Regulated Distribution			Regulated Transmission			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated			Regulated Distribution			Regulated Transmission			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)												(In millions)
Revenues:
External
Electric	$	2,698		$	341		$	(30	)	$	3,009		$	2,698		$	341		$	(30	)	$	3,009
Other	68			5			(18		)	55			68			5			(18		)	55
Total Revenues	2,766			346			(48		)	3,064			2,766			346			(48		)	3,064

Operating Expenses:
Fuel	137			—			—			137			137			—			—			137
Purchased power	873			—			3			876			873			—			3			876
Other operating expenses	663			68			8			739			663			68			8			739
Provision for depreciation	202			64			17			283			202			64			17			283
Amortization of regulatory assets, net	65			2			—			67			65			2			—			67
General taxes	197			49			6			252			197			49			6			252
Total Operating Expenses	2,137			183			34			2,354			2,137			183			34			2,354

Operating Income (Loss)	629			163			(82		)	710			629			163			(82		)	710

Other Income (Expense):
Miscellaneous income, net	34			4			11			49			34			4			11			49
Interest expense	(127		)	(43		)	(85		)	(255		)	(127		)	(43		)	(85		)	(255		)
Capitalized financing costs	6			9			1			16			6			9			1			16
Total Other Expense	(87		)	(30		)	(73		)	(190		)	(87		)	(30		)	(73		)	(190		)

Income (Loss) Before Income Taxes (Benefits)	542			133			(155		)	520			542			133			(155		)	520
Income taxes (benefits)	126			34			(27		)	133			126			34			(39		)	121
Income (Loss) From Continuing Operations	416			99			(128		)	387			416			99			(116		)	399
Discontinued Operations, net of tax	—			—			(845		)	(845		)
Discontinued operations, net of tax													—			—			(857		)	(857		)
Net Income (Loss)	$	416		$	99		$	(973	)	$	(458	)	$	416		$	99		$	(973	)	$	(458	)


Third Quarter 2017 Financial Results	Regulated Distribution			Regulated Transmission			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated
Changes Between Third Quarter 2019 and Third Quarter 2018 Financial Results													Regulated Distribution			Regulated Transmission			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)												(In millions)
Revenues:
External
Electric	$	2,553		$	337		$	(26	)	$	2,864		$	(127	)	$	30		$	(3	)	$	(100	)
Other	56			4			(14		)	46			(3		)	(1		)	3			(1		)
Total Revenues	2,609			341			(40		)	2,910			(130		)	29			—			(101		)

Operating Expenses:
Fuel	126			—			—			126			(15		)	—			—			(15		)
Purchased power	776			—			(2		)	774			(79		)	—			1			(78		)
Other operating expenses	621			55			(24		)	652			52			7			(40		)	19
Provision for depreciation	183			59			19			261			13			7			1			21
Amortization of regulatory assets, net	107			6			—			113			(23		)	(1		)	—			(24		)
General taxes	187			45			6			238			—			4			1			5
Impairment of assets	—			13			—			13
Total Operating Expenses	2,000			178			(1		)	2,177			(52		)	17			(37		)	(72		)

Operating Income (Loss)	609			163			(39		)	733			(78		)	12			37			(29		)

Other Income (Expense):
Miscellaneous income, net	16			1			2			19			2			—			6			8
Interest expense	(133		)	(38		)	(91		)	(262		)	3			(6		)	(3		)	(6		)
Capitalized financing costs	5			7			1			13			4			—			(1		)	3
Total Other Expense	(112		)	(30		)	(88		)	(230		)	9			(6		)	2			5

Income (Loss) Before Income Taxes (Benefits)	497			133			(127		)	503			(69		)	6			39			(24		)
Income taxes (benefits)	183			49			(30		)	202			(23		)	(8		)	17			(14		)
Income (Loss) From Continuing Operations	314			84			(97		)	301			(46		)	14			22			(10		)
Discontinued Operations, net of tax	—			—			95			95
Discontinued operations, net of tax													—			—			859			859
Net Income (Loss)	$	314		$	84		$	(2	)	$	396		$	(46	)	$	14		$	881		$	849



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

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



Title of Each Class	Trading Symbol	Name of Each Exchange on Which Registered
Common Stock, $0.10 par value	FE	New York Stock Exchange



Yes	~~Yes~~ þ No o☑	No	☐



Yes	~~Yes~~ þ No o ☑	No	☐



Large Accelerated Filerþ	☑

Accelerated Filero	☐

Non-accelerated Filero	☐

Smaller Reporting Companyo	☐

Emerging Growth Companyo	☐



		OUTSTANDING
CLASS		AS OF SEPTEMBER 30, ~~2018~~2019
~~FirstEnergy Corp.,~~Common Stock, $0.10 par value		~~511,445,350~~540,311,707

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

Notes To Consolidated Financial Statements	5

Item 2. ~~Management's~~Management’s Discussion and Analysis of Financial Condition and Results of Operations	4241

Item 3. Quantitative and Qualitative Disclosures About Market Risk	8378

Item 4. Controls and Procedures	8378

Part II. Other Information

Item 1. Legal Proceedings	8378

Item 1A. Risk Factors	8378

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	9678

Item 3. Defaults Upon Senior Securities	9678

Item 4. Mine Safety Disclosures	96

~~Item 5. Other Information~~	9678

Item ~~6. Exhibits~~5. Other Information	~~100~~78

Item 6. Exhibits	79



AE	Allegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy on February 25, 2011, which subsequently merged with and into 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, formerly a generation subsidiary of AE Supply that became a wholly owned subsidiary of MP in May 2018
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
BSPC	Bay Shore Power Company
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~~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.~~LLC, and FGMUC, which provides ~~unregulated~~ energy-related products and services
FES Debtors	FES and FENOC
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~~MAIT and ~~MAIT,~~TrAIL, 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~~GPUN	GPU Nuclear, Inc., ~~former parent~~a subsidiary of ~~JCP&L, ME and PN, that merged with~~ FE, ~~on November 7, 2001~~which operates TMI-2
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
Transmission Companies	ATSI, MAIT and TrAIL
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~~

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

ACE	Affordable Clean Energy
~~ADIT~~	~~Accumulated Deferred Income Taxes~~
~~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 Reliability Pricing Model Base Residual Auction~~
~~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~~
~~D.C. Circuit~~	~~United States Court of Appeals for the District of Columbia Circuit~~
~~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~~
~~EGU~~	~~Electric Generation Units~~
~~EKPC~~	~~East Kentucky Power Cooperative, Inc.~~
~~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~~ADIT	~~Unit Power Agreement entered into on April 1, 2016 by and between the Ohio Companies and FES~~Accumulated Deferred Income Taxes
	Facebook®	Facebook is a registered trademark of Facebook, Inc.
AEP	American Electric Power Company, Inc.		FASB	Financial Accounting Standards Board
AFS	Available-for-sale		FERC	Federal Energy Regulatory Commission

~~GLOSSARY OF TERMS,~~ ~~Continued~~
AFUDC	Allowance for Funds Used During Construction
	FE Tomorrow	~~FirstEnergy's~~FirstEnergy’s initiative launched in late 2016 to identify its optimal organizational structure and properly align corporate costs and systems to efficiently support a fully regulated company going forward
ALJ	Administrative Law Judge		FES Bankruptcy	~~Voluntary~~FES Debtors’ voluntary petitions for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code with the Bankruptcy Court ~~by the FES Debtors.~~
AOCI	Accumulated Other Comprehensive Income		Fitch	Fitch Ratings
ARO	Asset Retirement Obligation		FMB	First Mortgage Bond
ARP	Alternative Revenue Program		FPA	Federal Power Act
~~FRR~~ASC	~~Fixed Resource Requirement~~Accounting Standard Codification
	FTR	Financial Transmission Right
ASU	Accounting Standards Update		GAAP	Accounting Principles Generally Accepted in the United States of America
Bankruptcy Court	U.S. Bankruptcy Court in the Northern District of Ohio in Akron		GHG	Greenhouse Gases
~~HCl~~Bath County	~~Hydrochloric Acid~~
~~ICE~~Bath County Pumped Storage Hydro-Power Station	~~Intercontinental Exchange, Inc.~~
IIP	Infrastructure Investment Program
~~IRP~~BGS	~~Integrated Resource Plan~~Basic Generation Service		kW	Kilowatt
~~IRS~~CAA	~~Internal Revenue Service~~
~~ISO~~Clean Air Act	~~Independent System Operator~~
~~JCP&L Reliability Plus~~	~~JCP&L Reliability Plus Infrastructure Investment Program~~
kV	~~Kilovolt~~
~~KWH~~	~~Kilowatt-hour~~
LBR	Little Blue Run
CCR	Coal Combustion Residuals		LCAPP	Long-Term Capacity Agreement Pilot Program
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980		LIBOR	London Interbank Offered Rate
CFR	Code of Federal Regulations		LOC	Letter of Credit
~~LS Power~~ CO₂	~~LS Power Equity Partners III, LP~~
~~LSE~~Carbon Dioxide	~~Load Serving Entity~~
LTIIPs	Long-Term Infrastructure Improvement Plans
~~MATS~~CPP	~~Mercury and Air Toxics Standards~~EPA’s Clean Power Plan
	MDPSC	Maryland Public Service Commission
CSAPR	Cross-State Air Pollution Rule		MGP	Manufactured Gas Plants
CTA	Consolidated Tax Adjustment		MISO	Midcontinent Independent System Operator, Inc.
~~MLP~~CWA	~~Master Limited Partnership~~Clean Water Act
	mmBTU	One Million British Thermal Units
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit		Moody’s	Moody’s Investors Service, Inc.
~~MOPR~~DCR	~~Minimum Offer Price Rule~~
~~MVP~~Delivery Capital Recovery	~~Multi-Value Project~~
MW	Megawatt
DMR	Distribution Modernization Rider		MWH	Megawatt-hour
DPM	Distribution Platform Modernization		NAAQS	National Ambient Air Quality Standards
DSIC	Distribution System Improvement Charge		NDT	Nuclear Decommissioning Trust
DSP	Default Service Plan		NERC	North American Electric Reliability Corporation
~~NJAPA~~EDC	~~New Jersey Administrative Procedure Act~~Electric Distribution Company
	NJBPU	New Jersey Board of Public Utilities
~~NOAC~~EDCP	~~Northwest Ohio Aggregation Coalition~~Executive Deferred Compensation Plan		NMB	Non-Market Based
EDIS	Electric Distribution Investment Surcharge		NOI	Notice of Inquiry
EE&C	Energy Efficiency and Conservation		NOL	Net Operating Loss
EEI	Edison Electric Institute		NOPR	Notice of Proposed Rulemaking
~~NOV~~EGS	~~Notice of Violation~~Electric Generation Supplier
	NOx	Nitrogen Oxide
~~NPDES~~EGU	~~National Pollutant Discharge Elimination System~~Electric Generation Units
	NRC	Nuclear Regulatory Commission
~~NSR~~EmPOWER Maryland	~~New Source Review~~EmPOWER Maryland Energy Efficiency Act
	NUG	Non-Utility Generation
ENEC	Expanded Net Energy Cost		NYPSC	New York State Public Service Commission

~~GLOSSARY OF TERMS,~~ ~~Continued~~
EPA	United States Environmental Protection Agency
	OCA	Office of Consumer Advocate
EPS	Earnings per Share		OCC	Ohio ~~Consumers'~~Consumers’ Counsel
ERO	Electric Reliability Organization		OEPA	Ohio Environmental Protection Agency




OMAEG	Ohio ~~Manufacturers'~~Manufacturers’ Association Energy Group		RTEP	Regional Transmission Expansion Plan
OPEB	Other Post-Employment Benefits		RTO	Regional Transmission Organization
OPIC	Other Paid-in Capital
~~ORC~~	~~Ohio Revised Code~~
~~OTTI~~S&P	~~Other Than Temporary Impairments~~Standard & Poor’s Ratings Service
OVEC	Ohio Valley Electric Corporation		SBC	Societal Benefits Charge
PA DEP	Pennsylvania Department of Environmental Protection
~~PCB~~	~~Polychlorinated Biphenyl~~
~~PCRB~~SCOH	~~Pollution Control Revenue Bond~~Supreme Court of Ohio
PJM	PJM Interconnection, ~~L.L.C.~~
~~PJM Region~~LLC	~~The aggregate of the zones within PJM~~	SEC	United States Securities and Exchange Commission
PJM Tariff	PJM Open Access Transmission Tariff
PM	~~Particulate Matter~~
~~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~~
~~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
POLR	Provider of Last Resort		SO₂	Sulfur Dioxide
~~Sixth Circuit~~POR	~~United States Court~~Purchase of ~~Appeals for the Sixth Circuit~~Receivables
	SOS	Standard Offer Service
PPA	Purchase Power Agreement		SPE	Special Purpose Entity
PPB	Parts per Billion		SREC	Solar Renewable Energy Credit
PPUC	Pennsylvania Public Utility Commission		SSO	Standard Service Offer
PUCO	Public Utilities Commission of Ohio		Tax Act	Tax Cuts and Jobs Act adopted December 22, 2017
~~TDS~~PURPA	~~Total Dissolved Solid~~Public Utility Regulatory Policies Act of 1978
	TMI-2	Three Mile Island Unit 2

~~GLOSSARY OF TERMS,~~ ~~Continued~~
RCRA
TOResource Conservation and Recovery Act	~~Transmission Owner~~
Twitter®	Twitter is a registered trademark of Twitter, Inc.
REC	Renewable Energy Credit		UCC	Official committee of unsecured creditors appointed in connection with the FES Bankruptcy
Regulation FD	Regulation Fair Disclosure promulgated by the SEC		VIE	Variable Interest Entity
RFC	ReliabilityFirst Corporation		VMS	Vegetation Management Surcharge
RFP	Request for Proposal		VSCC	Virginia State Corporation Commission
~~WVDEP~~RGGI	~~West Virginia Department of Environmental Protection~~Regional Greenhouse Gas Initiative
	WVPSC	Public Service Commission of West Virginia
ROE	Return on Equity		ZEC	Zero Emissions Certificate


(In millions, except share amounts)	September 30, 2018			December 31, 2017			September 30, 2019			December 31, 2018
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	436		$	588		$	716		$	367
Restricted cash	51			51			34			62
Receivables-
Customers, net of allowance for uncollectible accounts of $49 in 2018 and 2017	1,317			1,282
Other, net of allowance for uncollectible accounts of $2 in 2018 and $1 in 2017	299			170
Customers, net of allowance for uncollectible accounts of $46 in 2019 and $50 in 2018							1,130			1,221
Affiliated companies, net of allowance for uncollectible accounts of $945 in 2019 and $920 in 2018							—			20
Other, net of allowance for uncollectible accounts of $7 in 2019 and $2 in 2018							206			270
Materials and supplies, at average cost	240			236			258			252
Prepaid taxes and other	236			151			239			175
Current assets - discontinued operations	17			632			33			25
	2,596			3,110			2,616			2,392
PROPERTY, PLANT AND EQUIPMENT:
In service	38,585			37,113			41,016			39,469
Less — Accumulated provision for depreciation	10,468			10,011			11,234			10,793
	28,117			27,102			29,782			28,676
Construction work in progress	1,290			999			1,370			1,235
	29,407			28,101			31,152			29,911

PROPERTY, PLANT AND EQUIPMENT, NET - DISCONTINUED OPERATIONS	—			1,132

INVESTMENTS:
Nuclear plant decommissioning trusts	822			822			871			790
Nuclear fuel disposal trust	253			251			271			256
Other	254			255			283			253
Investments - discontinued operations	—			1,875
	1,329			3,203			1,425			1,299
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	5,618			5,618			5,618			5,618
Regulatory assets	80			40			77			91
Other	413			697			618			752
Deferred charges and other assets - discontinued operations	—			356
	6,111			6,711			6,313			6,461
	$	39,443		$	42,257		$	41,506		$	40,063
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,128		$	558		$	381		$	503
Short-term borrowings	1,700			300			1,000			1,250
Accounts payable	997			827			893			965
Accounts payable - affiliated companies	107			—			46			—
Accrued taxes	529			533			537			533
Accrued compensation and benefits	300			257			268			318
Collateral	27			39			30			39
Other	1,012			621			1,084			1,026
Current liabilities - discontinued operations	—			978
	5,800			4,113			4,239			4,634
CAPITALIZATION:
Stockholders’ equity-
Common stock, $0.10 par value, authorized 700,000,000 shares - 511,445,350 and 445,334,111 shares outstanding as of September 30, 2018 and December 31, 2017, respectively	51			44
Preferred stock, $100 par value, authorized 5,000,000 shares, of which 1,616,000 are designated Series A Convertible Preferred - 704,589 shares outstanding as of September 30, 2018	70			—
Common stock, $0.10 par value, authorized 700,000,000 shares - 540,311,707 and 511,915,450 shares outstanding as of September 30, 2019 and December 31, 2018, respectively							54			51
Preferred stock, $100 par value, authorized 5,000,000 shares, of which 1,616,000 are designated Series A Convertible Preferred - none outstanding as of September 30, 2019, and 704,589 shares outstanding as of December 31, 2018							—			71
Other paid-in capital	11,708			10,001			11,047			11,530
Accumulated other comprehensive income	61			142			27			41
Accumulated deficit	(5,017		)	(6,262		)	(3,856		)	(4,879		)
Total stockholders’ equity	6,873			3,925			7,272			6,814
Long-term debt and other long-term obligations	16,608			18,687			19,422			17,751
	23,481			22,612			26,694			24,565
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	2,427			3,171			2,900			2,502
Retirement benefits	2,742			3,975			2,403			2,906
Regulatory liabilities	2,673			2,720			2,605			2,498
Asset retirement obligations	630			570			844			812
Adverse power contract liability	99			130			66			89
Other	1,591			1,438			1,755			2,057
Noncurrent liabilities - discontinued operations	—			3,528
	10,162			15,532			10,573			10,864
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 14)
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13)
	$	39,443		$	42,257		$	41,506		$	40,063


Note Number		Page Number		Page Number

1	Organization and Basis of Presentation	6	Organization and Basis of Presentation	6

2	Revenue	9	Revenue	8

3	Discontinued Operations	12	Discontinued Operations	12

4	Earnings Per Share of Common Stock	16	Earnings Per Share of Common Stock	15

5	Pension and Other Postemployment Benefits	18	Pension and Other Postemployment Benefits	17

6	Accumulated Other Comprehensive Income	19	Accumulated Other Comprehensive Income	18

7	Income Taxes	20	Income Taxes	19

8	Variable Interest Entities	21	Leases	20

9	Fair Value Measurements	23	Capitalization	23

10	Derivative Instruments	26	Variable Interest Entities	25

11	Capitalization	27	Fair Value Measurements	25

12	Asset Retirement Obligations	28	Regulatory Matters	29

13	Regulatory Matters	29	Commitments, Guarantees and Contingencies	34

14	Commitments, Guarantees and Contingencies	36	Segment Information	39

15	Segment Information	40



	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
Revenues by Customer Class	2019		2018		2019		2018
	(In millions)
Residential	$	1,538	$	1,572	$	4,145	$	4,290
Commercial	600		628		1,759		1,778
Industrial	286		276		786		792
Other	22		23		66		70
Total Revenues	$	2,446	$	2,499	$	6,756	$	6,930



	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
Transmission Owner	2019		2018		2019		2018
	(In millions)
ATSI	$	184	$	167	$	542	$	492
TrAIL	55		60		172		183
MAIT	58		43		157		106
Other	74		71		219		215
Total Revenues	$	371	$	341	$	1,090	$	996



	For the Three Months Ended September 30, 2018		For the Nine Months Ended September 30, 2018
Revenues from Contracts with Customers by Transmission Asset Owner	For the Three Months Ended September 30, 2018		For the Nine Months Ended September 30, 2018
	(In millions)
ATSI	$	167	$	492
TrAIL	60		183
MAIT	43		106
Other	71		215
Total Revenues	$	341	$	996



	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
Reconciliation of Basic and Diluted EPS of Common Stock	2019		2018			2019			2018

(In millions, except per share amounts)
EPS of Common Stock
Income from continuing operations	$	389	$	399		$	1,085		$	888
Less: Preferred dividends	—		(19		)	(3		)	(61		)
Less: Amortization of beneficial conversion feature	—		(35		)	—			(296		)
Less: Undistributed earnings allocated to preferred stockholders⁽¹⁾	—		—			(4		)	—
Income from continuing operations available to common stockholders	389		345			1,078			531
Discontinued operations, net of tax	2		(857		)	(62		)	322
Less: Undistributed earnings allocated to preferred stockholders ⁽¹⁾	—		—			—			—
Income (loss) from discontinued operations available to common stockholders	2		(857		)	(62		)	322

Income (loss) available to common stockholders, basic	$	391	$	(512	)	$	1,016		$	853

Income allocated to preferred shareholders, preferred dilutive ⁽²⁾	—		N/A			7			N/A

Income (loss) available to common stockholders, dilutive	$	391	$	(512	)	$	1,023		$	853

Share Count information:
Weighted average number of basic shares outstanding	538		503			533			485
Assumed exercise of dilutive stock options and awards	2		2			2			2
Assumed conversion of preferred stock	2		—			6			—
Weighted average number of diluted shares outstanding	542		505			541			487

Income (loss) available to common stockholders, per common share:
Income from continuing operations, basic	$	0.72	$	0.68		$	2.02		$	1.10
Discontinued operations, basic	0.01		(1.70		)	(0.12		)	0.66
Income (loss) available to common stockholders, basic	$	0.73	$	(1.02	)	$	1.90		$	1.76

Income from continuing operations, diluted	$	0.72	$	0.68		$	2.00		$	1.09
Discontinued operations, diluted	—		(1.70		)	(0.11		)	0.66
Income (loss) available to common stockholders, diluted	$	0.72	$	(1.02	)	$	1.89		$	1.75


⁽¹⁾	Undistributed earnings were not allocated to participating securities for the three and nine months ended September 30, 2018, as well as the three months ended September 30, 2019, as income from continuing operations less dividends declared (common and preferred) and deemed dividends were a net loss.


⁽²⁾	The shares of common stock issuable upon conversion of the preferred shares (26 million shares) were not included for 2018 as their inclusion would be anti-dilutive to basic EPS from continuing operations.



Components of Net Periodic Benefit Costs (Credits)	Pension						OPEB
For the Three Months Ended September 30,	2019			2018			2019			2018
	(In millions)
Service costs ⁽¹⁾	$	48		$	56		$	1		$	1
Interest costs ⁽²⁾	93			93			6			6
Expected return on plan assets ⁽²⁾	(135		)	(144		)	(7		)	(7		)
Amortization of prior service costs (credits) ⁽²⁾	2			2			(9		)	(20		)
Special termination costs ^{(2) (3)}	—			21			—			6
Net periodic costs (credits), including amounts capitalized	$	8		$	28		$	(9	)	$	(14	)
Net periodic costs (credits), recognized in earnings	$	(11	)	$	5		$	(10	)	$	(15	)


Components of Net Periodic Benefit Costs (Credits)	Pension						OPEB
For the Nine Months Ended September 30,	2019			2018			2019			2018
	(In millions)
Service costs ⁽¹⁾	$	144		$	168		$	3		$	3
Interest costs ⁽²⁾	279			279			16			18
Expected return on plan assets ⁽²⁾	(405		)	(432		)	(21		)	(22		)
Amortization of prior service costs (credits) ⁽²⁾	6			6			(27		)	(60		)
Special termination costs ^{(2) (3)}	14			21			—			6
Net periodic costs (credits), including amounts capitalized	$	38		$	42		$	(29	)	$	(55	)
Net periodic credits, recognized in earnings	$	(19	)	$	(27	)	$	(30	)	$	(57	)



	Gains & Losses on Cash Flow Hedges ⁽¹⁾			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance, July 1, 2019	$	(10	)	$	—		$	41		$	31

Amounts reclassified from AOCI	—			—			(7		)	(7		)
Other comprehensive loss	—			—			(7		)	(7		)
Income tax benefits on other comprehensive loss	—			—			(3		)	(3		)
Other comprehensive loss, net of tax	—			—			(4		)	(4		)

AOCI Balance, September 30, 2019	$	(10	)	$	—		$	37		$	27

AOCI Balance, July 1, 2018	$	(14	)	$	—		$	87		$	73

Amounts reclassified from AOCI	2			—			(18		)	(16		)
Other comprehensive income (loss)	2			—			(18		)	(16		)
Income tax benefits on other comprehensive loss	—			—			(4		)	(4		)
Other comprehensive income (loss), net of tax	2			—			(14		)	(12		)

AOCI Balance, September 30, 2018	$	(12	)	$	—		$	73		$	61

	Gains & Losses on Cash Flow Hedges ⁽¹⁾			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance, January 1, 2019	$	(11	)	$	—		$	52		$	41

Amounts reclassified from AOCI	1			—			(21		)	(20		)
Other comprehensive income (loss)	1			—			(21		)	(20		)
Income tax benefits on other comprehensive loss	—			—			(6		)	(6		)
Other comprehensive income (loss), net of tax	1			—			(15		)	(14		)

AOCI Balance, September 30, 2019	$	(10	)	$	—		$	37		$	27

AOCI Balance, January 1, 2018	$	(22	)	$	67		$	97		$	142

Other comprehensive income before reclassifications	—			(97		)	—			(97		)
Amounts reclassified from AOCI	6			(1		)	(55		)	(50		)
Deconsolidation of FES and FENOC	13			(8		)	—			5
Other comprehensive income (loss)	19			(106		)	(55		)	(142		)
Income taxes (benefits) on other comprehensive income (loss)	9			(39		)	(31		)	(61		)
Other comprehensive income (loss), net of tax	10			(67		)	(24		)	(81		)

AOCI Balance, September 30, 2018	$	(12	)	$	—		$	73		$	61



	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, 2018	$	(14	)	$	—		$	87		$	73

Amounts reclassified from AOCI^{(1) (2)}	2			—			(18		)	(16		)
Other comprehensive income (loss)	2			—			(18		)	(16		)
Income tax benefits on other comprehensive income (loss)	—			—			(4		)	(4		)
Other comprehensive income (loss), net of tax	2			—			(14		)	(12		)

AOCI Balance as of September 30, 2018	$	(12	)	$	—		$	73		$	61

AOCI balance as of July 1, 2017	$	(26	)	$	61		$	128		$	163

Other comprehensive income before reclassifications	—			27			—			27
Amounts reclassified from AOCI^{(1) (2)}	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

	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, 2018	$	(22	)	$	67		$	97		$	142

Other comprehensive income before reclassifications	—			(97		)	—			(97		)
Amounts reclassified from AOCI^{(1) (2) (3)}	6			(1		)	(55		)	(50		)
Deconsolidation of FES and FENOC	13			(8		)	—			5
Other comprehensive income (loss)	19			(106		)	(55		)	(142		)
Income taxes (benefits) on other comprehensive income (loss)	9			(39		)	(31		)	(61		)
Other comprehensive income (loss), net of tax	10			(67		)	(24		)	(81		)

AOCI Balance as of September 30, 2018	$	(12	)	$	—		$	73		$	61

AOCI Balance as of January 1, 2017	$	(28	)	$	52		$	150		$	174

Other comprehensive income before reclassifications	—			63			—			63
Amounts reclassified from AOCI^{(1) (2)}	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

⁽¹⁾Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.
⁽²⁾ Components are included in the computation of net periodic pension cost. See Note 5, "Pension and Other Postemployment Benefits," for additional details.
⁽³⁾ Includes stranded tax amounts reclassified from AOCI in connection with the adoption of ASU 2018-02, "Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income".



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						Affected Line Item in Consolidated Statements of Income (Loss)
Reclassifications from AOCI⁽¹⁾	2019			2018			2019			2018 ⁽²⁾
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	—		$	—		$	—		$	1		Other operating expenses
Long-term debt	—			2			1			5			Interest expense
	—			—			—			(1		)	Income taxes
	$	—		$	2		$	1		$	5		Net of tax

Unrealized gains on AFS securities
Realized gains on sales of securities	$	—		$	—		$	—		$	(1	)	Discontinued operations

Defined benefit pension and OPEB plans
Prior-service costs	$	(7	)	$	(15	)	$	(21	)	$	(55	)	⁽³⁾
	3			5			6			14			Income taxes
	$	(4	)	$	(10	)	$	(15	)	$	(41	)	Net of tax

⁽¹⁾Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.
⁽²⁾ Includes stranded tax amounts reclassified from AOCI in connection with the adoption of ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.”
⁽³⁾ Prior-service costs are reported within Miscellaneous income, net, within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income (Loss). Components are included in the computation of net periodic cost (credits), see Note 5, “Pension and Other Postemployment Benefits.”



	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⁽¹⁾	2018			2017			2018 ⁽³⁾			2017
	(In millions)
Gains & losses on cash flow hedges
Long-term debt	$	2		$	4		$	6		$	8		Interest expense
	—			(1		)	(1		)	(3		)	Income taxes
	$	2		$	3		$	5		$	5		Net of tax

Unrealized gains on AFS securities
Realized gains on sales of securities	$	—		$	(21	)	$	(1	)	$	(35	)	Discontinued Operations

Defined benefit pension and OPEB plans
Prior-service costs	$	(18	)	$	(19	)	$	(55	)	$	(55	)	⁽²⁾
	5			7			14			21			Income taxes
	$	(13	)	$	(12	)	$	(41	)	$	(34	)	Net of tax

⁽¹⁾Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.
⁽²⁾ Components are included in the computation of net periodic pension cost. See Note 5, "Pension and Other Postemployment Benefits," for additional details.
⁽³⁾ Includes stranded tax amounts reclassified from AOCI in connection with the adoption of ASU 2018-02, "Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income".



	For the Three Months Ended September 30, 2019
(In millions)	Vehicles		Buildings		Other		Total
Operating lease costs ⁽¹⁾	$	5	$	3	$	3	$	11

Finance lease costs:
Amortization of right-of-use assets	4		—		—		4
Interest on lease liabilities	—		—		—		—
Total finance lease cost	4		—		—		4
Total lease cost	$	9	$	3	$	3	$	15



	As of September 30, 2019
Weighted-average remaining lease terms (years)
Operating leases	8.39
Finance leases	4.66

Weighted-average discount rate ⁽¹⁾
Operating leases	4.76	%
Finance leases	3.45	%



(In millions)	Financial Statement Line Item	As of September 30, 2019

Assets
Operating lease assets, net of accumulated amortization of $17 million	Deferred charges and other assets	$	200
Finance lease assets, net of accumulated amortization of $91 million	Property, plant and equipment	76
Total leased assets		$	276

Liabilities
Current:
Operating	Other current liabilities	$	34
Finance	Currently payable long-term debt	16

Noncurrent:
Operating	Other noncurrent liabilities	212
Finance	Long-term debt and other long-term obligations	47
Total leased liabilities		$	309



Capital Leases
	(In millions)
2019	$	24
2020	19
2021	16
2022	13
2023	8
Years thereafter	16
Total minimum lease payments	96
Interest portion	(23		)
Present value of net minimum lease payments	73
Less current portion	18
Noncurrent portion	$	55



	Series A Convertible Preferred Stock					Common Stock			OPIC			AOCI			Accumulated Deficit			Total Stockholders’ Equity
(In millions)	Shares		Amount			Shares	Amount		OPIC			AOCI			Accumulated Deficit			Total Stockholders’ Equity
Balance, January 1, 2019	0.7		$	71		512	$	51	$	11,530		$	41		$	(4,879	)	$	6,814
Net income															320			320
Other comprehensive loss, net of tax												(5		)				(5		)
Stock-based compensation									7									7
Stock Investment Plan and certain share-based benefit plans						1			1									1
Cash dividends declared on common stock ($0.38/common share)									(202		)							(202		)
Cash dividends declared on preferred stock ($0.38/as-converted share)									(3		)							(3		)
Conversion of Series A Convertible Preferred Stock	(0.5	)	(50		)	18	2		48									—
Balance, March 31, 2019	0.2		$	21		531	$	53	$	11,381		$	36		$	(4,559	)	$	6,932
Net income															312			312
Other comprehensive loss, net of tax												(5		)				(5		)
Stock-based compensation									9									9
Stock Investment Plan and certain share-based benefit plans						1			21									21
Balance, June 30, 2019	0.2		$	21		532	$	53	$	11,411		$	31		$	(4,247	)	$	7,269
Net income															391			391
Other comprehensive loss, net of tax												(4		)				(4		)
Stock-based compensation									7									7
Stock Investment Plan and certain share-based benefit plans						1			20									20
Cash dividends declared on common stock ($0.38/share in July and September)									(411		)							(411		)
Conversion of Series A Convertible Preferred Stock	(0.2	)	(21		)	7	1		20									—
Balance, September 30, 2019	—		$	—		540	$	54	$	11,047		$	27		$	(3,856	)	$	7,272



	September 30, 2018⁽¹⁾									December 31, 2017⁽¹⁾
	Cost Basis		Unrealized Gains		Unrealized Losses			Fair Value		Cost Basis		Unrealized Gains		Unrealized Losses			Fair Value
	(In millions)

Debt securities	$	712	$	2	$	(23	)	$	691	$	774	$	11	$	(17	)	$	768
Equity securities	$	286	$	42	$	(1	)	$	327	$	254	$	40	$	—		$	294



Changes Between Third Quarter 2018 and Third Quarter 2017 Financial Results	Regulated Distribution			Regulated Transmission			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	145		$	4		$	(4	)	$	145
Other	12			1			(4		)	9
Total Revenues	157			5			(8		)	154

Operating Expenses:
Fuel	11			—			—			11
Purchased power	97			—			5			102
Other operating expenses	42			13			32			87
Provision for depreciation	19			5			(2		)	22
Amortization of regulatory assets, net	(42		)	(4		)	—			(46		)
General taxes	10			4			—			14
Impairment of assets	—			(13		)	—			(13		)
Total Operating Expenses	137			5			35			177

Operating Income (Loss)	20			—			(43		)	(23		)

Other Income (Expense):
Miscellaneous income, net	18			3			9			30
Interest expense	6			(5		)	6			7
Capitalized financing costs	1			2			—			3
Total Other Expense	25			—			15			40

Income (Loss) Before Income Taxes (Benefits)	45			—			(28		)	17
Income taxes (benefits)	(57		)	(15		)	3			(69		)
Income (Loss) From Continuing Operations	102			15			(31		)	86
Discontinued Operations, net of tax	—			—			(940		)	(940		)
Net Income (Loss)	$	102		$	15		$	(971	)	$	(854	)


	For the Three Months Ended September 30,		Increase		For the Three Months Ended September 30,
Electric Distribution MWH Deliveries	2018	2017	(Decrease)		2019	2018	Decrease
	(In thousands)				(In thousands)
Residential	15,657	13,863	12.9	%	15,306	15,657	(2.2	)%
Commercial	11,358	11,060	2.7	%	10,013	10,412	(3.8	)%
Industrial	13,672	13,341	2.5	%	14,477	14,618	(1.0	)%
Other	137	147	(6.8	)%	135	137	(1.5	)%
Total Electric Distribution MWH Deliveries	40,824	38,411	6.3	%	39,931	40,824	(2.2	)%