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

Forward-Looking Statements: This Form 10-K includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 based on information currently available. Such statements are subject to certain risks and uncertainties and readers are cautioned not to place undue reliance on these forward-looking statements. These statements include declarations regarding management's intents, beliefs and current expectations, and typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” "forecast," "target," "will," "intend," “believe,” "project," “estimate," "plan" and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements, which may include the following (see Glossary of Terms for definitions of capitalized terms):

•	The ability to successfully execute an exit from commodity-based generation.

•

The risks associated with the FES Bankruptcy that could adversely affect us, our liquidity or results of operations, including, without limitation, that conditions to the FES Bankruptcy settlement agreement may not be met or that the FES Bankruptcy settlement agreement may not be otherwise consummated, and if so, the potential for litigation and payment demands against us by FES, FENOC or their creditors.

•

The ability to accomplish or realize anticipated benefits from strategic and financial goals, including, but not limited to, our strategy to operate and grow as a fully regulated business, to execute our transmission and distribution investment plans, to continue to reduce costs through FE Tomorrow and other initiatives, and to improve our credit metrics, strengthen our balance sheet and grow earnings.

•	Legislative and regulatory developments at the federal and state levels, including, but not limited to, matters related to rates, compliance and enforcement activity.

•	Economic and weather conditions affecting future operating results, such as significant weather events and other natural disasters, and associated regulatory events or actions.

•	Changes in assumptions regarding economic conditions within our territories, the reliability of our transmission and distribution system, or the availability of capital or other resources supporting identified transmission and distribution investment opportunities.

•	Changes in customers' demand for power, including, but not limited to, the impact of state and federal energy efficiency and peak demand reduction mandates.

•	Changes in national and regional economic conditions affecting us and/or our major industrial and commercial customers or others with which we do business.

•	The risks associated with cyber-attacks and other disruptions to our information technology system that may compromise our operations, and data security breaches of sensitive data, intellectual property and proprietary or personally identifiable information.

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

•	Changes to federal and state environmental laws and regulations, including, but not limited to, those related to climate change.

•	Changing market conditions affecting the measurement of certain liabilities and the value of assets held in our pension trusts and other trust funds, or causing us to make additional contributions sooner, or in amounts that are larger, than currently anticipated.

•	The risks associated with the decommissioning of our retired nuclear facility.

•	The risks and uncertainties associated with litigation, arbitration, mediation and like proceedings.

•	Labor disruptions by our unionized workforce.

•	Changes to significant accounting policies.

•	Any changes in tax laws or regulations, including the Tax Act, or adverse tax audit results or rulings.

•	The ability to access the public securities and other capital and credit markets in accordance with our financial plans, the cost of such capital and overall condition of the capital and credit markets affecting us.

•	Actions that may be taken by credit rating agencies that could negatively affect either our access to or terms of financing or our financial condition and liquidity.

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

Dividends declared from time to time on our common stock, and thereby on our preferred stock, during any period may in the aggregate vary from prior periods due to circumstances considered by our Board of Directors at the time of the actual declarations. A security rating is not a recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.

These forward-looking statements are also qualified by, and should be read together with, the risk factors included in (a) Item 1A. Risk Factors, (b) Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) other factors discussed herein and in FirstEnergy's other filings with the SEC. The foregoing review of factors also should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on our business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. We expressly disclaim any obligation to update or revise, except as required by law, any forward-looking statements contained herein as a result of new information, future events or otherwise.

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 through its reportable segments, Regulated Distribution and Regulated Transmission.

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. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. Regulation of our retail distribution rates is generally premised on providing an opportunity to earn a reasonable return of and on prudently incurred invested capital to provide service to our customers through the use of both base rate proceedings and other cost-based rate mechanisms, including recovery riders and trackers. The segment's results reflect the costs of securing and delivering electric generation from transmission facilities to customers, including the deferral and amortization of certain related costs.

The service areas of, and customers served by, FirstEnergy's regulated distribution utilities as of December 31, 2018 are summarized below (in thousands):

Company		Area Served		Customers Served
OE		Central and Northeastern Ohio		1,051
Penn		Western Pennsylvania		167
CEI		Northeastern Ohio		753
TE		Northwestern Ohio		312
JCP&L		Northern, Western and East Central New Jersey		1,135
ME		Eastern Pennsylvania		572
PN		Western Pennsylvania and Western New York		587
WP		Southwest, South Central and Northern Pennsylvania		727
MP		Northern, Central and Southeastern West Virginia		393
PE		Western Maryland and Eastern West Virginia		414
				6,111

The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment's revenues are primarily derived from forward-looking formula rates at 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 results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities.

The Corporate/Other segment reflects corporate support not charged to FE's subsidiaries, interest expense on FE’s holding company debt and other businesses that do not constitute an operating segment. Additionally, reconciling adjustments for the elimination of inter-segment transactions and discontinued operations are included in Corporate/Other. As of December 31, 2018, approximately 70 MWs of electric generating capacity, representing AE Supply's OVEC capacity entitlement, was included in continuing operations of the Corporate/Other reportable segment. As of December 31, 2018, Corporate/Other had approximately $7.1 billion of FE holding company debt.

FES, FENOC, BSPC and a portion of AE Supply (including the Pleasants Power Station), representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, are presented 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, as discussed below. During the third quarter of 2018, the Pleasants Power Station was reclassified to discontinued operations following its inclusion in the definitive FES Bankruptcy settlement agreement for the benefit of FES' creditors. Prior period results have been reclassified to conform with such presentation as discontinued operations. 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.

EXECUTIVE SUMMARY

FirstEnergy is a forward-thinking electric utility, powered by a diverse team of employees committed to making customers' lives brighter, the environment better and its communities stronger.

Over the past year, FirstEnergy has transformed into a fully regulated utility company, focused on driving sustainable long-term regulated earnings growth and stable cash flows that support its dividend, while also sustaining investment grade credit ratings at FE and its regulated subsidiaries. FirstEnergy believes that the right investments are those that the customers value and are willing to pay for, while also providing attractive returns for its investors.

The scale and diversity of the company’s distribution and transmission operations position FirstEnergy for sustained growth well into the future. Since 2015, the Regulated Distribution business has experienced significant growth through investments, which has been realized through base rates and/or various recovery riders and trackers that have improved reliability and added operating flexibility to distribution infrastructure, benefiting to the customers and communities those Utilities service. The Regulated Transmission business is the centerpiece of FirstEnergy’s regulated investment strategy, where approximately 80% of its capital investments are recovered under forward-looking formula rates for its three standalone Transmission operating companies ATSI, MAIT and TrAIL.

2018-2021 “Unlocking the Future” Plan

The January 2018 equity issuance served as a catalyst to FirstEnergy's 2018-2021 “Unlocking the Future” regulated growth plan, which includes earnings growth targets, Regulated Distribution segment average annual rate base growth of 5%, formula transmission average annual rate base growth of 11%, and assumes no additional equity issuances through 2021, outside of FirstEnergy's regular stock investment and employee benefit plans.

FirstEnergy’s transmission growth program, Energizing the Future, provides a stable and proven investment platform, while producing important customer benefits. Through the program, $4.4 billion in capital investments were made from 2014 through 2017, and the company plans to invest up to an additional $4.8 billion in the 2018-2021 timeframe, which includes approximately $1.2 billion in 2018 and a target of $1.2 billion annually through 2021. As noted above, over 80% of these capital investments are recoverable through formula rate mechanisms, reducing regulatory lag in recovering a return on investment, while offering a reasonable rate of return. These investments are expected to continue to improve the performance and condition of the transmission system while increasing automation and communication, adding capacity to the system and improving customer reliability. Beyond 2021, FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of up to approximately $20 billion, 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.

In the Regulated Distribution segment, FirstEnergy remains committed to providing customer service-oriented growth opportunities by investing between $6.2 billion and $6.7 billion over 2018 to 2021, including $1.6 billion invested in 2018. Approximately 40% of capital expenditures are recoverable through various rate mechanisms, riders and trackers. Beginning in 2019, expected investments at the Ohio Companies include the pending Ohio Grid Modernization plan which includes installation of approximately 700,000 advanced meters, distribution automation, and integrated ‘volt/var’ controls. Additionally, the pending JCP&L Reliability Plus infrastructure improvement plan filed with the NJBPU is expected to bring both reduced outages and strengthen the system while preparing for the grid of the future in New Jersey. FirstEnergy continues to explore other opportunities for growth in its Regulated Distribution business, 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 electrification of customers’ homes and businesses by providing a full range of products and services.

Regulated Growth Plans - 2018 Achievements

In addition to our definitive settlement agreement in the FES Bankruptcy, which allowed us to turn our full focus to the implementation of our regulated growth plans in 2018, FirstEnergy made significant progress in positioning the company for sustained and continued regulated growth, including:

•	Reached a settlement that is subject to PUCO approval on the Ohio Grid Modernization plan

•	Filed a JCP&L Reliability Plus infrastructure investment plan in New Jersey

•	Filed a PE distribution rate case in Maryland, the first such base rate filing since 1994

•	Announced and implemented a new shared services organizational structure through the FE Tomorrow initiative

•	Earned an upgrade from S&P on FE’s issuer credit rating to BBB from BBB-

•	Earned a positive ratings outlook from Fitch on FE’s BBB- credit rating

•	Established a Board of Directors approved dividend policy and declared an increased dividend for March 1, 2019

•	Implemented rate reductions across all Utilities and at the formula-rate transmission subsidiaries to address the impacts of tax reform to appropriately pass on the benefits to customers

Also in 2018, the FE Tomorrow cost cutting initiative was implemented to define the corporate services FirstEnergy would need to support its regulated business once the company exited commodity-exposed generation. Through the initiative, FirstEnergy sought to ensure the company has the right talent, organizational and cost structure to efficiently service customers and achieve its earnings growth targets. In support of the FE Tomorrow initiative, more than 80% of eligible employees, totaling nearly 500 people in the shared services, utility services and sustainability organizations, accepted a voluntary enhanced retirement package that included severance compensation and a temporary pension enhancement, with most employees having already retired. Management expects the cost savings resulting from the FE Tomorrow initiative to support the company's growth targets.

In November 2018, the Board of Directors approved a dividend policy that includes a targeted payout ratio. As a first step, the Board declared a $0.02 increase to the common dividend payable March 1, 2019 to $0.38 per share, which represents an increase of 6% compared to the quarterly dividend of $0.36 per share that has been paid since 2014. Resuming modest dividend growth enables enhanced shareholder returns, while still allowing for continued substantial regulated investments. Dividend payments are subject to declaration by the Board and future dividend decisions determined by the Board may be impacted by earnings growth, cash flows, credit metrics and other business conditions.

FirstEnergy is making progress in its sustainability efforts. In 2018, FirstEnergy enhanced its focus on sustainability efforts by including the responsibility of Sustainability and Corporate Responsibility oversight into one of the Board’s Charters and created a Sustainability group focused on the continued realization of sustainability accomplishments that make FirstEnergy customers’ lives brighter, the environment better and its communities stronger. These actions reinforce FirstEnergy’s commitment to including the broad concepts of Environmental, Social, Governance (ESG), and corporate responsibility in our sustainability strategy. In 2019, FirstEnergy is focusing on additional initiatives that aim to inform, engage and achieve its sustainability goals, and demonstrate its commitment to stakeholders.

In recognition of customers using electricity in diverse ways, FirstEnergy created an Emerging Technologies department responsible for analyzing and implementing new technologies such as microgrids, plug-in electric vehicles, energy storage, and smart cities. The department will focus on monitoring changing energy policies which support utilities to enable the grid of the future, expanding on sustainable solutions for a better environment, and empowering customers through personalized solutions.

RESULTS OF OPERATIONS

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 19, "Segment Information," of the Notes to Consolidated Financial Statements. Certain prior year amounts have been reclassified to conform to the current year presentation.

Net income (loss) by business segment was as follows:

		For the Years Ended December 31,												Increase (Decrease)
		2018				2017				2016				2018 vs 2017				2017 vs 2016
		(In millions, except per share amounts)
Net Income (Loss) By Business Segment:
Regulated Distribution		$	1,242			$	916			$	651			$	326			$	265
Regulated Transmission		397				336				331				61				5
Corporate/Other		(617		)		(1,541		)		(431		)		924				(1,110		)
Income (Loss) from Continuing Operations		$	1,022			$	(289	)		$	551			$	1,311			$	(840	)
Discontinued Operations		326				(1,435		)		(6,728		)		1,761				5,293
Net Income (Loss)		$	1,348			$	(1,724	)		$	(6,177	)		$	3,072			$	4,453
Earnings (Loss) per share of common stock
Basic - Continuing Operations		$	1.33			$	(0.65	)		$	1.29			$	1.98			$	(1.94	)
Basic - Discontinued Operations		0.66				(3.23		)		(15.78		)		3.89				12.55
Basic - Net Income (Loss) Attributable to		$	1.99			$	(3.88	)		$	(14.49	)		$	5.87			$	10.61
Common Stockholders
Earnings (Loss) per share of common stock
Diluted - Continuing Operations		$	1.33			$	(0.65	)		$	1.29			$	1.98			$	(1.94	)
Diluted - Discontinued Operations		0.66				(3.23		)		(15.78		)		3.89				12.55
Diluted - Net Income (Loss) Attributable to		$	1.99			$	(3.88	)		$	(14.49	)		$	5.87			$	10.61
Common Stockholders

Summary of Results of Operations — 2018 Compared with 2017

Financial results for FirstEnergy’s business segments for the years ended December 31, 2018 and 2017, were as follows:

2018 Financial Results		Regulated Distribution				Regulated Transmission				Corporate/Other and Reconciling Adjustments				FirstEnergy Consolidated
		(In millions)
Revenues:
External
Electric		$	9,851			$	1,335			$	(136	)		$	11,050
Other		252				18				(59		)		211
Total Revenues		10,103				1,353				(195		)		11,261
Operating Expenses:
Fuel		538				—				—				538
Purchased power		3,103				—				6				3,109
Other operating expenses		2,984				253				(104		)		3,133
Provision for depreciation		812				252				72				1,136
Amortization (deferral) of regulatory assets, net		(163		)		13				—				(150		)
General taxes		760				192				41				993
Total Operating Expenses		8,034				710				15				8,759
Operating Income (Loss)		2,069				643				(210		)		2,502
Other Income (Expense):
Miscellaneous income (expense), net		192				14				(1		)		205
Pension and OPEB mark-to-market adjustment		(109		)		(8		)		(27		)		(144		)
Interest expense		(514		)		(167		)		(435		)		(1,116		)
Capitalized financing costs		26				37				2				65
Total Other Expense		(405		)		(124		)		(461		)		(990		)
Income (Loss) Before Income Taxes (Benefits)		1,664				519				(671		)		1,512
Income taxes		422				122				(54		)		490
Income (Loss) From Continuing Operations		1,242				397				(617		)		1,022
Discontinued Operations, net of tax		—				—				326				326
Net Income (Loss)		$	1,242			$	397			$	(291	)		$	1,348

2017 Financial Results		Regulated Distribution				Regulated Transmission				Corporate/Other and Reconciling Adjustments				FirstEnergy Consolidated
		(In millions)
Revenues:
External
Electric		$	9,521			$	1,307			$	(94	)		$	10,734
Other		239				17				(62		)		194
Total Revenues		9,760				1,324				(156		)		10,928
Operating Expenses:
Fuel		493				—				4				497
Purchased power		2,924				—				2				2,926
Other operating expenses		2,546				203				12				2,761
Provision for depreciation		724				224				79				1,027
Amortization of regulatory assets, net		292				16				—				308
General taxes		727				173				40				940
Impairment of assets		—				41				—				41
Total Operating Expenses		7,706				657				137				8,500
Operating Income (Loss)		2,054				667				(293		)		2,428
Other Income (Expense):
Miscellaneous income (expense), net		57				1				(5		)		53
Pension and OPEB mark-to-market adjustment		(102		)		—				—				(102		)
Interest expense		(535		)		(156		)		(314		)		(1,005		)
Capitalized financing costs		22				29				1				52
Total Other Expense		(558		)		(126		)		(318		)		(1,002		)
Income (Loss) Before Income Taxes (Benefits)		1,496				541				(611		)		1,426
Income taxes (benefits)		580				205				930				1,715
Income (Loss) From Continuing Operations		916				336				(1,541		)		(289		)
Discontinued Operations, net of tax		—				—				(1,435		)		(1,435		)
Net Income (Loss)		$	916			$	336			$	(2,976	)		$	(1,724	)

Changes Between 2018 and 2017 Financial Results Increase (Decrease)		Regulated Distribution				Regulated Transmission				Corporate/Other and Reconciling Adjustments				FirstEnergy Consolidated
		(In millions)
Revenues:
External
Electric		$	330			$	28			$	(42	)		$	316
Other		13				1				3				17
Total Revenues		343				29				(39		)		333
Operating Expenses:
Fuel		45				—				(4		)		41
Purchased power		179				—				4				183
Other operating expenses		438				50				(116		)		372
Provision for depreciation		88				28				(7		)		109
Amortization (deferral) of regulatory assets, net		(455		)		(3		)		—				(458		)
General taxes		33				19				1				53
Impairment of assets		—				(41		)		—				(41		)
Total Operating Expenses		328				53				(122		)		259
Operating Income		15				(24		)		83				74
Other Income (Expense):
Miscellaneous income (expense), net		135				13				4				152
Pension and OPEB mark-to-market adjustment		(7		)		(8		)		(27		)		(42		)
Interest expense		21				(11		)		(121		)		(111		)
Capitalized financing costs		4				8				1				13
Total Other Income (Expense)		153				2				(143		)		12
Income (Loss) Before Income Taxes (Benefits)		168				(22		)		(60		)		86
Income taxes (benefits)		(158		)		(83		)		(984		)		(1,225		)
Income (Loss) From Continuing Operations		326				61				924				1,311
Discontinued Operations, net of tax		—				—				1,761				1,761
Net Income (Loss)		$	326			$	61			$	2,685			$	3,072

Regulated Distribution — 2018 Compared with 2017

Regulated Distribution's operating results increased $326 million in 2018, as compared to 2017, primarily reflecting the reversal of a reserve on recoverability of certain REC purchases in Ohio, the net impact of a FERC settlement that reallocated certain transmission costs, higher revenues associated with increased weather-related usage and the implementation of approved rates in Ohio and Pennsylvania, as further described below, and lower pension and OPEB non-service costs.

Revenues —

The $343 million increase in total revenues resulted from the following sources:

		For the Years Ended December 31,
Revenues by Type of Service		2018				2017				Increase
		(In millions)
Distribution services (1)		$	5,413			$	5,323			$	90
Generation sales:
Retail		3,936				3,733				203
Wholesale		502				465				37
Total generation sales		4,438				4,198				240
Other		252				239				13
Total Revenues		$	10,103			$	9,760			$	343

(1) Includes $254 million and $263 million of ARP revenues for the years ended December 31, 2018 and 2017, respectively.

Distribution services revenues increased $90 million primarily resulting from the impact of approved base distribution rate increases in Pennsylvania, effective January 27, 2017, higher revenue from the DCR in Ohio, and higher weather-related customer usage as described below. Additionally, distribution revenues were impacted by higher rates associated with the recovery of deferred costs, partially offset by certain tax impacts reflected as a reduction in revenues resulting from the Tax Act. Distribution deliveries by customer class are summarized in the following table:

		For the Years Ended December 31,						Increase
Electric Distribution MWH Deliveries		2018			2017			(Decrease)
		(In thousands)
Residential		55,994			52,048			7.6	%
Commercial		42,213			41,220			2.4	%
Industrial		53,004			51,876			2.2	%
Other		560			572			(2.1	)%
Total Electric Distribution MWH Deliveries		151,771			145,716			4.2	%

Higher distribution deliveries to residential and commercial customers primarily reflect higher weather-related usage resulting from cooling degree days that were 26% above 2017, and 34% above normal, as well as, heating degree days that were 14% above 2017, and 2% above normal. Deliveries to industrial customers increased reflecting higher shale and steel customer usage.

The following table summarizes the price and volume factors contributing to the $240 million increase in generation revenues in 2018, as compared to 2017:

Source of Change in Generation Revenues		Increase (Decrease)
		(In millions)
Retail:
Effect of increase in sales volumes		$	253
Change in prices		(50		)
		203
Wholesale:
Effect of decrease in sales volumes		(41		)
Change in prices		49
Capacity revenue		29
		37
Increase in Generation Revenues		$	240

The increase in retail generation sales volumes was primarily due to higher weather-related usage, as described above, as well as decreased customer shopping in New Jersey and Pennsylvania. Total generation provided by alternative suppliers as a percentage of total MWH deliveries decreased to 50% from 52% in New Jersey and to 67% from 68% in Pennsylvania. The decrease in retail generation prices primarily resulted from lower default service auction prices in New Jersey and Pennsylvania.

Wholesale generation revenues increased $37 million in 2018, as compared to 2017, primarily due to higher spot market energy prices and capacity revenue, partially offset by lower wholesale sales volumes. The difference between current wholesale generation revenues and certain energy costs incurred are deferred for future recovery or refund, with no material impact to earnings.

Operating Expenses —

Total operating expenses increased $328 million primarily due to the following:

•	Fuel expense increased $45 million in 2018, as compared to 2017, primarily related to higher unit costs.

•	Purchased power costs increased $179 million in 2018, as compared to 2017, primarily due to increased volumes resulting from higher customer weather-related usage as well as decreased customer shopping.

	Source of Change in Purchased Power		Increase (Decrease)
			(In millions)
	Purchases from non-affiliates:
	Change due to decreased unit costs		$	(25	)
	Change due to increased volumes		200
			175
	Purchases from affiliates:
	Change due to decreased unit costs		(9		)
	Change due to decreased volumes		(35		)
			(44		)
	Capacity expense		48
	Increase in Purchased Power Costs		$	179

•	Other operating expenses increased $438 million primarily due to:

•	Increased storm restoration costs of $228 million, primarily associated with the March 2018 east coast storms,

which were mostly deferred for future recovery, resulting in no material impact on current period earnings.

•	Higher net network transmission expenses of $49 million reflecting increased transmission costs, partially offset

by a FERC settlement during the second quarter of 2018 that reallocated certain transmission costs across utilities in PJM and resulted in a refund to the Ohio Companies. Except for certain transmission costs and credits at the

Ohio Companies, the difference between current revenues and transmission costs incurred are deferred for future recovery or refund, resulting in no material impact on current period earnings.

•	Higher energy efficiency and other program costs of $18 million, which are deferred for future recovery, resulting

in no material impact on current period earnings.

•	Higher operating and maintenance expenses of $115 million, primarily due to higher benefit costs, increased vegetation management costs and higher contractor spend.

•	Pension special termination costs associated with the voluntary retirement program in 2018 of $28 million.

•	Depreciation expense increased $88 million, primarily due to a higher asset base.

•	Amortization expense decreased $455 million, primarily due to increased deferral of storm restoration costs, the Ohio

Supreme Court ruling regarding purchase of RECs, higher deferral of transmission and generation expenses including the net impact of the FERC settlement discussed above, and higher deferral of energy efficiency program costs.

•	General taxes expense increased $33 million, primarily due to higher property taxes and revenue-related taxes associated with increased sales volumes.

Other Expense —

Total other expense decreased $153 million, primarily due to higher net miscellaneous income resulting from lower pension and OPEB non-service costs from the pension contribution discussed above, and lower capitalization, as well as lower interest expense resulting from debt maturities and refinancings.

Income Taxes —

Regulated Distribution’s effective tax rate was 25.4% and 38.8% for 2018 and 2017, respectively. The lower rate is primarily a result of certain impacts of the Tax Act and the absence of a $30 million charge to income tax expense as a result of the remeasurement of accumulated deferred income taxes recognized in 2017.

Regulated Transmission — 2018 Compared with 2017

Regulated Transmission's operating results increased $61 million in 2018, as compared to 2017, primarily resulting from the impact of a higher rate base at ATSI and MAIT, higher revenues at JCP&L, and the absence of a pre-tax impairment charge of $41 million in 2017, partially offset by a lower rate base at TrAIL.

Revenues —

Total revenues increased $29 million in 2018, as compared to 2017, primarily due to the full year impact of the implementation of approved settlement rates at JCP&L and recovery of incremental operating expenses and a higher rate base at ATSI and MAIT, partially offset by a lower rate base at TrAIL.

Revenues by transmission asset owner are shown in the following table:

		For the Years Ended December 31,								Increase
Revenues by Transmission Asset Owner		2018				2017				(Decrease)
		(In millions)
ATSI		$	668			$	657			$	11
TrAIL		246				282				(36		)
MAIT		154				110				44
Other		285				275				10
Total Revenues		$	1,353			$	1,324			$	29

Operating Expenses —

Total operating expenses increased $53 million in 2018, as compared to 2017, primarily due to higher operating and maintenance expenses, as well as higher property taxes and depreciation due to a higher asset base. The majority of the increases are recovered through formula rates at the Transmission Companies, resulting in no material impact on current period earnings. Additionally, as a result of settlement agreements filed with FERC regarding the transmission rates for MAIT and JCP&L, a pre-tax impairment charge of $41 million was recognized in 2017.

Income Taxes —

Regulated Transmission’s effective tax rate was 23.5% and 37.9% for 2018 and 2017, respectively. The lower rate is primarily a result of certain impacts of the Tax Act and the absence of a $6 million charge to income tax expense as a result of the remeasurement of accumulated deferred income taxes recognized in 2017.

Corporate/Other — 2018 Compared with 2017

Financial results from the Corporate/Other operating segment and reconciling adjustments resulted in a $924 million increase in income from continuing operations for 2018 compared to 2017, primarily associated with the absence of FES' and FENOC's remeasurement of deferred taxes in 2017, resulting from the Tax Act and lower operating expenses, partially offset by an increase in the ARO at McElroy’s Run, higher interest expense and the 2018 remeasurement of West Virginia unitary group deferred taxes. Although FES' and FENOC's operations are presented in discontinued operations, the 2017 remeasurement of deferred taxes remain in continuing operations in accordance with accounting standards for the impact of tax rate changes. Higher interest expense resulted from FE's issuance of $3 billion of senior notes in June 2017, as well as make-whole premiums of approximately $89 million in connection with the repayment of AE Supply and AGC senior notes in the second quarter of 2018. The increase in taxes resulting from the remeasurement of West Virginia unitary group deferred taxes is primarily due to the legal and financial separation of FES and FENOC from FirstEnergy. This separation officially eroded the ties between FES, FENOC and other FirstEnergy subsidiaries doing business in West Virginia. As such, FES and FENOC were removed from the West Virginia unitary group when calculating West Virginia state income taxes, resulting in a $126 million charge to income tax expense in continuing operations associated with the remeasurement in state deferred taxes.

For the year ended December 31, 2018 and 2017, FirstEnergy recorded income (loss) from discontinued operations, net of tax, of $326 million and $(1,435) million, respectively. Discontinued operations were comprised of the results of FES, FENOC, BSPC and a portion of AE Supply (including the Pleasants Power Station, designated as discontinued operations in the third quarter of 2018) and a net gain on disposal of $435 million in 2018, which consisted of the following:

(In millions)		For the Year Ended December 31, 2018
Removal of investment in FES and FENOC		$	2,193
Assumption of benefit obligations retained at FE		(820		)
Guarantees and credit support provided by FE		(139		)
Reserve on receivables and allocated Pension/OPEB mark-to-market		(914		)
Settlement consideration and services credit		(1,197		)
Loss on disposal of FES and FENOC, before tax		(877		)
Income tax benefit, including estimated worthless stock deduction		1,312
Gain on disposal of FES and FENOC, net of tax		$	435

Summary of Results of Operations — 2017 Compared with 2016

Financial results for FirstEnergy’s business segments for the years ended December 31, 2017 and 2016, were as follows:

2017 Financial Results		Regulated Distribution				Regulated Transmission				Corporate/Other and Reconciling Adjustments				FirstEnergy Consolidated
		(In millions)
Revenues:
External
Electric		$	9,521			$	1,307			$	(94	)		$	10,734
Other		239				17				(62		)		194
Total Revenues		9,760				1,324				(156		)		10,928
Operating Expenses:
Fuel		493				—				4				497
Purchased power		2,924				—				2				2,926
Other operating expenses		2,546				203				12				2,761
Provision for depreciation		724				224				79				1,027
Amortization of regulatory assets, net		292				16				—				308
General taxes		727				173				40				940
Impairment of assets		—				41				—				41
Total Operating Expenses		7,706				657				137				8,500
Operating Income (Loss)		2,054				667				(293		)		2,428
Other Income (Expense):
Miscellaneous income (expense), net		57				1				(5		)		53
Pension and OPEB mark-to-market adjustment		(102		)		—				—				(102		)
Interest expense		(535		)		(156		)		(314		)		(1,005		)
Capitalized financing costs		22				29				1				52
Total Other Expense		(558		)		(126		)		(318		)		(1,002		)
Income (Loss) Before Income Taxes (Benefits)		1,496				541				(611		)		1,426
Income taxes (benefits)		580				205				930				1,715
Income (Loss) From Continuing Operations		916				336				(1,541		)		(289		)
Discontinued Operations, net of tax		—				—				(1,435		)		(1,435		)
Net Income (Loss)		$	916			$	336			$	(2,976	)		$	(1,724	)

2016 Financial Results		Regulated Distribution				Regulated Transmission				Corporate/Other and Reconciling Adjustments				FirstEnergy Consolidated
		(In millions)
Revenues:
External
Electric		$	9,352			$	1,123			$	(12	)		$	10,463
Other		267				20				(50		)		237
Total Revenues		9,619				1,143				(62		)		10,700
Operating Expenses:
Fuel		567				—				4				571
Purchased power		3,303				—				7				3,310
Other operating expenses		2,455				152				(28		)		2,579
Provision for depreciation		676				187				70				933
Amortization of regulatory assets, net		290				7				—				297
General taxes		720				153				40				913
Impairment of assets		—				—				43				43
Total Operating Expenses		8,011				499				136				8,646
Operating Income (Loss)		1,608				644				(198		)		2,054
Other Income (Expense):
Miscellaneous income (expense), net		85				(1		)		(40		)		44
Pension and OPEB mark-to-market adjustment		(101		)		(1		)		—				(102		)
Interest expense		(586		)		(158		)		(229		)		(973		)
Capitalized financing costs		20				34				1				55
Total Other Expense		(582		)		(126		)		(268		)		(976		)
Income (Loss) Before Income Taxes (Benefits)		1,026				518				(466		)		1,078
Income taxes (benefits)		375				187				(35		)		527
Income (Loss) From Continuing Operations		651				331				(431		)		551
Discontinued Operations, net of tax		—				—				(6,728		)		(6,728		)
Net Income (Loss)		$	651			$	331			$	(7,159	)		$	(6,177	)

Changes Between 2017 and 2016 Financial Results Increase (Decrease)		Regulated Distribution				Regulated Transmission				Corporate/Other and Reconciling Adjustments				FirstEnergy Consolidated
		(In millions)
Revenues:
External
Electric		$	169			$	184			$	(82	)		$	271
Other		(28		)		(3		)		(12		)		(43		)
Internal		—				—				—				—
Total Revenues		141				181				(94		)		228
Operating Expenses:
Fuel		(74		)		—				—				(74		)
Purchased power		(379		)		—				(5		)		(384		)
Other operating expenses		91				51				40				182
Provision for depreciation		48				37				9				94
Amortization of regulatory assets, net		2				9				—				11
General taxes		7				20				—				27
Impairment of assets		—				41				(43		)		(2		)
Total Operating Expenses		(305		)		158				1				(146		)
Operating Income (Loss)		446				23				(95		)		374
Other Income (Expense):
Miscellaneous income (expense), net		(28		)		2				35				9
Pension and OPEB mark-to-market adjustment		(1		)		1				—				—
Interest expense		51				2				(85		)		(32		)
Capitalized financing costs		2				(5		)		—				(3		)
Total Other Expense		24				—				(50		)		(26		)
Income (Loss) Before Income Taxes (Benefits)		470				23				(145		)		348
Income taxes (benefits)		205				18				965				1,188
Income (Loss) From Continuing Operations		265				5				(1,110		)		(840		)
Discontinued Operations, net of tax		—				—				5,293				5,293
Net Income (Loss)		$	265			$	5			$	4,183			$	4,453

Regulated Distribution — 2017 Compared with 2016

Regulated Distribution's operating results increased $265 million in 2017, as compared to 2016, primarily reflecting the implementation of approved rates in Ohio, Pennsylvania, and New Jersey, and the absence of a $51 million regulatory charge recognized in 2016 resulting from the PUCO's March 31, 2016 Opinion and Order adopting and approving, with modifications, the Ohio Companies' ESP IV, partially offset by lower weather-related customer usage, as further described below.

Revenues —

The $141 million increase in total revenues resulted from the following sources:

		For the Years Ended December 31,								Increase
Revenues by Type of Service		2017				2016				(Decrease)
		(In millions)
Distribution services (1)		$	5,323			$	4,720			$	603
Generation sales:
Retail		3,733				4,147				(414		)
Wholesale		465				485				(20		)
Total generation sales		4,198				4,632				(434		)
Other		239				267				(28		)
Total Revenues		$	9,760			$	9,619			$	141

(1) Includes $263 million and $67 million of ARP revenues for the years ended December 31, 2017 and 2016, respectively.

Distribution services revenues increased $603 million, primarily resulting from the implementation of the DMR in Ohio effective January 1, 2017, approved base distribution rate increases in Pennsylvania and New Jersey effective January 27, 2017 and January 1, 2017, respectively, and higher revenue from the DCR in Ohio. Additionally, distribution revenues were impacted by higher rates associated with the recovery of deferred costs and the implementation of certain energy efficiency programs in Ohio. Partially offsetting these rate increases was a decline in MWH deliveries, primarily resulting from lower weather-related usage, as described below. Distribution deliveries by customer class are summarized in the following table:

		For the Years Ended December 31,						Increase
Electric Distribution MWH Deliveries		2017			2016			(Decrease)
		(In thousands)
Residential		52,048			54,840			(5.1	)%
Commercial		41,220			42,771			(3.6	)%
Industrial		51,876			50,651			2.4	%
Other		572			579			(1.2	)%
Total Electric Distribution MWH Deliveries		145,716			148,841			(2.1	)%

Lower distribution deliveries to residential and commercial customers primarily reflect lower weather-related usage resulting from

heating degree days that were 4% below 2016, and 11% below normal as well as cooling degree days that were 19% below 2016, but 8% above normal. Deliveries to industrial customers increased reflecting higher shale and steel customer usage.

The following table summarizes the price and volume factors contributing to the $434 million decrease in generation revenues in 2017 as compared to 2016:

Source of Change in Generation Revenues		Decrease
		(In millions)
Retail:
Effect of decrease in sales volumes		$	(242	)
Change in prices		(172		)
		(414		)
Wholesale:
Effect of decrease in sales volumes		(6		)
Capacity revenue		(14		)
		(20		)
Decrease in Generation Revenues		$	(434	)

The decrease in retail generation sales volumes was primarily due to increased customer shopping in Ohio, Pennsylvania, and JCP&L, as well as lower weather-related usage, as described above. Total generation provided by alternative suppliers as a percentage of total MWH deliveries increased to 86% from 83% for the Ohio Companies, to 68% from 67% for the Pennsylvania

Companies and to 52% from 51% for JCP&L. The decrease in retail generation prices primarily resulted from lower default service auction prices in Ohio, Pennsylvania, and New Jersey.

Wholesale generation revenues decreased $20 million in 2017, as compared to 2016, primarily due to lower capacity revenue and lower wholesale sales. The difference between current wholesale generation revenues and certain energy costs is deferred for future recovery or refund, with no material impact to earnings.

Other revenues decreased $28 million, primarily related to lower transition cost recovery revenues in New Jersey.

Operating Expenses —

Total operating expenses decreased $305 million primarily due to the following:

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

•	Purchased power costs decreased $379 million, in 2017 as compared to 2016, primarily due to decreased volumes, as

described above, as well as lower default service auction prices.

	Source of Change in Purchased Power		Increase (Decrease)
			(In millions)
	Purchases from non-affiliates:
	Change due to decreased unit costs		$	(147	)
	Change due to decreased volumes		(151		)
			(298		)
	Purchases from affiliates:
	Change due to decreased unit costs		(26		)
	Change due to decreased volumes		(67		)
			(93		)
	Capacity expense		12
	Decrease in Purchased Power Costs		$	(379	)

•	Other operating expenses increased $91 million primarily due to:

•	Higher network transmission expenses of $35 million. The difference between current revenues and transmission

costs incurred are deferred for future recovery or refund, resulting in no material impact on current period earnings.

•	Higher operating and maintenance expenses of $62 million, including increased expenses in Pennsylvania

recovered through the new base distribution rates, effective January 27, 2017, and increased storm restoration

costs, which were deferred for future recovery, resulting in no material impact on current period earnings.

•	Higher energy efficiency program expenses of $45 million in Ohio, which were recovered through higher

distribution rider revenues; partially offset by,

•	Lower regulatory costs of $51 million resulting from the absence of economic development and energy efficiency

obligations recognized in 2016 in accordance with the PUCO's March 31, 2016 Opinion and Order adopting and approving, with modifications, the Ohio Companies' ESP IV.

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

Other Expense —

Total other expense decreased $24 million primarily related to lower interest expense resulting from various debt maturities at

JCP&L, CEI and OE, partially offset by the absence of a $29 million gain on the sale of oil and gas rights at WP recognized in 2016.

Income Taxes —

Regulated Distribution’s effective tax rate was 38.8% and 36.5% for 2017 and 2016, respectively. The increase primarily resulted from a $30 million charge to income tax expense as a result of the remeasurement of accumulated deferred income taxes in conjunction with the Tax Act.

Regulated Transmission — 2017 Compared with 2016

Regulated Transmission's operating results increased $5 million in 2017 as compared to 2016, primarily resulting from the impact of a higher rate base at ATSI and TrAIL, partially offset by a pre-tax impairment charge of $41 million, as discussed below.

Revenues —

Total revenues increased $181 million in 2017, as compared to 2016, primarily due to recovery of incremental operating expenses and a higher rate base at ATSI and TrAIL, and the implementation of new rates at MAIT and JCP&L.

Revenues by transmission asset owner are shown in the following table:

		For the Years Ended December 31,								Increase (Decrease)
Revenues by Transmission Asset Owner		2017				2016
		(In millions)
ATSI		$	657			$	540			$	117
TrAIL		282				252				30
MAIT(1)		110				101				9
JCPL		125				91				34
Other		150				159				(9		)
Total Revenues		$	1,324			$	1,143			$	181

(1) Revenues prior to January 31, 2017, represent transmission revenues under stated rates at ME and PN.

Operating Expenses —

Total operating expenses increased $158 million in 2017, as compared to 2016, principally due to higher operating and maintenance

expenses, as well as higher property taxes and depreciation expense due to a higher asset base. Additionally, as a result of settlement agreements filed with FERC regarding the transmission rates for MAIT and JCP&L, a pre-tax impairment charge of $41 million was recognized in 2017.

Income Taxes —

Regulated Transmission’s effective tax rate was 37.9% and 36.1% for 2017 and 2016, respectively. The increase resulted from a $6 million charge to income tax expense as a result of the remeasurement of accumulated deferred income taxes in conjunction with the Tax Act.

Corporate/Other — 2017 Compared with 2016

Financial results from the Corporate/Other operating segment and reconciling adjustments resulted in a $1,110 million decrease in income from continuing operations for 2017 compared to 2016, primarily associated with higher interest expense and a charge

to income tax expense as a result of the remeasurement of accumulated deferred income taxes in conjunction with the Tax Act. Higher interest expense resulted from the issuance of $3 billion of senior notes in June 2017.

For 2017 and 2016, FirstEnergy recorded a loss from discontinued operations, net of tax, of $1,435 million and $6,728 million, respectively. Discontinued operations were comprised of the results of FES, FENOC, BSPC and a portion of AE Supply (including the Pleasants Power Station). Included in these amounts were impairment charges of $2,358 million and $10,622 million for the years ended December 31, 2017 and 2016, respectively.

Regulatory Assets and Liabilities

Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent amounts that are expected to be credited to customers through future regulated rates or amounts collected from customers for costs not yet incurred. FirstEnergy, the Utilities and the Transmission Companies net their regulatory assets and liabilities based on federal and state jurisdictions.

As a result of the Tax Act, FirstEnergy adjusted its net deferred tax liabilities at December 31, 2017, for the reduction in the corporate federal income tax rate from 35% to 21%. For the portions of FirstEnergy’s business that apply regulatory accounting, the impact of reducing the net deferred tax liabilities was offset with a regulatory liability, as appropriate, for amounts expected to be refunded to rate payers in future rates, with the remainder recorded to deferred income tax expense.

The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2018 and December 31, 2017, and the changes during the year ended December 31, 2018:

Net Regulatory Assets (Liabilities) by Source		December 31, 2018				December 31, 2017				Change
		(In millions)
Regulatory transition costs		$	49			$	46			$	3
Customer payables for future income taxes		(2,725		)		(2,765		)		40
Nuclear decommissioning and spent fuel disposal costs		(148		)		(323		)		175
Asset removal costs		(787		)		(774		)		(13		)
Deferred transmission costs		170				187				(17		)
Deferred generation costs		202				198				4
Deferred distribution costs		208				258				(50		)
Contract valuations		62				118				(56		)
Storm-related costs		500				329				171
Other		62				46				16
Net Regulatory Liabilities included on the Consolidated Balance Sheets		$	(2,407	)		$	(2,680	)		$	273

The following is a description of the regulatory assets and liabilities described above:

Regulatory transition costs - Primarily relates to JCP&L costs incurred during the transition to a competitive retail market and under-recovered during the period from August 1, 1999 through July 31, 2003; and JCP&L costs associated with basic generation service, capacity and ancillary services, net of all revenues from the sale of the committed supply in the wholesale market. Amounts are amortized through 2021.

Customer payables for future income taxes - Reflects amounts to be recovered or refunded through future rates to pay income taxes that become payable when rate revenue is provided to recover items such as AFUDC-equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to tax rate changes such as tax reform. These amounts are being amortized over the period in which the related deferred tax asset reverse, which is generally over the expected life of the underlying asset. See Note 7, "Taxes" for further discussion on the Tax Act.

Nuclear decommissioning and spent fuel disposal costs - Reflects a regulatory liability representing amounts collected from customers and placed in external trusts including income, losses and changes in fair value thereon (as well as accretion of the related ARO) for the future decommissioning of TMI-2.

Asset removal costs - Primarily represents the rates charged to customers by FirstEnergy’s regulated businesses that include a provision for the cost of future activities to remove assets, including obligations for which an asset retirement obligation has been recognized, that are expected to be incurred at the time of retirement.

Deferred transmission costs - Principally represents differences between revenues earned based on actual costs for formula rate companies (the Transmission Companies) and the amounts billed. Amounts are recorded as a regulatory asset or liability and recovered or refunded, respectively, in subsequent periods.

Deferred generation costs - Primarily relates to regulatory assets associated with the securitized recovery of certain electric customer heating discounts, fuel and purchased power regulatory assets at the Ohio Companies (amortized through 2034) as well as the ENEC at MP and PE. 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. The ENEC rate is updated annually.

Deferred distribution costs - Primarily relates to the Ohio Companies deferral of certain expenses resulting from distribution and reliability related expenditures, including interest, and are amortized through 2036.

Contract valuations - Primarily relates to the recovery of Penelec above-market NUG costs. Amounts also include the amortization of a purchase accounting adjustment which was recorded in connection with the AE merger representing the fair value of NUG purchased power contracts (amortized over the life of the contracts with various end dates from 2027 through 2036).

Storm-related costs - Relates to the recovery of storm costs which vary by jurisdiction of which $232 million is currently being recovered through rates. Approximately $268 million is not currently being recovered as of December 31, 2018.

Approximately $503 million and $223 million of regulatory assets, primarily related to storm damage costs, do not earn a current return as of December 31, 2018 and 2017, respectively, and a majority of which are currently being recovered through rates over varying periods depending on the nature of the deferral and the jurisdiction. Additionally, certain regulatory assets, totaling approximately $141 million as of December 31, 2018, are recorded based on prior precedent or anticipated recovery based on rate making premises without a specific order.

CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest payments, dividend payments and contributions to its pension plan.

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 preferred shares participate in dividends paid on common stock on an as-converted basis and are non-voting except in certain limited circumstances. The preferred shares are convertible at the option of the holders, and will mandatorily convert in July 2019, subject to limited exceptions. Proceeds from the investment were used to reduce FE holding company debt by $1.45 billion and fund FirstEnergy's pension plan as discussed below, with the remainder used for general corporate purposes. As of December 31, 2018, 911,411 preferred shares have been converted into 33,238,910 common shares at the option of the holders, resulting in 704,589 shares of preferred shares outstanding. An additional 494,767 preferred shares were converted into 18,044,018 common shares at the option of the holders in January 2019, resulting in 209,822 preferred shares outstanding and yet to be converted as of January 31, 2019.

The equity investment is strengthening FirstEnergy's balance sheet and is supporting the company's transition to a fully regulated utility company. By deleveraging the company, the investment also enabled FirstEnergy to enhance its investment grade credit metrics. The January 2018 equity issuance served as a catalyst to FirstEnergy's 2018-2021 "Unlocking the Future" regulated growth plan, which includes earnings growth targets, Regulated Distribution segment average annual rate base growth of 5%, formula transmission average annual rate base growth of 11%, and assumes no additional equity issuances through 2021, outside of FE's regular stock investment and employee benefit plans.

In addition to this equity investment, FE and its distribution and transmission subsidiaries expect their existing sources of liquidity to remain sufficient to meet their respective anticipated obligations. In addition to internal sources to fund liquidity and capital requirements for 2019 and beyond, FE and its distribution and transmission subsidiaries expect to rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through the issuance of long-term debt at certain distribution and transmission subsidiaries to, among other things, fund capital expenditures and refinance short-term and maturing long-term debt, subject to market conditions and other factors.

In January 2018, FirstEnergy satisfied its minimum required funding obligations to its qualified pension plan of $500 million and addressed anticipated required funding obligations through 2020 to its pension plan with an additional contribution of $750 million. On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. As a result of this contribution, FirstEnergy expects no required contributions through 2021.

FirstEnergy's capital expenditures for 2019 are expected to be approximately $2.9 to $3.0 billion. Planned capital initiatives are intended to promote reliability, improve operations, and support current environmental and energy efficiency directives.

Capital expenditures for 2018 and forecasted expenditures for 2019, 2020, and 2021, by reportable segment are included below:

Reportable Segment		2018 Actual				2019 Forecast			2020 Forecast			2021 Forecast
		(In millions)
Regulated Distribution		$	1,635			$ 1,600 - 1,700			$ 1,500 - 1,700			$ 1,500 - 1,700
Regulated Transmission		1,165				1,200			1,200			1,200
Corporate/Other		183				85			90			110
Total		$	2,983			$ 2,885 - 2,985			$ 2,790 - 2,990			$ 2,810 - 3,010

FirstEnergy’s transmission growth program, Energizing the Future, provides a stable and proven investment platform, while producing important customer benefits. Through the program, $4.4 billion in capital investments were made from 2014 through 2017, and the company plans to invest up to an additional $4.8 billion in the 2018-2021 timeframe, which includes approximately $1.2 billion in 2018 and a target of $1.2 billion annually through 2021. As noted above, over 80% of these capital investments are recoverable through formula rate mechanisms, reducing regulatory lag in recovering a return on investment, while offering a reasonable rate of return. These investments are expected to continue to improve the performance and condition of the transmission system while increasing automation and communication, adding capacity to the system and improving customer reliability. Beyond 2021, FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of up to approximately $20 billion, 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.

In the Regulated Distribution segment, FirstEnergy remains committed to providing customer service-oriented growth opportunities by investing between $6.2 billion and $6.7 billion over 2018 to 2021, including $1.6 billion invested in 2018. Approximately 40% of capital expenditures are recoverable through various rate mechanisms, riders and trackers. Beginning in 2019, expected investments at the Ohio Companies include the pending Ohio Grid Modernization plan which includes installation of approximately 700,000

advanced meters, distribution automation, and integrated ‘volt/var’ controls. Additionally, the pending JCP&L Reliability Plus infrastructure improvement plan filed with the NJBPU is expected to bring both reduced outages and strengthen the system while preparing for the grid of the future in New Jersey. FirstEnergy continues to explore other opportunities for growth in its Regulated Distribution business, 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 electrification of customers’ homes and businesses by providing a full range of products and services.

Any financing plans by FE or any of its consolidated subsidiaries, including the issuance of equity and debt, and the refinancing of short-term and maturing long-term debt are subject to market conditions and other factors. No assurance can be given that any such issuances, financing or refinancing, as the case may be, will be completed as anticipated or at all. Any delay in the completion of financing plans could require FE or any of its consolidated subsidiaries to utilize short-term borrowing capacity, which could impact available liquidity. In addition, FE and its consolidated subsidiaries expect to continually evaluate any planned financings, which may result in changes from time to time.

The FES Bankruptcy has also impacted FirstEnergy's capital requirements. On March 9, 2018, FES borrowed $500 million from FE under the secured credit facility, dated as of December 6, 2016, among FES, as Borrower, FG and NG as guarantors, and FE, as lender, which fully utilized the committed line of credit available under the secured credit facility. Following the FES Bankruptcy deconsolidation of FES, FE fully reserved for the $500 million associated with the borrowings under the secured credit facility. Under the terms of the FES Bankruptcy settlement agreement discussed below, FE will release any and all claims against the FES Debtors with respect to the $500 million borrowed under the secured credit facility.

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. The FES Bankruptcy settlement agreement resolves certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and their creditors against FirstEnergy, and includes the following terms, among others:

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

•

FE will 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/CSX rail settlement guarantee, and the FES Debtors' unfunded pension obligations.

•	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, including the economic interests therein as of January 1, 2019, and a requirement that FE continue to provide access to the McElroy's Run CCR Impoundment Facility, which is not being transferred. FE will provide certain guarantees for 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 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 fund through its pension plan a pension enhancement, subject to a cap, should FES offer a voluntary enhanced retirement package in 2019 and to offer certain other employee benefits.

•

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 (of which approximately $52 million has been paid through December 31, 2018).

FirstEnergy determined a loss is probable with respect to the FES Bankruptcy and recorded pre-tax charges totaling $877 million in 2018. See Note 3, "Discontinued Operations," for additional information.

The FES Bankruptcy settlement agreement remains subject to satisfaction of certain conditions, 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 FES Bankruptcy settlement agreement. 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 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.

In support of the strategic review to exit commodity-exposed generation, management launched the FE Tomorrow cost cutting 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 retiring by December 31, 2018. Management expects the cost savings resulting from the FE Tomorrow initiative to support the company's growth targets.

As of December 31, 2018, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was due in large part to currently payable long-term debt. Currently payable long-term debt as of December 31, 2018, included the following:

Currently Payable Long-Term Debt		December 31, 2018
		(In millions)
Unsecured notes		$	425
Sinking fund requirements		64
Other notes		14
		$	503

Short-Term Borrowings / Revolving Credit Facilities

FE and the Utilities, and FET and certain of its subsidiaries, each participate in two separate five-year syndicated revolving credit facilities, which were amended on October 19, 2018, providing for aggregate commitments of $3.5 billion (Facilities), which are available through December 6, 2022. Under the amended FE facility, an aggregate amount of $2.5 billion is available to be borrowed, repaid and reborrowed, subject to separate borrowing sub-limits for each borrower including FE and its regulated distribution subsidiaries. Under the amended FET Facility, an aggregate amount of $1.0 billion is available to be borrowed, repaid and reborrowed under a syndicated credit facility, subject to separate borrowing sub-limits for each borrower including FET and the Transmission Companies. Prior to the amendments to the Facilities, the aggregate commitments under the Facilities was $5.0 billion, which were available until December 6, 2021. FirstEnergy amended the Facilities to reduce costs and to better align FirstEnergy's ongoing liquidity needs with its strategy to be a fully regulated utility company.

Borrowings under the Facilities may be used for working capital and other general corporate purposes, including intercompany loans and advances by a borrower to any of its subsidiaries. Generally, borrowings under the Facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the Facilities contains financial covenants requiring each borrower to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter.

FirstEnergy had $1,250 million and $300 million of short-term borrowings as of December 31, 2018 and 2017, respectively. FirstEnergy’s available liquidity from external sources as of February 18, 2019, was as follows:

Borrower(s)		Type		Maturity		Commitment				Available Liquidity
						(In millions)
FirstEnergy(1)		Revolving		December 2022		$	2,500			$	2,490
FET(2)		Revolving		December 2022		1,000				1,000
				Subtotal		$	3,500			$	3,490
		Cash and cash equivalents				—				156
				Total		$	3,500			$	3,646

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

(2)	Includes FET and the Transmission Companies.

The following table summarizes the borrowing sub-limits for each borrower under the facilities, the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of January 31, 2019:

Borrower		FirstEnergy Revolving Credit Facility Sub-Limit					FET Revolving Credit Facility Sub-Limit					Regulatory and Other Short-Term Debt Limitations
		(In millions)
FE			$	2,500				$	—				$	—		(1)
FET			—					1,000					—			(1)
OE			500					—					500			(2)
CEI			500					—					500			(2)
TE			300					—					300			(2)
JCP&L			500					—					500			(2)
ME			500					—					500			(2)
PN			300					—					300			(2)
WP			200					—					200			(2)
MP			500					—					500			(2)
PE			150					—					150			(2)
ATSI			—					500					500			(2)
Penn			100					—					100			(2)
TrAIL			—					400					400			(2)
MAIT			—					400					400			(2)

(1)	No limitations.

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

The FE Facility and the FET Facility have $250 million and $100 million, respectively, subject to each borrower's sub-limit, available for the issuance of LOCs (subject to borrowings drawn under the Facilities) expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the Facilities and against the applicable borrower’s borrowing sub-limit.

The Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the facilities is related to the credit ratings of the company borrowing the funds, other than the FET Facility, which is based on its subsidiaries' credit ratings. Additionally, borrowings under each of the Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million.

As of December 31, 2018, the borrowers were in compliance with the applicable debt-to-total-capitalization covenants in each case as defined under the respective Facilities. The minimum interest charge coverage ratio no longer applies following FE's upgrade to an investment grade credit rating.

Term Loans

On October 19, 2018, FE entered into two separate syndicated term loan credit agreements, the first being a $1.25 billion 364-day facility with The Bank of Nova Scotia, as administrative agent, and the lenders identified therein, and the second being a $500 million two-year facility with JPMorgan Chase Bank, N.A., as administrative agent, and the lenders identified therein, respectively, the proceeds of each were used to reduce short-term debt. The term loans contain covenants and other terms and conditions substantially similar to those of the FE Facility described above, including a consolidated debt-to-total-capitalization ratio.

The initial borrowing of $1.75 billion under the new term loans, which took the form of a Eurodollar rate advance, may be converted from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances. Outstanding alternate base rate advances will bear interest at a fluctuating interest rate per annum equal to the sum of an applicable margin for alternate base rate advances determined by reference to FE’s reference ratings plus the highest of (i) the administrative agent’s publicly-announced “prime rate”, (ii) the sum of 1/2 of 1% per annum plus the Federal Funds Rate in effect from time to time and (iii) the rate of interest per annum appearing on a nationally-recognized service such as the Dow Jones Market Service (Telerate) equal to one-month LIBOR on each day plus 1%. Outstanding Eurodollar rate advances will bear interest at LIBOR for interest periods of one week or one, two, three or six months plus an applicable margin determined by reference to FE’s reference ratings. Changes in FE’s reference ratings would lower or raise its applicable margin depending on whether ratings improved or were lowered, respectively.

FirstEnergy Money Pools

FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and FE to meet their short-term working capital requirements. Similar but separate arrangements exist among FirstEnergy’s unregulated companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries. FESC administers these money pools and tracks surplus funds of FE and the respective regulated and unregulated subsidiaries, as the case may be, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2018 was 2.26% per annum for the regulated companies’ money pool and 2.96% per annum for the unregulated companies’ money pools.

Long-Term Debt Capacity

FE's and its subsidiaries' access to capital markets and costs of financing are influenced by the credit ratings of their securities. The following table displays FE’s and its subsidiaries’ credit ratings as of February 19, 2019:

		Senior Secured						Senior Unsecured
Issuer		S&P		Moody’s		Fitch		S&P		Moody’s		Fitch
FE		—		—		—		BBB-		Baa3		BBB-
AGC		—		—		—		—		—		—
ATSI		—		—		—		BBB		Baa1		BBB+
CEI		A-		Baa1		A-		BBB		Baa3		BBB+
FET		—		—		—		BBB-		Baa2		BBB-
JCP&L		—		—		—		BBB		Baa2		BBB
ME		—		—		—		BBB		A3		BBB+
MAIT		—		—		—		BBB		Baa1		BBB+
MP		A-		A3		BBB+		BBB		Baa2		—
OE		A-		A2		A-		BBB		Baa1		BBB+
PN		—		—		—		BBB		Baa1		BBB+
Penn		—		A2		A-		—		—		—
PE		—		—		BBB+		—		—		—
TE		A-		Baa1		A-		—		—		—
TrAIL		—		—		—		BBB		A3		BBB+
WP		—		—		A-		—		—		—

Debt capacity is subject to the consolidated debt-to-total-capitalization limits in the credit facilities previously discussed. As of January 31, 2019, FE and its subsidiaries could issue additional debt of approximately $8.8 billion, or incur a $4.7 billion reduction to equity, and remain within the limitations of the financial covenants required by the FE Facility.

Changes in Cash Position

As of December 31, 2018, FirstEnergy had $367 million of cash and cash equivalents and approximately $62 million of restricted cash compared to $589 million of cash and cash equivalents ($1 million in discontinued operations) and approximately $54 million of restricted cash ($3 million in discontinued operations) as of December 31, 2017, on the Consolidated Balance Sheet.

Cash Flows From Operating Activities

FirstEnergy's most significant sources of cash are derived from electric service provided by its distribution and transmission operating subsidiaries. The most significant use of cash from operating activities is buying electricity to serve non-shopping customers and paying fuel suppliers, employees, tax authorities, lenders and others for a wide range of material and services.

FirstEnergy's Consolidated Statement of Cash Flows combines the cash flows from discontinued operations with cash flows from continuing operations within each cash flow statement category. The following table summarized the major classes of cash flow items as discontinued operations for the years ended December 31, 2018, 2017 and 2016:

		For the Years Ended December 31,
(In millions)		2018				2017				2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) from discontinued operations		$	326			$	(1,435	)		$	(6,728	)
Gain on disposal, net of tax		(435		)		—				—
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs		110				333				669
Deferred income taxes and investment tax credits, net		61				(842		)		(3,582		)
Unrealized (gain) loss on derivative transactions		(10		)		81				9

Net cash provided from operating activities was $1,410 million during 2018, $3,808 million during 2017 and $3,383 million during 2016.

2018 compared with 2017

Cash flows from operations decreased $2,398 million in 2018 as compared with 2017. The year-over-year change in cash from operations decreased due to the following:

•	the absence of FES' cash from operations in the last nine months of 2018;

•	credit for shared services provided to FES and FENOC during the last nine months of 2018;

•	payments of $52 million to FES and FENOC under the intercompany income tax allocation agreement;

•	a $1.25 billion cash contribution to the qualified pension plan in 2018;

•	a $93 million coal supply agreement dispute settlement payment by AE Supply in the first quarter of 2018;

•	a $229 million increase in deferred storm restoration costs;

•	a $72 million payment in connection with FE's guarantee of remaining payments on FG's settlement of a coal transportation contract dispute; partially offset by

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

•	higher distribution services retail receipts reflecting higher weather-related usage and the implementation of approved rates in Ohio and Pennsylvania.

2017 compared with 2016

Cash flows from operations increased $425 million in 2017 compared with 2016 due to the following:

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

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

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

•	lower receipts from a decrease in competitive business capacity revenue and contract sales at Corporate/Other (formerly CES).

Cash Flows From Financing Activities

In 2018, cash provided from financing activities was $1,394 million compared to cash used for financing activities of $702 million in 2017 and $34 million in 2016. The following table summarizes new equity and debt financing, redemptions, repayments, short-term borrowings and dividends:

		For the Years Ended December 31,
Securities Issued or Redeemed / Repaid		2018				2017				2016
		(In millions)
New Issues
Preferred stock issuance		$	1,616			$	—			$	—
Common stock issuance		850				—				—
Unsecured notes		850				3,800				—
PCRBs		74				—				471
FMBs		50				625				305
Term loan		500				250				1,200
		$	3,940			$	4,675			$	1,976
Redemptions / Repayments
Unsecured notes		$	(555	)		$	(1,330	)		$	(300	)
PCRBs		(216		)		(158		)		(483		)
FMBs		(325		)		(725		)		(246		)
Term loan		(1,450		)		—				(1,200		)
Senior secured notes		(62		)		(78		)		(102		)
		$	(2,608	)		$	(2,291	)		$	(2,331	)
Tender premiums paid on debt redemptions		$	(89	)		$	—			$	—
Short-term borrowings (repayments), net		$	950			$	(2,375	)		$	975
Preferred stock dividend payments		$	(61	)		$	—			$	—
Common stock dividend payments		$	(711	)		$	(639	)		$	(611	)

On January 22, 2018, FE entered into agreements for the private placement of its equity securities representing an approximately $2.5 billion investment in the company, including $1.62 billion in mandatorily convertible preferred equity and $850 million of common equity.

On January 22, 2018, FE repaid $1.2 billion of a variable rate syndicated term loan and two separate $125 million term loans using the proceeds from the $2.5 billion equity investment as discussed above.

On May 3, 2018, AGC redeemed $100 million of 5.06% senior notes due 2021 and paid $5.7 million in related make-whole premiums in connection with the redemption.

On May 10, 2018, MAIT issued $450 million of 4.10% senior notes due 2028. Proceeds from the issuance of the notes were used to establish a capital structure, to finance capital improvements and for general corporate purposes, including funding working capital needs and day-to-day operations.

On June 4, 2018, AE Supply repaid approximately $155 million of 5.75% senior notes due 2019 and approximately $150 million of 6.75% senior notes due 2039, and paid $83.3 million in related make-whole premiums in connection with repayments.

On June 4, 2018, AE Supply and MP caused to be redeemed $73.5 million of 5.50% PCRBs due 2037. On July 10, 2018, such PCRBs were refinanced as MP issued $73.5 million of 3.0% PCRBs with an October 2021 mandatory put.

On June 11, 2018, AE Supply caused to be redeemed $142 million of 5.25% PCRBs due 2037.

On June 15, 2018, JCP&L retired $150 million of 4.8% senior notes at maturity.

On September 27, 2018, ATSI issued $100 million of 4.32% senior notes due 2030. Proceeds were used to refinance existing indebtedness, including amounts under the FE regulated utility money pool, and remaining proceeds will be used to fund working capital needs, and for other general corporate purposes.

On October 3, 2018, Penn issued $50 million of 4.37% first mortgage bonds due 2048. Proceeds were used to refinance existing indebtedness, including amounts under the FE regulated utility money pool, to fund capital expenditures; and for other general corporate purposes.

On October 15, 2018, OE repaid $25 million of 8.25% first mortgage bonds at maturity.

On October 19, 2018, FE entered into a $1.25 billion 364-day term loan due 2019 (classified as short-term borrowings). Proceeds were used for general corporate purposes. Additionally, on October 19, 2018, FE entered into a $500 million two-year variable rate term loan due 2020. Proceeds were used to reduce revolver borrowings.

On November 2, 2018, CEI issued $300 million of 4.55% senior unsecured notes due 2030. Proceeds were used to retire $300 million of 8.875% first mortgage bonds at maturity on November 15, 2018.

On January 10, 2019, ME issued $500 million of 4.30% senior note due 2029. Proceeds from the issuance of senior notes were used to refinance existing indebtedness, including ME's 7.70% senior notes due January 15, 2019, and borrowings outstanding under the FE regulated utility money pool, to fund capital expenditures, and for other general corporate purposes.

On February 8, 2019, JCP&L issued $400 million of 4.30% senior notes due 2026. Proceeds from the issuance of the senior notes were used to refinance existing indebtedness, including amounts under the FE regulated utility money pool incurred in connection with the repayment at maturity of JCP&L's 7.35% senior notes due 2019.

Cash Flows From Investing Activities

Cash used for investing activities in 2018 principally represented cash used for property additions. The following table summarizes investing activities for 2018, 2017 and 2016:

		For the Years Ended December 31,
Cash Used for Investing Activities		2018				2017				2016
		(In millions)
Property Additions:
Regulated Distribution		$	1,411			$	1,191			$	1,063
Regulated Transmission		1,104				1,030				1,101
Corporate/Other		160				366				671
Nuclear fuel		—				254				232
Proceeds from asset sales		(425		)		(388		)		(15		)
Investments		54				98				111
Notes receivable from affiliated companies		500				—				—
Asset removal costs		218				172				145
Other		(4		)		—				(6		)
		$	3,018			$	2,723			$	3,302

2018 compared with 2017

Cash used for investing activity in 2018 increased $295 million, as compared to 2017, primarily due to higher property additions and asset removal costs, partially offset by the absence of nuclear fuel purchases and higher proceeds from asset sales. Additionally, the increase in notes receivable from affiliated companies resulted from FES' borrowings from the committed line of credit available under the secured credit facility with FE. The increase in property additions was due to the following:

•	an increase of $220 million at Regulated Distribution due to an increase in storm restoration work;

•	an increase of $74 million at Regulated Transmission due to timing of capital investments associated with its Energizing the Future investment program; partially offset by,

•	a decrease of $206 million at Corporate/Other due to lower competitive generation related investments.

2017 compared with 2016

Cash used for investing activity in 2017 decreased $579 million, compared to 2016, primarily due to lower property additions. The decline in property additions was due to the following:

•	a decrease of $305 million at Corporate/Other, resulting from lower competitive generation capital investments associated with outages, MATS compliance and the Mansfield dewatering facility,

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

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

CONTRACTUAL OBLIGATIONS

As of December 31, 2018, FirstEnergy's estimated cash payments under existing contractual obligations that it considers firm obligations are as follows:

Contractual Obligations		Total				2019				2020-2021				2022-2023				Thereafter
		(In millions)
Long-term debt(1)		$	18,305			$	489			$	996			$	2,337			$	14,483
Short-term borrowings		1,250				1,250				—				—				—
Interest on long-term debt(2)		11,307				850				1,632				1,487				7,338
Operating leases(3)		289				34				70				58				127
Capital leases(3)		96				24				35				21				16
Fuel and purchased power(4)		5,102				877				1,261				1,139				1,825
Capital expenditures (5)		1,841				576				905				360				—
Pension funding (6)		1,951				500				—				837				614
Total		$	40,141			$	4,600			$	4,899			$	6,239			$	24,403

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

(2)	Interest on variable-rate debt based on rates as of December 31, 2018.

(3)	See Note 8, "Leases," of the Notes to Consolidated Financial Statements.

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

(5)	Amounts represent committed capital expenditures as of December 31, 2018.

(6) 2019 reflects voluntary cash contribution made to the qualified pension plan on February 1, 2019.

Excluded from the table above are estimates for the cash outlays from power purchase contracts entered into by most of the Utilities and under which they procure the power supply necessary to provide generation service to their customers who do not choose an alternative supplier. Although actual amounts will be determined by future customer behavior and consumption levels, management currently estimates these cash outlays will be approximately $2.6 billion in 2019.

The table above also excludes regulatory liabilities (see Note 16, "Regulatory Matters"), AROs (see Note 15, "Asset Retirement Obligations"), reserves for litigation, injuries and damages, environmental remediation, and annual insurance premiums, including nuclear insurance (see Note 17, "Commitments, Guarantees and Contingencies") since the amount and timing of the cash payments are uncertain. The table also excludes accumulated deferred income taxes and investment tax credits since cash payments for income taxes are determined based primarily on taxable income for each applicable fiscal year.

NUCLEAR INSURANCE

JCP&L, ME and PN maintain property damage insurance provided by NEIL for their interest in the retired TMI- 2 nuclear facility, a permanently shut down and defueled facility. Under these arrangements, up to $150 million of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. JCP&L, ME and PN pay annual premiums and are subject to retrospective premium assessments of up to approximately $1.2 million during a policy year.

JCP&L, ME and PN intend to maintain insurance against nuclear risks as long as it is available. To the extent that property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of JCP&L, ME or PN’s plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by JCP&L, ME or PN’s insurance policies, or to the extent such insurance becomes unavailable in the future, JCP&L, ME or PN would remain at risk for such costs.

The Price-Anderson Act limits public liability relative to a single incident at a nuclear power plant. In connection with TMI-2, JCP&L, ME and PN carry the required ANI third party liability coverage and also have coverage under a Price Anderson indemnity agreement issued by the NRC. The total available coverage in the event of a nuclear incident is $560 million, which is also the limit of public liability for any nuclear incident involving TMI-2.

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. The maximum potential amount of future payments FirstEnergy and its subsidiaries could be required to make under these guarantees as of December 31, 2018, was approximately $1.7 billion, as summarized below:

Guarantees and Other Assurances		Maximum Exposure
		(In millions)
FE's Guarantees on Behalf of FES and FENOC
Energy and Energy-Related Contracts(1)		$	5
Surety Bonds - FG(2)		200
Deferred compensation arrangements		140
		345
FE's Guarantees on Behalf of its Consolidated Subsidiaries
AE Supply asset sales(3)		555
Deferred compensation arrangements		423
Fuel related contracts and other		21
		999
FE's Guarantees on Behalf of Business Ventures
Global Holding Facility		190
Other Assurances
Surety Bonds		130
LOCs(4)		10
		140
Total Guarantees and Other Assurances		$	1,674

(1)	Issued for open-ended terms, with a 10-day termination right by FirstEnergy. As of December 31, 2018, FE recorded an obligation for these guarantees in other non-current liabilities with a corresponding loss from discontinued operations.

(2)	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.

(3)

As a condition to closing AE Supply's sale of four natural gas generating plants in December 2017, FE provided the purchaser two limited three-year guarantees totaling $555 million of certain obligations of AE Supply and AGC. In connection with the FES Bankruptcy settlement agreement, FirstEnergy has also committed to provide certain additional guarantees to FG for retained environmental liabilities of AE Supply related to the Pleasants Power Station and the McElroy's Run CCR disposal facility.

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

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 or its subsidiaries' credit rating 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 December 31, 2018, AE Supply has posted no collateral. The Utilities and Transmission Companies have posted collateral 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 December 31, 2018:

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		—				62				—				62
Surety Bonds (Collateralized Amount)(1)		1				59				246				306
Total Exposure from Contractual Obligations		$	2			$	121			$	246			$	369

(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.

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 outstanding principal balance is $190 million as of December 31, 2018. 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 guaranties of the obligations of Global Holding under the facility.

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

MARKET RISK INFORMATION

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

Commodity Price Risk

FirstEnergy has limited exposure to financial risks resulting from fluctuating commodity prices, including prices for electricity, natural gas, coal and energy transmission. FirstEnergy's Risk Management Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice.

The valuation of derivative contracts is based on observable market information. As of December 31, 2018, FirstEnergy has a net liability of $44 million in non-hedge derivative contracts that are primarily related to NUG contracts at certain of the Utilities. NUG contracts are subject to regulatory accounting and do not impact earnings.

Equity Price Risk

As of December 31, 2018, the FirstEnergy pension plan assets were allocated approximately as follows: 36% in equity securities, 34% in fixed income securities, 11% in absolute return strategies, 10% in real estate, 2% in private equity, 2% in derivatives and 5% in cash and short-term securities. A decline in the value of pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. In January 2018, FirstEnergy satisfied its minimum required funding obligations to its qualified pension plan of $500 million and addressed anticipated required funding obligations through 2020 to its pension plan with an additional contribution of $750 million. On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. As a result of this contribution, FirstEnergy expects no required contributions through 2021. See Note 5, "Pension and Other Postemployment Benefits," of the Notes to Consolidated Financial Statements for additional details on FirstEnergy's pension and OPEB plans. Through December 31, 2018, FirstEnergy's pension plan assets had losses of approximately (4.2)% as compared to an annual expected return on plan assets of 7.5%.

As of December 31, 2018, FirstEnergy's OPEB plans were invested in fixed income and equity securities. Through December 31, 2018, FirstEnergy's OPEB plans have earned approximately (1.0)% as compared to an annual expected return on plan assets of 7.5%.

NDT funds have been established to satisfy JCP&L, ME and PN's nuclear decommissioning obligations associated with TMI-2. As of December 31, 2018, approximately 55% of the funds were invested in fixed income securities, 43% of the funds were invested in equity securities and 2% were invested in short-term investments, with limitations related to concentration and investment grade ratings. The investments are carried at their market values of approximately $438 million, $338 million and $13 million for fixed income securities, equity securities and short-term investments, respectively, as of December 31, 2018, excluding $(1) million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $34 million reduction in fair value as of December 31, 2018. A decline in the value of JCP&L, ME and PN’s NDTs or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2018, JCP&L, ME and PN made no contributions to the NDTs.

Interest Rate Risk

FirstEnergy’s exposure to fluctuations in market interest rates is reduced since a significant portion of debt has fixed interest rates, as noted in the table below. FirstEnergy is subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities.

Comparison of Carrying Value to Fair Value
Year of Maturity		2019				2020				2021				2022				2023				There-after				Total				Fair Value
		(In millions)
Assets:
Investments Other Than Cash and Cash Equivalents:
Fixed Income		$	—			$	—			$	—			$	—			$	—			$	688			$	688			$	688
Average interest rate		—		%		—		%		—		%		—		%		—		%		3.1		%		3.1		%
Liabilities:
Long-term Debt:
Fixed rate		$	489			$	364			$	58			$	1,100			$	1,150			$	14,654			$	17,815			$	18,766
Average interest rate		6.7		%		5.4		%		4.7		%		4.1		%		4.2		%		5.0		%		4.9		%
Variable rate		$	—			$	500			$	—			$	—			$	—			$	—			$	500			$	500
Average interest rate		—		%		3.3		%		—		%		—		%		—		%		—		%		3.3		%

CREDIT RISK

Credit risk is the risk that FirstEnergy would incur a loss as a result of nonperformance by counterparties of their contractual obligations. FirstEnergy maintains credit policies and procedures with respect to counterparty credit (including requirement that counterparties maintain specified credit ratings) and require other assurances in the form of credit support or collateral in certain circumstance in order to limit counterparty credit risk. However, FirstEnergy, as applicable, has concentrations of suppliers and customers among electric utilities, financial institutions and energy marketing and trading companies. These concentrations may impact FirstEnergy's overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions. In the event an energy supplier of the Ohio Companies, Pennsylvania Companies, JCP&L or PE defaults on its obligation, the Ohio Companies, Pennsylvania Companies, JCP&L and PE would be required to seek replacement power in the market. In general, subject to regulatory review or other processes, appropriate incremental costs incurred by these entities would be recoverable from customers through applicable rate mechanisms, thereby mitigating the financial risk for these entities. FirstEnergy's credit policies to manage credit risk include the use of an established credit approval process, daily credit mitigation provisions, such as margin, prepayment or collateral requirements. FirstEnergy and its subsidiaries may request additional credit assurance, in certain circumstances, in the event that the counterparties' credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit.

OUTLOOK

STATE REGULATION

Each of the 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 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. 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.

The following table summarizes the key terms of distribution rate orders in effect for the Utilities.

Company		Rates Effective		Allowed Debt/Equity		Allowed ROE
CEI		May 2009		51% / 49%		10.5%
ME(1)		January 2017		48.8% / 51.2%		Settled(2)
MP		February 2015		54% / 46%		Settled(2)
JCP&L		January 2017		55% / 45%		9.6%
OE		January 2009		51% / 49%		10.5%
PE-West Virginia		February 2015		54% / 46%		Settled(2)
PE-Maryland		November 1994		48% / 52%		11.9%
PN(1)		January 2017		47.4% / 52.6%		Settled(2)
Penn(1)		January 2017		49.9% / 50.1%		Settled(2)
TE		January 2009		51% / 49%		10.5%
WP(1)		January 2017		49.7% / 50.3%		Settled(2)

(1) Reflects filed debt/equity as final settlement/orders do not specifically include capital structure.

(2) Commission-approved settlement agreements did not disclose ROE rates.

MARYLAND

PE operates under MDPSC approved base rates that were effective as of November 11, 1994. 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 EmPOWER Maryland program requires each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, 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 2016 starting goal under this requirement was 0.97%. PE's approved 2018-2020 EmPOWER Maryland plan continues and expands upon prior years' programs, and adds new programs, for a projected total cost of $116 million over the three-year period. 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.

In 2013, the MDPSC required Maryland electric utilities to submit analyses relating to the costs and benefits of making further system and staffing enhancements in order to attempt to reduce storm outage durations. PE's submitted analysis projected that it would require up to 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 MDPSC's scenarios. The MDPSC conducted a hearing September 2014, but has not taken further action on this matter.

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 in connection with a 2016 MDPSC 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. PE proposed an electric vehicle charging infrastructure program at a projected total cost of $12 million, to be recovered over a five-year amortization. On January 14, 2019, the MDPSC approved the petition subject to certain reductions in the scope of the program.

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 must 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 that recommended the MDPSC instead 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 further direct that PE pay customers a one-time credit for what the Staff estimated were the tax savings to PE through the end of 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 totaled approximately $5 million, and reserved all other Tax Act impacts to be resolved in the pending rate case.

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 requested an annual increase in base distribution rates of $19.7 million, plus creation of an 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 reflects $7.3 million in annual savings

for customers resulting from the recent federal tax law changes. On November 20, 2018, the Staff of the MDPSC filed testimony recommending an increase in base rates of $12.9 million and conditional approval of the EDIS, while the Maryland Office of People's Counsel filed testimony recommending a reduction in rates of $11.1 million and rejection of the EDIS. The evidentiary hearing concluded on January 28, 2019, and a final order is expected by March 23, 2019.

NEW JERSEY

JCP&L operates under NJBPU approved rates that were effective as of January 1, 2017. In addition, on January 25, 2017, the NJBPU approved the acceleration of the amortization of JCP&L’s 2012 major storm expenses that are recovered through the SRC in order for JCP&L to achieve full recovery by December 31, 2019. 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. 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.

In December 2017, the NJBPU issued proposed rules to modify its current CTA policy in base rate cases to: (i) calculate savings using a five-year look back from the beginning of the test year; (ii) allocate savings with 75% retained by the company and 25% allocated to rate payers; and (iii) exclude transmission assets of electric distribution companies in the savings calculation, which were published in the NJ Register in the first quarter of 2018. JCP&L filed comments supporting the proposed rulemaking. On January 17, 2019, the NJBPU approved the proposed CTA rules with no changes.

Also in December 2017, 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. On August 29, 2018, the NJBPU retained the petition for hearing and, on November 22, 2018, issued a procedural schedule. On December 17, 2018, the Division of Rate Counsel recommended a $97 million program, a return on equity of 8.75%, and 5.38% cost of debt. On January 23, 2019, the NJBPU granted JCP&L's request to temporarily suspend procedural schedule in the matter pending settlement discussions. There can be no assurance that a definitive settlement agreement will be reached and, if so, will be approved by the NJBPU.

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. The NJBPU, however, did not address refunds and other proposed rider tariffs at such time.

OHIO

The Ohio Companies currently operate under ESP IV through May 31, 2024. ESP IV includes 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 and is 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 freeze through May 31, 2024. In addition, ESP IV continues the supply of power to non-shopping customers at a market-based price set through an auction process. On February 1, 2019, the Ohio Companies filed with the PUCO an application requesting a two-year extension of Rider DMR at the same amount and conditions.

ESP IV also 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 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. ESP IV 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 was filed in February 2016, and remains pending as part of the grid modernization settlement described below; (3) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; (4) 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 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 for residential customers' base distribution rates, which filing 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. On August 16, 2017, the PUCO denied all remaining intervenor applications for rehearing, denied the Ohio Companies’ challenges to the modifications to Rider DMR and added a third-party monitor to ensure that Rider DMR funds are spent appropriately. The Ohio Companies then filed an application for rehearing of the PUCO’s August 16, 2017 ruling on the issues of the third-party monitor and the ROE calculation for advanced metering infrastructure, which the PUCO denied. In October 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. The Ohio Companies intervened in the appeal, and additional parties subsequently filed notices of appeal with the Supreme Court of Ohio challenging various PUCO entries on their applications for rehearing. 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 was held on January 9, 2019.

Under Ohio law, the Ohio Companies are required to implement energy efficiency programs that achieve certain annual energy savings and total peak demand reductions. The Ohio Companies’ 2017-2019 plan, as proposed in April 2016, 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. In December 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. The Ohio Companies anticipate the cost of the plans will be approximately $268 million over the life of the portfolio plans 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 proposed plans with several modifications, including a cap on the Ohio Companies’ collection of program costs and shared savings set at 4% of the Ohio Companies’ total sales to customers. On December 21, 2017, the Ohio Companies filed an application for rehearing challenging the PUCO’s modifications, which the PUCO denied on January 10, 2018. On March 12, 2018, the Ohio Companies appealed to the Supreme Court of Ohio challenging the PUCO’s imposition of a 4% cost cap. Various other parties also appealed challenging various PUCO entries on their applications for rehearing. 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, which in 2017 was 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. In August 2013, the PUCO approved the Ohio Companies' REC acquisitions 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. Following appeals, on January 24, 2018, the Supreme Court of Ohio reversed the PUCO order finding that the order violated the rule against retroactive ratemaking. After the OCC and ELPC filed a motion for reconsideration, to which the Ohio Companies responded in opposition, 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.

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. 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, discussed below, to flow back to customers. 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. The PUCO conducted a hearing and the settlement agreement remains subject to PUCO approval.

On January 10, 2018, the PUCO opened a case to consider the impacts of the Tax Act and determine the appropriate course of action to pass benefits on to customers. 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, and 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. On October 24, 2018, the PUCO entered an Order in its investigation into the impacts of the Tax Act on Ohio's utilities directing that by January 1, 2019, all Ohio rate-regulated utility companies, unless ordered otherwise, file applications not for an increase in rates to reflect the impact of the Tax Act on each specific utility's current rates. On October 30, 2018, the Ohio Companies filed an application to open a new proceeding for the implementation of matters relating to the impact of the Tax Act. As discussed further above, on November 9, 2018, the Ohio Companies filed a settlement agreement that provides for all tax savings associated with the Tax Act to flow back to customers and for the implementation of the first phase of grid modernization plans. 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 December 19, 2018, the PUCO upheld its January 10, 2018 ruling that utilities should be required to establish a deferred tax liability, effective January 1, 2018, in response to the Tax Act. 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 PUCO conducted a hearing and the settlement agreement remains subject to PUCO approval.

PENNSYLVANIA

The Pennsylvania Companies operate under rates approved by the PPUC, effective as of January 27, 2017. The Pennsylvania Companies operate under DSPs for the June 1, 2017 through May 31, 2019 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.

The Pennsylvania Companies' DSPs for the June 1, 2019 through May 31, 2023 delivery period were approved by the PPUC in September 2018. Under the 2019-2023 DSPs, the supply 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 also include modifications to the Pennsylvania Companies’ POR programs in order to continue their clawback pilot program as a long-term, permanent program term, and modifications to the Pennsylvania Companies’ customer class definitions to allow for the introduction of hourly priced default service to customers at or above 100kW. The PPUC directed a working group to further discuss the implementation of customer assistance program shopping limitations and appropriate scripting for the Pennsylvania Companies' customer referral programs, and in November 2018, issued a subsequent order to approve additional customer assistance program shopping parameters and further limit the scope of the working group discussion. On December 21, 2018, the PPUC issued a tentative order proposing a model to incorporate the directed shopping restrictions. Comments on the proposal were filed January 22, 2019.

Pursuant to Pennsylvania's EE&C legislation in Act 129 of 2008 and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. The Pennsylvania 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 Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders.

Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. LTIIPs outlining infrastructure improvement plans for PPUC review and approval must be filed prior to approval of a DSIC. 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. On September 20, 2018, following a periodic review of the LTIIPs as required by regulation once every five years, 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 and directed the Pennsylvania Companies to file modified or new LTIIPs. On January 18, 2019, the Pennsylvania Companies filed modifications to their current LTIIPs that would terminate those LTIIPs at the end of 2019, and proposed revised LTIIP spending in 2019 of $44.52 million by ME, $24.72 million by PN, $26.06 million by Penn and $50.85 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.

The Pennsylvania Companies’ approved DSIC riders for quarterly cost recovery went into effect July 1, 2016, subject to hearings and refund or reallocation among customer classes. In the January 19, 2017 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 April 19, 2018, the PPUC approved the Joint Settlement without modification and reversed the 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 decision of April 19, 2018. On June 11, 2018, the Pennsylvania Companies filed a Notice of Intervention in the Pennsylvania OCA's appeal to the Commonwealth Court. Briefing is complete and oral argument is scheduled for June 3, 2019.

On February 12, 2018, 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, the Pennsylvania Companies submitted their calculation of the net annual effect of the Tax Act on 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. On March 15, 2018, 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 of the Tax Act for the period July 1, 2018 through December 31, 2018, to be prospectively updated for new rates effective January 1, 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, the PPUC issued an order revising this directive such that the Pennsylvania Companies must instead establish accounts to track tax savings for the 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. The cumulative value of the tracked amounts and the regulatory liability is expected to amount to $12 million for ME, $13 million for PN, $3 million for Penn, and $10 million for WP. These amounts are expected to be addressed 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 June 1, 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 returned to customers was approximately $22 million for ME, $23 million for PN, $6 million for Penn, and $18 million for WP.

WEST VIRGINIA

MP and PE provide electric service to all customers through traditional cost-based, regulated utility 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 and PE's ENEC rate is updated annually.

In September 2016, the WVPSC approved the Phase II energy efficiency program for MP and PE as reflected in a unanimous settlement, which included three energy efficiency programs to meet the Phase II requirement of energy efficiency reductions of 0.5% of 2013 distribution sales for the January 1, 2017 through May 31, 2018 period. On December 15, 2017, the WVPSC approved MP's and PE's proposed annual decrease in their EE&C rates, effective January 1, 2018, which is not material to FirstEnergy. This Phase II energy efficiency program ended May 31, 2018.

Previously, AE Supply was the winning bidder of a December 2016 RFP to address MP’s generation shortfall and on March 6, 2017, MP and AE Supply signed an asset purchase agreement for MP to acquire AE Supply’s Pleasants Power Station (1,300 MWs), subject to customary and other closing conditions, including regulatory approvals. In January 2018, FERC issued an order denying authorization for the transaction and the WVPSC issued an order approving the transfer of Pleasants Power Station conditioned on MP assuming significant commodity risk. Based on the adverse FERC ruling and the conditions included in the WVPSC order, MP and AE Supply terminated the asset purchase agreement.

On August 31, 2018, MP and PE filed a $100.9 million decrease in their ENEC rates proposed to be effective January 1, 2019, which included 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 included 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% annual decrease in rates versus those in effect on August 31, 2018. A unanimous settlement was filed with the WVPSC on November 20, 2018, and a hearing was held on November 27, 2018. An order adopting the settlement in full without modification was issued on January 2, 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. MP and PE filed written testimony on May 30, 2018, explaining the impact of the Tax Act on federal income tax and revenue requirements and showing an annual rate impact of $26.2 million. MP and PE, the Staff of the WVPSC, the WV Consumer Advocate and a coalition of industrial customers entered into a settlement agreement on August 23, 2018, to have $25.6 million in rate reductions flow through to customers beginning September 1, 2018, and to defer to 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 and the issue of whether MP and PE should be required to credit to customers any of the reduced income tax expense occurring between January 1, 2018 and August 31, 2018. The WVPSC approved the settlement on August 24, 2018.

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 their wholesale services and rates, the Utilities, AE Supply, AGC, and the 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 JCP&L, MP, PE, WP and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff.

The following table summarizes the key terms of rate orders in effect for transmission customer billings for FirstEnergy's transmission owner entities:

Company		Rates Effective		Capital Structure		Allowed ROE
ATSI		January 1, 2015		Actual (13 month average)		10.38%
JCP&L		June 1, 2017		Settled(1)		Settled(1)
MP		March 21, 2018(2)		Settled(1)		Settled(1)
PE		March 21, 2018(2)		Settled(1)		Settled(1)
WP		March 21, 2018(2)		Settled(1)		Settled(1)
MAIT		July 1, 2017		50% / 50% (hypothetical)(3)		10.3%
TrAIL		July 1, 2008		Actual (year-end)		12.7% (TrAIL the Line & Black Oak SVC) 11.7% (All other projects)

(1) FERC-approved settlement agreements did not specify.

(2) See FERC Actions on Tax Act below.

(3) Effective January 2019, converts to lower of actual (13 month average) or 60%.

FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Utilities and 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 relevant state commissions.

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, and 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 regional entities, including RFC. All of 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 compliance with all 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 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 advocated for a traditional "beneficiary pays" (or usage based) approach, others advocated 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. On May 31, 2018, FERC issued an order approving a settlement agreement among various parties, including ATSI and the Utilities, 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. As a result of the settlement, FirstEnergy recorded a pre-tax benefit of approximately $115 million in 2018 (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, of which $73 million is associated with the "black box" calculation of historical transmission costs prior to January 1, 2016, and $42 million is associated with the "50/50" calculation of historical transmission costs from January 1, 2016 to June 30, 2018. PJM implemented the settlement for transmission service in August 2018. Requests for rehearing or clarification of FERC's May 31, 2018, orders and related responses remain pending before FERC. FirstEnergy does not expect a material impact from implementation of the settlement agreement going forward.

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 transmission rate for certain charges that collectively can be described as "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. In a subsequent order, FERC 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 September 20, 2018, FERC denied rehearing with respect to its 2016 order regarding allocation of MVP costs and affirmed and clarified its prior decision that MISO may allocate MVP costs to PJM customers for power withdrawals from MISO to PJM as such exports occur.

MAIT Transmission Formula Rate

MAIT previously submitted an application to FERC requesting authorization to implement a forward-looking formula transmission rate to recover and earn a return on transmission assets effective February 1, 2017. Following various protests to the proposed MAIT formula transmission rate, on March 10, 2017, FERC issued an order accepting the MAIT formula transmission rate for filing, suspending the formula transmission rate for five months to become effective July 1, 2017, and establishing hearing and settlement judge procedures. On May 21, 2018, FERC issued an order accepting a settlement agreement as filed by MAIT and certain parties, without conditions. The settlement agreement provides for certain changes to MAIT's formula rate, including changing MAIT's ROE from 11% to 10.3%, setting the recovery amount for certain regulatory assets, and establishing that MAIT's capital structure will not exceed 60% equity over the period ending December 31, 2021. The settlement agreement further provides that the ROE and the 60% cap on the equity component of MAIT's capital structure will remain in effect unless changed pursuant to section 205 or 206 of the FPA provided the effective date for any change shall be no earlier than January 1, 2022. Refunds for the difference between the filed rate and the settlement rate will be handled through MAIT's true-up process.

JCP&L Transmission Formula Rate

In October 2016, after withdrawing its request to the NJBPU to transfer its transmission assets to MAIT, JCP&L submitted an application to FERC requesting authorization to implement a forward-looking formula transmission rate to recover and earn a return on transmission assets effective January 1, 2017. Following various protests to the proposed formula transmission rate, on March 10, 2017, FERC issued an order accepting the JCP&L formula transmission rate for filing, suspending the transmission rate for five months to become effective June 1, 2017, and establishing hearing and settlement judge procedures. On February 20, 2018, FERC issued an order accepting a settlement agreement filed by JCP&L and certain parties, with an effective date of June 1, 2017. The settlement agreement provides for a $135 million stated annual revenue requirement for Network Integration Transmission Service and an average of $20 million stated annual revenue requirement for certain projects listed on the PJM Tariff where the costs are allocated in part beyond the JCP&L transmission zone within the PJM Region. The revenue requirements are subject to a moratorium on additional revenue requirements proceedings through December 31, 2019, other than limited filings to seek recovery for certain additional costs. Refunds for the difference between the filed rate and the settlement rate were paid out ratably in 2018.

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 their stated transmission rates 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 reduced the stated rate by 6.70%. FERC issued an order on November 15, 2018, accepting the revisions without modifications or conditions.

Also, on March 15, 2018, FERC issued a Notice of Inquiry seeking information regarding whether and how FERC should address possible changes to ADIT and bonus depreciation as a result of the Tax Act. Such possible changes could impact FERC-jurisdictional rates, including transmission rates. On November 15, 2018, FERC issued a NOPR suggesting mechanisms to revise transmission rates to address the 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 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 affiliated transmission owners, supported comments submitted by Edison Electric Institute requesting additional clarification on the ratemaking and 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 to FERC for further review. On October 16, 2018, FERC issued its order on remand, in which it proposed a revised ROE methodology. Specifically, in complaint proceedings alleging that an existing ROE is not just and 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 identity a range of just and reasonable ROEs. FERC then will utilize the transmission utility’s risk relative to other utilities within that zone of reasonableness to assign the 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 ROE falls outside the quartile, FERC would deem the existing ROE presumptively unjust and unreasonable and 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 four financial models. FERC established a paper hearing on how the new methodology should apply to the remanded proceedings. FirstEnergy is monitoring the proceedings.

ENVIRONMENTAL MATTERS

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

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

Clean Air Act

FirstEnergy complies with SO2 and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls 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 bid for a lengthy pause in the litigation and set a briefing schedule. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the EPA and the states ultimately implement CSAPR, the future cost of compliance may be material and changes to FirstEnergy's operations may result.

The EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of 75 PPB to 70 PPB on October 1, 2015. The EPA stated the vast majority of U.S. counties will meet the new 70 PPB standard by 2025 due to other federal and state rules and programs but on April 30, 2018, the EPA designated fifty-one areas in twenty-two states as non-attainment; however, FirstEnergy has no power plants operating in those areas. States have roughly three years to develop implementation plans to attain 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. In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating facility's NOx emissions significantly contribute to Delaware's inability to attain the ozone NAAQS. The petition 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 inability to attain the ozone NAAQS. The petition sought NOx emission rate limits for the 36 EGUs by May 1, 2017. On September 14, 2018, the EPA denied both the States of Delaware and Maryland 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 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, but has not taken any further action. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss.

On May 1, 2017, FE and FG, and CSX and BNSF entered into a definitive settlement agreement, which resolved all claims related to a coal transportation contract dispute as a result of MATS. Pursuant to the settlement agreement, FG agreed to pay CSX and BNSF an aggregate amount equal to $109 million, payable in three annual installments, the first of which was made on May 1, 2017. FE agreed to unconditionally and continually guarantee the settlement payments due by FG pursuant to the terms of the settlement agreement. The settlement agreement further provided that in the event of the initiation of bankruptcy proceedings or failure to make timely settlement payments, the unpaid settlement amount will immediately accelerate and become due and payable in full. On April 6, 2018, FE paid the remaining $72 million under the settlement agreement as a result of the FES Bankruptcy.

As to a specific coal supply agreement, AE Supply, the party thereto, asserted termination rights effective in 2015 as a result of MATS. In response to notification of the termination, on January 15, 2015, Tunnel Ridge, LLC, the coal supplier, commenced litigation in the Court of Common Pleas of Allegheny County, Pennsylvania, alleging AE Supply did not have sufficient justification to terminate the agreement and seeking damages for the difference between the market and contract price of the coal, or lost profits plus incidental damages. On February 18, 2018, the parties reached an agreement in principle settling all claims in dispute. The agreement in principle includes, among other matters, a $93 million payment by AE Supply, as well as certain coal supply commitments for Pleasants Power Station during its remaining operation by AE Supply. Certain aspects of the final settlement agreement are guaranteed by FE, including the $93 million payment, which was paid in the first quarter of 2018. The parties executed the final settlement agreement on March 9, 2018, and the plaintiff dismissed the matter with prejudice on March 15, 2018.

Climate Change

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

The EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act,” 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. The EPA released its final CPP regulations in August 2015 to reduce CO2 emissions from existing fossil fuel-fired EGUs and also 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 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 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 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 October 16, 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 September 2016, joined in adopting the agreement reached on December 12, 2015, at the United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement was ratified by the requisite number of countries (i.e., at least 55 countries representing at least 55% of global GHG emissions) in October 2016 and its non-binding obligations to limit global warming to well below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.

Clean Water Act

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

The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. 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. On April 13, 2017, the EPA granted a Petition for Reconsideration and administratively stayed all deadlines in the effluent limits rule pending a new rulemaking. On September 18, 2017, the EPA replaced the administrative stay with a rulemaking which postponed only 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 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. 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 evaluation of the need for future regulation.

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. 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.

Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit for the Little Blue Run CCR impoundment requiring the Bruce Mansfield plant to cease disposal of CCRs by December 31, 2016, and FG to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizing FG to seek a permit modification based on "unexpected site conditions that have or will slow closure progress." The permit does not require active dewatering of the CCRs, but does require a groundwater assessment for arsenic and abatement if certain conditions in the permit are met. The CCRs from the Bruce Mansfield plant are being beneficially reused with the majority used for reclamation of a site owned by the Marshall County Coal Company in Moundsville, West Virginia, and the remainder recycled into drywall by National Gypsum. These beneficial reuse options are expected to be sufficient for ongoing plant operations, however, the Bruce Mansfield plant is pursuing other options. On May 22, 2015 and September 21, 2015, the PA DEP reissued a permit for the Hatfield's Ferry CCR disposal facility and then modified that permit to allow disposal of Bruce Mansfield plant CCR. The Sierra Club's Notices of Appeal before the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit for the Hatfield’s Ferry CCR disposal facility were resolved through a Consent Adjudication between FG, PA DEP and the Sierra Club requiring operational changes that became effective November 3, 2017. As noted above, FE provides credit support for FG surety bonds of $169 million and $31 million for the benefit of the PA DEP with respect to LBR and the Hatfield's Ferry disposal site, respectively.

FirstEnergy or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often

unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of December 31, 2018, based on estimates of the total costs of cleanup, FirstEnergy's proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $121 million have been accrued through December 31, 2018, including approximately $85 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. 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 December 31, 2018, JCP&L, ME and PN had in total approximately $790 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 to 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 Operations," for additional information.

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against 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 16, "Regulatory Matters," of the Notes to Consolidated Financial Statements.

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 or its subsidiaries' financial condition, results of operations and cash flows.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

FirstEnergy prepares consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. FirstEnergy's accounting policies require significant judgment regarding estimates and assumptions underlying the amounts included in the financial statements. Additional information regarding the application of accounting policies is included in the Notes to Consolidated Financial Statements.

Revenue Recognition

FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled sales is recognized. The determination of unbilled sales and revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, applicable billing demands, weather-related impacts, number of days unbilled and tariff rates in effect within each customer class. In connection with adopting the new revenue recognition guidance in 2018, FirstEnergy has elected the optional invoice practical expedient for most of its revenues and, with the exception of JCP&L transmission revenues, 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. See Note 2, "Revenue," for additional information.

Regulatory Accounting

FirstEnergy’s Regulated Distribution and Regulated Transmission segments are subject to regulations that set the prices (rates) the Utilities, AGC, and the Transmission Companies are permitted to charge customers based on costs that the regulatory agencies

determine are permitted to be recovered. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows. Certain regulatory assets are recorded based on prior precedent or anticipated recovery based on rate making premises without a specific rate order. FirstEnergy regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. See Note 16, "Regulatory Matters," for additional information.

FirstEnergy reviews the probability of recovery of regulatory assets at each balance sheet date and whenever new events occur. Similarly, FirstEnergy records regulatory liabilities when a determination is made that a refund is probable or when ordered by a commission. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. If recovery of a regulatory asset is no longer probable, FirstEnergy will write off that regulatory asset as a charge against earnings. FirstEnergy considers the entire regulatory asset balance as the unit of account for the purposes of balance sheet classification rather than the next years recovery and as such net regulatory assets and liabilities are presented in the non-current section on the FirstEnergy Consolidated Balance Sheets.

Pension and OPEB Accounting

FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels.

FirstEnergy provides some non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits and/or subsidies to purchase health insurance, which include certain employee contributions, deductibles and co-payments, may also be available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

FirstEnergy recognizes a pension and OPEB mark-to-market adjustment for the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. The remaining components of pension and OPEB expense, primarily service costs, interest on obligations, assumed return on assets and prior service costs, are recorded on a monthly basis. The pre-tax pension and OPEB mark-to-market adjustment charged to earnings for the years ended December 31, 2018, 2017, and 2016, were $145 million, $141 million, and $147 million, respectively, of these amounts, approximately $1 million, $39 million, and $45 million are included in discontinued operations.

In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and OPEB obligations. The assumed discount rates for pension were 4.44%, 3.75% and 4.25% as of December 31, 2018, 2017 and 2016, respectively. The assumed discount rates for OPEB were 4.30%, 3.50% and 4.00% as of December 31, 2018, 2017 and 2016, respectively.

Effective in 2019, FirstEnergy changed the approach utilized to estimate the service cost and interest cost components of net periodic benefit cost for pension and OPEB plans. Historically, FirstEnergy estimated these components utilizing a single, weighted average discount rate derived from the yield curve used to measure the benefit obligation. FirstEnergy has elected to use a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the relevant projected cash flows, as this provides a better estimate of service and interest costs by improving the correlation between projected benefit cash flows to the corresponding spot yield curve rates. This change did not affect the measurement of total benefit obligations or annual net period benefit cost and the change in service and interest cost is offset in the actuarial mark-to-market adjustment reported. This election is considered a change in estimate and, accordingly, accounted prospectively.

FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the pension trusts. In 2018, FirstEnergy’s qualified pension and OPEB plan assets experienced losses of $371 million or (4.0)%, compared to gains of $999 million, or 15.1% in 2017, and losses of $472 million, or 8.2% in 2016 and assumed a 7.50% rate of return on plan assets in 2018, 2017 and 2016, which generated $605 million, $478 million and $429 million of expected returns on plan assets, respectively. The expected return on pension and OPEB assets is based on the trusts’ asset allocation targets and the historical performance of risk-based and fixed income securities. The gains or losses generated as a result of the difference between expected and actual returns on plan assets will increase or decrease future net periodic pension and OPEB cost as the difference is recognized annually in the fourth quarter of each fiscal year or whenever a plan is determined to qualify for remeasurement. The expected return on plan assets for 2019 is 7.50%.

During 2018, the Society of Actuaries released its updated mortality improvement scale for pension plans, MP-2018, incorporating SSA mortality data from 2014-2016. The updated improvement scale indicates a slight decline in life expectancy. Due to the additional data on population mortality, the RP2014 mortality table with the projection scale MP-2018 was utilized to determine the 2018 benefit cost and obligation as of December 31, 2018, for the FirstEnergy pension and OPEB plans. The impact of using the projection scale MP-2018 resulted in a decrease in the projected pension benefit obligation of approximately $16 million and was included in the 2018 pension and OPEB mark-to-market adjustment.

Based on discount rates of 4.44% for pension, 4.30% for OPEB and an estimated return on assets of 7.50%, FirstEnergy expects its 2019 pre-tax net periodic benefit credit to be approximately $28 million (excluding any actuarial mark-to-market adjustments that would be recognized in 2019). The following table reflects the portion of pension and OPEB costs that were charged to expense, including any pension and OPEB mark-to-market adjustments, in the three years ended December 31, 2018, 2017, and 2016:

Postemployment Benefits Expense (Credits)		2018				2017				2016
		(In millions)
Pension		$	200			$	247			$	277
OPEB		(158		)		(45		)		(40		)
Total		$	42			$	202			$	237

Health care cost trends continue to increase and will affect future OPEB costs. The composite health care trend rate assumptions were approximately 6.0-5.5% in 2018 and 2017, gradually decreasing to 4.5% in later years. In determining FirstEnergy’s trend rate assumptions, included are the specific provisions of FirstEnergy’s health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in FirstEnergy’s health care plans, and projections of future medical trend rates. The effects on 2019 pension and OPEB net periodic benefit costs from changes in key assumptions are as follows:

Increase in Net Periodic Benefit Costs from Adverse Changes in Key Assumptions

Assumption		Adverse Change		Pension				OPEB				Total
				(In millions)
Discount rate		Decrease by 0.25%		$	288			$	15			$	303
Long-term return on assets		Decrease by 0.25%		$	18			$	1			$	19
Health care trend rate		Increase by 1.0%		N/A				$	22			$	22

See Note 5, "Pension and Other Postemployment Benefits," for additional information.

Long-Lived Assets

FirstEnergy evaluates long-lived assets classified as held and used for impairment when events or changes in circumstances indicate the carrying value of the long-lived assets may not be recoverable. First, the estimated undiscounted future cash flows attributable to the assets is compared with the carrying value of the assets. If the carrying value is greater than the undiscounted future cash flows, an impairment charge is recognized equal to the amount the carrying value of the assets exceeds its estimated fair value. See Note 1, "Organization and Basis of Presentation."

See Note 1, "Organization and Basis of Presentation - Asset impairments," for impairments recognized in 2018, 2017 and 2016.

Asset Retirement Obligations

FE recognizes an ARO for the future decommissioning of its nuclear power plant and future remediation of other environmental liabilities associated with all of its long-lived assets. The ARO liability represents an estimate of the fair value of FirstEnergy's current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. 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 associated asset and/or regulatory requirements. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset. In certain circumstances, FirstEnergy has recovery of asset retirement costs and, as such, certain accretion and depreciation is offset against regulatory assets.

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. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not the timing of the liability recognition.

AROs as of December 31, 2018, are described further in Note 15, "Asset Retirement Obligations."

Income Taxes

FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the

recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled.

FirstEnergy accounts for uncertainty in income taxes in its financial statements using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. FirstEnergy recognizes interest expense or income related to uncertain tax positions by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken, or expected to be taken, on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. See Note 7, "Taxes," for additional information.

On December 22, 2017, the President signed into law the Tax Act, which included significant changes to the Internal Revenue Code of 1986 (as amended, the Code). The more significant changes that impacted FirstEnergy were as follows:

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

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

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

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

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

At December 31, 2017, FirstEnergy completed its assessment of the accounting for certain effects of the provisions in the Tax Act, and as allowed under SEC Staff Accounting Bulletin 118 (SAB 118), recorded provisional income tax amounts related to depreciation for which the impacts of the Tax Act could not be finalized, but for which a reasonable estimate could be determined. Under the Tax Act, qualified property acquired and placed into service after September 27, 2017 would be eligible for full expensing for all taxpayers other than regulated utilities. On August 3, 2018, the IRS released proposed regulations clarifying the immediate expensing of qualified property, specifically addressing that regulated utility property acquired after September 27, 2017, and placed into service by December 31, 2017, qualifies for full expensing. While not final as of December 31, 2018, corporate taxpayers may rely on the proposed regulations for tax years ending after September 27, 2017. As of December 31, 2018, FirstEnergy has now completed its accounting for all of the enactment-date income tax effects of the Tax Act, resulting in an immaterial adjustment to the provisional income tax amounts recorded at December 31, 2017.

The Tax Act also amended Section 163(j) of the Code, limiting interest expense deductions for corporations, with exemption for certain regulated utilities. On November 26, 2018, the IRS issued proposed regulations implementing Section 163(j), including its application of the rules to consolidated groups with both regulated utility and non-regulated members. Based on its interpretation of these proposed regulations, FirstEnergy has estimated the amount of deductible interest for its consolidated group in 2018 and has recorded a deferred tax asset on the nondeductible portion as it is carried forward with an indefinite life. The deferred tax asset related to the indefinite lived carryforward of nondeductible interest has a full valuation allowance ($60 million) recorded against it as future profitability from sources other than regulated utility businesses is required for utilization. Of this tax effected nondeductible interest, $27 million has been reflected as an uncertain tax position. All tax expense related to nondeductible interest in 2018 has been recorded in discontinued operations as it is entirely attributed to the anticipated inclusion of entities reported in discontinued operations in FirstEnergy's consolidated federal tax return.

Goodwill

In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise. In evaluating goodwill for impairment, FirstEnergy assesses qualitative factors to determine whether it is more likely than not (that is, likelihood of more than 50%) that the fair value of a reporting unit is less than its carrying value (including goodwill). If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then no further testing is required. However, if FirstEnergy concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying value or bypasses the qualitative assessment, then the quantitative goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized, if any.

As of July 31, 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 values of these reporting units were, more likely than not, greater than their carrying values and a quantitative analysis was not necessary.

See Note 3, "Discontinued Operations", for further discussion of CES' goodwill impairment charges recognized in 2016.

NEW ACCOUNTING PRONOUNCEMENTS

ASU 2014-09, "Revenue from Contracts with Customers" (Issued May 2014 and subsequently updated to address implementation questions): The new revenue recognition guidance establishes a new control-based revenue recognition model, changes the basis for deciding when revenue is recognized over time or at a point in time, provides new and more detailed guidance on specific topics and expands and improves disclosures about revenue. FirstEnergy evaluated its revenues and determined the new guidance had immaterial impacts to recognition practices upon adoption on January 1, 2018. As part 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 timing or amount of revenue. In addition, upon adoption, certain immaterial financial statement presentation changes were implemented. See Note 2, "Revenue," for additional information on FirstEnergy's revenues.

ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities" (Issued January 2016 and subsequently updated in 2018): ASU 2016-01 primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. FirstEnergy adopted this standard on January 1, 2018, and recognizes all gains and losses for equity securities in income with the exception of those that are accounted for under the equity method of accounting. The NDT equity portfolios of JCP&L, ME and PN will not be impacted as unrealized gains and losses will continue to be offset against regulatory assets or liabilities. As a result of adopting this standard, FirstEnergy recorded a cumulative effect adjustment to retained earnings of $57 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 gains and losses on 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 $27 million and $6 million of non-service costs from Other operating expenses to Miscellaneous income, net, for the years ended December 31, 2017 and December 31, 2016, 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, "Taxes," for additional information on FirstEnergy's accounting for the Tax Act.

ASU 2018-13, "Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement" (Issued August 2018): ASU 2018-13 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. Entities are permitted to early adopt either the entire standard or only the provisions that eliminate or modify the requirements. FirstEnergy early adopted all the provisions of this standard as of December 31, 2018 which are reflected in Note 11, "Fair Value Measurements".

ASU 2018-14, "Compensation-Retirement Benefits-Defined Benefit Plans-General (Subtopic 715-20): Disclosure Framework-Changes 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. FirstEnergy early adopted ASU 2018-14 as of December 31, 2018 and the provisions of this standard are reflected within Note 5, "Pension and Other Postemployment Benefits".

Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB was not adopted in 2018. 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 and has not included these standards based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting.

ASU 2016-02, "Leases (Topic 842)" (Issued February 2016 and subsequently updated to address implementation questions): The new guidance will require organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets as well as new qualitative and quantitative disclosures. FirstEnergy has implemented 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. FirstEnergy elected all of these practical expedients. Upon adoption, on January 1, 2019, FirstEnergy increased assets and liabilities by approximately $190 million, with no impact to results of operations or cash flows.

ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (issued June 2016 and subsequently updated): ASU 2016-13 removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted for fiscal years beginning after December 15, 2018.

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.