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

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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, including, without limitation, mitigating exposure for remedial activities associated with formerly owned generation assets.


•	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, and to improve our credit metrics, strengthen our balance sheet and grow earnings.


•	Legislative and regulatory developments, 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 climate change or 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, which 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 reliability standards and energy efficiency and peak demand reduction mandates.


•	Changes to 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 contributions sooner, or in amounts that are larger, than currently anticipated.


•	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 or FENOC or their creditors.

•

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 or FENOC or their creditors.


•	The risks associated with the decommissioning of our retired and former nuclear facilities.


•	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, 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, including the increasing number of financial institutions evaluating the impact of climate change on their investment decisions.


•	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 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 or in the information incorporated by reference 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, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The segment's 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, 2019, are summarized below (in thousands):



Company	Area Served	Customers Served
OE	Central and Northeastern Ohio	1,055
Penn	Western Pennsylvania	168
CEI	Northeastern Ohio	752
TE	Northwestern Ohio	313
JCP&L	Northern, Western and East Central New Jersey	1,142
ME	Eastern Pennsylvania	575
PN	Western Pennsylvania and Western New York	587
WP	Southwest, South Central and Northern Pennsylvania	729
MP	Northern, Central and Southeastern West Virginia	392
PE	Western Maryland and Eastern West Virginia	419
		6,132

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. Effective January 1, 2020, JPC&L's transmission rates became forward-looking formula rates, subject to refund, pending further hearing and settlement proceedings. 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.

Corporate/Other 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, 2019, 67 MWs of electric generating capacity, representing AE Supply's OVEC capacity entitlement, was included in continuing operations of Corporate/Other. As of December 31, 2019, Corporate/Other had approximately $7.1 billion of FE holding company debt.

EXECUTIVE SUMMARY

FirstEnergy is a forward-thinking fully regulated electric utility focused on stable and predictable earnings and cash flow from its regulated business units - Regulated Distribution and Regulated Transmission - through delivering enhanced customer service and reliability that supports FE's dividend.

In 2019, FirstEnergy continued its significant progress of executing on its regulated growth plans, which included the following achievements:


•	MDPSC-approved distribution base rate increase,


•	MDPSC-approved EDIS programs,


•	NJ BPU-approved JCP&L IIP settlement,


•	PUCO-approved Ohio Grid Modernization plan and Tax Reform settlement,


•	PUCO-approved Ohio Companies’ decoupling application,


•	WVPSC-approved ENEC rates that began January 1, 2020,


•	Filed for forward-looking formula rates for JCP&L’s transmission assets,


•	Pennsylvania Companies filed LTIIP II plans for 2020-2024, including a DSIC cap increase at Penn to 7.5%, approved in January 2020,


•	Signed an agreement to transfer TMI-2 to a subsidiary of EnergySolutions, LLC,


•	Received credit ratings upgrades from Fitch Ratings at FE and all rated Utility and Transmission subsidiaries,


•	Received credit ratings upgrades from Moody's at ATSI, CEI, JCP&L, MAIT, OE, Penn and TE,


•	Announced that the FE Board of Directors approved a 3% increase to the dividend payable March 1, 2020, and


•	Published a Strategic Plan and a Corporate Responsibility Report as part of our forward-thinking strategy and commitment to ESG issues.

With an operating territory of 65,000 square miles, the scale and diversity of the ten Utilities that comprise the Regulated Distribution business uniquely position this business for growth through opportunities for additional investment. Over the past several years, Regulated Distribution has experienced rate base growth through investments that have improved reliability and added operating flexibility to the distribution infrastructure, which provide benefits to the customers and communities those Utilities serve. Based on its current capital plan, which includes over $10 billion in forecasted capital investments from 2018 through 2023, Regulated Distribution’s rate base compounded annual growth rate is expected to be approximately 4% from 2018 through 2023. Additionally, this business is exploring other opportunities for growth, including investments in electric system improvement and modernization projects to increase reliability and improve service to customers, as well as exploring opportunities in customer engagement that focus on the electrification of customers’ homes and businesses by providing a full range of products and services.

With approximately 24,500 miles of transmission lines in operation, the Regulated Transmission business is the centerpiece of FirstEnergy’s regulated investment strategy with nearly 90% of its capital investments recovered under forward-looking formula rates at the Transmission Companies, and beginning in 2020, JCP&L. Regulated Transmission has also experienced significant growth as part of its Energizing the Future transmission plan with plans to invest over $7 billion in capital from 2018 to 2023, which is expected to result in Regulated Transmission rate base compounded annual growth rate of approximately 10% from 2018 through 2023.

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

FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of over $20 billion beyond those identified through 2023, 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 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. In November 2019, the Board declared a $0.01 increase to the common dividend payable March 1, 2020, to $0.39 per share, which represents a 3% increase. 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 progressing in its sustainability efforts. In 2019, FirstEnergy's Sustainability group focused on the continued realization of sustainability accomplishments. In November 2019, FirstEnergy's Corporate Responsibility Report was published. The report addresses FirstEnergy's work to reduce the environmental impact of our operations, including progress on our CO2 reduction goal, as we continue to build, strengthen and modernize our transmission and distribution system. The report also describes FirstEnergy's high standards for corporate governance and our work to improve lives in our communities, while providing safe, reliable electric service to our customers. In 2020, FirstEnergy is focusing on additional initiatives that aim to inform, engage and achieve its sustainability goals, and demonstrate its commitment to stakeholders.

As previously disclosed, on January 22, 2018, FirstEnergy announced a $2.5 billion equity issuance, which included $1.62 billion in mandatorily convertible preferred equity with an initial conversion price of $27.42 per share and $850 million of common equity issued at $28.22 per share. The equity investment strengthened the Company’s balance sheet, supported the company’s transition to a fully regulated utility company and positions FirstEnergy for sustained investment-grade credit metrics. The shares of preferred stock participated in the dividend paid on common stock on an as-converted basis and were non-voting except in certain limited circumstances. Because of this investment, FirstEnergy does not currently anticipate the need to issue additional equity through 2021 and expects to issue, subject to, among other things, market conditions, pricing terms and business operations, up to $600 million of equity annually in 2022 and 2023, including approximately $100 million in equity for its regular stock investment and employee benefit plans. As of August 1, 2019, an aggregate of 1,616,000 shares of preferred stock had been converted into 58,935,078 shares of common stock, and as a result, there were no shares of preferred stock outstanding as of December 31, 2019.

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

On April 23, 2018, FirstEnergy and the FES Key Creditor Groups reached an agreement in principle to resolve certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and their creditors against FirstEnergy. 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 the FES Key Creditor Groups against FirstEnergy. See below for further discussion on the terms of the settlement agreement.

The FES Bankruptcy settlement agreement remains subject to satisfaction of certain conditions. There can be no assurance that such conditions will be satisfied or the FES Bankruptcy settlement agreement will be otherwise consummated, and the actual outcome of this matter may differ materially from the terms of the agreement described herein. FirstEnergy will continue to evaluate the impact of any new factors on the settlement and their relative impact on the financial statements.

With the bankruptcy filings of the FES Debtors, the completed sale of the previously announced competitive Bath hydroelectric station, and the completed transfer of the Pleasants Power Station, FirstEnergy’s electric generation fleet is now made up of 3,790 MW of regulated generation, including four plants in West Virginia, Virginia and New Jersey.

The Form 10-K discusses 2019 and 2018 items and year-over-year comparisons between 2019 and 2018. Discussions of 2017 items and year-over-year comparisons between 2018 and 2017 that are not included in this Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018, filed with the SEC on February 19, 2019.

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 17, "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:



(In millions, except per share amounts)	For the Years Ended December 31,									Increase (Decrease)
	2019			2018			2017			2019 vs 2018			2018 vs 2017
Net Income (Loss) By Business Segment:
Regulated Distribution	$	1,076		$	1,242		$	916		$	(166	)	$	326
Regulated Transmission	447			397			336			50			61
Corporate/Other	(619		)	(617		)	(1,541		)	(2		)	924
Income (Loss) from Continuing Operations	$	904		$	1,022		$	(289	)	$	(118	)	$	1,311

Discontinued Operations	8			326			(1,435		)	(318		)	1,761
Net Income (Loss)	$	912		$	1,348		$	(1,724	)	$	(436	)	$	3,072

Earnings (Loss) per share of common stock
Basic - Continuing Operations	$	1.69		$	1.33		$	(0.65	)	$	0.36		$	1.98
Basic - Discontinued Operations	0.01			0.66			(3.23		)	(0.65		)	3.89
Basic - Net Income (Loss) Attributable to	$	1.70		$	1.99		$	(3.88	)	$	(0.29	)	$	5.87
Common Stockholders

Earnings (Loss) per share of common stock
Diluted - Continuing Operations	$	1.67		$	1.33		$	(0.65	)	$	0.34		$	1.98
Diluted - Discontinued Operations	0.01			0.66			(3.23		)	(0.65		)	3.89
Diluted - Net Income (Loss) Attributable to	$	1.68		$	1.99		$	(3.88	)	$	(0.31	)	$	5.87
Common Stockholders

Summary of Results of Operations — 2019 Compared with 2018

Financial results for FirstEnergy’s business segments for the years ended December 31, 2019 and 2018, were as follows:



2019 Financial Results	Regulated Distribution			Regulated Transmission			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
Electric	$	9,452		$	1,510		$	(128	)	$	10,834
Other	246			16			(61		)	201
Total Revenues	9,698			1,526			(189		)	11,035

Operating Expenses:
Fuel	497			—			—			497
Purchased power	2,910			—			17			2,927
Other operating expenses	2,836			272			(156		)	2,952
Provision for depreciation	863			284			73			1,220
Amortization (deferral) of regulatory assets, net	(89		)	10			—			(79		)
General taxes	760			209			39			1,008
Total Operating Expenses	7,777			775			(27		)	8,525

Operating Income (Loss)	1,921			751			(162		)	2,510

Other Income (Expense):
Miscellaneous income, net	174			15			54			243
Pension and OPEB mark-to-market adjustment	(290		)	(47		)	(337		)	(674		)
Interest expense	(495		)	(192		)	(346		)	(1,033		)
Capitalized financing costs	37			33			1			71
Total Other Expense	(574		)	(191		)	(628		)	(1,393		)

Income (Loss) Before Income Taxes (Benefits)	1,347			560			(790		)	1,117
Income taxes (benefits)	271			113			(171		)	213
Income (Loss) From Continuing Operations	1,076			447			(619		)	904
Discontinued Operations, net of tax	—			—			8			8
Net Income (Loss)	$	1,076		$	447		$	(611	)	$	912



2018 Financial Results	Regulated Distribution			Regulated Transmission			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
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 (benefits)	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



Changes Between 2019 and 2018 Financial Results Increase (Decrease)	Regulated Distribution			Regulated Transmission			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
Electric	$	(399	)	$	175		$	8		$	(216	)
Other	(6		)	(2		)	(2		)	(10		)
Total Revenues	(405		)	173			6			(226		)

Operating Expenses:
Fuel	(41		)	—			—			(41		)
Purchased power	(193		)	—			11			(182		)
Other operating expenses	(148		)	19			(52		)	(181		)
Provision for depreciation	51			32			1			84
Amortization (deferral) of regulatory assets, net	74			(3		)	—			71
General taxes	—			17			(2		)	15
Total Operating Expenses	(257		)	65			(42		)	(234		)

Operating Income (Loss)	(148		)	108			48			8

Other Income (Expense):
Miscellaneous income (expense), net	(18		)	1			55			38
Pension and OPEB mark-to-market adjustment	(181		)	(39		)	(310		)	(530		)
Interest expense	19			(25		)	89			83
Capitalized financing costs	11			(4		)	(1		)	6
Total Other Expense	(169		)	(67		)	(167		)	(403		)

Income (Loss) Before Income Taxes (Benefits)	(317		)	41			(119		)	(395		)
Income taxes (benefits)	(151		)	(9		)	(117		)	(277		)
Income (Loss) From Continuing Operations	(166		)	50			(2		)	(118		)
Discontinued Operations, net of tax	—			—			(318		)	(318		)
Net Income (Loss)	$	(166	)	$	50		$	(320	)	$	(436	)

Regulated Distribution — 2019 Compared with 2018

Regulated Distribution's net income decreased $166 million in 2019, as compared to 2018, primarily resulting from the SCOH ruling that ceased collection of Rider DMR, a higher pension and OPEB mark-to-market adjustment, the absence of the reversal of a reserve on recoverability of certain REC purchases in Ohio, and lower revenues associated with decreased weather-related usage.

Revenues —

The $405 million decrease in total revenues resulted from the following sources:



	For the Years Ended December 31,
Revenues by Type of Service	2019		2018		Decrease
	(In millions)
Distribution services (1)	$	5,314	$	5,413	$	(99	)

Generation sales:
Retail	3,727		3,936		(209		)
Wholesale	411		502		(91		)
Total generation sales	4,138		4,438		(300		)

Other	246		252		(6		)
Total Revenues	$	9,698	$	10,103	$	(405	)

(1) Includes $181 million and $254 million of ARP revenues for the years ended December 31, 2019 and 2018, respectively.

Distribution services revenues decreased $99 million in 2019, as compared to 2018, primarily resulting from the SCOH ruling that ceased collection of Rider DMR, lower weather-related customer usage, and the implementation of rate orders and settlements related to the Tax Act, partially offset by implementation of NJ Zero Emission Program in June 2019 and higher rates associated with the recovery of deferred costs. Distribution deliveries by customer class are summarized in the following table:



	For the Years Ended December 31,
Electric Distribution MWH Deliveries	2019	2018	Decrease
	(In thousands)
Residential	54,159	55,994	(3.3	)%
Commercial	37,330	38,605	(3.3	)%
Industrial	55,649	56,611	(1.7	)%
Other	558	560	(0.4	)%
Total Electric Distribution MWH Deliveries	147,696	151,770	(2.7	)%

Lower distribution deliveries to residential and commercial customers primarily reflect lower weather-related usage resulting from cooling degree days that were 16% below 2018, but 16% above normal, as well as, heating degree days that were 5% below 2018, and 4% below normal. Deliveries to industrial customers reflect lower steel and automotive customer usage, partially offset by higher shale customer usage.

The following table summarizes the price and volume factors contributing to the $300 million decrease in generation revenues in 2019, as compared to 2018:



Source of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of decrease in sales volumes	$	(2	)
Change in prices	(207		)
	(209		)
Wholesale:
Effect of increase in sales volumes	2
Change in prices	(51		)
Capacity revenue	(42		)
	(91		)
Decrease in Generation Revenues	$	(300	)

Total generation provided by alternative suppliers as a percentage of total MWH deliveries was flat. The decrease in retail generation prices primarily resulted from lower non-shopping generation auction rates across all service territories and a lower ENEC rate in West Virginia, which included rate reductions resulting from the Tax Act.

Wholesale generation revenues decreased $91 million in 2019, as compared to 2018, primarily due to lower spot market energy prices and capacity revenue. 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 decreased $257 million primarily due to the following:


•	Fuel expense decreased $41 million in 2019, as compared to 2018, primarily due to lower unit costs.


•	Purchased power costs decreased $193 million in 2019, as compared to 2018, primarily due to lower unit costs and capacity expense, partially offset by the implementation of the NJ Zero Emission Program in June 2019.



Source of Change in Purchased Power	Increase (Decrease)

	(In millions)
Purchases from non-affiliates:
Change due to decreased unit costs	$	(82	)
Change due to increased volumes	89
	7
Purchases from affiliates:
Change due to decreased unit costs	(9		)
Change due to decreased volumes	(138		)
	(147		)
Capacity expense	(53		)
Decrease in Purchased Power Costs	$	(193	)


•	Other operating expenses decreased $148 million primarily due to:


•	Decreased storm restoration costs of $129 million, which were mostly deferred for future recovery, resulting in no material impact on current period earnings.


•	Lower operating and maintenance expenses of $49 million, primarily associated with lower employee benefits and corporate support costs.


•	Decreased expenses due to transactions now accounted for as finance leases of $21 million. As a result of the adoption of the new lease accounting standard, financing lease expenses that were recognized in other operating expenses are now recognized in depreciation and interest expense.


•	The absence of $30 million in costs that occurred in 2018 associated with the voluntary enhanced retirement program.


•	Lower energy efficiency and other program costs of $27 million, partially offset by higher vegetation management spend of $13 million. These costs are deferred for future recovery, resulting in no material impact on current period earnings.

•

Higher network transmission expenses of $95 million reflecting increased transmission costs as well as the absence of the FERC settlement during 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 recognized in 2018, 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.


•	Depreciation expense increased $51 million, primarily due to a higher asset base and transactions now accounted for as finance leases, as discussed above.

•

Net amortization expense increased $74 million, primarily due to decreased storm restoration cost deferrals, the absence of the reversal of a liability at the Ohio Companies for an Ohio Supreme Court ruling regarding the purchase of RECs, partially offset by higher deferrals of generation and transmission expenses, including the FERC settlement discussed above and the termination of the Morgantown Energy Associates PPA.

Other Expense —

Total other expense increased $169 million, primarily due to an increase in the 2019 pension and OPEB mark-to-market adjustment, higher net pension and OPEB non-service costs, and transactions now accounted for as finance leases, as discussed above. This was partially offset by lower interest expense resulting from activities related to debt maturities and refinancing and higher capitalized financing costs. The 2019 mark-to-market adjustment resulted from a decrease in the discount rate used to measure benefit obligations, partially offset by higher than expected asset returns.

Income Taxes

Regulated Distribution’s effective tax rate was 20.1% and 25.4% for 2019 and 2018, respectively. The lower effective tax rate in 2019 was primarily due the amortization of net excess deferred income taxes resulting from Tax Act settlements and orders with certain regulatory commissions.

Regulated Transmission — 2019 Compared with 2018

Regulated Transmission's operating results increased $50 million in 2019, as compared to 2018, primarily resulting from the impact of a higher rate base at ATSI and MAIT, partially offset by a lower rate base at TrAIL.

Revenues —

Total revenues increased $173 million in 2019, as compared to 2018, primarily due to higher rate base at ATSI and MAIT and the recovery of incremental expenses at the formula rate companies, 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,
Revenues by Transmission Asset Owner	2019		2018		Increase
	(In millions)
ATSI	$	758	$	668	$	90
TrAIL	251		246		5
MAIT	227		154		73
Other	290		285		5
Total Revenues	$	1,526	$	1,353	$	173

Operating Expenses —

Total operating expenses increased $65 million in 2019, as compared to 2018, 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 ATSI and MAIT, resulting in no material impact on current period earnings.

Other Expense —

Total other expense increased $67 million in 2019, as compared to 2018, primarily due to an increase in the 2019 pension and OPEB mark-to-market adjustment and higher interest expense associated with new debt issuances at ATSI, MAIT and FET. The 2019 mark-to-market adjustment resulted from a decrease in the discount rate used to measure benefit obligations partially offset by higher than expected asset returns.

Income Taxes —

Regulated Transmission’s effective tax rate was 20.2% and 23.5% for 2019 and 2018, respectively. The lower effective tax rate was primarily due to the amortization of net excess deferred income taxes resulting from FERC guidance related to the Tax Act.

Corporate/Other — 2019 Compared with 2018

Financial results from Corporate/Other and reconciling adjustments resulted in a $2 million decrease in income from continuing operations for 2019 compared to 2018, primarily due to a $310 million increase in the 2019 pension and OPEB mark-to-market adjustment. This was partially offset by lower income taxes from the absence of a $126 million charge in the first quarter of 2018 associated with the remeasurement of state deferred taxes in West Virginia when the FES Debtors were removed from the unitary group following their bankruptcy filing on March 31, 2018, lower interest expense of $89 million due to the absence of make-whole payments, and lower other operating expenses of $42 million primarily due to lower incurred corporate support costs in continuing operations related to the FES Debtors and the absence of remeasuring the ARO of McElroy’s Run. Although the operations of the FES Debtors for the first quarter of 2018 (prior to deconsolidation on March 31, 2018) are reflected as discontinued operations, certain allocated corporate support costs to the FES Debtors continue to be reflected in continuing operations. Additionally, higher net miscellaneous income was primarily due to higher returns on certain equity method investments and lower non-operating expenses.

For the years ended December 31, 2019 and 2018, FirstEnergy recorded income from discontinued operations, net of tax, of $8 million and $326 million, respectively. The change in discontinued operations, net of tax was primarily due to the absence of a $435 million gain on deconsolidation of FES and FENOC.

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.

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 2020 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 by FE and certain of its 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.

On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. FirstEnergy expects no required contributions through 2021.

Capital expenditures for 2018 and 2019 and forecasted expenditures for 2020, 2021, 2022, and 2023, by reportable segment are included below:



Reportable Segment	2018 Actual		2019 Actual		2020 Forecast		2021 Forecast		2022 Forecast		2023 Forecast
	(In millions)
Regulated Distribution	$	1,635	$	1,698	$	1,700	$	1,700	$	1,700	$	1,700
Regulated Transmission		1,165		1,189		1,200		1,200 - 1,450		1,200 - 1,450		1,200 - 1,450
Corporate/Other		183		105		90		110		110		110
Total	$	2,983	$	2,992	$	2,990	$	3,010 - 3,260	$	3,010 - 3,260	$	3,010 - 3,260

In alignment with FirstEnergy’s strategy to invest in its Regulated Transmission and Regulated Distribution segments as a fully regulated company, FirstEnergy is also focused on improving the balance sheet over time consistent with its business profile and maintaining investment grade ratings at its regulated businesses and FE. Specifically, at the regulated businesses, regulatory authority has been obtained for various regulated distribution and transmission subsidiaries to issue and/or refinance debt.

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.

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 the FES Key Creditor Groups against FirstEnergy, and includes the following terms, among others:


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

•

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 Railway Company/CSX Transportation, Inc. rail settlement guarantee, and the FES Debtors' unfunded pension obligations.


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


•	A $225 million cash payment from FirstEnergy.

•

An additional $628 million cash payment from FirstEnergy, 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. On November 21, 2019, FirstEnergy, the FES Debtors, the UCC, and the FES Key Creditors Group entered into an amendment to the settlement agreement, which among other things, changed the $628 million note issuance, into a cash payment to be made upon emergence. The amendment was approved by the Bankruptcy Court on December 16, 2019.

•

Transfer of the Pleasants Power Station and related assets, including the economic interests therein as of January 1, 2019, and a requirement that FE continues to provide access to the McElroy's Run CCR Impoundment Facility, which is not being transferred. In addition, FE provides guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. On January 21, 2020, AE Supply, FG and a newly formed subsidiary of FG, entered into a letter agreement authorizing the transfer of Pleasants Power Station prior to the FES Debtors’ emergence from bankruptcy. The letter agreement was approved by the Bankruptcy Court on January 28, 2020. The transfer of the Pleasants Power Station was completed on January 30, 2020.


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


•	Subject to a cap, FirstEnergy has agreed to fund a pension enhancement through its pension plan for voluntary enhanced retirement packages offered to certain FES employees, as well as offer certain other employee benefits (approximately $14 million recognized for the year ending December 31, 2019).

•

FirstEnergy agrees to perform under the Intercompany Tax Allocation Agreement through the FES Debtors’ emergence from bankruptcy, at which time FirstEnergy will waive a 2017 overpayment for NOLs of approximately $71 million, reverse 2018 estimated payments for NOLs of approximately $88 million and pay the FES Debtors for the use of NOLs in an amount no less than $66 million for 2018. Based on the 2018 federal tax return filed in September 2019, FirstEnergy owes the FES debtors approximately $31 million associated with 2018, which will be paid upon emergence. Based on current estimates for the 2019 tax return to be filed in 2020, FirstEnergy estimates that it owes the FES Debtors approximately $83 million of which FirstEnergy has paid $14 million as of December 31, 2019. The estimated amounts owed to the FES Debtors for 2018 and 2019 tax returns excludes amounts allocated for non-deductible interest as discussed in Note 3, "Discontinued Operations." FirstEnergy is currently reconciling tax matters under the Intercompany Tax Allocation Agreement with the FES Debtors.

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.

As of December 31, 2019, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was due in large part to short-term borrowings of $1.0 billion, accounts payable of $918 million, current payable long-term debt of $380 million, and other current liabilities of $1.4 billion primarily attributable to customer deposits and anticipated payments under the FES Bankruptcy settlement. Currently payable long-term debt as of December 31, 2019, consistent of the following:



Currently Payable Long-Term Debt	December 31, 2019
	(In millions)
Unsecured notes	$	250
Secured notes	50
Sinking fund requirements	64
Other notes	16
	$	380

FirstEnergy believes its cash from operations and available liquidity will be sufficient to meet its working capital needs.

Short-Term Borrowings / Revolving Credit Facilities

FE and the Utilities and FET and certain of its subsidiaries participate in two separate five-year syndicated revolving credit facilities providing for aggregate commitments of $3.5 billion, which are available until December 6, 2022. Under the FE credit 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 FET credit 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 FE's transmission subsidiaries.

Borrowings under the credit 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 each of the credit 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 credit facilities contains financial covenants requiring each borrower to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the credit facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter.

FirstEnergy had $1.0 billion and $1.25 billion of short-term borrowings as of December 31, 2019 and 2018, respectively. FirstEnergy’s available liquidity from external sources as of January 31, 2020, was as follows:



Borrower(s)	Type	Maturity	Commitment		Available Liquidity
			(In millions)
FirstEnergy(1)	Revolving	December 2022	$	2,500	$	2,496
FET(2)	Revolving	December 2022	1,000		1,000
		Subtotal	$	3,500	$	3,496
	Cash and cash equivalents		—		465
		Total	$	3,500	$	3,961


(1)	FE and the Utilities. Available liquidity includes impact of $4 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, 2020:



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.

$250 million of the FE Facility and $100 million of the FET Facility, subject to each borrower's sub-limit, is 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. 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, 2019, the borrowers were in compliance with the applicable debt-to-total-capitalization ratio 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 revolving credit facility described above, including a consolidated debt-to-total-capitalization ratio. Effective September 11, 2019, the two credit agreements noted above were amended to change the amounts available under the existing facilities from $1.25 billion and $500 million to $1 billion and $750 million, respectively, and extend the maturity dates until September 9, 2020, and September 11, 2021, respectively.

The borrowing of $1.75 billion under the 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.

A portion of FirstEnergy’s indebtedness bears interest at fluctuating interest rates, primarily based on LIBOR. LIBOR tends to fluctuate based on general interest rates, rates set by the U.S. Federal Reserve and other central banks, the supply of and demand for credit in the London interbank market and general economic conditions. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on LIBOR and other variable interest rates. On July 27, 2017, the Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is considering replacing U.S. dollar LIBOR with a newly created index, calculated based on repurchase agreements backed by treasury securities. It is not possible to predict the effect of these changes, other reforms or the establishment of alternative reference rates in the United Kingdom, the United States or elsewhere. To the extent these interest rates increase, interest expense will increase. If sources of capital for FirstEnergy are reduced, capital costs could increase materially. Restricted access to capital markets and/or increased borrowing costs could have an adverse effect on our results of operations, cash flows, financial condition and liquidity.

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 2019 was 2.27% per annum for the regulated companies’ money pool and 2.74% per annum for the unregulated companies’ money pool.

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 6, 2020:



	Corporate Credit Rating			Senior Secured			Senior Unsecured			Outlook (1)
Issuer	S&P	Moody’s	Fitch	S&P	Moody’s	Fitch	S&P	Moody’s	Fitch	S&P	Moody’s	Fitch
FE	BBB	Baa3	BBB	—	—	—	BBB-	Baa3	BBB	S	S	S
AGC	BBB-	Baa2	BBB	—	—	—	—	—	—	S	S	S
ATSI	BBB	A3	BBB+	—	—	—	BBB	A3	A-	S	S	S
CEI	BBB	Baa2	BBB+	A-	A3	A	BBB	Baa2	A-	S	S	S
FET	BBB	Baa2	BBB	—	—	—	BBB-	Baa2	BBB	S	S	S
JCP&L	BBB	Baa1	BBB+	—	—	—	BBB	Baa1	A-	S	P	S
ME	BBB	A3	BBB+	—	—	—	BBB	A3	A-	S	S	S
MAIT	BBB	A3	BBB+	—	—	—	BBB	A3	A-	S	S	S
MP	BBB	Baa2	BBB	A-	A3	A-	BBB	Baa2	—	S	S	S
OE	BBB	A3	BBB+	A-	A1	A	BBB	A3	A-	S	P	S
PN	BBB	Baa1	BBB+	—	—	—	BBB	Baa1	A-	S	S	S
Penn	BBB	A3	BBB+	—	A1	A	—	—	—	S	P	S
PE	BBB	Baa2	BBB	—	—	A-	—	—	—	S	S	S
TE	BBB	Baa1	BBB+	A-	A2	A	—	—	—	S	S	S
TrAIL	BBB	A3	BBB+	—	—	—	BBB	A3	A-	S	S	S
WP	BBB	A3	BBB+	—	—	A	—	—	—	S	S	S

(1) S = Stable and P = Positive

On March 21, 2019, Moody’s upgraded the Senior Unsecured and Issuer ratings of ATSI and MAIT to A3 from Baa1. At the same time, Moody's affirmed the Senior Unsecured and Issuer ratings of their intermediate holding company, FET, at Baa2 as well as TrAIL at A3. The rating outlooks of these companies are stable.

On March 27, 2019, Moody’s upgraded JCP&L’s Senior Unsecured and Issuer ratings to Baa1 from Baa2, and maintained the positive outlook pending the outcome of the Reliability Plus infrastructure investment program.

On April 17, 2019, Fitch upgraded JCP&L’s Issuer rating to BBB from BBB- and its Senior Unsecured rating to BBB+ from BBB with a positive outlook. Also, on April 17, 2019, Fitch upgraded MP, AGC, and PE’s Issuer ratings to BBB from BBB- and the Senior Secured ratings of MP and PE to A- from BBB+ with a stable outlook for MP, AGC and PE and affirmed FE’s and all other FE subsidiaries ratings and positive outlooks.

On July 23, 2019, Moody’s upgraded the Senior Unsecured and Issuer ratings of OE and Penn to A3 from Baa1, TE to Baa1 from Baa3, and CEI to Baa2 from Baa3. The secured ratings for OE and Penn were changed to A1 from A2, TE to A2 from Baa1, and CEI to A3 from Baa1. The rating outlook for OE remains positive, Penn was revised to positive, and TE and CEI were revised to stable.

On November 8, 2019, Fitch upgraded the Corporate Credit Ratings and Senior Unsecured Ratings of FE and FET to BBB from BBB-. The Corporate Credit Ratings of ATSI, CEI, JCP&L, ME, MAIT, OE, PN, Penn, TE, TrAIL, and WP were upgraded to BBB+ from BBB, and the Senior Unsecured Ratings of ATSI, CEI, JCP&L, ME, MAIT, OE, PN, and TrAIL were upgraded to A- from BBB+. Additionally, the Senior Secured Ratings of CEI, OE, Penn, TE, and WP were upgraded to A from A-. At the same time, the Outlook for each of the companies upgraded was changed to Stable from Positive.

Debt capacity is subject to the consolidated debt-to-total-capitalization limits in the credit facilities previously discussed. As of December 31, 2019, FE and its subsidiaries could issue additional debt of approximately $7.8 billion, or incur a $4.2 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, 2019, FirstEnergy had $627 million of cash and cash equivalents and approximately $52 million of restricted cash compared to $367 million of cash and cash equivalents and approximately $62 million of restricted cash as of December 31, 2018, on the Consolidated Balance Sheets.

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 materials and services.

Net cash provided from operating activities was $2,467 million during 2019, $1,410 million during 2018 and $3,808 million during 2017.

2019 compared with 2018

Cash flows from operations increased $1,057 million in 2019 as compared with 2018. The year-over-year change in cash from operations increased due to the following:


•	a $750 million decrease in cash contributions to the qualified pension plan;


•	higher transmission revenue reflecting a higher base rate and recovery of incremental operating expenses at ATSI and MAIT;


•	decrease to working capital primarily due to higher receipts from customers;


•	lower storm costs; partially offset by


•	lower revenues due to tax savings being provided to customers in relation to the Tax Act;


•	the absence of FES' cash from operations from the first quarter of 2018.

FirstEnergy's Consolidated Statements of Cash Flows combine cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of operating cash flow items from discontinued operations for the years ended December 31, 2019, 2018 and 2017:



	For the Years Ended December 31,
(In millions)	2019			2018			2017

CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) from discontinued operations	$	8		$	326		$	(1,435	)
Gain on disposal, net of tax	(59		)	(435		)	—
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs	—			110			333
Deferred income taxes and investment tax credits, net	47			61			(842		)
Unrealized (gain) loss on derivative transactions	—			(10		)	81

Cash Flows From Financing Activities

Cash provided from financing activities was $656 million and $1,394 million in 2019 and 2018, respectively, compared to cash used for financing activities of $702 million in 2017. The following table summarizes new equity and debt financing, redemptions, repayments, make-whole premiums paid on debt redemptions short-term borrowings and dividends:



	For the Years Ended December 31,
Securities Issued or Redeemed / Repaid	2019			2018			2017
	(In millions)
New Issues
Preferred stock issuance	$	—		$	1,616		$	—
Common stock issuance	—			850			—
Unsecured notes	1,850			850			3,800
PCRBs	—			74			—
FMBs	450			50			625
Term loan	—			500			250
	$	2,300		$	3,940		$	4,675

Redemptions / Repayments
Unsecured notes	$	(725	)	$	(555	)	$	(1,330	)
PCRBs	—			(216		)	(158		)
FMBs	(1		)	(325		)	(725		)
Term loan	—			(1,450		)	—
Senior secured notes	(63		)	(62		)	(78		)
	$	(789	)	$	(2,608	)	$	(2,291	)

Tender premiums paid on debt redemptions	$	—		$	(89	)	$	—

Short-term borrowings (repayments), net	$	—		$	950		$	(2,375	)

Preferred stock dividend payments	$	(6	)	$	(61	)	$	—

Common stock dividend payments	$	(814	)	$	(711	)	$	(639	)

On January 10, 2019, ME issued $500 million of 4.30% senior notes due 2029. Proceeds from the issuance of senior notes were primarily used to refinance existing indebtedness, including ME’s $300 million of 7.70% senior notes due 2019, and borrowings outstanding under the FE regulated utility money pool and the FE Facility, 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 primarily used to refinance existing indebtedness, including amounts outstanding under the FE regulated utility money pool incurred in connection with the repayment at maturity of JCP&L’s $300 million of 7.35% senior notes due 2019 and the funding of storm recovery and restoration costs and expenses, to fund capital expenditures and working capital requirements and for other general corporate purposes.

On March 28, 2019, FET issued $500 million of 4.55% senior notes due 2049. Proceeds from the issuance of the senior notes were used primarily to support FET’s capital structure, to repay short-term borrowings outstanding under the FE unregulated money pool, to finance capital improvements, and for other general corporate purposes, including funding working capital needs and day-to-day operations.

On April 15, 2019, ATSI issued $100 million of 4.38% senior notes due 2031. Proceeds from the issuance of the senior notes were used primarily to repay short-term borrowings, to fund capital expenditures and working capital needs, and for other general corporate purposes.

On May 21, 2019, WP issued $100 million of 4.22% FMBs due 2059. Proceeds from the issuance of the FMBs were or are, as the case may be, used to refinance existing indebtedness, to fund capital expenditures, and for other general corporate purposes.

On June 3, 2019, PN issued $300 million of 3.60% senior notes due 2029. Proceeds from the issuance of the senior notes were used to refinance existing indebtedness, including amounts outstanding under the FE regulated companies’ money pool incurred in connection with the repayment at maturity of PN’s $125 million of 6.63% senior notes due 2019, to fund capital expenditures, and for other general corporate purposes.

On June 5, 2019, AGC issued $50 million of 4.47% senior unsecured notes due 2029. Proceeds from the issuance of the senior notes were used to improve liquidity, re-establish the debt component within its capital structure following the recent redemption of all of its existing long-term debt, and satisfy working capital requirements and other general corporate purposes.

On August 15, 2019, WP issued $150 million of 4.22% FMBs due 2059. Proceeds were used to refinance existing indebtedness, fund capital expenditures and for other general corporate purposes.

On November 14, 2019, MP issued $155 million of 3.23% FMBs due 2029 and $45 million of 3.93% FMBs due 2049. Proceeds were used to refinance existing debt, to fund capital expenditures, and for other general corporate purposes.

Cash Flows From Investing Activities

Cash used for investing activities in 2019 principally represented cash used for property additions. The following table summarizes investing activities for 2019, 2018 and 2017:



	For the Years Ended December 31,
Cash Used for Investing Activities	2019			2018			2017
	(In millions)
Property Additions:
Regulated Distribution	$	1,473		$	1,411		$	1,191
Regulated Transmission	1,090			1,104			1,030
Corporate/Other	102			160			366
Nuclear fuel	—			—			254
Proceeds from asset sales	(47		)	(425		)	(388		)
Investments	38			54			98
Notes receivable from affiliated companies	—			500			—
Asset removal costs	217			218			172
Other	—			(4		)	—
	$	2,873		$	3,018		$	2,723

2019 compared with 2018

Cash used for investing activities in 2019 decreased $145 million compared to 2018, primarily due to the decrease in notes receivable from affiliated companies resulting from FES's borrowings from the committed line of credit available under the secured credit facility with FE during the first quarter of 2018 and investments, partially offset by lower proceeds from asset sales.

FirstEnergy's Consolidated Statements of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of investing cash flow items from discontinued operations for the years ended December 31, 2019, 2018 and 2017:



	For the Years Ended December 31,
(In millions)	2019		2018			2017

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	$	—	$	(27	)	$	(317	)
Nuclear fuel	—		—			(254		)
Sales of investment securities held in trusts	—		109			940
Purchases of investment securities held in trusts	—		(122		)	(999		)

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.

Management assesses the probability of recovery of regulatory assets at each balance sheet date and whenever new events occur. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. Management applies judgment in evaluating the evidence available to assess the probability of recovery of regulatory assets from customers, including, but not limited to evaluating evidence related to precedent for similar items at the Company and information on comparable companies within similar jurisdictions, as well as assessing progress of communications between the Company and regulators. Certain of these regulatory assets, totaling approximately $111 million as of December 31, 2019, are recorded based on prior precedent or anticipated recovery based on rate making premises without a specific order.

The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2019 and December 31, 2018, and the changes during the year ended December 31, 2019:



Net Regulatory Assets (Liabilities) by Source	December 31, 2019			December 31, 2018			Change
	(In millions)
Regulatory transition costs	$	(8	)	$	49		$	(57	)
Customer payables for future income taxes	(2,605		)	(2,725		)	120
Nuclear decommissioning and spent fuel disposal costs	(197		)	(148		)	(49		)
Asset removal costs	(756		)	(787		)	31
Deferred transmission costs	298			170			128
Deferred generation costs	214			202			12
Deferred distribution costs	155			208			(53		)
Contract valuations	51			72			(21		)
Storm-related costs	551			500			51
Other	36			52			(16		)
Net Regulatory Liabilities included on the Consolidated Balance Sheets	$	(2,261	)	$	(2,407	)	$	146

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

Regulatory transition costs - Includes the recovery of PN above-market NUG costs; 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 BGS, capacity and ancillary services, net of all revenues from the sale of the committed supply in the wholesale market. Amounts are amortized primarily 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 assets reverse, which is generally over the expected life of the underlying asset.

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) primarily for the future decommissioning of TMI-2.

Asset removal costs - Primarily represents the rates charged to customers that include a provision for the cost of future activities to remove assets, including obligations for which an ARO 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 the formula-rate 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 - Includes the changes in fair value of PN above-market NUG costs and the amortization of purchase accounting adjustments at MP and PE which were 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 2034 through 2036).

Storm-related costs - Relates to the recovery of storm costs, which vary by jurisdiction. Approximately $193 million and $232 million are currently being recovered through rates as of December 31, 2019 and 2018, respectively.

The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2019 and 2018, of which approximately $228 million and $290 million, respectively, are currently being recovered through rates over varying periods depending on the nature of the deferral and the jurisdiction.



Regulatory Assets by Source Not Earning a Current Return	December 31, 2019		December 31, 2018		Change
			(in millions)
Regulatory transition costs	$	7	$	10	$	(3	)
Deferred transmission costs	27		80		(53		)
Deferred generation costs	15		8		7
Storm-related costs	471		363		108
Other	25		42		(17		)
Regulatory Assets Not Earning a Current Return	$	545	$	503	$	42

CONTRACTUAL OBLIGATIONS

As of December 31, 2019, FirstEnergy's estimated undiscounted cash payments under existing contractual obligations that it considers firm obligations are as follows:



Contractual Obligations	Total		2020		2021-2022		2023-2024		Thereafter
	(In millions)
Long-term debt(1)	$	20,066	$	364	$	2,024	$	2,440	$	15,238
Short-term borrowings	1,000		1,000		—		—		—
Interest on long-term debt(2)	12,131		928		1,781		1,581		7,841
Operating leases(3)	339		40		80		65		154
Finance leases(3)	80		20		32		12		16
Fuel and purchased power(4)	1,687		540		770		377		—
Capital expenditures(5)	1,445		503		573		369		—
Pension funding	1,385		—		159		721		505
FES bankruptcy settlement agreement(6)	853		853		—		—		—
Intercompany tax allocation agreement(7)	100		100		—		—		—
Total	$	39,086	$	4,348	$	5,419	$	5,565	$	23,754


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


(2)	Interest on variable-rate debt based on rates as of December 31, 2019.


(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, 2019.


(6)	Assumes FES Debtors emergence in 2020, see Note 1, "Organization and Basis of Presentation," of the Notes to Consolidated Financial Statements for further discussion on settlement.


(7)	Estimated amounts owed to the FES Debtors under the intercompany tax allocation agreement for the 2018 and 2019 tax returns, see Note 1, "Organization and Basis of Presentation," of the Notes to Consolidated Financial Statements for further discussion on tax sharing agreement with the FES Debtors.

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 2020.

The table above also excludes regulatory liabilities (see Note 14, "Regulatory Matters"), AROs (see Note 13, "Asset Retirement Obligations"), reserves for litigation, injuries and damages, environmental remediation, and annual insurance premiums, including nuclear insurance (see Note 15, "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, 2019, was approximately $1.6 billion, as summarized below:



Guarantees and Other Assurances	Maximum Exposure
	(In millions)
FE's Guarantees on Behalf of the FES Debtors
Surety Bonds - FG(1)	$	200
Deferred compensation arrangements	150
	350
FE's Guarantees on Behalf of its Consolidated Subsidiaries
AE Supply asset sales(2)	555
Deferred compensation arrangements	466
Fuel related contracts and other	10
	1,031
FE's Guarantees on Other Assurances
Global Holding Facility	114
Surety Bonds	135
LOCs and other	16
	265
Total Guarantees and Other Assurances	$	1,646


(1)	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.

(2)

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 provided 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.

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, 2019, AE Supply has posted no collateral. The Utilities and Transmission Companies have posted no collateral.

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, 2019:



Potential Collateral Obligations	AE Supply		Utilities and FET		FE		Total
	(In millions)
Contractual Obligations for Additional Collateral
At Current Credit Rating	$	1	$	—	$	—	$	1
Upon Further Downgrade	—		36		—		36
Surety Bonds (Collateralized Amount)(1)	—		63		257		320
Total Exposure from Contractual Obligations	$	1	$	99	$	257	$	357

(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 $120 million syndicated senior secured term loan facility due November 12, 2024, under which Global Holding's outstanding principal balance is $114 million as of December 31, 2019. In addition to FE, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, continue to provide their joint and several 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, 2019, FirstEnergy has a net liability of $13 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, 2019, the FirstEnergy pension plan assets were allocated approximately as follows: 29% in equity securities, 36% in fixed income securities, 9% in hedge funds, 2% in insurance-linked securities, 7% in real estate, 4% in private equity and 13% 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. On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. 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, 2019, FirstEnergy's pension plan assets have earned approximately 20.3% as compared to an annual expected return on plan assets of 7.50%.

As of December 31, 2019, FirstEnergy's OPEB plans were invested in fixed income and equity securities. Through December 31, 2019, FirstEnergy's OPEB plans have earned approximately 18.1% as compared to an annual expected return on plan assets of 7.50%.

NDT funds have been established to satisfy JCP&L, ME and PN's nuclear decommissioning obligations associated with TMI-2. As of December 31, 2019, approximately 15% and 85% of the funds were invested in fixed income securities and short-term investments, respectively, with limitations related to concentration and investment grade ratings. The investments are carried at their market values of approximately $135 million and $763 million for fixed income securities and short-term investments, respectively, as of December 31, 2019, excluding $16 million of net receivables, payables and accrued income. 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 2019, 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	2020			2021			2022			2023			2024			There-after			Total			Fair Value
	(In millions)
Assets:
Investments Other Than Cash and Cash Equivalents:
Fixed Income	$	—		$	—		$	—		$	—		$	—		$	401		$	401		$	401
Average interest rate	—		%	—		%	—		%	—		%	—		%	3.0		%	3.0		%

Liabilities:
Long-term Debt:
Fixed rate	$	364		$	132		$	1,142		$	1,194		$	1,246		$	15,238		$	19,316		$	22,178
Average interest rate	5.4		%	3.7		%	4.1		%	4.1		%	4.7		%	4.9		%	4.8		%
Variable rate	$	—		$	750		$	—		$	—		$	—		$	—		$	750		$	750
Average interest rate	—		%	2.5		%	—		%	—		%	—		%	—		%	2.5		%

FirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. A primary factor contributing to these actuarial gains and losses are changes in the discount rates used to value pension and OPEB obligations as of the measurement date and the difference between expected and actual returns on the plans’ assets. Upon the FES Debtors' emergence from bankruptcy, FirstEnergy will perform a remeasurement of the pension and OPEB plans. Assuming an emergence in the first quarter of 2020, FirstEnergy anticipates an after-tax mark-to-market loss to be up to $400 million assuming a discount rate of approximately 3.10% to 3.35% and a return on the pension and OPEB plans’ assets based on actual investment performance through January 31, 2020.

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 affected company 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 New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. 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)	March 2019	47% / 53%	9.65%
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 March 23, 2019. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.

The 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 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.

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. The MDPSC approved PE’s compliance filing, which implements the pilot program, with minor modifications, on July 3, 2019.

On August 24, 2018, PE filed a base rate case with the MDPSC, which it supplemented on October 22, 2018, to update the partially forecasted test year with a full twelve months of actual data. The rate case 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 reflected $7.3 million in annual savings for customers resulting from the recent federal tax law changes. On March 22, 2019, the MDPSC issued a final order that approved a rate increase of $6.2 million, approved three of the four EDIS programs for four years, directed PE to file a new depreciation study within 18 months, and ordered the filing of a new base rate case in four years to correspond to the ending of the approved EDIS programs.

NEW JERSEY

JCP&L operates under NJBPU approved rates that were effective as of January 1, 2017. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third-party EGSs that fail to provide the contracted service. 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.

On April 18, 2019, pursuant to the May 2018 New Jersey enacted legislation establishing a ZEC program to provide ratepayer funded subsidies of New Jersey nuclear energy supply, the NJBPU approved the implementation of a non-bypassable, irrevocable ZEC charge for all New Jersey electric utility customers, including JCP&L’s customers. Once collected from customers by JCP&L, these funds will be remitted to eligible nuclear energy generators.

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 ratepayers; 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. On May 17, 2019, the Rate Counsel filed an appeal with the Appellate Division of the Superior Court of New Jersey. JCP&L is contesting this appeal but is unable to predict the outcome of this matter.

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 April 23, 2019, JCP&L filed a Stipulation of Settlement with the NJBPU on behalf of the JCP&L, Rate Counsel, NJBPU Staff and New Jersey Large Energy Users Coalition, which provides that JCP&L will invest up to approximately $97 million in capital investments beginning on June 1, 2019 through December 31, 2020. JCP&L shall seek recovery of the capital investment through an accelerated cost recovery mechanism, provided for in the rules, that includes a revenue adjustment calculation and a process for two rate adjustments. On May 8, 2019, the NJBPU issued an order approving the Stipulation of Settlement without modifications. Pursuant to the Stipulation, JCP&L filed a petition on September 16, 2019, to seek approval of rate adjustments to provide for cost recovery established with JCP&L Reliability Plus.

On January 31, 2018, the NJBPU instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of New Jersey utilities. The NJBPU ordered New Jersey utilities to: (1) defer on their books the impacts of the Tax Act effective January 1, 2018; (2) to file tariffs effective April 1, 2018, reflecting the rate impacts of changes in current taxes; and (3) to file tariffs effective July 1, 2018, reflecting the rate impacts of changes in deferred taxes. On March 2, 2018, JCP&L filed a petition with the NJBPU, which included proposed tariffs for a base rate reduction of $28.6 million effective April 1, 2018, and a rider to reflect $1.3 million in rate impacts of changes in deferred taxes. On March 26, 2018, the NJBPU approved JCP&L’s rate reduction effective April 1, 2018, on an interim basis subject to refund, pending the outcome of this proceeding. On April 23, 2019, JCP&L filed a Stipulation of Settlement on behalf of the Rate Counsel, NJBPU Staff, and the New Jersey Large Energy Users Coalition with the NJBPU. The terms of the Stipulation of Settlement provide that between January 1, 2018 and March 31, 2018, JCP&L’s refund obligation is estimated to be approximately $7 million, which was refunded to customers in 2019. The Stipulation of Settlement also provides for a base rate reduction of $28.6 million, which was reflected in rates on April 1, 2018, and a Rider Tax Act Adjustment for certain items over a five-year period. On May 8, 2019, the NJBPU issued an order approving the Stipulation of Settlement without modification.

JCP&L expects to file a distribution base rate case in New Jersey in February 2020, which will seek to recover certain costs associated with providing safe and reliable electric service to JCP&L customers, along with recovery of previously incurred storm costs.

OHIO

The Ohio Companies operate under base distribution rates approved by the PUCO effective in 2009. The Ohio Companies’ residential and commercial base distribution revenues are decoupled, through a mechanism that took effect on February 1, 2020, to the base distribution revenue and lost distribution revenue associated with energy efficiency and peak demand reduction programs recovered as of the twelve-month period ending on December 31, 2018. The Ohio Companies currently operate under ESP IV effective June 1, 2016, and continuing through May 31, 2024, that continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $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. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (3) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and (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.

ESP IV further provided for the Ohio Companies to collect through Rider DMR $132.5 million annually for three years beginning in 2017, grossed up for federal income taxes, resulting in an approved amount of approximately $168 million annually in 2018 and 2019. Revenues from Rider DMR are excluded from the significantly excessive earnings test. On appeal, the SCOH, on June 19, 2019, reversed the PUCO’s determination that Rider DMR is lawful, and remanded the matter to the PUCO with instructions to remove Rider DMR from ESP IV. On August 20, 2019, the SCOH denied the Ohio Companies’ motion for reconsideration. The PUCO entered an Order directing the Ohio Companies to cease further collection through Rider DMR, credit back to customers a refund of Rider DMR funds collected since July 2, 2019, and remove Rider DMR from ESP IV. On October 1, 2019, the Ohio

Companies implemented PUCO approved tariffs to refund approximately $28 million to customers, including Rider DMR revenues billed from July 2, 2019 through August 31, 2019.

On July 15, 2019, OCC filed a Notice of Appeal with the SCOH, challenging the PUCO’s exclusion of Rider DMR revenues from the determination of the existence of significantly excessive earnings under ESP IV for calendar year 2017 and claiming a $42 million refund is due to OE customers. The Ohio Companies are contesting this appeal but are unable to predict the outcome of this matter.

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 includes a portfolio of energy efficiency programs targeted to a variety of customer segments. The Ohio Companies anticipate the cost of the plan will be approximately $268 million over the life of the plan and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms. On November 21, 2017, the PUCO issued an order that approved the proposed plan 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 October 15, 2019, the SCOH reversed the PUCO’s decision to impose the 4% cost-recovery cap and remanded the matter to the PUCO for approval of the portfolio plans without the cost-recovery cap.

On July 23, 2019, Ohio enacted legislation establishing support for nuclear energy supply in Ohio. In addition to the provisions supporting nuclear energy, the legislation included a provision implementing a decoupling mechanism for Ohio electric utilities. The legislation also is ending current energy efficiency program mandates on December 31, 2020, provided statewide energy efficiency mandates are achieved as determined by the PUCO. On October 23, 2019, the PUCO solicited comments on whether the PUCO should terminate the energy efficiency programs once the statewide energy efficiency mandates are achieved. Opponents to the legislation sought to submit it to a statewide referendum, and stay its effect unless and until approved by a majority of Ohio voters. Petitioners filed a lawsuit in the U.S. District Court for the Southern District of Ohio seeking additional time to gather signatures in support of a referendum. Petitioners failed to file the necessary number of petition signatures, and the legislation took effect on October 22, 2019. On October 23, 2019, the U.S. District Court denied petitioners’ request for more time, and certified questions of state law to the SCOH to answer. Petitioners appealed the U.S. District Court’s decision to the U.S. Court of Appeals for the Sixth Circuit. The Petitioners ended their challenge to the legislation voluntarily at the end of January 2020 causing the dismissal of the appeal, the lawsuit before the U.S District Court, and the proceedings before the SCOH.

On November 21, 2019, the Ohio Companies applied to the PUCO for approval of a decoupling mechanism, which would set residential and commercial base distribution related revenues at the levels collected in 2018. As such, those base distribution revenues would no longer be based on electric consumption, which allows continued support of energy efficiency initiatives while also providing revenue certainty to the Ohio Companies. On January 15, 2020, the PUCO approved the Ohio Companies’ decoupling application, and the decoupling mechanism took effect on February 1, 2020.

In February 2016, the Ohio Companies filed a Grid Modernization Business Plan for PUCO consideration and approval, as required by the terms of ESP IV. On December 1, 2017, the Ohio Companies filed an application with the PUCO for approval of a DPM Plan, a portfolio 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. Also, on January 10, 2018, the PUCO opened a case to consider the impacts of the Tax Act on Ohio utilities’ rates and determine the appropriate course of action to pass benefits on to customers. On November 9, 2018, the Ohio Companies filed a settlement agreement that provides for the implementation of the first phase of grid modernization plans, including the investment of $516 million over three years to modernize the Ohio Companies’ electric distribution system, and for all tax savings associated with the Tax Act to flow back to customers. As part of the agreement, the Ohio Companies also filed an application for approval of a rider to return the remaining tax savings to customers following PUCO approval of the settlement. On January 25, 2019, the Ohio Companies filed a supplemental settlement agreement that keeps intact the provisions of the settlement described above and adds further customer benefits and protections, which broadened support for the settlement. The settlement had broad support, including PUCO Staff, the OCC, representatives of industrial and commercial customers, a low-income advocate, environmental advocates, hospitals, competitive generation suppliers and other parties. On July 17, 2019, the PUCO approved the settlement agreement with no material modifications. On September 11, 2019, the PUCO denied the application for rehearing of environmental advocates who were not parties to the settlement.

The Ohio Companies’ Rider NMB is designed to recover NMB transmission-related costs imposed on or charged to the Ohio Companies by FERC or PJM. On December 14, 2018, the Ohio Companies filed an application for a review of their 2019 Rider NMB, including recovery of future Legacy RTEP costs and previously absorbed Legacy RTEP costs, net of refunds received from PJM. On February 27, 2018, the PUCO issued an order directing the Ohio Companies to file revised final tariffs recovering Legacy RTEP costs incurred since May 31, 2018, but excluding recovery of approximately $95 million in Legacy RTEP costs incurred prior to May 31, 2018, net of refunds received from PJM. The PUCO solicited comments on whether the Ohio Companies should be permitted to recover the Legacy RTEP charges incurred prior to May 31, 2018. On October 9, 2019, the PUCO approved the recovery of the $95 million of previously excluded Legacy RTEP charges.

PENNSYLVANIA

The Pennsylvania Companies operate under rates approved by the PPUC, effective as of January 27, 2017. These rates were adjusted for the net impact of the Tax Act, effective March 15, 2018. The net impact of the Tax Act for the period January 1, 2018 through March 14, 2018 must also be separately tracked for treatment in a future rate proceeding. The Pennsylvania Companies operate under DSPs for the June 1, 2019 through May 31, 2023 delivery period, which provide for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service.

Under the 2019-2023 DSPs, 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, modifications to the Pennsylvania Companies’ customer class definitions to allow for the introduction of hourly priced default service to customers at or above 100kW, customer assistance program shopping limitations, and script modifications related to the Pennsylvania Companies' customer referral programs.

Pursuant to Pennsylvania 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. 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. Following a periodic review of the LTIIPs in 2018 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 May 23, 2019, the PPUC approved the Pennsylvania Companies’ Modified LTIIPs that revised LTIIP spending in 2019 of approximately $45 million by ME, $25 million by PN, $26 million by Penn and $51 million by WP, and terminating at the end of 2019. On August 30, 2019, the Pennsylvania Companies filed Petitions for approval of proposed LTIIPs for the five-year period beginning January 1, 2020 and ending December 31, 2024 for a total capital investment of approximately $572 million for certain infrastructure improvement initiatives. On January 16, 2020, the PPUC approved the LTIIPs without modification, as well as directed the Pennsylvania Companies to submit corrective action plans by March 16, 2020, which outline how they will reduce their pole replacement backlogs over a five-year period to a rolling two-year backlog.

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. The parties to the DSIC proceeding submitted a Joint Settlement that resolved the issues that were pending from the order issued on June 9, 2016, and 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. The Pennsylvania OCA filed an appeal with the Pennsylvania Commonwealth Court of the PPUC’s decision, and the Pennsylvania Companies contested the appeal. The Commonwealth Court reversed the PPUC’s decision of April 19, 2018 and remanded the matter to the PPUC to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. The Commonwealth Court denied Applications for Reargument in the Court’s July 11, 2019 Opinion and Order filed by the PPUC and the Pennsylvania Companies. On October 7, 2019, the PPUC and the Pennsylvania Companies filed separate Petitions for Allowance of Appeal of the Commonwealth Court’s Opinion and Order to the Pennsylvania Supreme Court.

On August 30, 2019, Penn filed a Petition seeking approval of a waiver of the statutory DSIC cap of 5% of distribution rate revenue and approval to increase the maximum allowable DSIC to 11.81% of distribution rate revenue for the five-year period of its proposed LTIIP. The Pennsylvania Office of Small Business Advocate, the PPUC’s Bureau of Investigation, and the Pennsylvania OCA opposed Penn’s Petition. On January 17, 2020, the parties filed a petition seeking approval of settlement that provides for a temporary increase in the recoverability cap from 5% to 7.5%, which will expire on the earlier of the effective date of new base rates following Penn’s next base rate case or the expiration of its LTIIP II program. The settlement is subject to PPUC approval.

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.

On August 21, 2019, MP and PE filed with the WVPSC their annual ENEC case requesting a decrease in ENEC rates of $6.1 million beginning January 1, 2020, representing a 0.4% decrease in rates versus those in effect on August 21, 2019. On October 11, 2019, MP and PE filed a supplement requesting approval of the termination of the 50 MW PPA with Morgantown Energy Associates, a NUG entity. A settlement between MP, PE, and the majority of the intervenors fully resolving the ENEC case, which maintains 2019 ENEC rates into 2020, and supports the termination of the Morgantown Energy Associates PPA, was filed with the WVPSC on October 18, 2019. An order was issued on December 20, 2019, approving the ENEC settlement and termination of the PPA with Morgantown Energy Associates.

On August 21, 2019, MP and PE filed with the WVPSC for a reconciliation of their VMS and a periodic review of its vegetation management program requesting an increase in VMS rates of $7.6 million beginning January 1, 2020. The increase is due to moving from a 5-year maintenance cycle to a 4-year cycle and performing more operation and maintenance work and less capital work on the rights of way. The increase is a 0.5% increase in rates versus those in effect on August 21, 2019. All the parties reached a settlement in the case, and the WVPSC issued its order approving the settlement without change on December 20, 2019.

FERC REGULATORY MATTERS

Under the FPA, FERC regulates rates for interstate wholesale sales, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Utilities, AE Supply 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(1)	Settled(1)(3)	Settled(1)(3)
MP	March 21, 2018(2)	Settled(3)	Settled(3)
PE	March 21, 2018(2)	Settled(3)	Settled(3)
WP	March 21, 2018(2)	Settled(3)	Settled(3)
MAIT	July 1, 2017	Lower of Actual (13 month average) or 60%	10.3%
TrAIL	July 1, 2008	Actual (year-end)	12.7% (TrAIL the Line & Black Oak SVC) 11.7% (All other projects)

(1) Effective on January 1, 2020, JCP&L has implemented a forward-looking formula rate, which has been accepted by FERC, subject to refund, pending further hearing and settlement proceedings.

(2) See FERC Actions on Tax Act below.

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

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 six 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 material 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.

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.

FERC Actions on Tax Act

On March 15, 2018, FERC initiated proceedings on the question of how to 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 21, 2019, FERC issued a final rule (Order 864). Order 864 requires utilities with transmission formula rates to update their formula rate templates to include mechanisms to (i) deduct any excess ADIT from or add any deficient ADIT to their rate base; (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. Alternatively, formula rate utilities can demonstrate to FERC that their formula rate template already achieves these outcomes. Utilities with transmission stated rates are required to address these new requirements as part of their next transmission rate case. 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. FirstEnergy’s formula rate transmission utilities will make the required filings on or before the deadlines established in FERC’s order. FirstEnergy’s stated rate transmission utilities will address the requirements as part of their next transmission rate case. JCP&L is addressing the requirements in the course of its pending transmission rate case.

Transmission ROE Methodology

FERC’s methodology for calculating electric transmission utility ROE has been in transition as a result of an April 14, 2017 ruling by the D.C. Circuit that vacated FERC’s then-effective methodology. On October 16, 2018, FERC issued an order in which it proposed a revised ROE methodology. FERC proposed that, for complaint proceedings alleging that an existing ROE is not just and reasonable, FERC will rely on three financial models - discounted cash flow, capital-asset pricing, and expected earnings - to establish a composite zone of reasonableness to identify a range of just and reasonable ROEs. FERC then will utilize the 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 replacement 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. On March 21, 2019, FERC established NOIs to collect industry and stakeholder comments on the revised ROE methodology that is described in the October 16, 2018 decision, and also whether to make changes to FERC’s existing policies and practices for awarding transmission rates incentives. On November 21, 2019, FERC announced in a complaint proceeding involving MISO utilities that FERC would rely on the discounted cash flow and capital-asset pricing models as the basis for establishing ROE. It is not clear at this time whether FERC’s November ruling will be applied more broadly. Any changes to FERC’s transmission rate ROE and incentive policies would be applied on a prospective basis. FirstEnergy currently is participating through various trade groups in the FERC dockets where the ROE methodology is being reviewed, and on December 23, 2019, JCP&L filed a request for rehearing of FERC’s November decision in the MISO utilities docket.

JCP&L Transmission Formula Rate

On October 30, 2019, JCP&L filed tariff amendments with FERC to convert JCP&L’s existing stated transmission rate to a forward-looking formula transmission rate. JCP&L requested that the tariff amendments become effective January 1, 2020. On December 19, 2019, FERC issued its initial order in the case, allowing JCP&L to transition to a forward-looking formula rate as of January 1, 2020 as requested, subject to refund, pending further hearing and settlement proceedings. JCP&L is engaged in settlement negotiations.

ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy's environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and

potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition.

Clean Air Act

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

CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. The D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO2 emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR, but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR update rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. On September 6, 2017, the D.C. Circuit rejected the industry's bid for a lengthy pause in the litigation and set a briefing schedule. On September 13, 2019, the D.C. Circuit remanded the CSAPR update rule to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the EPA and the states ultimately implement CSAPR, the future cost of compliance may materially impact FirstEnergy's operations, cash flows and financial condition.

In February 2019, the EPA announced its final decision to retain without changes the NAAQS for SO2, specifically retaining the 2010 primary (health-based) 1-hour standard of 75 PPB. As of September 30, 2019, FirstEnergy has no power plants operating in areas designated as non-attainment by the EPA.

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's petitions under CAA Section 126. In October 2018, Delaware and Maryland appealed the denials of their petitions to the D.C. Circuit. In March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including Ohio, Pennsylvania and West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition seeks suitable emission rate limits for large stationary sources that are affecting New York’s air quality within the three years allowed by CAA Section 126. On May 3, 2018, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to November 9, 2018. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss.

Climate Change

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.

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. In 2015, FirstEnergy set a goal of reducing company-wide CO2 emissions by at least 90 percent below 2005 levels by 2045. As of December 31, 2018, FirstEnergy has reduced its CO2 emissions by approximately 62 percent. In September 2016, the U.S. joined in adopting the agreement reached on December 12, 2015, at the United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement’s non-binding obligations to limit global warming to below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.

In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHG under the Clean Air Act,” concluding that concentrations of several key GHGs constitutes an "endangerment" and may be regulated as "air pollutants" under

the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. The EPA released its final CPP regulations in August 2015 to reduce CO2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO2 emission limits for new, modified, and reconstructed fossil fuel fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On 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. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that establishes guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired power plants. Depending on the outcomes of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material.

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's facilities. 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 on September 18, 2017, the EPA postponed certain compliance deadlines for two years. On November 4, 2019, the EPA issued a proposed rule revising the effluent limits for discharges from wet scrubber systems and extending the deadline for compliance to December 31, 2025. The EPA’s proposed rule retains the zero discharge standard and 2023 compliance date for ash transport water, but adds some allowances for discharge under certain circumstances. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. 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.

On September 29, 2016, FirstEnergy received a request from the EPA for information pursuant to CWA Section 308(a) for information concerning boron exceedances of effluent limitations established in the NPDES Permit for the former Mitchell Power Station’s Mingo landfill, owned by WP. On November 1, 2016, WP provided an initial response that contained information related to a similar boron issue at the former Springdale Power Station’s landfill. The EPA requested additional information regarding the Springdale landfill and on November 15, 2016, WP provided a response and intends to fully comply with the Section 308(a) information request. On March 3, 2017, WP proposed to the PA DEP a re-route of its wastewater discharge to eliminate potential boron exceedances at the Springdale landfill. On January 29, 2018, WP submitted an NPDES permit renewal application to PA DEP proposing to re-route its wastewater discharge to eliminate potential boron exceedances at the Mingo landfill. On February 20, 2018, the DOJ issued a letter and tolling agreement on behalf of EPA alleging violations of the CWA at the Mingo landfill while seeking to enter settlement negotiations in lieu of filing a complaint. On November 4, 2019, the EPA proposed a penalty of nearly $1.3 million to settle alleged past boron exceedances at the Mingo and Springdale landfills. On December 17, 2019, WP responded to the EPA's settlement proposal but is unable to predict the outcome of this matter.

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. On November 4, 2019, the EPA issued a proposed rule accelerating the

date that certain CCR impoundments must cease accepting waste and initiate closure to August 31, 2020. The proposed rule, which includes a 60-day comment period, provides exceptions, which could allow extensions to closure dates.

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, 2019, 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 $109 million have been accrued through December 31, 2019. Included in the total are accrued liabilities of approximately $77 million for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.

OTHER LEGAL PROCEEDINGS

Nuclear Plant Matters

Under NRC regulations, JCP&L, ME and PN must ensure that adequate funds will be available to decommission their retired nuclear facility, TMI-2. As of December 31, 2019, JCP&L, ME and PN had in total approximately $882 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.

On October 15, 2019, JCP&L, ME, PN and GPUN executed an asset purchase and sale agreement with TMI-2 Solutions, LLC, a subsidiary of EnergySolutions, LLC, concerning the transfer and dismantlement of TMI-2. This transfer of TMI-2 to TMI-2 Solutions, LLC will include the transfer of: (i) the ownership and operating NRC licenses for TMI-2; (ii) the external trusts for the decommissioning and environmental remediation of TMI-2; and (iii) related liabilities of approximately $900 million as of December 31, 2019. There can be no assurance that the transfer will receive the required regulatory approvals and, even if approved, whether the conditions to the closing of the transfer will be satisfied. On November 12, 2019, JCP&L filed a Petition with the NJBPU seeking approval of the transfer and sale of JCP&L’s entire 25% interest in TMI-2 to TMI-2 Solutions, LLC. Also on November 12, 2019, JCP&L, ME, PN, GPUN and TMI-2 Solutions, LLC filed an application with the NRC seeking approval to transfer the NRC license for TMI-2 to TMI-2 Solutions, LLC. Both proceedings are ongoing.

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 14, "Regulatory Matters."

FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FE or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FE's 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 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. Management applies judgment in evaluating the evidence available to assess the probability of recovery of regulatory assets from customers, including, but not limited to evaluating evidence related to precedent for similar items experienced at the Company and comparable companies within similar jurisdictions, as well as assessing progress of communications between the Company and regulators. 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 14, "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, 2019, 2018, and 2017, were $676 million, $145 million, and $141 million, respectively, of these amounts, approximately $2 million, $1 million, and $39 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 3.34%, 4.44% and 3.75% as of December 31, 2019, 2018 and 2017, respectively. The assumed discount rates for OPEB were 3.18%, 4.30% and 3.50% as of December 31, 2019, 2018 and 2017, 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 election is considered a change in estimate and, accordingly, accounted for prospectively, and did not have a material impact on FirstEnergy's financial statements.

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 2019, FirstEnergy’s qualified pension and OPEB plan assets experienced gains of $1,492 million or 20.2%, compared to losses of $371 million, or (4)% in 2018, and gains of $999 million, or 15.1% in 2017 and assumed a 7.50% rate of return on plan assets in 2019, 2018 and 2017, which generated $569 million, $605 million and $478 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 decrease or increase 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 2020 is 7.50%.

During 2019, the Society of Actuaries published new mortality tables that include more current data than the RP-2014 tables as well as new improvement scales. An analysis of FirstEnergy pension and OPEB plan mortality data indicated the use of the Pri-2012 mortality table with projection scale MP-2019 was most appropriate. As such, the Pri-2012 mortality table with projection scale MP-2019 was utilized to determine the 2019 benefit cost and obligation as of December 31, 2019 for the FirstEnergy pension and OPEB plans. The impact of using the Pri-2012 mortality table with projection scale MP-2019 resulted in a decrease to the projected benefit obligation approximately $29 million and $3 million for the pension and OPEB plans, respectively, and was included in the 2019 pension and OPEB mark-to-market adjustment.

Based on discount rates of 3.34% for pension, 3.18% for OPEB and an estimated return on assets of 7.50%, FirstEnergy expects its 2020 pre-tax net periodic benefit credit to be approximately $108 million (excluding any actuarial mark-to-market adjustments that would be recognized in 2020 or impacts resulting from FES' emergence from bankruptcy). Upon the FES Debtors' emergence from bankruptcy, FirstEnergy will perform a remeasurement of the pension and OPEB plans. Assuming an emergence in the first quarter of 2020, FirstEnergy anticipates an after-tax mark-to-market loss to be up to $400 million assuming a discount rate of approximately 3.10% to 3.35% and a return on the pension and OPEB plans’ assets based on actual investment performance through January 31, 2020.

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, 2019, 2018, and 2017:



Postemployment Benefits Expense (Credits)	2019			2018			2017
	(In millions)
Pension	$	622		$	200		$	247
OPEB	(21		)	(158		)	(45		)
Total	$	601		$	42		$	202

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 2019 and 2018, 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 2020 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%	$	360	$	16	$	376
Long-term return on assets	Decrease by 0.25%	$	20	$	1	$	21
Health care trend rate	Increase by 1.0%	N/A		$	20	$	20

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

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 FirstEnergy income taxes.

NEW ACCOUNTING PRONOUNCEMENTS

ASU 2016-02, "Leases (Topic 842)" (Issued February 2016 and subsequently updated to address implementation questions): The new guidance requires organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets, as well as new qualitative and quantitative disclosures. FirstEnergy implemented a third-party software tool that assisted with the initial adoption and will assist with ongoing compliance. FirstEnergy chose to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Upon adoption, on January 1, 2019, FirstEnergy increased assets and liabilities by $186 million, with no impact to results of operations or cash flows. See Note 8, "Leases," for additional information on FirstEnergy's leases.

Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting.

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 expected credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost 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, with early adoption permitted. FirstEnergy has analyzed its financial instruments within the scope of this guidance, primarily trade receivables, AFS debt securities and certain third-party guarantees and does not expect a material impact to its financial statements upon adoption in 2020.

ASU 2018-15, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract" (Issued August 2018): ASU 2018-15 requires implementation costs incurred by customers in cloud computing arrangements to be deferred and recognized over the term of the arrangement, if those costs would be capitalized by the customers in a software licensing arrangement. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. FirstEnergy does not expect a material impact to its financial statements upon adoption in 2020.

ASU 2019-12, "Simplifying the Accounting for Income Taxes" (Issued in December 2019): ASU 2019-12 enhances and simplifies various aspects of the income tax accounting guidance including the elimination of certain exceptions related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020, with early adoption permitted.

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