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 to management. 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. These statements 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 results of the ongoing internal investigation matters and evaluation of our controls framework and remediation of our material weakness in internal control over financial reporting.
The risks and uncertainties associated with government investigations regarding HB 6 and related matters including potential adverse impacts on federal or state regulatory matters including, but not limited to, matters relating to rates.
The risks and uncertainties associated with litigation, arbitration, mediation and similar proceedings.
Legislative and regulatory developments, including, but not limited to, matters related to rates, compliance and enforcement activity.
The ability to accomplish or realize anticipated benefits from strategic and financial goals, including, but not limited to, maintaining financial flexibility, overcoming current uncertainties and challenges associated with the ongoing governmental investigations, executing our transmission and distribution investment plans, controlling costs, improving our credit metrics, strengthening our balance sheet and growing earnings.
Economic and weather conditions affecting future operating results, such as a recession, significant weather events and other natural disasters, and associated regulatory events or actions in response to such conditions.
Mitigating exposure for remedial activities associated with retired and formerly owned electric generation assets.
The extent and duration of COVID-19 and the impacts to our business, operations and financial condition resulting from the outbreak of COVID-19 including, but not limited to, disruption of businesses in our territories, volatile capital and credit markets, legislative and regulatory actions, the effectiveness of our pandemic and business continuity plans, the precautionary measures we are taking on behalf of our customers, contractors and employees, our customers’ ability to make their utility payment and the potential for supply-chain disruptions.
The potential of non-compliance with debt covenants in our credit facilities due to matters associated with the government investigations regarding HB 6 and related matters.
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.
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.
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 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, of which, 210 MWs are related to the Yards Creek generating station that is being sold pursuant to an asset purchase agreement as further discussed below. 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, 2020, are summarized below:


Company	Area Served	Customers Served
		(In thousands)
OE	Central and Northeastern Ohio	1,060
Penn	Western Pennsylvania	169
CEI	Northeastern Ohio	755
TE	Northwestern Ohio	314
JCP&L	Northern, Western and East Central New Jersey	1,147
ME	Eastern Pennsylvania	580
PN	Western Pennsylvania and Western New York	588
WP	Southwest, South Central and Northern Pennsylvania	734
MP	Northern, Central and Southeastern West Virginia	395
PE	Western Maryland and Eastern West Virginia	426
		6,168

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 MP, PE and WP; although as explained in Note 14, "Regulatory Matters", effective January 1, 2021, subject to refund, MP's, PE's and WP's existing stated rates became forward-looking formula rates. JCP&L previously had stated transmission rates, however, effective January 1, 2020, JCP&L implemented forward-looking formula rates, subject to refund, pending further hearing and settlement proceedings. Both forward-looking formula and stated rates recover costs that FERC determines 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. Revenue requirements under stated rates are calculated annually by multiplying the highest one-hour peak load in each respective transmission zone by the approved, stated rate in that zone. 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 costs not charged to FE's subsidiaries, including FE’s retained Pension and OPEB assets and liabilities of the FES Debtors, 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, 2020, 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, 2020, Corporate/Other had approximately $8.2 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.

On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. Also, on July 21, 2020, and in connection with the investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the S.D. Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020. In addition to the subpoenas referenced above, the OAG, certain FE shareholders and FirstEnergy customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, each relating to the allegations against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. In addition, on August 10, 2020, the SEC, through its Division of Enforcement, issued an order directing an investigation of possible securities laws violations by FE, and on September 1, 2020, issued subpoenas to FE and certain FE officers.

As previously disclosed, a committee of independent members of the Board of Directors is directing an internal investigation related to ongoing government investigations. In connection with FirstEnergy’s internal investigation, such committee determined on October 29, 2020, to terminate FirstEnergy’s Chief Executive Officer, Charles E. Jones, together with two other executives: Dennis M. Chack, Senior Vice President of Product Development, Marketing, and Branding; and Michael J. Dowling, Senior Vice President of External Affairs. Each of these terminated executives violated certain FirstEnergy policies and its code of conduct. These executives were terminated as of October 29, 2020. Such former members of senior management did not maintain and promote a control environment with an appropriate tone of compliance in certain areas of FirstEnergy’s business, nor sufficiently promote, monitor or enforce adherence to certain FirstEnergy policies and its code of conduct. Furthermore, certain former members of senior management did not reasonably ensure that relevant information was communicated within our organization and not withheld from our independent directors, our Audit Committee, and our independent auditor. Among the matters considered with respect to the determination by the committee of independent members of the Board of Directors that certain former members of senior management violated certain FirstEnergy policies and its code of conduct related to a payment of approximately $4 million made in early 2019 in connection with the termination of a purported consulting agreement, as amended, which had been in place since 2013. The counterparty to such agreement was an entity associated with an individual who subsequently was appointed to a full-time role as an Ohio government official directly involved in regulating the Ohio Companies, including with respect to distribution rates. FirstEnergy believes that payments under the consulting agreement may have been for purposes other than those represented within the consulting agreement. Immediately following these terminations, the independent members of its Board appointed Mr. Steven E. Strah to the position of Acting Chief Executive Officer and Mr. Christopher D. Pappas, a current member of the Board, to the temporary position of Executive Director, each effective as of October 29, 2020. Mr. Donald T. Misheff will continue to serve as Non-Executive Chairman of the Board. Additionally, on November 8, 2020, Robert P. Reffner, Senior Vice President and Chief Legal Officer, and Ebony L. Yeboah-Amankwah, Vice President, General Counsel, and Chief Ethics Officer, were separated from FirstEnergy due to inaction and conduct that the Board determined was influenced by the improper tone at the top. The matter is a subject of the ongoing internal investigation as it relates to the government investigations.

Also, in connection with the internal investigation, FirstEnergy recently identified certain transactions, which, in some instances, extended back ten years or more, including vendor services, that were either improperly classified, misallocated to certain of the Utilities and Transmission Companies, or lacked proper supporting documentation. These transactions resulted in amounts collected from customers that were immaterial to FirstEnergy, and the Utilities and Transmission Companies will be working with the appropriate regulatory agencies to address these amounts.

On January 31, 2021, FirstEnergy reached a partial settlement with the OAG and other parties regarding decoupling, which resulted in the Ohio Companies requesting PUCO approval to set the respective decoupling riders (Rider CSR) to zero effective February 9, 2021. While the partial settlement with the OAG focused specifically on decoupling, the Ohio Companies will of their own accord not seek to recover lost distribution revenue from residential and commercial customers. FirstEnergy is committed to pursuing an open dialogue in an appropriate manner with respect to a number of regulatory proceedings currently underway, including several audits, and multi-year SEET and ESP quadrennial review, among other matters. FirstEnergy believes a holistic, transparent discussion with the PUCO staff, and interested stakeholders in the regulatory process, is an important step towards removing uncertainties about regulatory concerns in Ohio and critical to re-establishing trust in FirstEnergy and restoring its reputation.

The Board has formed a new sub-committee of our Audit committee to, together with the Board, assess FirstEnergy’s compliance program and implement potential changes, as appropriate. In addition, in his role of Executive Director, Mr. Pappas assisted the FirstEnergy leadership team with execution of strategic initiatives, engage with FirstEnergy’s external stakeholders, and support the development of enhanced controls and governance policies and procedures. Additionally, on February 17, 2021, the Board appointed Mr. John Somerhalder to the positions of Vice Chairperson of the Board and Executive Director, each effective as of March 1, 2021, increasing the size of the Board from 10 to 11 members. Mr. Somerhalder has been elected to serve for a term expiring at the Company's 2021 Annual Meeting of Shareholders and until his successor shall have been

elected. Mr. Donald T. Misheff will continue to serve as Non-Executive Chairman of the Board. Mr. Pappas, who was named to the temporary role of Executive Director in October 2020, will continue to serve on the Board of the Company as an independent director. Mr. Somerhalder will help lead efforts to enhance the company's reputation.

Despite the many disruptions FirstEnergy is currently facing, the leadership team remains committed and focused on executing its strategy and running the business. See “Outlook - Other Legal Proceedings” below for additional details on the government investigation and subsequent litigation surrounding the investigation of HB 6. See also “Outlook - State Regulation - Ohio” below for details on the PUCO proceeding reviewing political and charitable spending and legislative activity in response to the investigation of HB 6. The outcome of the government investigations, PUCO proceedings, legislative activity, and any of these lawsuits is uncertain and could have a material adverse effect on FE’s or its subsidiaries’ financial condition, results of operations and cash flows. FirstEnergy is considering reductions to its Regulated Distribution and Regulated Transmission capital investment plans and reductions to operating expenses, as well as changes to its planned equity issuances, to allow for flexibility should a fine or other regulatory actions be imposed as a result of the government investigations.

FirstEnergy is also working to improve how it conducts business and serve its customers. To address opportunities for improvement, FirstEnergy kicked off a new initiative to make process and cultural improvements across our entire organization that will keep FirstEnergy moving forward in a positive direction. Called "FE Forward," the initiative will play a critical first step in our transformation journey as it looks to align business practices with our values and behaviors. FirstEnergy will do this by reviewing policies and practices as well as the structure and processes around how decisions are made. FirstEnergy expects that this project will not only help FirstEnergy overcome current uncertainties and challenges, but it will further our goal of creating a truly sustainable company and provide opportunities to reinvest in our employees and customers. The initial phase of FE Forward, which is expected to go through the first quarter of 2021, will involve a comprehensive assessment that will pinpoint the areas of opportunity across all business units and outline the project's scope.

The outbreak of COVID-19 is a global pandemic. FirstEnergy is taking steps to mitigate known risks and is continuously evaluating the rapidly evolving situation based on guidance from governmental officials and public health experts. The full impact on FirstEnergy’s business from the COVID-19 pandemic, including the governmental and regulatory responses, is unknown at this time and difficult to predict. FirstEnergy provides a critical and essential service to its customers and the health and safety of FirstEnergy’s employees, contractors and customers are its first priority. FirstEnergy is effectively managing its operations, while still providing flexibility for approximately 7,000 of its 12,000 employees to work from home.

Beginning March 13, 2020, FirstEnergy temporarily suspended customer disconnections for nonpayment and ceased collection activities as a result of the ongoing pandemic. Starting September 15, 2020, certain FirstEnergy utilities began non-residential disconnections for non-payment, and began the same on October 5, 2020 for residential disconnections. FirstEnergy is actively monitoring the impact COVID-19 is having on customers’ receivable balances, which include increasing arrears balance since the pandemic has begun. Additionally, FirstEnergy has incurred, and it is expected to incur for the foreseeable future, incremental uncollectible and other COVID-19 related expenses. Such incrementally incurred COVID-19 pandemic related expenses consist of additional costs that FirstEnergy is incurring to protect its employees, contractors and customers, and to support social distancing requirements. These costs include, but are not limited to, new or added benefits provided to employees, the purchase of additional personal protection equipment and disinfecting supplies, additional facility cleaning services, initiated programs and communications to customers on utility response, and increased technology expenses to support remote working, where possible. The Ohio Companies and JCP&L had existing regulatory mechanisms in place prior to the outbreak of COVID-19, where incremental uncollectible expenses are able to be recovered through riders with no material impact to earnings. Additionally, in response to the COVID-19 pandemic, the MDPSC, NJBPU and WVPSC issued orders allowing PE, JCP&L and MP to track and create a regulatory asset for future recovery of incremental costs, including uncollectible expenses, incurred as a result of the pandemic. In Pennsylvania, the PPUC authorized utilities to track all prudently incurred incremental costs arising from COVID-19, and to create a regulatory asset for future recovery of incremental uncollectible expense incurred as a result of COVID-19 above what is included in the Pennsylvania Companies’ existing rates.

FirstEnergy is continuously monitoring its supply chain and is working closely with essential vendors to understand the continued impact of COVID-19 to its business and does not currently expect disruptions in its ability to deliver service to customers or any material impact to its capital spending plan. FirstEnergy’s Distribution and Transmission revenues benefit from geographic and economic diversity across a five-state service territory. Two-thirds of base distribution revenues come from the residential customer class. FirstEnergy’s commercial and industrial revenues are primarily fixed and demand-based, rather than volume-based. As a result of this, FirstEnergy’s Distribution and Transmission investments provide stable and predictable earnings. However, due to the actions taken by state governments in our service territories limiting certain commercial and industrial activities, FirstEnergy’s residential load has increased, while commercial and industrial loads have declined; however, the magnitude of future load trends are currently unknown and difficult to predict. FirstEnergy believes it is well positioned to manage the economic slowdown resulting from the COVID-19 pandemic. However, the situation remains fluid and future impacts to FirstEnergy, that are presently unknown or unanticipated, may occur.

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 sublimits 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 sublimits for each borrower including FE's transmission subsidiaries. On November 17, 2020, FE and the Utilities and FET and certain of its subsidiaries entered into amendments to the FE credit facility and the FET credit facility, respectively. The amendments provide for modifications and/or waivers of: (i) certain representations and warranties, and (ii) certain affirmative and negative covenants, contained therein, which allowed FirstEnergy to regain compliance with such provisions. In addition, among other things, the amendment to the FE credit facility reduces the sublimit applicable to FE to $1.5 billion, and the amendments increased certain tiers of pricing applicable to borrowings under the credit facilities.

On November 23, 2020, FE and its regulated distribution subsidiaries, JCP&L, ME, Penn, TE and WP, borrowed $950 million in the aggregate under the FE Revolving Facility, bringing the outstanding principal balance under the FE Revolving Facility to $1.2 billion, with $1.3 billion of remaining availability under the FE Revolving Facility. On November 23, 2020, FET and its regulated transmission subsidiary, ATSI, borrowed $1 billion in the aggregate under the FET Revolving Facility, bringing the outstanding principal balance under the FET Revolving Facility to $1 billion, with no remaining availability under the FET Revolving Facility. FE, FET and certain of their respective subsidiaries increased their borrowings under the Revolving Facilities as a proactive measure to increase their respective cash positions and preserve financial flexibility.

In 2020, FirstEnergy continues to execute its regulated growth plans, through the following achievements and plans:

Implemented forward-looking rates, subject to refund, at JCP&L effective January 1, 2020,
In October 2020, the NJBPU approved JCP&L’s distribution base rate case settlement agreement, resulting in, among other things, a $94 million increase in annual base distribution revenues,
Filed for rider recovery of smart meters in NJ, to be deployed beginning in 2023 with a total program cost estimated at $732 million,
PAPUC-approved DSIC waiver for Penn, which increased the cap from 5% to 7.5% on March 12, 2020,
Completed final step of FirstEnergy’s strategy to exit the competitive generation business with FES Debtors’ emergence from bankruptcy on February 27, 2020,
Integrated resource plan filing in West Virginia made on December 30, 2020,
Issued Climate Position and Strategy Statement, including a pledge to be carbon neutral by 2050, and
FERC approval that converted the existing stated transmission rates of MP, PE and WP to a forward-looking formula transmission rate, effective January 1, 2021.

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. 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, 100% of its capital investments recovered under forward-looking formula rates at the Transmission Companies effective January 1, 2021. Regulated Transmission has also experienced significant growth as part of its Energizing the Future transmission plan with plans to invest up to $7 billion in capital from 2018 to 2023.

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.

While FirstEnergy continues to have customer-focused investment opportunities across its distribution and transmission businesses of up to $3 billion annually, it has discontinued providing a long-term compound annual growth rate until there is further clarity regarding Ohio regulatory matters and the ongoing government investigations.

In November 2018, the Board of Directors approved a dividend policy that includes a targeted payout ratio. Dividend payments are subject to declaration by the Board and future dividend decisions determined by the Board may be impacted by earnings, cash flows, credit metrics and other business conditions, including the risk and uncertainties of the government investigations.

In November 2020, FirstEnergy published its Climate Story which includes our climate position and strategy, as well as a new comprehensive and ambitious greenhouse gas emission goal. FirstEnergy pledged to achieve carbon neutrality by 2050 and set an interim goal for a 30% reduction in greenhouse gases within the company’s direct operational control by 2030, based on 2019 levels. In addition, FirstEnergy has also set a fleet electrification goal in which beginning in 2021, FirstEnergy plans for 100% of new purchases for our light duty and aerial truck fleet to be electric or hybrid vehicles, creating a path to 30% fleet electrification by 2030. Also, in 2021, FirstEnergy will seek approval to construct a solar generation source of at least 50 MWs in West Virginia. Future resource plans to achieve carbon reductions, including any determination of retirement dates of our regulated coal-fired generating facilities, will be developed by working collaboratively with regulators in West Virginia. Determination of the useful life

of our regulated coal-fired generating facilities could result in changes in depreciation, and/or continued collection of net plant in rates after retirement, securitization, sale, impairment or regulatory disallowances. If MP is unable to recover these costs, it could have a material adverse effect on FE and/or MP’s financial condition, results of operations, and cash flow.

In January 2021, our updated Strategic Plan – Powered by our Core Values & Behaviors was published. This comprehensive update provides a vision of our company’s path forward in an evolving electric industry. It also articulates significant new goals that will help us achieve our long-term strategic commitments in a transparent, sustainable and responsible manner.

The $2.5 billion equity issuance in 2018 strengthened FirstEnergy’s balance sheet and supported the company’s transition to a fully regulated utility company. 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 equity issuance, 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. FirstEnergy's expectations regarding the amount and timing of any potential equity issuances are subject to, among other matters, the ongoing government investigations and related lawsuits.

On March 31, 2018, the FES Debtors announced that, in order to facilitate an orderly financial restructuring, they filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code with the Bankruptcy Court. In September 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement 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 resolved certain claims by FirstEnergy against the FES Debtors, all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, as well as releases from third parties who voted in favor of the FES Debtors' plan of reorganization, in return for among other things, a cash payment of $853 million upon emergence. The FES Bankruptcy settlement was conditioned on the FES Debtors confirming and effectuating a plan of reorganization acceptable to FirstEnergy.

On February 18, 2020, the FES Debtors and FirstEnergy entered into an IT Access Agreement that provided IT support to enable the FES Debtors to emerge from bankruptcy prior to full IT separation by the FES Debtors. As part of the IT Access Agreement, the FES Debtors and FirstEnergy resolved, among other things, the on-going reconciliation of outstanding tax sharing payments for tax years 2018, 2019 and 2020 for a total of $125 million. On February 25, 2020, the Bankruptcy Court approved the IT Access Agreement. On February 27, 2020, the FES Debtors effectuated their plan, emerged from bankruptcy and FirstEnergy tendered the settlement payments totaling $853 million and the $125 million tax sharing payment to the FES Debtors, with no material impact to net income in 2020.

As contemplated under the FES Bankruptcy settlement agreement, AE Supply entered into an agreement on December 31, 2018, to transfer the 1,300 MW Pleasants Power Station and related assets to FG, while retaining certain specified liabilities. Under the terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply operated Pleasants until ownership was transferred on January 30, 2020. AE Supply will continue to provide access to the McElroy's Run CCR impoundment facility, which was not transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR impoundment facility.

As of June 30, 2020, FirstEnergy had substantially ceased providing post-emergence services to FES Debtors under the terms of the amended and restated shared services agreement. In connection with the FES Debtors emergence from bankruptcy, FirstEnergy entered into an amended separation agreement with the FES Debtors to implement the separation of FES Debtors and their businesses from FirstEnergy.

The emergence of the FES Debtors from bankruptcy represents the final step 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.

The Form 10-K discusses 2020 and 2019 items and year-over-year comparisons between 2020 and 2019. Discussions of 2018 items and year-over-year comparisons between 2019 and 2018 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, 2019, filed with the SEC on February 10, 2020.

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.

Net income by business segment was as follows:


(In millions, except per share amounts)	For the Years Ended December 31,						Increase (Decrease)
	2020		2019		2018		2020 vs 2019		2019 vs 2018
Net Income By Business Segment:
Regulated Distribution	$	959	$	1,076	$	1,242	$	(117)	$	(166)
Regulated Transmission	464		447		397		17		50

Corporate/Other	(420)		(619)		(617)		199		(2)
Income from Continuing Operations	$	1,003	$	904	$	1,022	$	99	$	(118)

Discontinued Operations	76		8		326		68		(318)
Net Income	$	1,079	$	912	$	1,348	$	167	$	(436)

Earnings per share of common stock
Basic - Continuing Operations	$	1.85	$	1.69	$	1.33	$	0.16	$	0.36
Basic - Discontinued Operations	0.14		0.01		0.66		0.13		(0.65)
Basic - Net Income Attributable to	$	1.99	$	1.70	$	1.99	$	0.29	$	(0.29)
Common Stockholders

Earnings per share of common stock
Diluted - Continuing Operations	$	1.85	$	1.67	$	1.33	$	0.18	$	0.34
Diluted - Discontinued Operations	0.14		0.01		0.66		0.13		(0.65)
Diluted - Net Income Attributable to	$	1.99	$	1.68	$	1.99	$	0.31	$	(0.31)
Common Stockholders

Summary of Results of Operations — 2020 Compared with 2019

Financial results for FirstEnergy’s business segments for the years ended December 31, 2020 and 2019, were as follows:


2020 Financial Results	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments		FirstEnergy Consolidated
	(In millions)
Revenues:

Electric	$	9,130	$	1,613	$	(139)	$	10,604
Other	233		17		(64)		186

Total Revenues	9,363		1,630		(203)		10,790

Operating Expenses:
Fuel	369		—		—		369
Purchased power	2,687		—		14		2,701
Other operating expenses	3,178		282		(169)		3,291

Provision for depreciation	896		313		65		1,274

Amortization (deferral) of regulatory assets, net	(64)		11		—		(53)
General taxes	770		232		44		1,046

Total Operating Expenses	7,836		838		(46)		8,628

Operating Income (Loss)	1,527		792		(157)		2,162

Other Income (Expense):

Miscellaneous income, net	332		30		70		432

Pension and OPEB mark-to-market adjustment	(323)		(40)		(114)		(477)
Interest expense	(501)		(219)		(345)		(1,065)
Capitalized financing costs	37		39		1		77
Total Other Expense	(455)		(190)		(388)		(1,033)

Income (Loss) Before Income Taxes (Benefits)	1,072		602		(545)		1,129
Income taxes (benefits)	113		138		(125)		126
Income (Loss) From Continuing Operations	959		464		(420)		1,003
Discontinued Operations, net of tax	—		—		76		76
Net Income (Loss)	$	959	$	464	$	(344)	$	1,079


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


Changes Between 2020 and 2019 Financial Results Increase (Decrease)	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments		FirstEnergy Consolidated
	(In millions)
Revenues:

Electric	$	(322)	$	103	$	(11)	$	(230)
Other	(13)		1		(3)		(15)

Total Revenues	(335)		104		(14)		(245)

Operating Expenses:
Fuel	(128)		—		—		(128)
Purchased power	(223)		—		(3)		(226)
Other operating expenses	342		10		(13)		339

Provision for depreciation	33		29		(8)		54

Amortization (deferral) of regulatory assets, net	25		1		—		26
General taxes	10		23		5		38

Total Operating Expenses	59		63		(19)		103

Operating Income (Loss)	(394)		41		5		(348)

Other Income (Expense):

Miscellaneous income, net	158		15		16		189

Pension and OPEB mark-to-market adjustment	(33)		7		223		197
Interest expense	(6)		(27)		1		(32)
Capitalized financing costs	—		6		—		6
Total Other Expense	119		1		240		360

Income (Loss) Before Income Taxes (Benefits)	(275)		42		245		12
Income taxes (benefits)	(158)		25		46		(87)
Income (Loss) From Continuing Operations	(117)		17		199		99
Discontinued Operations, net of tax	—		—		68		68
Net Income (Loss)	$	(117)	$	17	$	267	$	167

Regulated Distribution — 2020 Compared with 2019

Regulated Distribution's net income decreased $117 million in 2020, as compared to 2019, primarily resulting from the charge associated with the impairment of an Ohio regulatory asset in 2020, as further discussed below, higher pension and OPEB mark-to-market adjustments, lower weather-related customer usage, the absence of the DMR revenues that ended in July 2019, and higher operating and maintenance expenses including the impact of non-deferred COVID-19 costs, partially offset by lower pension and OPEB non-service costs, higher revenues from incremental riders in Ohio and Pennsylvania and increased weather-adjusted residential sales due to the impact of COVID-19.

Revenues —

The $335 million decrease in total revenues resulted from the following sources:


	For the Years Ended December 31,
Revenues by Type of Service	2020		2019		Decrease
	(In millions)
Distribution services (1)	$	5,302	$	5,314	$	(12)

Generation sales:
Retail	3,577		3,727		(150)
Wholesale	251		411		(160)
Total generation sales	3,828		4,138		(310)





Other	233		246		(13)
Total Revenues	$	9,363	$	9,698	$	(335)

(1) Includes $43 million and $181 million of ARP revenues for the years ended December 31, 2020 and 2019, respectively.

Distribution services revenues decreased $12 million in 2020, as compared to 2019, primarily resulting from the charge associated with the impairment of an Ohio regulatory asset in 2020, as further discussed below, the absence of the New Jersey storm recovery rider and DMR revenues that ended in July 2019, lower weather-related customer usage, the expiration of a NUG contract and lower commercial and industrial sales due to the impact of COVID-19, partially offset by higher rates associated with incremental riders in Ohio and Pennsylvania, including the recovery of distribution capital investment programs and transmission expenses, increased weather-adjusted residential sales due to the impact of COVID-19 and the implementation of the New Jersey Zero Emission Program in June 2019. Distribution services by customer class are summarized in the following table:


	For the Years Ended December 31,
Electric Distribution MWH Deliveries	2020	2019	Increase (Decrease)
	(In thousands)
Residential	54,978	54,159	1.5	%
Commercial(1)	34,811	37,888	(8.1)	%
Industrial	52,034	55,649	(6.5)	%

Total Electric Distribution MWH Deliveries	141,823	147,696	(4.0)	%

(1) Includes street lighting.

Distribution services to residential customers primarily reflects an increase in weather-adjusted load due to the impact of COVID-19, partially offset by lower weather-related usage. Deliveries to commercial customers reflects lower weather-related usage and the impact of COVID-19. Heating degree days were 6% below 2019 and 10% below normal. Cooling degree days were 1% below 2019, and 14% above normal. Deliveries to industrial customers were also negatively impacted due to the impact of COVID-19, contributing to lower steel, mining, and educational services customer usage, partially offset by higher shale customer usage.

The following table summarizes the price and volume factors contributing to the $310 million decrease in generation revenues in 2020, as compared to 2019:


Source of Change in Generation Revenues	(Decrease)
	(In millions)
Retail:
Change in sales volumes	$	(54)
Change in prices	(96)
	(150)
Wholesale:
Change in sales volumes	(94)
Change in prices	(3)
Capacity revenue	(63)
	(160)
Change in Generation Revenues	$	(310)

Retail generation revenues decreased $150 million, primarily due to lower weather-related usage, partially offset by an increase in weather-adjusted residential load due to the impact of COVID-19 and decreased customer shopping in Pennsylvania and New Jersey. Total generation provided by alternative suppliers as a percentage of total MHW deliveries decreased to 64% from 66% in Pennsylvania and to 47% from 48% in New Jersey. The decrease in retail generation prices primarily resulted from lower non-shopping generation auction rates in New Jersey and Pennsylvania.

Wholesale generation revenues decreased $160 million, primarily due to decreased volumes associated with lower economic dispatch of MP’s generating units, resulting from low spot market energy prices and an increase in the number of planned outages as compared to 2019, the expiration of a NUG contract and lower capacity revenues. The difference between current wholesale generation revenues and certain energy costs incurred are deferred for future recovery or refund, with no material impact to earnings.

Operating Expenses —

Total operating expenses increased $59 million primarily due to the following:

Fuel expense decreased $128 million in 2020, as compared to 2019, primarily due to lower unit costs and lower fuel consumption as a result of economic dispatch and an increase in the number of planned outages as compared to 2019.
Purchased power costs decreased $223 million in 2020, as compared to 2019, primarily due to lower prices and capacity expenses, the absence of the termination of Morgantown Energy Associates PPA and decreased purchases resulting from the expiration of a NUG contract, partially offset by the implementation of the New Jersey Zero Emission Program in June 2019 and an increase in the number of planned outages as compared to 2019.


Source of Change in Purchased Power	Increase (Decrease)

	(In millions)
Purchases
Change due to unit costs	$	(185)
Change due to volumes	21
	(164)

Capacity expense	(59)

Change in Purchased Power Costs	$	(223)

Other operating expenses increased $342 million primarily due to:
Higher incremental uncollectible and other COVID-19 related expenses of $157 million, of which $99 million

was deferred for future recovery.

Higher storm restoration costs of $75 million, which were mostly deferred for future recovery, resulting in no

material impact on current period earnings.

Higher network transmission expenses of $49 million. These costs are deferred for future recovery, resulting in

no material impact on current period earnings.

Higher pension and OPEB service costs of $33 million.
Higher employee benefit costs of approximately $30 million.
Higher other operating and maintenance expense of $40 million, primarily associated with increased material and contractor spend and an additional planned generation outage in 2020,
Lower energy efficiency program costs of $42 million, which are deferred for future recovery, resulting in no material impact on earnings.
Depreciation expense increased $33 million, primarily due to a higher asset base.
Net amortization (deferral) of regulatory assets increased $25 million, primarily due to lower generation and transmission deferrals including the absence of the termination of the Morgantown Energy Associates PPA, the recovery of distribution investment programs and lower energy efficiency related costs, partially offset by the deferral of higher storm restoration costs, and uncollectible and other COVID-19 related costs.
General taxes increased $10 million primarily due to higher Ohio property taxes and payroll taxes.

Other Expense —

Total other expense decreased $119 million, primarily due to lower pension and OPEB non-service costs, partially offset by a $33 million increase in pension and OPEB mark-to-market adjustments, higher interest expense from debt issuances primarily at WP and MP, and increased borrowings under the Revolving Facilities. The 2020 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 10.5% and 20.1% for 2020 and 2019, respectively. The change in the effective tax rate was primarily due to the recognition of $52 million in deferred gains relating to prior intercompany transfers of generation assets that were triggered by the deconsolidation of the FES Debtors from FirstEnergy’s consolidated federal income tax group as a result of their emergence from bankruptcy in the first quarter of 2020. Additionally, FirstEnergy recorded a $40 million benefit related to reversals of certain tax regulatory liabilities resulting from the transfer of TMI-2.

Regulated Transmission — 2020 Compared with 2019

Regulated Transmission's operating results increased $17 million in 2020, as compared to 2019, primarily resulting from the impact of a higher rate base at ATSI, MAIT, and JCPL, and higher capitalized financing costs, partially offset by higher interest expense at FET and a true-up of the forward-looking formula rate at ATSI and MAIT.

Revenues —

Total revenues increased $104 million in 2020, as compared to 2019, primarily due to the recovery of incremental operating expenses and a higher rate base at ATSI, MAIT and JCP&L, partially offset by the impact of a true-up of the forward-looking rate.

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


	For the Years Ended December 31,
Revenues by Transmission Asset Owner	2020		2019		Increase
	(In millions)
ATSI	$	809	$	758	$	51
TrAIL	255		251		4
MAIT	254		227		27
JCP&L	178		160		18
Other	134		130		4
Total Revenues	$	1,630	$	1,526	$	104

Operating Expenses —

Total operating expenses increased $63 million in 2020, as compared to 2019, primarily due to higher property taxes and depreciation due to a higher asset base. The majority of operating expenses are recovered through formula rates, resulting in no material impact on current period earnings.

Income Taxes —

Regulated Transmission’s effective tax rate was 22.9% and 20.2% for 2020 and 2019, respectively due to changes in the amortization of excess deferred income taxes and the absence of certain tax benefits recognized in 2019.

Corporate/Other — 2020 Compared with 2019

Financial results from Corporate/Other and reconciling adjustments resulted in a $199 million increase in income from continuing operations for 2020 compared to 2019, primarily due to a $223 million decrease in the pension and OPEB mark-to-market adjustment, $10 million tax benefits from accelerated amortization of certain investment tax credits and lower other Pension and OPEB non-service costs. These were partially offset by higher other operating expenses from investigation-related costs and lower returns on certain equity method investments.

For the years ended December 31, 2020 and 2019, FirstEnergy recorded income from discontinued operations, net of tax, of $76 million and $8 million, respectively. The change in discontinued operations, net of tax was primarily due to lower settlement-related expenses with the FES Debtors, including adjustments to the estimated worthless stock deduction and Intercompany Tax Allocation Agreement, as well as the acceleration of net pension and OPEB prior service credits in 2020 and the absence of tax expense in 2019 associated with non-deductible interest.

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 relate to 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 FirstEnergy and information on comparable companies within similar jurisdictions, as well as assessing progress of communications between FirstEnergy and regulators. Certain of these regulatory assets, totaling approximately $117 million and $111 million as of December 31, 2020 and December 31, 2019, respectively, are recorded based on prior precedent or anticipated recovery based on rate making premises without a specific order, of which, $79 million and $73 million as of December 31, 2020 and December 31, 2019, respectively, are being sought for recovery in a formula rate amendment filing at ATSI that is pending before FERC. See Note 14, "Regulatory Matters" for additional information.

The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2020 and December 31, 2019, and the changes during the year ended December 31, 2020:


Net Regulatory Assets (Liabilities) by Source	December 31, 2020		December 31, 2019		Change
	(In millions)

Customer payables for future income taxes	$	(2,369)	$	(2,605)	$	236
Nuclear decommissioning and spent fuel disposal costs	(102)		(197)		95
Asset removal costs	(721)		(756)		35
Deferred transmission costs	316		298		18
Deferred generation costs	104		214		(110)
Deferred distribution costs	136		155		(19)
Contract valuations	41		51		(10)
Storm-related costs	748		551		197
Uncollectible and COVID-19 related costs	97		3		94
Other	6		25		(19)
Net Regulatory Liabilities included on the Consolidated Balance Sheets	$	(1,744)	$	(2,261)	$	517

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

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 and spent nuclear fuel disposal costs. As further discussed below, TMI-2, along with the NDT and related decommissioning liabilities, was transferred to TMI-2 Solutions, LLC, a subsidiary of EnergySolutions, LLC, on December 18, 2020, and therefore the related regulatory liabilities were written off. The remaining balance as of December 31, 2020, reflects liabilities for spent nuclear fuel disposal costs from former nuclear generating facilities, Oyster Creek and 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 (amortized through 2036), which are recorded as a regulatory asset or liability and recovered or refunded, respectively, in subsequent periods.

Contract valuations - Includes the amortization of purchase accounting adjustments at PE which were recorded in connection with the Allegheny Energy, Inc. merger representing the fair value of NUG purchased power contracts (amortized over the life of the contracts through 2030).

Storm-related costs - Relates to the recovery of storm costs, which vary by jurisdiction. Approximately $167 million and $193 million are currently being recovered through rates as of December 31, 2020 and 2019, respectively.

Uncollectible and COVID-19 related costs - Includes the deferral of prudently incurred incremental costs arising from COVID-19, including uncollectible expenses under new and existing riders prior to the pandemic.

The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2020 and 2019, of which approximately $195 million and $228 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral and the jurisdiction:


Regulatory Assets by Source Not Earning a Current Return	December 31, 2020		December 31, 2019		Change
			(in millions)

Deferred transmission costs	$	29	$	27	$	2
Deferred generation costs	5		15		(10)
Storm-related costs	654		471		183
COVID-19 related costs	66		—		66
Other	35		32		3
Regulatory Assets Not Earning a Current Return	$	789	$	545	$	244

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 2021 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 until 2022.

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


Reportable Segment	2019 Actual		2020 Actual		2021 Forecast	2022 Forecast	2023 Forecast
	(In millions)
Regulated Distribution		$1,698		$1,756	$1,725	$1,745	$1,680
Regulated Transmission		1,189		1,150	1,200	1,200 - 1,450	1,200 - 1,450
Corporate/Other		105		80	90	80	75
Total		$2,992		$2,986	Up to $3,015	Up to $3,025 - $3,275	Up to $2,955 - $3,205

In alignment with FirstEnergy’s strategy to invest in its Regulated Transmission and Regulated Distribution segments as a fully regulated company, FirstEnergy is focused on maintaining balance sheet strength and flexibility. 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.

(collectively, the FES Key Creditor Groups), the FES Debtors and the UCC. The FES Bankruptcy settlement agreement resolved certain claims by FirstEnergy against the FES Debtors, all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, as well as releases from third parties who voted in favor of the FES Debtors' plan of reorganization, in return for among other things, a cash payment of $853 million upon emergence. The FES Bankruptcy settlement was conditioned on the FES Debtors confirming and effectuating a plan of reorganization acceptable to FirstEnergy.

The outbreak of COVID-19 is a global pandemic. FirstEnergy is continuously evaluating the global pandemic and taking steps to mitigate known risks. FirstEnergy is actively monitoring the continued impact COVID-19 is having on its customers’ receivable balances, which include increasing arrears balances since the pandemic has begun. FirstEnergy has incurred, and it is expected to incur for the foreseeable future, incremental uncollectible and other COVID-19 pandemic related expenses. COVID-19 related expenses consist of additional costs that FirstEnergy is incurring to protect its employees, contractors and customers, and to support social distancing requirements. These costs include, but are not limited to, new or added benefits provided to employees, the purchase of additional personal protection equipment and disinfecting supplies, additional facility cleaning services, initiated programs and communications to customers on utility response, and increased technology expenses to support remote working, where possible. The full impact on FirstEnergy’s business from the COVID-19 pandemic, including the governmental and regulatory responses, is unknown at this time and difficult to predict. FirstEnergy provides a critical and essential service to its customers and the health and safety of its employees, contractors and customers is its first priority. FirstEnergy is continuously monitoring its supply chain and is working closely with essential vendors to understand the continued impact the COVID-19 pandemic is having on its business, however, FirstEnergy does not currently expect disruptions in its ability to deliver service to customers or any material impact on its capital spending plan.

FirstEnergy continues to effectively manage operations during the pandemic in order to provide critical service to customers and believes it is well positioned to manage through the economic slowdown. FirstEnergy Distribution and Transmission revenues benefit from geographic and economic diversity across a five-state service territory, which also allows for flexibility with capital investments and measures to maintain sufficient liquidity over the next twelve months. However, the situation remains fluid and future impacts to FirstEnergy that are presently unknown or unanticipated may occur. Furthermore, the likelihood of an impact to FirstEnergy, and the severity of any impact that does occur, could increase the longer the global pandemic persists.

investment plans and reductions to operating expenses, as well as changes to its planned equity issuances, to allow for flexibility should a fine or other regulatory actions be imposed as a result of the government investigations.

As further discussed below, in connection with a partial settlement with the OAG and other parties, the Ohio Companies filed an application with the PUCO on February 1, 2021, to set the respective decoupling riders (Rider CSR) to zero. While the partial settlement with the OAG focused specifically on decoupling, the Ohio Companies will of their own accord not seek to recover lost distribution revenue from residential and commercial customers. FirstEnergy is committed to pursuing an open dialogue with stakeholders in an appropriate manner with respect to the numerous regulatory proceedings currently underway as further discussed herein. As a result of the partial settlement, and the decision to not seek lost distribution revenue, FirstEnergy recognized a $108 million pre-tax charge ($84 million after-tax) in the fourth quarter of 2020, and $77 million (pre-tax) of which is associated with forgoing collection of lost distribution revenue. FirstEnergy does not believe a refund for previously collected amounts under decoupling, which was approximately $18 million, is probable. Furthermore, as FirstEnergy would not have financially benefited from the Clean Air Fund included in HB 6, which is the mechanism to provide support to nuclear energy in Ohio, there is no expected additional impact to FirstEnergy due to any repeal of that provision of HB 6.

As of December 31, 2020, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was primarily due to accounts payable, short-term borrowings, and accrued interest, taxes, compensation and benefits. FirstEnergy believes its cash from operations and available liquidity will be sufficient to meet its current working capital needs.

Short-Term Borrowings / Revolving Credit Facilities

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’s revolving credit facilities bear 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, and there is considerable uncertainty regarding the publication of LIBOR beyond 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.

On November 17, 2020, FE and the Utilities and FET and certain of its subsidiaries entered into amendments to the FE credit facility and the FET credit facility, respectively. The amendments provide for modifications and/or waivers of: (i) certain representations and warranties, and (ii) certain affirmative and negative covenants, contained therein, which allowed FirstEnergy to regain compliance with such provisions. In addition, among other things, the amendment to the FE credit facility reduces the

sublimit applicable to FE to $1.5 billion, and the amendments increased certain tiers of pricing applicable to borrowings under the credit facilities.

FirstEnergy had $2.2 billion and $1.0 billion of short-term borrowings as of December 31, 2020 and 2019, respectively. FirstEnergy’s available liquidity from external sources as of February 15, 2021, was as follows:


Borrower(s)	Type	Maturity	Commitment		Available Liquidity
			(In millions)
FirstEnergy(1)	Revolving	December 2022	$	2,500	$	1,296

FET(2)	Revolving	December 2022	1,000		—
		Subtotal	$	3,500	$	1,296
	Cash and cash equivalents		—		1,792
		Total	$	3,500	$	3,088

(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 sublimits 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, 2021:


Borrower	FirstEnergy Revolving Credit Facility Sublimit			FET Revolving Credit Facility Sublimit			Regulatory and Other Short-Term Debt Limitations
	(In millions)
FE		$	1,500		$	—		$	—	(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.

Subject to each borrower’s sublimit, $250 million of the FE credit facility and $100 million of the FET credit facility, 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 sublimit.

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, 2020, the borrowers were in compliance with the applicable debt-to-total-capitalization ratio covenants in each case as defined under the respective Facilities.

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 2020 was 0.89% per annum for the regulated companies’ money pool and 1.19% 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 15, 2021:


	Corporate Credit Rating			Senior Secured			Senior Unsecured			Outlook/Watch (1)
Issuer	S&P	Moody’s	Fitch	S&P	Moody’s	Fitch	S&P	Moody’s	Fitch	S&P	Moody’s	Fitch
FE	BB	Ba1	BB+				BB	Ba1	BB+	CW-N	N	N
AGC	BB	Baa2	BBB-							CW-N	S	N
ATSI	BB	A3	BBB-				BB+	A3	BBB	CW-N	S	N
CEI	BB	Baa2	BBB-	BBB	A3	BBB+	BB+	Baa2	BBB	CW-N	N	N
FET	BB	Baa2	BB+				BB	Baa2	BB+	CW-N	N	N
JCP&L	BB	A3	BBB-				BB+	A3	BBB	CW-N	S	N
ME	BB	A3	BBB-				BB+	A3	BBB	CW-N	S	N
MAIT	BB	A3	BBB-				BB+	A3	BBB	CW-N	S	N
MP	BB	Baa2	BBB-	BBB	A3	BBB+	BB+	Baa2		CW-N	S	N
OE	BB	A3	BBB-	BBB	A1	BBB+	BB+	A3	BBB	CW-N	N	N
PN	BB	Baa1	BBB-				BB+	Baa1	BBB	CW-N	S	N
Penn	BB	A3	BBB-	BBB	A1	BBB+				CW-N	S	N
PE	BB	Baa2	BBB-	BBB	A3	BBB+				CW-N	S	N
TE	BB	Baa1	BBB-	BBB	A2	BBB+				CW-N	N	N
TrAIL	BB	A3	BBB-				BB+	A3	BBB	CW-N	S	N
WP	BB	A3	BBB-	BBB	A1	BBB+				CW-N	S	N

(1) S = Stable, P = Positive, N = Negative, CW-N = CreditWatch with Negative implications

On May 27, 2020, Moody’s upgraded the issuer and senior unsecured ratings of JCP&L to A3 from Baa1 and the rating outlook was changed to stable.

On July 23, 2020, S&P placed the ratings of FE and its subsidiaries on CreditWatch with negative implications.

On July 24, 2020, Moody’s revised FE’s ratings outlook to negative from stable. FE’s Baa3 corporate credit rating and Baa3 senior unsecured rating were affirmed.

On July 28, 2020, Fitch revised FE and its subsidiaries, with the exception of MP, AGC and PE, ratings outlook to negative from stable. The outlook of MP, AGC and PE is stable. Fitch also affirmed FE and its subsidiary ratings.

On August 14, 2020, Moody’s affirmed OE’s A3 senior unsecured and issuer ratings and Penn’s A3 issuer rating. The outlooks were changed to stable from positive.

On October 30, 2020, Fitch downgraded FE and FET’s issuer default ratings and senior unsecured ratings one notch to BBB- from BBB. Fitch also downgraded FE’s subsidiaries issuer default ratings one notch to BBB from BBB+, except for PE, MP, and AGC, whose ratings were affirmed at BBB. Senior unsecured issue ratings for the subsidiaries were downgraded one notch, where applicable, to BBB+ from A-. Senior secured issue ratings for the subsidiaries were downgraded one notch, where applicable, to A- from A. The rating outlook is negative for FE and its subsidiaries.

On October 30, 2020, S&P downgraded FE and its subsidiaries issuer credit ratings two notches to BB+ from BBB, except for AGC which was lowered to BB from BBB-. The senior unsecured issue ratings of FE and FET were changed one notch to BB+ from BBB-. The senior unsecured issue ratings of the subsidiaries, where applicable, were lowered one notch to BBB- from BBB. Additionally, the senior secured issue ratings of the subsidiaries, where applicable, were lowered one notch to BBB+ from A-. The ratings on FE and its subsidiaries remain on CreditWatch with negative implications.

On November 20, 2020, Fitch downgraded the issuer default rating (IDR) and senior unsecured ratings of FE and FET one notch, to BB+ from BBB-. The IDRs of the remaining subsidiaries were also lowered one notch to BBB- from BBB, the senior unsecured ratings were lowered (where applicable) one notch to BBB from BBB+, and the senior secured ratings were lowered (where applicable) one notch to BBB+ from A-. The outlook for FE and its subsidiaries remains negative.

On November 24, 2020, Moody’s downgraded the ratings of FE Corp, including its senior unsecured rating to Ba1 from Baa3. Moody’s also assigned a Ba1 Corporate Family Rating to FE and withdrew FE’s Baa3 Issuer Rating. The outlook for FE remains negative. Additionally, the outlooks for OE, TE, CE, and FET were changed to negative from stable.

On November 24, 2020, S&P downgraded FE and its subsidiaries issuer credit ratings to BB from BB+ and affirmed the BB issuer credit rating of AGC. The senior unsecured ratings on FE and FET were lowered to BB from BB+. The subsidiary senior unsecured ratings were lowered, where applicable, to BB+ from BBB-, and the senior secured ratings, where applicable, were lowered to BBB from BBB+. The ratings remain on CreditWatch Negative.

On December 17, 2020, Moody’s assigned senior secured ratings of A3 to PE and A1 to WP.

On December 21, 2020, S&P assigned senior secured ratings of BBB to PE, Penn and WP.

As of December 31, 2020, $20 million of collateral has been posted by FE or its subsidiaries, of which, $19 million was posted as a result of the credit rating downgrades in the fourth quarter of 2020.

The applicable undrawn and drawn margin on the FE and FET credit facilities are subject to ratings-based pricing grids. The applicable fee paid on the undrawn commitments under the FE and FET credit facilities are based on FE and FET’s senior unsecured non-credit enhanced debt ratings as determined by S&P and Moody’s. The fee paid on actual borrowings are determined based on each borrower’s senior unsecured non-credit enhanced debt ratings as determined by S&P and Moody’s.

The interest rate payable on approximately $3.85 billion in FE’s senior unsecured notes are subject to adjustments from time to time if the ratings on the notes from any one or more of S&P, Moody’s and Fitch decreases to a rating set forth in the applicable documents. Generally a one-notch downgrade by the applicable rating agency may result in a 25 bps coupon rate increase beginning at BB, Ba1, and BB+ for S&P, Moody’s and Fitch, respectively, to the extent such rating is applicable to the series of outstanding senior unsecured notes, during the next interest period, subject to an aggregate cap of 2% from issuance interest rate.

Debt capacity is subject to the consolidated debt-to-total-capitalization limits in the credit facilities previously discussed. As of December 31, 2020, FE and its subsidiaries could issue additional debt of approximately $4.8 billion, or incur a $2.6 billion reduction to equity, and remain within the limitations of the financial covenants required by the FE credit facility.

Changes in Cash Position

As of December 31, 2020, FirstEnergy had $1,734 million of cash and cash equivalents and approximately $67 million of restricted cash compared to $627 million of cash and cash equivalents and approximately $52 million of restricted cash as of December 31, 2019, 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. Beyond the cash settlement and tax sharing payments to the FES Debtors in 2020, and pension contribution in 2019, 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 $1,423 million during 2020, $2,467 million during 2019 and $1,410 million during 2018.

2020 compared with 2019

Cash flows from operations decreased $1,044 million in 2020 as compared with 2019. The year-over-year change in cash from operations is primarily due to the $978 million cash settlement and tax sharing payments made to the FES Debtors upon their emergence in February 2020, an increase to accounts receivable customer balances due to the impact of COVID-19, and higher storm restoration costs, partially offset by the absence of a $500 million cash contribution to the qualified pension plan in 2019.

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, 2020, 2019 and 2018:


	For the Years Ended December 31,
(In millions)	2020		2019		2018

CASH FLOWS FROM OPERATING ACTIVITIES:
Income from discontinued operations	$	76	$	8	$	326
Gain on disposal, net of tax	(76)		(59)		(435)
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs	—		—		110
Deferred income taxes and investment tax credits, net	—		47		61
Unrealized (gain) loss on derivative transactions	—		—		(10)

Cash Flows From Financing Activities

Cash provided from financing activities was $2,607 million, $656 million, and $1,394 million in 2020, 2019, and 2018, respectively. 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	2020		2019		2018
	(In millions)
New Issues
Preferred stock issuance	$	—	$	—	$	1,616
Common stock issuance	—		—		850
Unsecured notes	3,250		1,850		850
PCRBs	—		—		74

FMBs	175		450		50
Term loan	—		—		500


	$	3,425	$	2,300	$	3,940

Redemptions / Repayments
Unsecured notes	$	(250)	$	(725)	$	(555)
PCRBs	—		—		(216)
FMBs	(50)		(1)		(325)
Term loan	(750)		—		(1,450)
Senior secured notes	(64)		(63)		(62)

	$	(1,114)	$	(789)	$	(2,608)

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

Short-term borrowings, net	$	1,200	$	—	$	950

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

Common stock dividend payments	$	(845)	$	(814)	$	(711)

On February 20, 2020, FE issued $1.75 billion in senior unsecured notes in three separate series: (i) $300 million aggregate principal amount of 2.050% Notes, Series A, due 2025, (ii) $600 million aggregate principal amount of 2.650% Notes, Series B, due 2030 and (iii) $850 million aggregate principal amount of 3.400% Notes, Series C, due 2050. Proceeds from the issuance of the notes, together with cash on hand, were used: (i) to repay the entire $750 million two-year term loan due September 2021, (ii) to make the $853 million in bankruptcy settlement payments and $125 million tax sharing agreement payment with the FES Debtors as discussed above, (iii) to repay $250 million of the $1 billion outstanding 364-day term loan due September 2020, and (iv) for working capital needs and general corporate purposes.

On March 31, 2020, MAIT issued $125 million of 3.60% senior unsecured notes due 2032 and $125 million of 3.70% senior unsecured notes due 2035. Proceeds from the issuance of the notes were used: (i) to refinance existing debt, (ii) for capital expenditures, and (iii) for general corporate purposes.

On April 20, 2020, PN issued $125 million of 3.61% senior unsecured notes due 2032 and $125 million of 3.71% senior unsecured notes due 2035. Proceeds of the issuance of the notes were used: (i) to refinance indebtedness, including short-term borrowings incurred under the FirstEnergy regulated money pool to repay a portion of the $250 million aggregate principle amount of PN’s 5.20% Senior Notes due April 1, 2020, (ii) to fund capital expenditures, (iii) to fund general corporate purposes, or (iv) for any combination of the above.

On June 8, 2020, FE issued $750 million in senior unsecured notes in two separate series: (i) $300 million aggregate principal amounts of 1.600% Notes, Series A, due 2026 and (ii) $450 million aggregate principal amount of 2.250% Notes, Series B, due 2030. Proceeds from the issuance of the notes were used to repay all amounts outstanding under the 364-day term loan due September 2020.

On June 29, 2020, PE issued $75 million of 2.67% FMBs due 2032 and $100 million of 3.43% FMBs due 2051. Proceeds of the issuance of the FMBs were used to repay short-term borrowings under the FirstEnergy regulated money pool, to fund capital expenditures, and for general corporate purposes.

On July 20, 2020, CEI issued $150 million of 2.77% senior unsecured notes due 2034 and $100 million of 3.23% senior unsecured notes due 2040. Proceeds from the issuance of the notes were used to refinance existing short-term borrowings, to fund capital expenditures, and for general corporate purposes.

Cash Flows From Investing Activities

Cash used for investing activities in 2020 principally represented cash used for property additions. The following table summarizes investing activities for 2020, 2019 and 2018:


	For the Years Ended December 31,
Cash Used for (Provided from) Investing Activities	2020		2019		2018
	(In millions)
Property Additions:
Regulated Distribution	$	1,514	$	1,473	$	1,411
Regulated Transmission	1,067		1,090		1,104

Corporate/Other	76		102		160
Proceeds from asset sales	(2)		(47)		(425)
Investments	22		38		54
Notes receivable from affiliated companies	—		—		500
Asset removal costs	224		217		218
Other	7		—		(4)
	$	2,908	$	2,873	$	3,018

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, 2020, 2019 and 2018:


	For the Years Ended December 31,
(In millions)	2020		2019		2018

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	$	—	$	—	$	(27)

Sales of investment securities held in trusts	—		—		109
Purchases of investment securities held in trusts	—		—		(122)

CONTRACTUAL OBLIGATIONS

As of December 31, 2020, FirstEnergy's estimated undiscounted cash payments under existing contractual obligations that it considers firm obligations are as follows:


Contractual Obligations	Total		2021		2022-2023		2024-2025		Thereafter
	(In millions)
Long-term debt(1)	$	22,377	$	132	$	2,337	$	3,269	$	16,639
Short-term borrowings	2,200		2,200		—		—		—
Interest on long-term debt(2)	12,808		999		1,874		1,647		8,288
Operating leases(3)	366		50		95		74		147
Finance leases(3)	61		18		23		8		12
Fuel and purchased power(4)	3,049		499		883		652		1,015
Capital expenditures(5)	2,028		548		778		702		—
Pension funding	870		—		399		471		—
Total	$	43,759	$	4,446	$	6,389	$	6,823	$	26,101

(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, 2020.

(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, 2020.

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 $2.7 billion in 2021.

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 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.

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, 2020, was approximately $1.7 billion, as summarized below:


Guarantees and Other Assurances	Maximum Exposure
	(In millions)








FE's Guarantees on Behalf of its Consolidated Subsidiaries
AE Supply asset sales(1)	$	570



Deferred compensation arrangements	475
Fuel related contracts and other	7
	1,052
FE's Guarantees on Other Assurances
Global Holding Facility	108
Deferred compensation arrangements	146
Surety Bonds	328

LOCs and other	16
	598
Total Guarantees and Other Assurances	$	1,650

(1)As a condition to closing AE Supply's sale of four natural gas generating plants and an approximately 59% portion of AGC's interest in the Bath Power Station, FE provided the purchaser two limited three-year guarantees totaling $555 million of certain obligations of AE Supply and AGC, which by their terms expire in May 2021. In addition, as a condition to closing AE Supply's transfer of Pleasants Power Station and as contemplated under the FES Bankruptcy settlement agreement, FE has provided two additional guarantees for certain retained liabilities of AE Supply, the first totaling up to $15 million for certain environmental liabilities associated with Pleasants Power Station, and the second being limited solely to environmental liabilities for the McElroy's Run CCR impoundment facility, for which an ARO of $46 million is reflected on FirstEnergy's Consolidated Balance Sheet, and which is not reflected on the table above.

Collateral and Contingent-Related Features

In the normal course of business, FE and its subsidiaries may enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain agreements 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.

These credit-risk-related contingent features 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. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of December 31, 2020:


Potential Collateral Obligations	Utilities and FET		FE		Total
	(In millions)
Contractual Obligations for Additional Collateral

Upon Further Downgrade	$	37	$	—	$	37

Surety Bonds (Collateralized Amount)(1)	55		258		313
Total Exposure from Contractual Obligations	$	92	$	258	$	350

(1) Surety Bonds are not tied to a credit rating. Surety Bonds' impact assumes maximum contractual obligations, which is ordinarily 100% of the face amount of the surety bond except with the respect to $39 million of surety obligations for which the collateral obligation is capped at 60% of the face amount, and typical obligations require 30 days to cure.

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 $108 million as of December 31, 2020. Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, and FE 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, 2020, FirstEnergy has a net liability of $3 million in non-hedge derivative contracts that are related to FTRs at certain of the Utilities. FTRs are subject to regulatory accounting and do not impact earnings.

Equity Price Risk

As of December 31, 2020, the FirstEnergy pension plan assets were allocated approximately as follows: 23% in equity securities, 35% in fixed income securities, 7% in hedge funds, 4% in insurance-linked securities, 9% in real estate, 5% in private equity and 17% 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. As a result of this contribution and pension investment performance returns to date, FirstEnergy expects no required contributions until 2022. As of December 31, 2020, FirstEnergy's OPEB plan assets were allocated approximately 55% in equity securities, 28% in fixed income securities and 17% in cash and short-term securities. Investment markets experienced elevated market volatility during 2020 as a result of the U.S. general election and the COVID-19 pandemic. In order to reduce the effect of market volatility on the plan's funded status and to preserve capital gains experienced during the first half of 2020, approximately $1.4 billion of return-seeking assets were sold (including approximately $800 million of equity securities) during the third quarter of 2020. These assets are expected be reinvested in return seeking investments (including equity securities) during 2021, which will more consistently align the pension and OPEB trust portfolios to the company’s target asset allocations. See Note 5, "Pension and Other Post-Employment Benefits," of the Notes to Consolidated Financial Statements for additional details on FirstEnergy's pension and OPEB plans.

During 2020, FirstEnergy's pension and OPEB plan assets gained approximately 14.8% and 13.2%, respectively, as compared to an annual expected return on plan assets of 7.50%. On February 27, 2020, FirstEnergy remeasured its plan assets, and from that date through December 31, 2020, FirstEnergy's pension and OPEB plan assets gained approximately 11.6% and 12.5%, respectively.

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	2021			2022			2023			2024			2025			There-after			Total			Fair Value
	(In millions)
Assets:
Investments Other Than Cash and Cash Equivalents:
Fixed Income	$	—		$	—		$	—		$	—		$	—		$	276		$	276		$	401
Average interest rate	—		%	—		%	—		%	—		%	—		%	4.0		%	4.0		%

Liabilities:
Long-term Debt:
Fixed rate	$	132		$	1,143		$	1,194		$	1,246		$	2,023		$	16,639		$	22,377		$	25,465
Average interest rate	3.7		%	4.1		%	4.1		%	4.7		%	3.8		%	4.6		%	4.5		%

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.

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. In addition, in response to the COVID-19 pandemic, FirstEnergy has increased reviews of counterparties, customers and industries that have been negatively impacted, which could affect meeting contractual obligations with FirstEnergy. FirstEnergy 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, it is expected that 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, and surveys to determine negative impacts to essential vendors as a result of the COVID-19 pandemic. 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

CARES ACT

On March 27, 2020, President Trump signed into law the CARES Act, an economic stimulus package in response to the COVID-19 pandemic containing several corporate income tax provisions, including making remaining AMT credits immediately refundable; providing a 5-year carryback of NOLs generated in tax years 2018, 2019, and 2020, and removing the 80% taxable income limitation on utilization of those NOLs if carried back to prior tax years or utilized in tax years beginning before 2021; and temporarily liberalizing the interest deductibility rules under Section 163(j) of the Tax Act, by raising the adjusted taxable income limitation from 30% to 50% for tax years 2019 and 2020 and giving taxpayers the election of using 2019 adjusted taxable income for purposes of computing 2020 interest deductibility. FirstEnergy has applied for refund of its remaining approximately $18 million refundable AMT credits. FirstEnergy does not expect to generate additional income tax refunds from the carryback of NOLs and expects interest to be fully deductible in the 2020 consolidated federal income tax return and going forward. FirstEnergy does not currently expect the other provisions of the CARES Act to have a material effect on current income tax expense or the realizability of deferred income tax assets.

On July 28, 2020, the IRS issued final regulations implementing interest expense deduction limitation rules under section 163(j) of the Internal Revenue Code. The final regulations changed certain rules on the computation of interest expense and limitation amount, as well as rules relevant to status as a regulated utility business and the allocation of consolidated group interest expense between utility and non-utility businesses. After reviewing the final regulations, FirstEnergy recorded a true-up to prior years’ reserve estimates during the third quarter of 2020, which did not have a material impact to FirstEnergy’s income statement. On January 6, 2021, the IRS released an additional set of final regulations under Section 163(j) primarily addressing partnership, real estate, and certain controlled foreign corporation issues, which do not materially impact FirstEnergy.

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, ATSI in Ohio, and the Transmission Companies in Pennsylvania are subject to certain regulations of the VSCC, PUCO and PPUC, respectively. 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(3)	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.

(3) On October 28, 2020, the NJBPU approved JCP&L's distribution rate case settlement with an allowed ROE of 9.6% and a 48.56% debt / 51.44% equity capital structure. Rates are effective for customers on November 1, 2021, but beginning January 1, 2021, JCP&L will offset the impact to customers' bills by amortizing an $86 million regulatory liability.

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 through an annually reconciled surcharge, with most 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 September 1, 2020, PE filed its proposed plan for the 2021-2023 EmPOWER Maryland program cycle. The new plan largely continues PE’s existing programs and is estimated to cost approximately $148 million over the three-year period. The MDPSC approved the plan on December 18, 2020.

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. On September 22, 2020, PE filed its depreciation study reflecting a depreciation expense of $36.2 million, which represented a slight increase, and as a result, is seeking difference in depreciation be deferred for future recovery in PE’s next base rate case. The MDPSC has set the matter for hearing and delegated it to a public utility law judge. On November 6, 2020, an order was issued scheduling evidentiary hearings in April 2021. On January 29, 2021, the Maryland Office of People's Counsel filed testimony recommending a reduction in depreciation expense of $10.8 million, and the staff of the MDPSC filed testimony recommending a reduction of $9.6 million. PE's rebuttal testimony is due on March 2, 2021.

Maryland’s Governor issued an order on March 16, 2020, forbidding utilities from terminating residential service or charging late fees for non-payment for the duration of the COVID-19 pandemic. On April 9, 2020, the MDPSC issued an order allowing utilities to track and create a regulatory asset for future recovery of all prudently incurred incremental costs arising from the COVID-19 pandemic, including incremental uncollectible expense, incurred from the date of the Governor’s order (or earlier if the utility could show that the expenses related to suspension of service terminations). On July 8, 2020, the MDPSC issued a notice opening a public conference to collect information from utilities and other stakeholders about the impacts of the COVID-19 pandemic on the utilities and their customers. The MDPSC subsequently issued orders allowing Maryland electric and gas utilities to resume residential service terminations for non-payment on November 15, 2020, subject to various restrictions, and clarifying that utilities could resume charging late fees on October 1, 2020.

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. Oral Argument is scheduled for March 10, 2021. 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 May 8, 2019, the NJBPU approved a stipulation of settlement submitted by JCP&L, Rate Counsel, NJBPU staff and New Jersey Large Energy Users Coalition to implement JCP&L’s infrastructure plan, JCP&L Reliability Plus. The plan provides that JCP&L will invest up to approximately $97 million in capital investments beginning on June 1, 2019 through December 31, 2020, to enhance the reliability and resiliency of JCP&L’s distribution system and reduce the frequency and duration of power outages. 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. The NJBPU approved adjusted rates that took effect on March 1, 2020. As further discussed below, JCP&L will recover the IIP capital investments, which totaled $97 million, as part of its distribution base rate case.

On February 18, 2020, JCP&L submitted a filing with the NJBPU requesting a distribution base rate increase of $186.9 million on an annual basis, which represents an overall average increase in JCP&L rates of 7.8%. The filing seeks to recover certain costs associated with providing safe and reliable electric service to JCP&L customers, along with recovery of previously incurred storm costs. JCP&L proposed a rate effective date of March 19, 2020. The NJBPU issued orders suspending JCP&L’s proposed rates

until November 19, 2020. JCP&L filed updates to the requested distribution base rate in both June and July 2020, resulting in JCP&L seeking a total annual distribution base rate increase of approximately $185 million. On October 16, 2020, the parties submitted a stipulation of settlement to the administrative law judge, providing for, among other things, a $94 million annual base distribution revenues increase for JCP&L based on an ROE of 9.6%, which will become effective for customers on November 1, 2021. Until the rates become effective, and starting on January 1, 2021, JCP&L is permitted to amortize an existing regulatory liability totaling approximately $86 million to offset the base rate increase that otherwise would have occurred in this period. The parties also agreed that the actual net gain from the sale of JCP&L’s interest in the Yards Creek pumped-storage hydro generation facility in New Jersey (210 MWs), as further discussed below, shall be applied to reduce JCP&L’s existing regulatory asset for previously deferred storm costs. Lastly, the parties agreed that $95.1 million of Reliability Plus capital investment for projects through December 31, 2020 is included in rate base effective December 31, 2020, with a final prudence review of only those capital investment projects from July 1, 2020 through December 31, 2020 to occur in January 2021. On October 22, 2020, the administrative law judge entered an initial decision adopting the settlement. On October 28, 2020, the NJBPU approved the settlement and directed an upcoming management audit for JCP&L. On January 4, 2021, JCP&L submitted its review of storm costs as required under the stipulation of settlement. On January 15, 2021, JCP&L filed a written report for its Reliability Plus projects placed in service from July 1, 2020 through December 31, 2020, also as required under the stipulation of settlement.

On April 6, 2020, JCP&L signed an asset purchase agreement with Yards Creek Energy, LLC, a subsidiary of LS Power to sell its 50% interest in the Yards Creek pumped-storage hydro generation facility. Subject to terms and conditions of the agreement, the base purchase price is $155 million. On July 31, 2020, FERC approved the transfer of JCP&L’s interest in the hydroelectric operating license. On October 8, 2020, FERC issued an order authorizing the transfer of JCP&L’s ownership interest in the hydroelectric facilities. On October 28, 2020, the NJBPU approved the sale of Yards Creek. Completion of the transaction is subject to several closing conditions; there can be no assurance that all closing conditions will be satisfied or that the transaction will be consummated. JCP&L currently anticipates closing of the transaction to occur during the first quarter of 2021. Assets held for sale on FirstEnergy’s Consolidated Balance Sheets associated with the transaction consist of property, plant and equipment of $45 million, which is included in the regulated distribution segment.

On August 27, 2020, JCP&L filed an AMI Program with the NJBPU, which proposes the deployment of approximately 1.2 million advanced meters over a three-year period beginning on January 1, 2023, at a total cost of approximately $418 million, including the pre-deployment phase. The 3-year deployment is part of the 20-year AMI Program that is expected to cost a total of approximately $732 million and proposes a cost recovery mechanism through a separate AMI tariff rider. On January 13, 2021, a procedural schedule was established, which includes evidentiary hearings the week of May 24, 2021.

On June 10, 2020, the NJBPU issued an order establishing a framework for the filing of utility-run energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act. Under the established framework, JCP&L will recover its program investments over a ten year amortization period and its operations and maintenance expenses on an annual basis, be eligible to receive lost revenues on energy savings that resulted from its programs and be eligible for incentives or subject to penalties based on its annual program performance, beginning in the fifth year of its program offerings. On September 25, 2020, JCP&L filed its energy efficiency and peak demand reduction program. JCP&L’s program consists of 11 energy efficiency and peak demand reduction programs and subprograms to be run from July 1, 2021 through June 30, 2024. The program also seeks approval of cost recovery totaling approximately $230 million as well as lost revenues associated with the energy savings resulting from the programs. While a procedural order has been established in this matter, on January 20, 2021, JCP&L filed a letter requesting a suspension of the procedural schedule to allow for settlement discussions. The Clean Energy Act contemplates a final order from the NJBPU by May 2, 2021.

On July 2, 2020, the NJBPU issued an order allowing New Jersey utilities to track and create a regulatory asset for future recovery of all prudently incurred incremental costs arising from the COVID-19 pandemic beginning March 9, 2020 through September 30, 2021, or until the Governor issues an order stating that the COVID-19 pandemic is no longer in effect. New Jersey utilities can request recovery of such regulatory asset in a stand-alone COVID-19 regulatory asset filing or future base rate case. On August 21, 2020, the Governor of New Jersey issued a press release announcing that the New Jersey utilities agreed to extend their voluntary moratorium preventing shutoffs to both residential and commercial customers during the COVID-19 pandemic until October 15, 2020. On October 15, 2020, the Governor issued an Executive Order prohibiting utilities from terminating service to any residential gas, electric, public and private water customer, through March 15, 2021, requiring the reconnection of certain customers, and disallowing the charging of late payment charges or reconnection fees during the public health emergency. On October 28, 2020, the NJBPU issued an order expanding the scope of the proceeding to examine all pandemic issues, including recovery of the COVID-19 regulatory assets, by way of a generic proceeding. On November 30, 2020, JCP&L submitted comments.

The recent credit rating actions taken on October 28, 2020, by S&P and Fitch triggered a requirement from various NJBPU orders that JCP&L file a mitigation plan, which was filed on November 5, 2020, to demonstrate that JCP&L has sufficient liquidity to meet its BGS obligations. On December 11, 2020, the NJBPU held a public hearing on the mitigation plan. Written comments on JCP&L’s mitigation plan were submitted on January 8, 2021.

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 were decoupled, through a mechanism that took effect on February 1, 2020 and under which the Ohio Companies billed customers until February 9, 2021, 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 the DCR rider, 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 revenue associated with energy efficiency and peak demand reduction programs, which is discussed further below; (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 the 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. On appeal, the SCOH, on June 19, 2019, reversed the PUCO’s determination that the DMR is lawful, and remanded the matter to the PUCO with instructions to remove the DMR from ESP IV. The PUCO entered an order directing the Ohio Companies to cease further collection through the DMR, credit back to customers a refund of the DMR funds collected since July 2, 2019 and remove the DMR from ESP IV. On July 15, 2019, OCC filed a Notice of Appeal with the SCOH, challenging the PUCO’s exclusion of the DMR revenues from the determination of the existence of significantly excessive earnings under ESP IV for calendar year 2017 for OE and claiming a $42 million refund is due to OE customers. On December 1, 2020, the SCOH reversed the PUCO’s exclusion of the DMR revenues from the determination of the existence of significantly excessive earnings under ESP IV for OE for calendar year 2017, and remanded the case to the PUCO with instructions to conduct new proceedings which includes the DMR revenues in the analysis, determines the threshold against which the earned return is measured, and makes other necessary determinations. FirstEnergy is unable to predict the outcome of these proceedings but has not deemed a liability probable as of December 31, 2020.

On July 23, 2019, Ohio enacted HB 6, which established support for nuclear energy supply in Ohio. In addition to the provisions supporting nuclear energy, HB 6 included provisions implementing a decoupling mechanism for Ohio electric utilities and ending current energy efficiency program mandates on December 31, 2020, provided that statewide energy efficiency mandates are achieved as determined by the PUCO. On February 26, 2020, the PUCO ordered a wind-down of statutorily required energy efficiency programs to commence on September 30, 2020, that the programs terminate on December 31, 2020, with the Ohio Companies' existing portfolio plans extended through 2020 without changes.

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. Legislation has been introduced in the first quarter of 2021 to, among other things, repeal parts of HB 6, the legislation that established support for nuclear energy supply in Ohio, provided for a decoupling mechanism for Ohio electric utilities, and provided for the ending of current energy efficiency program mandates. As further discussed below, in connection with a partial settlement with the OAG and other parties, the Ohio Companies filed an application with the PUCO on February 1, 2021, to set the respective decoupling riders (Rider CSR) to zero. While the partial settlement with the OAG focused specifically on decoupling, the Ohio Companies will of their own accord not seek to recover lost distribution revenue from residential and commercial customers. FirstEnergy is committed to pursuing an open dialogue with stakeholders in an appropriate manner with respect to the numerous regulatory proceedings currently underway as further discussed herein. As a result of the partial settlement, and the decision to not seek lost distribution revenue, FirstEnergy recognized a $108 million pre-tax charge ($84 million after-tax) in the fourth quarter of 2020, and $77 million (pre-tax) of which is associated with forgoing collection of lost distribution revenue. FirstEnergy does not believe a refund for previously collected amounts under decoupling, which was approximately $18 million, is probable. Furthermore, as FirstEnergy would not have financially benefited from the Clean Air Fund included in HB 6, which is the mechanism to provide support to nuclear energy in Ohio, there is no expected additional impact to FirstEnergy due to any repeal of that provision of HB 6.

On July 17, 2019, the PUCO approved, with no material modifications, a settlement agreement that provides for the implementation of the Ohio Companies’ 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. 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.

In March 2020, the PUCO issued entries directing utilities to review their service disconnection and restoration policies and suspend, for the duration of the COVID-19 pandemic, otherwise applicable requirements that may impose a service continuity hardship or service restoration hardship on customers. The Ohio Companies are utilizing their existing approved cost recovery mechanisms where applicable to address the financial impacts of these directives. On July 31, 2020, the Ohio Companies filed with the PUCO their transition plan and requests for waivers to allow for the safe resumption of normal business operations, including service disconnections for non-payment. On September 23, 2020, the PUCO approved the Ohio Companies’ transition plan, including approval of the resumption of service disconnections for non-payment, which the Ohio Companies began on October 5, 2020.

On July 29, 2020, the PUCO consolidated the Ohio Companies’ Applications for determination of the existence of significantly excessive earnings, or SEET, under ESP IV for calendar years 2018 and 2019, which had been previously filed on July 15, 2019, and May 15, 2020, respectively, and set a procedural schedule with evidentiary hearings scheduled for October 29, 2020. The calculations included in the Ohio Companies’ SEET filings for calendar years 2018 and 2019 demonstrate that the Ohio Companies did not have significantly excessive earnings, however, FirstEnergy and the Ohio Companies are unable to predict the PUCO’s ultimate determination of the applications. On August 3, 2020, the OCC filed an interlocutory appeal asking the PUCO to stay the SEET proceeding until the SCOH determines whether DMR should be excluded from the SEET, as further discussed above. Furthermore, on January 21, 2021, Senate Bill 10 was introduced, which would repeal legislation passed in 2019 that permitted the Ohio Companies to file their SEET results on a consolidated basis instead of on an individual company basis. On September 4, 2020, the PUCO opened its quadrennial review of ESP IV, consolidated it with the Ohio Companies’ 2018 and 2019 SEET Applications, and set a procedural schedule for the consolidated matters. On October 29, 2020, the PUCO issued an entry extending the deadline for the Ohio Companies to file quadrennial review of ESP IV testimony to March 1, 2021, with the evidentiary hearings to commence no sooner than May 3, 2021. On January 12, 2021, the PUCO consolidated these matters with the determination of the existence of significantly excessive earnings under ESP IV for calendar year 2017, which the SCOH had remanded to the PUCO.

On September 8, 2020, the OCC filed motions in the Ohio Companies’ corporate separation audit and DMR audit dockets, requesting the PUCO to open an investigation and management audit, hire an independent auditor, and require FirstEnergy to show it did not improperly use money collected from consumers or violate any utility regulatory laws, rules or orders in its activities regarding HB 6. The Ohio Companies’ filed a response in opposition to the OCC’s motions on September 23, 2020. On December 30, 2020, in response to the OCC's motion, the PUCO reopened the DMR audit docket, and directed PUCO staff to solicit a third-party auditor and conduct a full review of the DMR to ensure funds collected from ratepayers through the DMR were only used for the purposes established in ESP IV. Deadlines relating to the selection of the auditor and the issuance of the final audit report have not yet been set.

On September 15, 2020, the PUCO opened a new proceeding to review the political and charitable spending by the Ohio Companies in support of HB 6 and the subsequent referendum effort, directing the Ohio Companies to show cause, demonstrating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by ratepayers. The Ohio Companies filed a response on September 30, 2020, stating that any political and charitable spending in support of HB 6 or the subsequent referendum were not included in rates or charges paid for by its customers. Several parties requested that the PUCO broaden the scope of the review of political and charitable spending.

In connection with an on-going audit of the Ohio Companies’ policies and procedures relating to the code of conduct rules between affiliates, on November 4, 2020, the PUCO initiated an additional corporate separation audit as a result of the FirstEnergy leadership transition announcement made on October 29, 2020, as further discussed below. The additional audit is to ensure compliance by the Ohio Companies and their affiliates with corporate separation laws and the Ohio Companies’ corporate separation plan. The additional audit is for the period from November 2016 through October 2020, with a final audit report to be filed in June 2021. On January 27, 2021, the PUCO selected an auditor.

On November 24, 2020, the Environmental Law and Policy Center filed motions to vacate the PUCO’s orders in proceedings related to the Ohio Companies’ settlement that provides for the implementation of the first phase of grid modernization plans and for all tax savings associated with the Tax Act to flow back to customers, the Ohio Companies’ energy efficiency portfolio plans for the period from 2013 through 2016, and the Ohio Companies’ application for a two-year extension of the DMR, on the grounds that the former Chairman of the PUCO should have recused himself in these matters. On December 30, 2020, the PUCO denied the motions, and reinstated the requirement under ESP IV that the Ohio Companies file a base distribution rate case by May 31, 2024, the end of ESP IV, which the Ohio Companies had indicated they would not oppose.

In the fourth quarter of 2020, motions were filed with the PUCO requesting that the PUCO amend the Ohio Companies’ riders for collecting charges required by HB 6, which the Ohio Companies are further required to remit to other Ohio electric distribution utilities or to the State Treasurer, to provide for refunds in the event HB 6 is repealed. The Ohio Companies contested the motions, which are pending before the PUCO.

On December 7, 2020, the Citizens’ Utility Board of Ohio filed a complaint with the PUCO against the Ohio Companies. The complaint alleges that the Ohio Companies’ new charges resulting from HB 6, and any increased rates resulting from proceedings over which the former PUCO Chairman presided, are unjust and unreasonable, and that the Ohio Companies violated Ohio corporate separation laws by failing to operate separately from unregulated affiliates. The complaint requests, among other things, that any rates authorized by HB 6 or authorized by the PUCO in a proceeding over which the former Chairman presided be made refundable; that the Ohio Companies be required to file a new distribution rate case at the earliest possible date; and that the Ohio Companies’ corporate separation plans be modified to introduce institutional controls. The Ohio Companies are contesting the complaint.

On December 9, 2020, the Ohio Manufacturers’ Association Energy Group filed an appeal to the SCOH challenging the PUCO’s generic order directing the form of rider all Ohio electric distribution utilities must charge to recover the costs of the HB 6 Clean Air Fund. The appeal contends that the PUCO erred in adopting the rate design for the riders, in establishing the riders during ongoing proceedings and investigations related to HB 6, and in not requiring electric distribution utilities to include refund language in the rider tariffs. On December 30, 2020, the PUCO vacated its generic order establishing the Clean Air Fund riders, as required by a preliminary injunction issued by the Court of Common Pleas of Franklin County, Ohio. On January 11, 2021, the SCOH granted a joint application of the Ohio Manufacturers' Association Energy Group and the PUCO and dismissed the appeal.

See “Outlook - Other Legal Proceedings” below for additional details on the government investigation and subsequent litigation surrounding the investigation of HB 6.

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 was separately tracked and its treatment will be addressed 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.

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. On June 18, 2020, the PPUC entered a Final Implementation Order for a Phase IV EE&C Plan, operating from June 2021 through May 2026. The Final Implementation Order set demand reduction targets, relative to 2007 to 2008 peak demands, at 2.9% MW for ME, 3.3% MW for PN, 2.0% MW for Penn, and 2.5% MW for WP; and energy consumption reduction targets, as a percentage of the Pennsylvania Companies’ historic 2009 to 2010 reference load at 3.1% MWH for ME, 3.0% MWH for PN, 2.7% MWH for Penn, and 2.4% MWH for WP. The Pennsylvania Companies’ Phase IV plans were filed November 30, 2020. A settlement has been reached in this matter, and a joint petition seeking approval of that settlement by the parties was filed on February 16, 2021. A PPUC decision on the settlement is expected in March 2021.

Pennsylvania EDCs may file with the PPUC for approval of an LTIIP for infrastructure improvements and costs related to highway relocation projects, after which a DSIC may be approved to recover LTIIP costs. On August 30, 2019, the Pennsylvania Companies filed Petitions for approval of new 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. The Pennsylvania Companies’ approved DSIC riders for quarterly cost recovery went into effect July 1, 2016. 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. On March 12, 2020, an order was entered approving a settlement by all parties to that case which provides for a temporary increase in the recoverability cap from 5% to 7.5%, to 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.

Following the Pennsylvania Companies’ 2016 base rate proceedings, the PPUC ruled in a separate proceeding related to the DSIC mechanisms that the Pennsylvania Companies were not required to reflect federal and state income tax deductions related to DSIC-eligible property in DSIC rates, which decision was appealed by the Pennsylvania OCA to the Pennsylvania Commonwealth Court. The Commonwealth Court reversed the PPUC’s decision and remanded the matter to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. On April 7, 2020, the Pennsylvania Supreme Court issued an order granting Petitions for Allowance of Appeal by both the PPUC and the Pennsylvania Companies of the Commonwealth Court’s Opinion and Order. Briefs and Reply Briefs of the parties were filed, and oral argument before the Supreme Court was held on October 21, 2020. An adverse ruling by the Pennsylvania Supreme Court is not expected to result in a material impact to FirstEnergy.

The PPUC issued an order on March 13, 2020, forbidding utilities from terminating service for non-payment for the duration of the COVID-19 pandemic. On May 13, 2020, the PPUC issued a Secretarial letter directing utilities to track all prudently incurred incremental costs arising from the COVID-19 pandemic, and to create a regulatory asset for future recovery of incremental uncollectibles incurred as a result of the COVID-19 pandemic and termination moratorium. On October 13, 2020, the PPUC entered an order lifting the service termination moratorium effective November 9, 2020, subject to certain additional notification, payment procedures and exceptions, and permits the Pennsylvania Companies to create a regulatory asset for all incremental expenses associated with their compliance with the order.

WEST VIRGINIA

MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate 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 March 13, 2020, the WVPSC urged all utilities to suspend utility service terminations except where necessary as a matter of safety or where requested by the customer. On May 15, 2020, the WVPSC issued an order to authorize MP and PE to record a deferral of additional, extraordinary costs directly related to complying with the various COVID-19 government shut-down orders and operational precautions, including impacts on uncollectible expense and cash flow related to temporary discontinuance of service terminations for non-payment and any credits to minimum demand charges associated with business customers adversely impacted by shut-downs or temporary closures related to the pandemic. MP and PE resumed disconnection activity for commercial and industrial customers on September 15, 2020, and for residential customers on November 4, 2020.

On August 28, 2020, MP and PE filed with the WVPSC their annual ENEC case requesting a decrease in ENEC rates of $55 million beginning January 1, 2021, representing a 4% decrease in rates compared to those in effect on August 28, 2020. The decrease in the ENEC rates is net of recovering approximately $10.5 million in previously deferred, incremental uncollectible and other related costs resulting from the COVID-19 pandemic. The WVPSC approved a unanimous settlement by the parties on December 16, 2020 with rates effective January 1, 2021.

Also, on August 28, 2020, MP and PE filed with the WVPSC for recovery of costs associated with modernization and improvement program for their coal-fired boilers. The proposed annual revenue increase for these environmental compliance projects is $5 million beginning January 1, 2021. The WVPSC approved a unanimous settlement by the parties on December 16, 2020 approving the recovery of those costs.

On December 30, 2020, MP and PE filed an integrated resource plan with the WVPSC. The plan projects a small capacity deficit but an energy surplus in MP’s and PE’s supply resources when compared with current WV load demand and projects the capacity deficit growing over the next 15 years. The plan does not recommend additional supply-side resources with a possible exception for small utility-scale solar resources and recommends that the capacity deficit be met through the PJM capacity market. MP currently expects to seek approval in 2021 to construct solar generation sources of up to 50 MWs.

On December 30, 2020, MP and PE filed with the WVPSC a determination of the rate impact of the Tax Act with respect to ADIT. The filing proposes an annual revenue reduction of $2.6 million annually, effective January 1, 2022, with reconciliation and any resulting adjustments incorporated into the annual ENEC proceedings.

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	January 2020(1)	Actual (13-month average)(1)	10.80%(1)
MP	March 21, 2018(2)(4)	Settled(2)(3)	Settled(2)(3)
PE	March 21, 2018(2)(4)	Settled(2)(3)	Settled(2)(3)
WP	March 21, 2018(2)(4)	Settled(2)(3)	Settled(2)(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) As filed in docket ER20-227, effective on January 1, 2020, which has been accepted by FERC, subject to refund, pending further hearing and settlement procedures. The settlement agreement that was filed on February 2, 2021, seeking approval by FERC sets JCP&L's Allowed ROE at 10.2%.

(2) Effective on January 1, 2021, MP, PE, and WP have implemented a forward-looking formula rate, which has been accepted by FERC, subject to refund, pending further hearing and settlement procedures.

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

(4) See FERC Actions on Tax Act below.

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 in the case of the Utilities major wholesale purchases remain subject to review and 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.

ATSI Transmission Formula Rate

On May 1, 2020, ATSI filed amendments to its formula rate to recover regulatory assets for certain costs that ATSI incurred as a result of its 2011 move from MISO to PJM, certain costs allocated to ATSI by FERC for transmission projects that were constructed by other MISO transmission owners, certain income tax-related adjustments, including, but not limited to impacts from the Tax Act discussed further below, and certain costs for transmission-related vegetation management programs. The amount on FirstEnergy’s Consolidated Balance Sheet for these regulatory assets was approximately $79 million and $73 million, as of December 31, 2020 and December 31, 2019, respectively. Per prior FERC orders, ATSI included a “cost-benefit study” to support recovery of ATSI’s costs to move to PJM, and the MISO transmission project costs that were allocated to ATSI. Certain intervenors filed protests of the formula rate amendments on May 29, 2020, and ATSI filed a reply on June 15, 2020. On June 30, 2020, FERC issued an initial order accepting the tariff amendments subject to refund, suspending the effective date for five months to be effective December 1, 2020, and setting the matter for hearing and settlement proceedings. ATSI is engaged in settlement negotiations with the other parties to the formula rate amendments proceeding.

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 No. 864). Order No. 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. Per FERC directives, ATSI submitted its compliance filing on May 1, 2020. MAIT submitted its compliance filing on June 1, 2020. Certain intervenors filed protests of the compliance filings, to which ATSI and MAIT responded. On October 28, 2020, FERC staff requested additional information about ATSI’s proposed rate base adjustment mechanism, and ATSI submitted the requested information on November 25, 2020. On May 15, 2020, TrAIL submitted its compliance filing and on June 1, 2020, PATH submitted its required compliance filing. These compliance filings each remain pending before FERC. MP, WP and PE (as holders of a “stated” transmission rate) are addressing these requirements in the transmission formula rates amendments that were filed on October 29, 2020. JCP&L is addressing these requirements as part of its pending transmission formula 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 May 21, 2020, FERC issued Opinion No. 569-A that changed FERC’s ROE methodology. Under this methodology FERC established an ROE that is based on three financial models – discounted cash flow, capital-asset pricing, and risk premium – to calculate a composite zone of reasonableness. FERC noted that utilities could, in utility-specific proceedings, ask to have the expected earnings methodology included in calculating the utility’s authorized ROE. FERC also noted that, going forward, it will divide that zone into three equal parts, to be used for high risk, normal risk, and low risk utilities. A given utility will be assigned to one of these three parts of the zone of reasonableness, and its ROE will be set at the median or midpoint of the other utilities that are in the applicable third of the zone. FirstEnergy filed a request for rehearing, which FERC denied on July 22, 2020. On November 19, 2020, FERC issued Opinion No. 569-B, which affirmed the Opinion No. 569-A rulings. FirstEnergy initiated, but subsequently withdrew, appeals of these orders. Appeals of Opinion Nos. 569, 569-A and 569-B are pending before the D.C. Circuit. Any changes to FERC’s transmission rate ROE and incentive policies would be applied on a prospective basis.

On March 20, 2020, FERC initiated a rulemaking proceeding on the transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act. Initial comments were submitted July 1, 2020, and reply comments were filed on July 16, 2020. FirstEnergy participated through EEI and through a consortium of PJM Transmission Owners. This proceeding is pending before FERC.

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 and the parties to the FERC proceeding subsequently were able to reach settlement, and on February 2, 2021, a settlement agreement was filed for approval by FERC.

Allegheny Power Zone Transmission Formula Rate Filings

On October 29, 2020, MP, PE and WP filed tariff amendments with FERC to convert their existing stated transmission rate to a forward-looking formula transmission rate, effective January 1, 2021. In addition, on October 30, 2020, KATCo filed a proposed new tariff to establish a forward-looking formula rate and requested that the new rate become effective January 1, 2021. In its filing, KATCo explained that while it currently owns no transmission assets, it may build new transmission facilities in the Allegheny zone, and that it may seek required state and federal authorizations to acquire transmission assets from PE and WP by January 1, 2022. These transmission rate filings were approved by FERC on December 31, 2020, subject to refund, pending further hearing and settlement proceedings. MP, PE and WP, and KATCo are engaged in settlement negotiations with the other parties to the formula rate proceedings. KATCo will be included in the Regulated Transmission reportable segment.

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 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 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 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 December 31, 2020, FirstEnergy has no power plants operating in areas designated as non-attainment by the EPA.

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 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 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. On July 14, 2020, the D.C. Circuit reversed and remanded the New York petition to the EPA for further consideration. 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. On January 20, 2021, President Biden signed an executive order re-adopting the agreement on behalf of the U.S. 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. 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. On January 19, 2021, the D.C. Circuit remanded the ACE rule declaring

that the EPA was “arbitrary and capricious” in its rule making, as such, the ACE rule is no longer in effect and all actions thus far taken by States to implement the federally mandated rule are now null and void. The D.C. Circuit decision is subject to legal challenge. 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 were to phase-in as permits are renewed on a five-year cycle from 2018 to 2023. However, 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 August 31, 2020, the EPA issued a final rule revising the effluent limits for discharges from wet scrubber systems, retaining the zero-discharge standard for ash transport water, (with some limited discharge allowances), and extending the deadline for compliance to December 31, 2025 for both. 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, how final rules are ultimately implemented and the compliance options MP elects to take with the new rules, the compliance with these standards, which could include capital expenditures at the Ft. Martin and Harrison power stations, may be substantial and changes to MP’s operations at those power stations may also 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 the EPA alleging violations of the CWA at the Springdale and Mingo landfills while seeking to enter settlement negotiations in lieu of filing a complaint. The EPA has proposed a penalty of $900,000 to settle alleged past boron exceedances at both facilities. Negotiations are continuing and WP 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 December 2, 2019, the EPA published a proposed rule accelerating the date that certain CCR impoundments must cease accepting waste and initiate closure to August 31, 2020. The proposed rule allows for an extension of the closure deadline based on meeting proscribed site-specific criteria. On July 29, 2020, the EPA published a final rule revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021. The final rule allows for an extension of the closure deadline based on meeting proscribed site-specific criteria. On November 30, 2020, AE Supply submitted a closure deadline extension request to the EPA seeking to extend the closure date until 2024 of McElroy's Run CCR impoundment facility, for which AE Supply continues to provide access to FG.

FE 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, 2020, 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 $107 million have been accrued through December 31, 2020. Included in the total are accrued liabilities of approximately $67 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

United States v. Larry Householder, et al.

Legal Proceedings Relating to United States v. Larry Householder, et al.

In addition to the subpoenas referenced above under “—United States v. Larry Householder, et. al.”, certain FE stockholders and FirstEnergy customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, and the complaints in each of these suits is related to allegations in the complaint and supporting affidavit relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder.

Owens v. FirstEnergy Corp. et al. and Frand v. FirstEnergy Corp. et al. (Federal District Court, S.D. Ohio); on July 28, 2020 and August 21, 2020, purported stockholders of FE filed putative class action lawsuits against FE and certain FE officers, purportedly on behalf of all purchasers of FE common stock from February 21, 2017 through July 21, 2020, asserting claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, alleging misrepresentations or omissions by FirstEnergy concerning its business and results of operations. These actions have been consolidated and a lead plaintiff has been appointed by the court.
Gendrich v. Anderson, et al. and Sloan v. Anderson, et al. (Common Pleas Court, Summit County, OH); on July 26, 2020 and July 31, 2020, respectively, purported stockholders of FE filed shareholder derivative action lawsuits against certain FE directors and officers, alleging, among other things, breaches of fiduciary duty. These actions have been consolidated.
Miller v. Anderson, et al. (Federal District Court, N.D. Ohio); Bloom, et al. v. Anderson, et al.; Employees Retirement System of the City of St. Louis v. Jones, et al.; Electrical Workers Pension Fund, Local 103, I.B.E.W. v. Anderson et al.; Massachusetts Laborers Pension Fund v. Anderson et al.; The City of Philadelphia Board of Pensions and Retirement v. Anderson et al.; Atherton v. Dowling et al; Behar v. Anderson, et al. (U.S. District Court, S.D. Ohio, all actions have been consolidated); beginning on August 7, 2020, purported stockholders of FE filed shareholder derivative actions alleging the board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Securities Exchange Act of 1934. The cases in the Southern District of Ohio have been consolidated and co-lead plaintiffs have been appointed by the court.
Smith v. FirstEnergy Corp. et al., Buldas v. FirstEnergy Corp. et al., and Hudock and Cameo Countertops, Inc. v. FirstEnergy Corp. et al. (Federal District Court, S.D. Ohio); on July 27, 2020, July 31, 2020, and August 5, 2020, respectively, purported customers of FirstEnergy filed putative class action lawsuits against FE and FESC, as well as certain current and former FirstEnergy officers, alleging civil Racketeer Influenced and Corrupt Organizations Act violations and related state law claims. These actions have been consolidated.
State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. and City of Cincinnati and City of Columbus v. FirstEnergy Corp. (Common Pleas Court, Franklin County, OH); on September 23, 2020 and October 27, 2020, the OAG and the cities of Cincinnati and Columbus, respectively, filed complaints against several parties including FE, each alleging civil violations of the Ohio Corrupt Activity Act in connection with the passage of HB 6. The OAG sought a preliminary injunction to prevent each of the defendants, including FE, through the end of 2020, from: (i) contributing to any groups whose purpose is to keep or modify HB 6; (ii) making any public statements for or against any repeal or modification legislation concerning HB 6; (iii) lobbying, consulting, or advising on these matters; or (iv) contributing to any Ohio legislative candidates. The court denied the OAG’s request for preliminary injunctive relief on October 2, 2020. On January 13, 2021, the OAG filed a motion for a temporary restraining order and preliminary injunction against FirstEnergy seeking to enjoin FirstEnergy from collecting the Ohio Companies' decoupling rider. On January 31, 2021, FE reached a partial settlement with the OAG and the cities of Cincinnati and Columbus with respect

to the temporary restraining order and preliminary injunction request and related issues. In connection with the partial settlement, the Ohio Companies filed an application on February 1, 2021, with the PUCO to set their respective decoupling riders (Rider CSR) to zero. On February 2, 2021, the PUCO approved the application of the Ohio Companies setting the rider to zero and no additional customer bills will include new decoupling rider charges after February 8, 2021. The cities of Dayton and Toledo have also been added as plaintiffs to the action. These actions have been consolidated.

Emmons v. FirstEnergy Corp. et al. (Common Pleas Court, Cuyahoga County, OH); on August 4, 2020, a purported customer of FirstEnergy filed a putative class action lawsuit against FE, FESC, OE, TE and CEI, along with FES, alleging several causes of action, including negligence and/or gross negligence, breach of contract, unjust enrichment, and unfair or deceptive consumer acts or practices. On October 1, 2020, plaintiffs filed a First Amended Complaint, adding as a plaintiff a purported customer of FirstEnergy and alleging a civil violation of the Ohio Corrupt Activity Act and civil conspiracy against FE, FESC and FES.

The plaintiffs in each of the above cases, seek, among other things, to recover an unspecified amount of damages (unless otherwise noted). In addition, on August 10, 2020, the SEC, through its Division of Enforcement, issued an order directing an investigation of possible securities laws violations by FE, and on September 1, 2020, issued subpoenas to FE and certain FE officers. Further, on January 26, 2021, staff of FERC's Division of Investigations issued a letter directing FirstEnergy to preserve and maintain all documents and information related to an ongoing audit being conducted by FERC's Division of Audits and Accounting, including activities related to lobbying and governmental affairs activities concerning HB 6. The outcome of any of these lawsuits, investigations and audit are uncertain and could have a material adverse effect on FE’s or its subsidiaries’ financial condition, results of operations and cash flows. No contingency has been reflected in FirstEnergy’s consolidated financial statements as a loss is neither probable, nor is a loss or range of a loss reasonably estimable.

Internal Investigation Relating to United States v. Larry Householder, et al.

Nuclear Plant Matters

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. On August 10, 2020, JCP&L, ME, PN, GPUN, TMI-2 Solutions, LLC, and the PA DEP reached a settlement agreement regarding the decommissioning of TMI-2. On December 2, 2020, the NJBPU issued an order approving the transfer and sale under the conditions requested by Rate Counsel and agreed to by JCP&L. Also, on December 2, 2020, the NRC issued its order approving the license transfer as requested. With the receipt of all required regulatory approvals, the transaction was consummated on December 18, 2020. See Note 1, "Organization and Basis of Presentation," for additional discussion.

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 and emerged on February 27, 2020. See Note 3, "Discontinued Operations," for additional discussion.

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. FirstEnergy has elected the optional invoice practical expedient for most of its revenues and 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. Under the cash-balance portion of the pension plan (for employees hired on or after January 1, 2014), FirstEnergy makes contributions to eligible employee retirement accounts based on a pay credit and an interest credit.

FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. 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.

Under the approved bankruptcy settlement agreement discussed above, upon emergence, FES and FENOC employees ceased earning years of service under the FirstEnergy pension and OPEB plans. The emergence on February 27, 2020, triggered a remeasurement of the affected pension and OPEB plans and as a result, FirstEnergy recognized a non-cash, pre-tax pension and OPEB mark-to-market adjustment of approximately $423 million in the first quarter of 2020. The first quarter 2020 pension and OPEB mark-to-market adjustment primarily reflects a 38 bps decrease in the discount rate used to measure benefit obligations from December 31, 2019, partially offset by a slightly higher than expected return on assets. In the fourth quarter 2020, FirstEnergy recognized a $54 million pension and OPEB mark-to-market adjustment, primarily reflecting a 29 bps decrease in the discount rate used to measure benefit obligations from February 27, 2020, partially offset by higher than expected return on assets. Of the $54 million, approximately $21 million was allocated to certain of the Transmission Companies that are expected to be recovered through formula transmission rates. The annual pension and OPEB mark-to-market adjustments for the years ended December 31, 2020, 2019, and 2018 were $477 million (including the $423 million in the first quarter of 2020 described above), $676 million, and $145 million, respectively. Of these amounts, approximately $2 million and $1 million are included in discontinued operations for the years ended December 31, 2019, and 2018, respectively. Furthermore, of these annual pension and OPEB mark-to-market amounts, approximately $40 million, $47 million and $8 million were allocated to certain of the Transmission Companies and expected to be recovered through formula transmission rates, respectively.

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 2.67%, 3.34% and 4.44% as of December 31, 2020, 2019 and 2018, respectively. The assumed discount rates for OPEB were 2.45%, 3.18% and 4.30% as of December 31, 2020, 2019 and 2018, 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 was 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 2020, FirstEnergy’s qualified pension and OPEB plan assets experienced gains of $1,225 million or 14.7%, compared to gains of $1,492 million, or 20.2% in 2019, and losses of $371 million, or (4)% in 2018 and assumed a 7.50% rate of return on plan assets in 2020, 2019 and 2018, which generated $651 million, $569 million and $605 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 2021 is 7.50%.

During 2020, 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-2020 was most appropriate. As such, the Pri-2012 mortality table with projection scale MP-2020 was utilized to determine the 2020 benefit cost and obligation as of December 31, 2020 for the FirstEnergy pension and OPEB plans. The impact of using the Pri-2012 mortality table with projection scale MP-2020 resulted in a decrease

to the projected benefit obligation of approximately $74 million and $2 million for the pension and OPEB plans, respectively, and was included in the 2020 pension and OPEB mark-to-market adjustment.

FirstEnergy expects its 2021 pre-tax net periodic benefit credit to be approximately $267 million based upon the following assumptions:


Assumptions	Pension		OPEB
Service cost weighted-average discount rate	3.10	%	3.03	%
Interest cost weighted-average discount rate	2.58	%	1.66	%
Expected long-term return on plan assets	7.50	%	7.50	%

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, 2020, 2019, and 2018:


Postemployment Benefits Expense (Credits)	2020		2019		2018
	(In millions)
Pension	$	254	$	622	$	247
OPEB	(47)		(21)		(45)
Total	$	207	$	601	$	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 2020 and 2019, 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 2021 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%	$	400	$	16	$	416
Long-term return on assets	Decrease by 0.25%	$	22	$	1	$	23
Health care trend rate	Increase by 1.0%	N/A		$	16	$	16

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

See Note 1, "Organization and Basis of Presentation," for a discussion of new accounting pronouncements.

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