What changed in this filing

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Item 8. Financial Statements and Supplementary Data

2022-02-16 compared with 2021-02-18 · 841 added, 981 removed, 1331 unchanged (58% of the section changed)

8 unchanged sentences

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020 , and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.

Also in our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO because a material weakness in internal control over financial reporting existed as of that date related to its senior management failing to set an appropriate tone at the top.

Specifically, certain members of senior management failed to reinforce the need for compliance with the Company’s policies and code of conduct, which resulted in inappropriate conduct that was inconsistent with the Company’s policies and code of conduct.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

The material weakness referred to above is described in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A.

We considered this material weakness in determining the nature, timing, and extent of audit tests applied in our audit of the 2020 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements.

Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in management's report referred to above.

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A.

Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits.

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The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Recoverability of Regulatory Assets That Do Not Have an Order for Recovery

As described in Note 1 to the consolidated financial statements, the Company accounts for the effects of regulation through the application of regulatory accounting to its regulated distribution and transmission subsidiaries as their rates are established by a third-party regulator with the authority to set rates that bind customers, are cost-based and can be charged to and collected from customers.

This ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows.

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 and certain of these assets, totaling approximately $117 million as of December 31, 2020, have been recorded based on precedent and rate making premises without a specific order.

The principal considerations for our determination that performing procedures relating to the recoverability of regulatory assets that do not have an order for recovery is a critical audit matter are (i) the significant judgment by management when assessing the probability of recovery of these regulatory assets from customers, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the recoverability of these regulatory assets.

Accounting for the Effects of Rate Regulation

As described in Note 1 to the consolidated financial statements, the Company’s Regulated Distribution and Regulated Transmission segments are subject to regulation that sets the prices (rates) the Company is permitted to charge customers based on costs that the regulatory agencies determine are permitted to be recovered.

At times, regulatory agencies permit the future recovery of costs that would be currently charged to expense by an unregulated company.

The ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows.

Management reviews the probability of recovery of regulatory assets, and settlement of regulatory liabilities, at each balance sheet date and whenever new events occur.

Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order, or passage of new legislation.

Upon material changes to these factors, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that currently recorded regulatory assets and liabilities will be recovered or settled in future rates.

As of December 31, 2021, there were $71 million of regulatory assets and $2,124 million of regulatory liabilities.

The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a critical audit matter are the significant audit effort in assessing the impact of regulation on accounting for regulatory assets and liabilities and in evaluating the complex audit evidence related to whether the regulatory assets will be recovered and liabilities settled.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements.

These procedures included testing the effectiveness of controls relating to management’s regulatory accounting process, including controls over management’s assessment of the recoverability of regulatory assets that do not have an order for recovery.

These procedures also included, among others, evaluating the reasonableness of management’s assessment of recoverability of regulatory assets.

Testing the recoverability of regulatory assets involved evaluating evidence related to precedent for similar items at the Company and information on comparable companies within similar regulatory jurisdictions as well as assessing progress of communications between management and regulators.

These procedures included testing the effectiveness of controls relating to the accounting for regulatory matters, including controls over the evaluation of the recoverability and settlement of existing regulatory assets and liabilities.

These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s assessment regarding regulatory guidance, proceedings, and legislation and the related accounting implications, and calculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.

/s/ PricewaterhouseCoopers LLP

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Provision for depreciation 1,302 1,274 1,220

Deferral of regulatory assets, net ( 53 ) ( 79 ) ( 150 )

Amortization (deferral) of regulatory assets, net 269 ( 53 ) ( 79 )

General taxes 1,073 1,046 1,008

DPA penalty (Note 13) 230 — —

Gain on sale of Yards Creek (Note 12) ( 109 ) — —

Total operating expenses 9,406 8,628 8,525

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(1) Includes excise and gross receipts tax collections of $ 374 million, $ 362 million and $ 373 million in 2021, 2020 and 2019, respectively.

(2) Net of income tax benefit of $ 59 million, $ 5 million, and $ 1.3 billion in 2020, 2019 and 2018, respectively.

(2) Net of income tax benefit of $ 48 million, $ 59 million, and $ 5 million in 2021, 2020 and 2019, respectively.

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

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Amortized losses on derivative hedges 1 1 2

Change in unrealized gains on available-for-sale securities — — ( 106 )

Other comprehensive loss ( 13 ) ( 33 ) ( 29 )

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Less — Allowance for uncollectible customer receivables 159 164

Affiliated companies, net of allowance for uncollectible accounts of $ 0 in 2020 and $ 1,063 in 2019

Other, net of allowance for uncollectible accounts of $ 10 in 2021 and $ 26 in 2020

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Prepaid taxes and other 187 157

Current assets - discontinued operations — 33

PROPERTY, PLANT AND EQUIPMENT:

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PROPERTY, PLANT AND EQUIPMENT, NET - HELD FOR SALE (NOTE 13) — 45

Nuclear fuel disposal trust 283 270

Other 322 299

Investments - held for sale (Note 15) — 882

DEFERRED CHARGES AND OTHER ASSETS:

INVESTMENTS AND OTHER NONCURRENT ASSETS

Goodwill 5,618 5,618

Investments (Note 8) 655 605

Regulatory assets 71 82

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Accounts payable 943 827

Accounts payable - affiliated companies — 87

Accrued interest 283 282

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Accrued compensation and benefits 313 349

Dividends payable (Note 9) 222 212

Other 402 348

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Stockholders’ equity-

Common stock, $ 0.10 par value, authorized 700,000,000 shares - 543,117,533 and 540,652,222 shares outstanding as of December 31, 2020 and December 31, 2019, respectively

Common stock, $ 0.10 par value, authorized 700,000,000 shares - 570,261,104 and 543,117,533 shares outstanding as of December 31, 2021 and 2020, respectively

Other paid-in capital 10,238 10,076

Accumulated other comprehensive income (loss) ( 5 ) 20

Accumulated other comprehensive loss ( 15 ) ( 5 )

Accumulated deficit ( 1,605 ) ( 2,888 )

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Regulatory liabilities 2,124 1,826

Asset retirement obligations 159 165

Adverse power contract liability 30 49

Other 1,863 1,826

Noncurrent liabilities - held for sale (Note 15) — 691

10,093 10,092

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Stock Investment Plan and certain share-based benefit plans 3 — 56 56

Stock issuance (Note 11) (1)

1.6 162 30 3 2,297 2,462

Conversion of Series A Convertible Stock ( 0.7 ) ( 71 ) 26 3 68 —

Impact of adopting new accounting pronouncements 35 35

Balance, December 31, 2019 — — 541 54 10,868 20 ( 3,967 ) 6,975

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Cash dividends declared on common stock ( 846 ) ( 846 )

Cash dividends declared on preferred stock ( 3 ) ( 3 )

Stock Investment Plan and certain share-based benefit plans 2 — 28 28

Conversion of Series A Convertible Stock ( 0.7 ) ( 71 ) 26 3 68 —

Balance, December 31, 2020 — — 543 54 10,076 ( 5 ) ( 2,888 ) 7,237

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Cash dividends declared on common stock ( 859 ) ( 859 )

Stock Investment Plan and certain share-based benefit plans 2 28 28

Common Stock issuance (Note 9) 26 3 971 974

Share-based benefit plans 1 24 24

Balance, December 31, 2021 — $ — 570 $ 57 $ 10,238 $ ( 15 ) $ ( 1,605 ) $ 8,675

(1) The Preferred Stock included an embedded conversion option at a price that is below the fair value of the Common Stock on the commitment date.

This BCF, which was approximately $ 296 million, was recorded to OPIC as well as the amortization of the BCF (deemed dividend) through the period from the issue date to the first allowable conversion date (July 22, 2018) and as such there is no net impact to OPIC for the year ended December 31, 2018.

Dividends declared for each share of common stock and as-converted share of preferred stock was $ 1.56 during 2020, $ 1.53 during 2019, and $ 1.82 during 2018.

Dividends declared for each share of common stock and as-converted share of preferred stock (applicable to 2019) were $ 1.56 during 2021 and 2020, as well as $ 1.53 during 2019.

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

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Adjustments to reconcile net income to net cash from operating activities-

Gain on disposal, net of tax (Note 3) ( 76 ) ( 59 ) ( 435 )

Depreciation and amortization 1,601 1,199 1,217

Pension trust contributions — ( 500 ) ( 1,250 )

Retirement benefits, net of payments ( 417 ) ( 301 ) ( 108 )

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Asset removal costs charged to income — 36 28

Transmission revenue collections, net 182 ( 32 ) ( 55 )

Gain on sale of Yards Creek ( 109 ) — —

Pension trust contributions — — ( 500 )

Settlement agreement and tax sharing payments to the FES Debtors — ( 978 ) —

Gain on disposal, net of tax (Note 14) ( 47 ) ( 76 ) ( 59 )

Changes in current assets and liabilities-

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Other current liabilities ( 16 ) ( 16 ) ( 21 )

Cash collateral, net 31 ( 12 ) ( 10 )

Other 65 ( 62 ) ( 18 )

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Short-term borrowings, net — 1,200 —

Preferred stock issuance — — 1,616

Common stock issuance 1,000 — —

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Long-term debt ( 532 ) ( 1,114 ) ( 789 )

Tender premiums paid on debt redemptions — — ( 89 )

Short-term borrowings, net ( 2,200 ) — —

Preferred stock dividend payments — — ( 6 )

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Other ( 61 ) ( 59 ) ( 35 )

Net cash provided from financing activities 2,607 656 1,394

Net cash provided from (used for) financing activities ( 542 ) 2,607 656

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions ( 2,445 ) ( 2,657 ) ( 2,665 )

Proceeds from asset sales 2 47 425

Proceeds from sale of Yards Creek 155 — —

Sales of investment securities held in trusts 48 186 1,637

Purchases of investment securities held in trusts ( 59 ) ( 208 ) ( 1,675 )

Notes receivable from affiliated companies — — ( 500 )

Asset removal costs ( 226 ) ( 224 ) ( 217 )

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SUPPLEMENTAL CASH FLOW INFORMATION:

Non-cash transaction:

beneficial conversion feature $ — $ — $ 296

Non-cash transaction:

deemed dividend convertible preferred stock $ — $ — $ ( 296 )

Cash paid during the year-

Cash paid (received) during the year-

Interest (net of amounts capitalized) $ 1,085 $ 970 $ 960

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Organization and Basis of Presentation

3 Discontinued Operations 92

3 Accumulated Other Comprehensive Income 89

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5 Stock-Based Compensation Plans 90

9 Intangible Assets 110

8 Fair Value Measurements 97

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13 Commitments, Guarantees and Contingencies 114

16 Transactions with Affiliated Companies 132

14 Discontinued Operations 120

15 Segment Information 121

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AE Supply, FirstEnergy Properties, Inc., FEV, FirstEnergy License Holding Company, GPUN, Allegheny Ventures, Inc., and Suvon, LLC, doing business as both FirstEnergy Home and FirstEnergy Advisors.

FE does not bill directly or allocate any of its costs to any subsidiary company.

Costs are charged to FE's subsidiaries for services received from FESC either through direct billing or through an allocation process.

Allocated costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas developed by FESC.

Intercompany transactions are generally settled under commercial terms within thirty days.

FE and its subsidiaries are principally involved in the transmission, distribution, and generation of electricity.

FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving over 6 million customers in the Midwest and Mid-Atlantic regions.

FirstEnergy’s transmission operations include approximately 24,500 miles of lines and two regional transmission operation centers.

AGC, JCP&L and MP control 3,790 MWs of total capacity, 210 MWs of which is related to the Yards Creek generating plant that is being sold pursuant to an asset purchase agreement as further discussed below.

FE and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the NRC, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU.

FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving over six million customers in the Midwest and Mid-Atlantic regions.

FirstEnergy’s transmission operations include over 24,000 miles of transmission lines and two regional transmission operation centers.

AGC and MP control 3,580 MWs of total capacity.

PN, as lessee of the property of its subsidiary, the Waverly Electric Light & Power Company, serves approximately 4,000 customers in the Waverly, New York vicinity.

On February 10, 2021, PN entered into an agreement to transfer its customers and the related assets in Waverly, New York to Tri-County Rural Electric Cooperative;

the completion of such transfer is subject to several closing conditions including regulatory approval, which are ongoing, but is expected to have an immaterial impact to FirstEnergy's financial statements.

FE and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU.

The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities.

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

Restricted Cash

Restricted cash primarily relates to the consolidated VIE's discussed below.

The cash collected from JCP&L, MP, PE and the Ohio Companies' customers is used to service debt of their respective funding companies.

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.

FirstEnergy is continuously evaluating the global COVID-19 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 began.

FirstEnergy has incurred, and it is expected to incur for the foreseeable future, 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.

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, COVID-19 test kits, 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 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 investment 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.

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.

Activity in the allowance for uncollectible accounts on receivables for the years ended December 31, 2020, 2019 and 2018 are as follows:

(In millions) 2020 2019 2018

Customer Receivables

Beginning of year balance $ 46 $ 50 $ 49

Charged to income (1)

Charged to other accounts (2)

Write-offs ( 102 ) ( 132 ) ( 136 )

End of year balance $ 164 $ 46 $ 50

Other Receivables

Beginning of year balance $ 21 $ 2 $ 1

Charged to income 7 27 13

Charged to other accounts (2)

Write-offs ( 12 ) ( 9 ) ( 12 )

End of year balance $ 26 $ 21 $ 2

Affiliated Companies Receivables (3)

Beginning of year balance $ 1,063 $ 920 $ —

Charged to income — 143 920

Charged to other accounts (2)

Write-offs ( 1,063 ) — —

End of year balance $ — $ 1,063 $ 920

(1) Customer receivable amounts charged to income for the years ended December 31, 2020, 2019 and 2018 include approximately $ 103 million, $ 25 million, and $ 24 million respectively, deferred for future recovery.

(2) Represents recoveries and reinstatements of accounts previously written off for uncollectible accounts.

(3) Amounts relate to the FES Debtors and are included in discontinued operations.

Write-off of $ 1.1 billion in 2020 was recognized upon their emergence in February 2020.

See Note 3, "Discontinued Operations" for additional information.

Receivables from customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers for the Utilities.

There was no material concentration of receivables as of December 31, 2020 and 2019, with respect to any particular segment of FirstEnergy’s customers.

Billed and unbilled customer receivables as of December 31, 2020 and 2019, net of allowance for uncollectible accounts, are included below.

Customer Receivables December 31, 2020 December 31, 2019

(In millions)

Billed $ 636 $ 564

Unbilled 567 527

Total $ 1,203 $ 1,091

The allowance for uncollectible customer receivables is based on historical loss information comprised of a rolling 36-month average net write-off percentage of revenues, in conjunction with a qualitative assessment of elements that impact the collectability of receivables to determine if allowances for uncollectible accounts should be further adjusted in accordance with the accounting guidance for credit losses.

Management contemplates available current information such as changes in economic factors, regulatory matters, industry trends, customer credit factors, amount of receivable balances that are past-due, payment options and programs available to customers, and the methods that the Utilities are able to utilize to ensure payment.

FirstEnergy reviews its allowance for uncollectible customer receivables utilizing a quantitative and qualitative assessment, which includes consideration of the outbreak of COVID-19 and the impact on customer receivable balances outstanding and the ability of customers to continue payment since the pandemic began.

Beginning March 13, 2020, FirstEnergy temporarily suspended customer disconnections for nonpayment and ceased collection activities as a result of the ongoing pandemic and in accordance with state regulatory requirements.

The temporary suspension of disconnections for nonpayment and ceased collection activities extended into the fourth quarter of 2020 and resumed for most customers before the end of 2020.

Customers are subject to each state's applicable regulations on winter moratoriums for residential customers, which begin as early as November 1, 2020, and are in effect until April 15, 2021.

See Note 14, “Regulatory Matters,” for further discussion on applicable regulations that may alter residential customer disconnection and collection activity, such as winter moratoriums.

The impact of COVID-19 on customers’ ability to pay for service, along with the actions FirstEnergy has taken in response to the pandemic, is expected to result in an increase in customer receivable write-offs as compared to historically incurred losses.

In order to estimate the additional losses and impacts expected, FirstEnergy analyzed the likelihood of loss based on increases in customer accounts in arrears since the pandemic began in mid-March 2020 as well as what collection methods are or were suspended, and that have historically been utilized to ensure payment.

Based on this assessment, and consideration of other qualitative factors described above, FirstEnergy recognized incremental uncollectible expense of $ 121 million in the year 2020, of which approximately $ 90 million is not currently being collected through rates and as a result was deferred for future recovery under regulatory mechanisms described below.

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, respectively, 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 has authorized the Pennsylvania Companies to track all prudently incurred incremental costs arising from COVID-19, and to create a regulatory asset for future recovery of incremental uncollectible expenses incurred as a result of COVID-19 above what is included in the Pennsylvania Companies existing rates.

On October 13, 2020, the PPUC entered an order that permits the Pennsylvania Companies to create a regulatory asset for incremental expenses associated with lifting the service termination moratorium, as further discussed below.

Receivables from customers also include PJM receivables resulting from transmission and wholesale sales.

FirstEnergy’s credit risk on PJM receivables is reduced due to the nature of PJM’s settlement process whereby members of PJM legally agree to share the cost of defaults and as a result there is no allowance for doubtful accounts.

Sale of Minority Interest in FirstEnergy Transmission, LLC

On November 6, 2021, FirstEnergy, along with FET, entered into the FET P&SA, with Brookfield and Brookfield Guarantors, pursuant to which FET agreed to issue and sell to Brookfield at the closing, and Brookfield agreed to purchase from FET, certain newly issued membership interests of FET, such that Brookfield will own 19.9% of the issued and outstanding membership interests of FET, for a purchase price of $2.375 billion.

KATCo, which is currently a subsidiary of FET, will become a wholly owned subsidiary of FE prior to the closing of the transaction and will remain in the Regulated Transmission segment.

The transaction is subject to customary closing conditions, including approval from the FERC and review by the CFIUS.

On January 5, 2022, the parties to this transaction submitted to FERC an application requesting approval of the transaction no later than April 30, 2022, and on February 10, 2022, the parties filed answers in the FERC docket to certain protests that were filed on January 26, 2022.

Pursuant to the terms of the FET P&SA, in connection with the closing, Brookfield, FET and FirstEnergy Corp will enter into the FET LLC Agreement.

The FET LLC Agreement, among other things, provides for the governance, exit, capital and distribution, and other arrangements for FET from and following the closing.

Under the FET LLC Agreement, Brookfield will be entitled to appoint a number of directors to the FET Board, in approximate proportion to Brookfield’s ownership percentage in FET (rounded to the next whole number).

Upon the closing, the FET Board will consist of five directors, one appointed by Brookfield and four appointed by FE.

The FET LLC Agreement contains certain investor protections, including, among other things, requiring Brookfield's approval for FET and its subsidiaries to take certain major actions.

Under the terms of the FET LLC Agreement, for so long as Brookfield holds a 9.9% interest in FET, Brookfield’s consent is required for FET or any of its subsidiaries to incur indebtedness (other than the refinancing of existing indebtedness on commercially reasonable terms reflecting then-current credit market conditions) that would reasonably be expected to result in the FET’s consolidated Debt-to-Capital Ratio (as defined in the FET LLC Agreement) equaling or exceeding (i) prior to the fifth anniversary of the effective date, 65%, and (ii) thereafter, 70%.

ACCOUNTING FOR THE EFFECTS OF REGULATION

FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to the Utilities and the Transmission Companies since their rates are established by a third-party regulator with the authority to set rates that bind customers, are cost-based and can be charged to and collected from customers.

FirstEnergy records regulatory assets and liabilities that result from the regulated rate-making process that would not be recorded under GAAP for non-regulated entities.

These assets and liabilities are amortized in the Consolidated Statements of Income concurrent with the recovery or refund through customer rates.

FirstEnergy believes that it is probable that its regulatory assets and liabilities will be recovered and settled, respectively, through future rates.

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,

FirstEnergy’s Regulated Distribution and Regulated Transmission segments are subject to regulation that sets 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, regulatory agencies permit the future recovery of costs that would be currently charged to expense by an unregulated company.

The ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows.

FirstEnergy reviews the probability of recovery of regulatory assets, and settlement of regulatory liabilities, at each balance sheet date and whenever new events occur.

Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order, or passage of new legislation.

Upon material changes to these factors, where applicable, FirstEnergy will record new regulatory assets or liabilities and will assess whether it is probable that currently recorded regulatory assets and liabilities will be recovered or settled in future rates.

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.

See Note 12, "Regulatory Matters," of the Notes to Consolidated Financial Statements for additional information.

The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2021 and 2020, and the changes during the year ended December 31, 2021:

As of December 31,

Net Regulatory Assets (Liabilities) by Source 2021 2020 Change

(In millions)

Customer payables for future income taxes $ ( 2,345 ) $ ( 2,369 ) $ 24

Nuclear decommissioning and spent fuel disposal costs ( 102 ) ( 197 ) 95

Spent nuclear fuel disposal costs ( 101 ) ( 102 ) 1

Asset removal costs ( 646 ) ( 721 ) 75

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Uncollectible and COVID-19 related costs 56 97 ( 41 )

Energy efficiency program costs 47 42 5

New Jersey societal benefit costs 109 112 ( 3 )

Regulatory transition costs ( 18 ) ( 20 ) 2

Vegetation management 33 22 11

Other ( 19 ) ( 9 ) ( 10 )

1 unchanged sentence

The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2021 and 2020, of which approximately $228 million and $195 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,

Regulatory Assets by Source Not Earning a As of December 31,

Current Return 2021 2020 Change

(in millions)

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COVID-19 related costs 65 66 ( 1 )

Other 35 32 3

Regulatory transition costs 13 16 ( 3 )

Vegetation management 31 22 9

Regulatory Assets Not Earning a Current Return $ 732 $ 789 $ ( 57 )

FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, coal and energy transmission.

To manage the volatility related to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy.

The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice.

FirstEnergy may use a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchases and normal sales criteria.

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

EARNINGS PER SHARE OF COMMON STOCK

Basic EPS available to common stockholders is computed using the weighted average number of common shares outstanding during the relevant period as the denominator.

The denominator for diluted EPS of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised.

During 2019 and 2018, EPS was computed using the two-class method required for participating securities.

The denominator for diluted EPS of common stock reflects the weighted average

of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised.

During 2019, EPS was computed using the two-class method required for participating securities.

The convertible preferred stock issued in January 2018 were considered participating securities since the shares participated in dividends on common stock on an “as-converted” basis.

All convertible preferred stock was converted to common stock during 2019.

All convertible preferred stock outstanding was converted to common stock during 2019.

The two-class method uses an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available only to common stockholders.

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• preferred stock dividends;

• deemed dividends for the amortization of the beneficial conversion feature recognized at issuance of the preferred stock (if any), and

• deemed dividends for the amortization of the beneficial conversion feature recognized at issuance of the preferred stock (if any);

• an allocation of undistributed earnings between the common stock and the participating securities (convertible preferred stock) based on their respective rights to receive dividends.

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The dilutive effect of outstanding share-based awards was computed using the treasury stock method, which assumes any proceeds that could be obtained upon the exercise of the award would be used to purchase common stock at the average market price for the period.

The dilutive effect of the convertible preferred stock was computed using the if-converted method, which assumes conversion of the convertible preferred stock at the beginning of the period, giving income recognition for the add-back of the preferred stock dividends, amortization of beneficial conversion feature, and undistributed earnings allocated to preferred stockholders.

Year Ended December 31,

The dilutive effect of the convertible preferred stock in 2019 was computed using the if-converted method, which assumes conversion of the convertible preferred stock at the beginning of the period, giving income recognition for the add-back of the preferred stock dividends and undistributed earnings allocated to preferred stockholders.

For the Years Ended December 31,

Reconciliation of Basic and Diluted EPS of Common Stock 2021 2020 2019

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Income from continuing operations $ 1,239 $ 1,003 $ 904

Preferred dividends — ( 3 ) ( 71 )

Amortization of beneficial conversion feature — — ( 296 )

Undistributed earnings allocated to preferred stockholders (1)

Preferred dividends N/A N/A ( 3 )

Undistributed earnings allocated to preferred stockholders N/A N/A ( 1 )

Income from continuing operations available to common stockholders 1,239 1,003 900

Discontinued operations, net of tax 44 76 8

Undistributed earnings allocated to preferred stockholders (1)

Undistributed earnings allocated to preferred stockholders N/A N/A —

Income from discontinued operations available to common stockholders 44 76 8

Income attributable to common stockholders, basic $ 1,283 $ 1,079 $ 908

Income allocated to preferred stockholders, preferred dilutive (2)

Income allocated to preferred stockholders, preferred dilutive N/A N/A 4

Income attributable to common stockholders, dilutive $ 1,283 $ 1,079 $ 912

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Weighted average number of basic shares outstanding 545 542 535

Assumed exercise of dilutive stock options and awards 1 3 2

Assumed conversion of preferred stock — 4 —

Assumed exercise of dilutive share based awards 1 1 3

Assumed conversion of preferred stock N/A N/A 4

Weighted average number of diluted shares outstanding 546 543 542

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$ 2.35 $ 1.99 $ 1.68

(1) Undistributed earnings were not allocated to participating securities for the year ended December 31, 2018, as income from continuing operations less dividends declared (common and preferred) and deemed dividends were a net loss.

Undistributed earning allocated to participating securities for the years ended December 31, 2019 and 2020 were immaterial.

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

Amounts allocated to preferred stockholders of $ 4 million for the year ended December 31, 2019 are included within Income from continuing operations available to common stockholders for diluted earnings.

For the year ended December 31, 2018, approximately 1 million shares from stock options and awards were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

For the year ended December 31, 2019, no shares from stock options or awards were excluded from the calculation of diluted shares.

For the year ended December 31, 2020, approximately 80 thousand shares from stock options and awards were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

For the years ended December 31, 2021, 2020 and 2019 there were no material amount of shares excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

In a business combination, the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed is recognized as goodwill.

FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise.

In evaluating goodwill for impairment, FirstEnergy assesses qualitative factors to determine whether it is more likely than not (that is, likelihood of more than 50%) that the fair value of a reporting unit is less than its carrying value (including goodwill).

If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then no further testing is required.

However, if FirstEnergy concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying value or bypasses the qualitative assessment, then the quantitative goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized, if any.

As of July 31, 2021, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission reporting units' goodwill, assessing economic, industry and market considerations in addition to the reporting units' overall financial performance.

Key factors used in the assessment included:

growth rates, interest rates, expected investments, utility sector market performance, regulatory and legal developments, and other market considerations.

It was determined that the fair values of these reporting units were, more likely than not, greater than their carrying values and a quantitative analysis was not necessary.

FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution and Regulated Transmission.

The following table presents goodwill by reporting unit as of December 31, 2021:

(In millions) Regulated Distribution Regulated Transmission Consolidated

Goodwill $ 5,004 $ 614 $ 5,618

Materials and supplies inventory includes fuel inventory and the distribution, transmission and generation plant materials, net of reserve for excess and obsolete inventory.

Materials charged to inventory are at weighted average cost when purchased and expensed or capitalized, as appropriate, when used or installed.

Fuel inventory is accounted for at weighted average cost when purchased and recorded to fuel expense when consumed.

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment reflects original cost (net of any impairments recognized), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service.

Property, plant and equipment reflects original cost (net of any impairments recognized), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and financing costs incurred to place the assets in service.

The costs of normal maintenance, repairs and minor replacements are expensed as incurred.

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(1) Includes finance leases of $ 143 million and $ 153 million as of December 31, 2021 and 2020, respectively.

The major classes of Property, plant and equipment are largely consistent with the segment disclosures above.

Regulated Distribution has approximately $ 2.1 billion of total regulated generation property, plant and equipment.

Included within Regulated Distribution is $ 882 million of assets classified as held for sale as of December 31, 2019 associated with the asset purchase and sale agreements with TMI-2 Solutions to transfer TMI-2 to TMI-2 Solutions, LLC.

With the receipt of all required regulatory approvals, the transaction was consummated on December 18, 2020.

As a result, during the fourth quarter of 2020 FirstEnergy recognized an after tax-gain of approximately $ 33 million, primarily associated with the write-off of a tax related regulatory liability.

See Note 15, "Commitments, Guarantees and Contingencies" for additional information.

Also included within the segment is $ 45 million of assets classified as held for sale as of December 31, 2020 associated with the asset purchase agreement with Yards Creek Energy, LLC to transfer JCP&L's 50 % interest in the Yards Creek pumped-storage hydro generation station ( 210 MWs).

Regulated Distribution has approximately $ 2.1 billion of total regulated generation property, plant and equipment as of December 31, 2021.

Included within the Regulated Distribution segment is $ 45 million of assets classified as held for sale as of December 31, 2020 associated with the asset purchase agreement with Yards Creek;

see Note 12, "Regulatory Matters," for additional information.

FirstEnergy provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service.

The respective annual composite depreciation rates for FirstEnergy were 2.7 %, 2.7 % and 2.6 % in 2020, 2019 and 2018, respectively.

The respective annual composite depreciation rates for FirstEnergy were approximately 2.7 % in each 2021, 2020 and 2019.

For the years ended December 31, 2021, 2020 and 2019, capitalized financing costs on FirstEnergy's Consolidated Statements of Income include $ 48 million, $ 49 million and $ 45 million, respectively, of allowance for equity funds used during construction and $ 27 million, $ 28 million and $ 26 million, respectively, of capitalized interest.

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Asset Retirement Obligations

FE recognizes an ARO for the future remediation of environmental liabilities associated with all of its long-lived assets.

The ARO liability represents an estimate of the fair value of FirstEnergy's current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets.

FirstEnergy recognizes an ARO for its legal obligation to perform asset retirement activities associated with its long-lived assets.

The ARO liability represents an estimate of the fair value of FirstEnergy's current obligation such that the ARO is accreted monthly to reflect the time value of money.

A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability.

FirstEnergy uses an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation AROs, considering the expected timing of settlement of the ARO based on the expected economic useful life of associated asset and/or regulatory requirements.

The fair value of an ARO is

recognized in the period in which it is incurred.

FirstEnergy uses an expected cash flow approach to measure the fair value of the remediation AROs, considering the expected timing of settlement of the ARO based on the expected economic useful life of associated asset and/or regulatory requirements.

The fair value of an ARO is recognized in the period in which it is incurred.

The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset.

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

AROs as of December 31, 2020, including the transfer of TMI-2, its NDT and related decommissioning liabilities to TMI-2 Solutions, LLC, a subsidiary of Energy Solutions , LLC, in the fourth quarter of 2020, are described further in Note 13, "Asset Retirement Obligations."

AROs as of December 31, 2021, are described further in Note 11, "Asset Retirement Obligations."

Asset Impairments

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If the carrying value is greater than the undiscounted future cash flows, an impairment charge is recognized equal to the amount the carrying value of the assets exceeds its estimated fair value.

In a business combination, the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed is recognized as goodwill.

FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise.

If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then no further testing is required.

As of July 31, 2020, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission reporting units' goodwill, assessing economic, industry and market considerations in addition to the reporting units' overall financial performance.

Key factors used in the assessment included:

growth rates, interest rates, expected capital expenditures, utility sector market performance, regulatory and legal developments, and other market considerations.

It was determined that the fair values of these reporting units were, more likely than not, greater than their carrying values and a quantitative analysis was not necessary.

FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution and Regulated Transmission.

The following table presents goodwill by reporting unit as of December 31, 2020:

(In millions) Regulated Distribution Regulated Transmission Consolidated

Goodwill $ 5,004 $ 614 $ 5,618

Materials and supplies inventory includes fuel inventory and the distribution, transmission and generation plant materials, net of reserve for excess and obsolete inventory.

Materials are generally charged to inventory at weighted average cost when purchased and expensed or capitalized, as appropriate, when used or installed.

Fuel inventory is accounted for at weighted average cost when purchased and recorded to fuel expense when consumed.

FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, coal and energy transmission.

FirstEnergy may use a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchases and normal sales criteria.

Receivables from customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers of the Utilities.

There was no material concentration of receivables as of December 31, 2021 and 2020, with respect to any particular segment of FirstEnergy’s customers.

Billed and unbilled customer receivables as of December 31, 2021 and 2020, are included below.

As of December 31,

Customer Receivables 2021 2020

(In millions)

Unbilled 576 567

Uncollectible Reserve 159 164

Total Customer Receivables $ 1,033 $ 1,203

(1) Includes approximately $ 318 million and $ 349 million as of December 31, 2021, 2020, respectively, that are past due by greater than 30 days.

Activity in the allowance for uncollectible accounts on receivables for the years ended December 31, 2021, 2020 and 2019 are as follows:

(In millions) 2021 2020 2019

Customer Receivables

Beginning of year balance $ 164 $ 46 $ 50

Charged to income (1)

Charged to other accounts (2)

Write-offs ( 101 ) ( 102 ) ( 132 )

End of year balance $ 159 $ 164 $ 46

Other Receivables

Beginning of year balance $ 26 $ 21 $ 2

Charged to income 3 7 27

Charged to other accounts (2)

Write-offs ( 22 ) ( 12 ) ( 9 )

End of year balance $ 10 $ 26 $ 21

Affiliated Companies Receivables (3)

Beginning of year balance $ — $ 1,063 $ 920

Charged to income — — 143

Charged to other accounts (2)

Write-offs — ( 1,063 ) —

End of year balance $ — $ — $ 1,063

(1) Customer receivable amounts charged to income for the years ended December 31, 2021, 2020 and 2019 include approximately $ 12 million, $ 103 million, and $ 25 million respectively, deferred for future recovery.

(2) Represents recoveries and reinstatements of accounts previously written off for uncollectible accounts.

(3) Amounts relate to the FES Debtors and are included in discontinued operations.

Write-off of $ 1.1 billion in 2020 was recognized upon their emergence in February 2020.

Beginning March 13, 2020, FirstEnergy temporarily suspended customer disconnections for nonpayment and ceased collection activities as a result of the ongoing COVID-19 pandemic and in accordance with state regulatory requirements.

The temporary suspension of disconnections for nonpayment and ceasing of collection activities extended into the fourth quarter of 2020 but resumed for many customers before the end of 2020, except in New Jersey where the moratorium was extended until the end of 2021.

Customers are subject to each state's applicable regulations on winter moratoriums.

See Note 12, “Regulatory Matters,” for further discussion on applicable regulations that may alter customer disconnections and collection activity as well as regulatory recovery.

During 2020, FirstEnergy analyzed the likelihood of loss based on increases in customer accounts in arrears since the pandemic began in mid-March 2020 as well as what collection methods at the time were suspended, and historically been utilized to ensure payment.

Based on this assessment, and consideration of other qualitative factors described above, FirstEnergy recognized incremental uncollectible expense of $ 121 million in the year 2020, of which approximately $ 90 million was not being collected through rates and as a result was deferred for future recovery under regulatory mechanisms.

During 2021, arrears levels continue to be elevated above 2019 pre-pandemic levels.

Various regulatory actions have impacted the growth and recovery of past due balances including extensions on moratoriums, significant restrictions regarding disconnections, and extended installment plans.

FirstEnergy has experienced a reduction in the amount of receivables that are past due by greater than 30 days since the end of 2020.

While total customer arrears balances continue to decrease in 2021, balances that are over 120 days past due continue to be elevated.

FirstEnergy considered other factors as part of its qualitative assessment, such as certain federal stimulus and state funding being made available to assist with past due utility bills.

As a result of this qualitative analysis, FirstEnergy did not recognize any incremental uncollectible expense for the twelve months ended December 31, 2021.

Additionally, as a result of the pandemic-related moratoriums and certain customer installment or extended payment plans offered, the allowance for uncollectible accounts on receivables in 2021 and 2020 are elevated due to the extension of when certain write-offs would have otherwise occurred.

Other receivables include PJM receivables resulting from transmission and wholesale sales.

FirstEnergy’s uncollectible risk on PJM receivables is minimal due to the nature of PJM’s settlement process whereby members of PJM legally agree to share the cost of defaults and as a result there is no allowance for doubtful accounts.

VARIABLE INTEREST ENTITIES

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• Ohio Securitization - In June 2013, SPEs formed by the Ohio Companies issued approximately $ 445 million of pass-through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets.

• JCP&L Securitization - JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS.

• MP and PE Environmental Funding Companies - Bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE which issued environmental control bonds.

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As of December 31, 2021, the carrying value of the equity method investment was $ 59 million.

As discussed in Note 15, "Commitments, Guarantees and Contingencies," FE is the guarantor under Global Holding's $ 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.

Failure by Global Holding to meet the terms and conditions under its term loan facility could require FE to be obligated under the provisions of its guarantee, resulting in consolidation of Global Holding by FE.

• PATH WV - PATH, a proposed transmission line from West Virginia through Virginia into Maryland which PJM cancelled in 2012, is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property.

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FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of PATH-WV.

FirstEnergy's ownership interest in PATH-WV is subject to the equity method of accounting.

FirstEnergy's ownership interest in

PATH-WV is subject to the equity method of accounting.

As of December 31, 2021, the carrying value of the equity method investment was $ 18 million.

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Recently Adopted Pronouncements

ASU 2016-13, “ Financial Instruments - Credit Losses (Topic 326):

Measurement of Credit Losses on Financial Instruments ” (Issued June 2016 and subsequently updated):

ASU 2016-13 removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life.

Prior to adoption, FirstEnergy analyzed its financial instruments within the scope of this guidance, primarily trade receivables and AFS debt securities.

The adoption of this standard upon January 1, 2020 did not have a material impact to FirstEnergy’s financial statements and required additional disclosures in these Notes to the Consolidated Financial Statements.

Please see above for additional information on FirstEnergy’s allowance for uncollectible customer receivables.

ASU 2018-15, " Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40):

Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract " (Issued August 2018):

ASU 2018-15 allows implementation costs incurred by customers in cloud computing arrangements to be deferred and recognized over the term of the arrangement, if those costs would be capitalized by the customers in a software licensing arrangement.

FirstEnergy adopted this standard as of January 1, 2020, with no material impact to its financial statements.

ASU 2020-04, " Reference Rate Reform (Topic 848):

Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (Issued March 2020 and subsequently updated):

ASU 2020-04 provides temporary optional expedients and exceptions to the current guidance on contract modifications to ease the financial reporting burdens related to the expected market transition from LIBOR and other interbank offered rates to alternative reference rates.

FirstEnergy’s $ 3.5 billion Revolving Credit Facility bears interest at fluctuating interest rates based on LIBOR and contains provisions (requiring an amendment) in the event that LIBOR can no longer be used.

As of December 31, 2020, FirstEnergy has not utilized any of the expedients discussed within this ASU.

Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted.

Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable.

FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting.

ASU 2019-12, " Simplifying the Accounting for Income Taxes" (Issued in December 2019):

ASU 2019-12 enhances and simplifies various aspects of the income tax accounting guidance including the elimination of certain exceptions related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences.

ASU 2019-12 enhances and simplifies various aspects of the income tax accounting guidance, including the elimination of certain exceptions related to the approach for intra-period tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences.

The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill.

The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020, with early adoption permitted.

FirstEnergy continues to evaluate the new guidance, but currently does not expect a material impact upon adopting this standard.

FirstEnergy adopted the guidance as of January 1, 2021, with no material impact to the financial statements.

Recently Issued Pronouncements - FirstEnergy has assessed new authoritative accounting guidance issued by the FASB that has not yet been adopted and none are currently expected to have a material impact to the financial statements.

FirstEnergy accounts for revenues from contracts with customers under ASC 606, “ Revenue from Contracts with Customers.

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Total revenues from contracts with customers $ 9,644 $ 1,608 $ ( 140 ) $ 11,112

Other non-customer revenue 93 17 ( 64 ) 46

( 27 ) — — ( 27 )

Other revenue unrelated to contracts with customers

94 10 ( 57 ) 47

Total revenues $ 9,711 $ 1,618 $ ( 197 ) $ 11,132

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(2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($ 3 million at Regulated Distribution and $( 2 ) million at Regulated Transmission).

(3) ARP revenue for the year ended December 31, 2020, is primarily related to shared savings revenue in Ohio.

(3) Reflects amounts the Ohio Companies refunded to customers that was previously collected under decoupling mechanisms, with interest.

See Note 12, “Regulatory Matters,” for further discussion on Ohio decoupling rates.

(4) Includes $ 38 million of customer refunds associated with the Ohio Stipulation that became effective in December 2021.

See Note 12, “Regulatory Matters,” for additional information.

The following represents a disaggregation of revenue from contracts with customers for the year ended December 31, 2020:

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Total revenues from contracts with customers $ 9,227 $ 1,613 $ ( 139 ) $ 10,701

Other non-customer revenue 96 16 ( 63 ) 49

Other revenue unrelated to contracts with customers

93 17 ( 64 ) 46

Total revenues $ 9,363 $ 1,630 $ ( 203 ) $ 10,790

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(2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($ 2 million at Regulated Distribution and $ 7 million at Regulated Transmission).

(3) ARP revenue for the year ended December 31, 2019, includes DMR revenue, lost distribution and shared savings revenue in Ohio.

(3) ARP revenue for the year ended December 31, 2020, is primarily related to shared savings revenue in Ohio.

The following represents a disaggregation of revenue from contracts with customers for the year ended December 31, 2019:

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Total revenues from contracts with customers $ 9,421 $ 1,510 $ ( 126 ) $ 10,805

Other non-customer revenue 108 18 ( 63 ) 63

Other revenue unrelated to contracts with customers

96 16 ( 63 ) 49

Total revenues $ 9,698 $ 1,526 $ ( 189 ) $ 11,035

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(3) ARP revenue for the year ended December 31, 2019, includes DMR revenue, lost distribution and shared savings revenue in Ohio.

Other non-customer revenue includes revenue from late payment charges of $ 31 million, $ 37 million and $ 39 million, respectively, for the years ended December 31, 2020, 2019 and 2018.

During 2020, certain late payment charges began to be waived in response to the COVID-19 pandemic, and as a result, FirstEnergy did not recognize these revenues.

Late payment charges have resumed for most customers as of December 31, 2020.

See Note 1, “Organization and Basis of Presentation,” for further discussion on the COVID-19 pandemic.

Other non-customer revenue also includes revenue from derivatives of $ 14 million, $ 8 million and $ 18 million, respectively, for the years ended December 31, 2020, 2019 and 2018.

Other revenue unrelated to contracts with customer s includes revenue from late payment charges of $ 36 million, $ 31 million and $ 37 million, respectively, for the years ended December 31, 2021, 2020 and 2019.

Other revenue unrelated to contracts with customer s also includes revenue from derivatives of $ 11 million, $ 14 million and $ 8 million, respectively, for the years ended December 31, 2021, 2020 and 2019.

Regulated Distribution

The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies and also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey, 210 MWs of which are related to the Yards Creek generating plant that is being sold pursuant to an asset purchase agreement as further discussed below.

The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies and also controls 3,580 MWs of regulated electric generation capacity located primarily in West Virginia and Virginia.

Each of the Utilities earns revenue from state-regulated rate tariffs under which it provides distribution services to residential, commercial and industrial customers in its service territory.

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Certain of the Utilities may also purchase power in the PJM markets to supply power to their customers.

Generally, these power sales from generation and purchases to serve load are netted hourly and reported as either revenues or purchased power on the Consolidated Statements of Income based on whether the entity was a net seller or buyer each hour.

Capacity revenues are recognized ratably over the PJM planning year at prices cleared in the annual PJM Reliability Pricing Model Base Residual Auction and Incremental Auctions.

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ASC 606 excludes industry-specific accounting guidance for recognizing revenue from ARPs as these programs represent contracts between the utility and its regulators, as opposed to customers.

Therefore, revenue from these programs are not within the scope of ASC 606 and regulated utilities are permitted to continue to recognize such revenues in accordance with existing practice but are presented separately from revenue arising from contracts with customers.

FirstEnergy currently has ARPs in Ohio, primarily under the DMR, lost distribution and shared savings revenue in 2019, and shared savings in 2020.

Therefore, revenues from these programs are not within the scope of ASC 606 and regulated utilities are permitted to continue to recognize such revenues in accordance with existing practice but are presented separately from revenue arising from contracts with customers.

FirstEnergy had ARPs in Ohio primarily for shared savings in 2020, and has reflected refunds of decoupling revenue owed to customers as reductions to ARPs in 2021.

See Note 12, “Regulatory Matters,” for further discussion on decoupling revenues in Ohio.

Regulated Transmission

The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities.

The segment's revenues are primarily derived from forward-looking formula rates at the Transmission Companies, as well as stated transmission rates at JCP&L, MP, PE and WP, although as further discussed in Note 14, “Regulatory Matters,” MP, PE and WP filed with FERC on October 29, 2020, to convert their existing stated transmission rates to forward-looking formula rates, effective January 1, 2021.

JCP&L had stated rates in 2019, but moved to forward-looking formula rates, subject to a refund, effective January 1, 2020, as further discussed in Note 14, “Regulatory Matters.”

Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment.

The segment's revenues are derived from forward-looking formula rates.

See Note 12, “Regulatory Matters,” for additional information.

Forward-looking formula rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment.

Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs.

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.

Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time.

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JCP&L 164 178 160

Other 134 130 125

MP, PE and WP 124 134 130

Total Revenues $ 1,608 $ 1,613 $ 1,510

DISCONTINUED OPERATIONS

FES and FENOC Chapter 11 Bankruptcy Filing

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.

By eliminating a significant portion of its competitive generation fleet with the deconsolidation of the FES Debtors, FirstEnergy has concluded the FES Debtors meet the criteria for discontinued operations, as this represents a significant event in management’s strategic review to exit commodity-exposed generation and transition to a fully regulated company.

Services Agreement

Pursuant to the FES Bankruptcy settlement agreement, FirstEnergy entered into an amended and restated shared services agreement with the FES Debtors to extend the availability of shared services until June 30, 2020, subject to reductions in services if requested by the FES Debtors, and extensions of time, subject to FirstEnergy’s approval.

Under the amended shared services agreement, and consistent with the prior shared services agreements, costs are directly billed or assigned at no more than cost.

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.

federal income taxes, the FES Debtors were included in FirstEnergy’s consolidated tax return until emergence from bankruptcy on February 27, 2020.

As a result of the FES Debtors’ deconsolidation, FirstEnergy recognized a worthless stock deduction for the remaining tax basis in the FES Debtors of approximately $ 4.9 billion, net of unrecognized tax benefits of $ 316 million.

Tax-effected, the worthless stock deduction is approximately $ 1.1 billion, net of valuation allowances recorded against the state tax benefit ($ 80 million) and the aforementioned unrecognized tax benefits ($ 72 million).

Additionally, the Tax Act amended Section 163(j) of the Internal Revenue Code, limiting interest expense deductions for corporations but with exemption for certain regulated utilities.

Based on interpretation of subsequently issued proposed regulations, FirstEnergy estimated the amount of deductible interest for its consolidated group in 2018 and 2019, with

nondeductible portions being carried forward with an indefinite life and for which deferred tax assets were recorded.

However, full valuation allowances were recorded against the deferred tax assets related to the carryforward of nondeductible interest as future utilization of the carryforwards requires taxable income from sources other than regulated utility businesses.

Final regulations under Section 163(j) were issued in July 2020 and January 2021 but do not materially change these results.

All tax expense related to nondeductible interest in 2018 and 2019 was recorded in discontinued operations as it was entirely attributed to the inclusion of the FES Debtors in FirstEnergy's consolidated tax group.

Pursuant to certain safe harbor rules in the final regulations under Section 163(j), and due to the FES Debtors’ emergence from bankruptcy on February 27, 2020, FirstEnergy expects all interest expense for 2020 to be fully deductible.

See Note 7, “Income Taxes” for further information

Upon emergence, FirstEnergy paid the FES Debtors $ 125 million to settle all reconciliations under the Intercompany Tax Allocation Agreement for 2018, 2019 and 2020 tax years, including all issues regarding nondeductible interest.

In September 2020, FirstEnergy filed its 2019 federal income tax return with the IRS and recognized a $ 6 million charge to discontinued operations in the third quarter of 2020, resulting from final adjustments to 2019 intercompany tax sharing related to the FES Debtors.

The final intercompany tax sharing adjustment for the 2020 federal income tax return to be filed during 2021 is an estimated $ 12 million tax benefit and was recorded during the fourth quarter of 2020 in discontinued operations.

Competitive Generation Asset Sales

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.

During the first quarter of 2020, FG paid AE Supply approximately $ 65 million of cash for related materials and supplies (at book value) and the settlement of FG’s economic interest in Pleasants.

Summarized Results of Discontinued Operations

Summarized results of discontinued operations for the years ended December 31, 2020, 2019, and 2018 were as follows:

For the Years Ended December 31,

(In millions) 2020 2019 2018 (1)

Revenues $ 7 $ 188 $ 989

Fuel ( 6 ) ( 140 ) ( 304 )

Purchased power — — ( 84 )

Other operating expenses ( 6 ) ( 63 ) ( 435 )

Provision for depreciation — — ( 96 )

General taxes — ( 14 ) ( 35 )

Pleasants economic interest (2)

Other expense, net — ( 2 ) ( 83 )

Loss from discontinued operations, before tax — ( 4 ) ( 48 )

Income tax expense (benefit) — 47 61

Loss from discontinued operations, net of tax — ( 51 ) ( 109 )

Removal of investment in FES and FENOC — — 2,193

Assumption of benefit obligations retained at FE — — ( 820 )

Guarantees and credit support provided by FE — — ( 139 )

Reserve on receivables and allocated pension/OPEB mark-to-market — — ( 914 )

Settlement consideration and services credit ( 1 ) 7 ( 1,197 )

Accelerated net pension and OPEB prior service credits 18 — —

Gain (loss) on Disposal of FES and FENOC, before tax 17 7 ( 877 )

Income tax benefit including worthless stock deduction ( 59 ) ( 52 ) ( 1,312 )

Gain on disposal of FES and FENOC, net of tax 76 59 435

Income from discontinued operations $ 76 $ 8 $ 326

(1) Discontinued operations include results of FES and FENOC through March 31, 2018, when deconsolidated from FirstEnergy's financial statements.

(2) Reflects the estimated amounts owed from FG for its economic interests in Pleasants effective January 1, 2019.

As discussed above, settlement of the economic interests occurred during the first quarter of 2020.

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 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 INVESTING ACTIVITIES:

Property additions — — ( 27 )

Sales of investment securities held in trusts — — 109

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

ACCUMULATED OTHER COMPREHENSIVE INCOME

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Gains & Losses on Cash Flow Hedges (1)

Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total

Defined Benefit Pension & OPEB Plans Total

(In millions)

1 unchanged sentence

Other comprehensive income before reclassifications — ( 2 ) ( 2 )

— ( 97 ) ( 9 ) ( 106 )

Amounts reclassified from AOCI 2 ( 29 ) ( 27 )

Deconsolidation of FES and FENOC 13 ( 8 ) — 5

Other comprehensive income (loss) 2 ( 31 ) ( 29 )

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AOCI Balance, December 31, 2019 $ ( 9 ) $ 29 $ 20

Other comprehensive income before reclassifications

— — ( 2 ) ( 2 )

Amounts reclassified from AOCI 1 ( 34 ) ( 33 )

4 unchanged sentences

Amounts reclassified from AOCI 1 ( 14 ) ( 13 )

1 — ( 34 ) ( 33 )

Other comprehensive income (loss) 1 ( 14 ) ( 13 )

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The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2021, 2020 and 2019:

Year Ended December 31, Affected Line Item in Consolidated Statements of Income

For the Years Ended December 31, Affected Line Item in Consolidated Statements of Income

Reclassifications from AOCI (1)

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Gains & losses on cash flow hedges

Commodity contracts $ — $ — $ 1 Other operating expenses

Long-term debt $ 1 $ 1 $ 2 Interest expense

— — ( 2 ) Income taxes

$ 1 $ 1 $ 2 Net of tax

Unrealized gains on AFS securities

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

Defined benefit pension and OPEB plans

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(1) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.

(2) Includes stranded tax amounts reclassified from AOCI in connection with the adoption of ASU 2018-02, " Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income ".

(2) Prior-service costs are reported within Miscellaneous income, net within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income.

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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.

In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance.

addition, 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.

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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.

FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method.

In January 2018, FirstEnergy satisfied its minimum required funding obligations to its qualified pension plan of $500 million and addressed anticipated required funding obligations through 2020 to its pension plan with an additional contribution of $750 million.

On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan.

FirstEnergy expects no required contributions until 2022.

On March 11, 2021, President Biden signed into law the American Rescue Plan Act of 2021, which, among other things, extended shortfall amortization periods and modification of the interest rate stabilization rules for single-employer plans thereby impacting funding requirements.

As a result, FirstEnergy does not currently expect to have a required contribution to the pension plan based on various assumptions including annual expected rate of returns for assets of 7.50 %.

However, FirstEnergy may elect to contribute to the pension plan voluntarily.

Pension and OPEB costs are affected by employee demographics (including age, compensation levels and employment periods), the level of contributions made to the plans and earnings on plan assets.

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The fair value of the plan assets represents the actual market value as of the measurement date.

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.

Discount Rate - 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 rates of return on plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy’s pension trusts.

The long-term rate of return is developed considering the portfolio’s asset allocation strategy.

FirstEnergy utilizes 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.

Expected Return on Plan Assets - 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 2021, FirstEnergy’s qualified pension and OPEB plan assets experienced gains of $ 689 million or 7.9 %, compared to gains of $ 1,225 million, or 14.7 % in 2020, and losses of $ 1,492 million, or 20.2 % in 2019 and assumed a 7.50 % rate of return on plan assets in 2021, 2020 and 2019, which generated $ 688 million, $ 651 million and $ 569 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.

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.

The expected return on pension and OPEB assets is based on input from investment consultants, including 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 is recognized as a pension and OPEB mark-to-market adjustment in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for remeasurement.

Mortality Rates - During 2021, 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 plan mortality data indicated the use of the Pri-2012 mortality table with projection scale MP-2021, actuarially adjusted to reflect increased mortality rates due to COVID-19 based on mortality experience reported by the Center for Disease and Control Prevention in 2020 and 2021, was most appropriate and such was utilized to determine the 2021 benefit cost and obligation as of December 31, 2021, for the FirstEnergy pension and OPEB plans.

The impact of using the Pri-2012 mortality table with projection scale MP-2021 (adjusted by FirstEnergy's actuary for COVID-19 impacts) resulted in a decrease to the projected benefit obligation of approximately $ 32 million and $ 2 million for the pension and OPEB plans, respectively, and was included in the 2021 pension and OPEB mark-to-market adjustment.

Net Periodic Benefit Costs - In addition to service costs, interest on obligations, expected return on plan assets, and prior service costs, FirstEnergy recognizes in net periodic benefit costs 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.

Service costs, net of capitalization, are reported within Other operating expenses on FirstEnergy’s Consolidated Statements of Income.

Non-service costs, other than the pension and OPEB mark-to-market adjustment, which is separately shown, are reported within Miscellaneous income, net, within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income.

Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December (1)

2021 2020 2019 2021 2020 2019

Service cost weighted-average discount rate (2)

3.10 % 3.60 %/ 3.24 %

4.66 % 3.03 % 3.63 %/ 3.29 %

Interest cost weighted-average discount rate (3)

2.58 % 3.27 %/ 2.90 %

4.37 % 1.66 % 2.71 %/ 2.30 %

Expected return on plan assets 7.50 % 7.50 % 7.50 % 7.50 % 7.50 % 7.50 %

Rate of compensation increase 4.10 % 4.10 % 4.10 % N/A N/A N/A

(1) Excludes impact of pension and OPEB mark-to-market adjustment.

(2) Weighted-average discount rates effect from January 1, 2020, through February 26, 2020, were 3.60 % and 3.63 % for pension and OPEB service cost, respectively.

Discount rates were 3.24 % and 3.29 % for pension and OPEB service cost, respectively, for the period February 27, 2020 through December 31, 2020.

(3) Weighted-average discount rates in effect from January 1, 2020, through February 26, 2020, were 3.27 % and 2.71 % for pension and OPEB interest cost, respectively.

Discount rates were 2.90 % and 2.30 % for pension and OPEB interest cost, respectively, for the period February 27, 2020, through December 31, 2020.

Components of Net Periodic Benefit Costs (Credits) for the Years Ended December 31, Pension OPEB

2021 2020 2019 2021 2020 2019

(In millions)

Service cost $ 195 $ 194 $ 193 $ 4 $ 4 $ 3

Interest cost 226 287 373 11 15 22

Expected return on plan assets ( 652 ) ( 618 ) ( 540 ) ( 36 ) ( 33 ) ( 29 )

Amortization of prior service costs (credits) (1)

3 12 7 ( 17 ) ( 46 ) ( 36 )

Special termination costs (2)

One-time termination benefits (3)

Pension & OPEB mark-to-market (4)

( 253 ) 463 656 ( 129 ) 14 20

Net periodic benefit costs (credits) $ ( 481 ) $ 346 $ 703 $ ( 167 ) $ ( 46 ) $ ( 20 )

(1) 2020 includes the acceleration of approximately $ 18 million in net credits as a result of the FES Debtors’ emergence during the first quarter of 2020 and is a component of discontinued operations in FirstEnergy’s Consolidated Statements of Income.

(2) Subject to a cap, FirstEnergy agreed to fund a pension enhancement through its pension plan, for voluntary enhanced retirement packages offered to certain FES employees, as well as offer certain other employee benefits.

The costs are a component of discontinued operations in FirstEnergy’s Consolidated Statements of Income.

(3) Costs represent additional benefits provided to FES and FENOC employees under the approved settlement agreement and are a component of discontinued operations.

(4) Of the total Pension and OPEB mark-to-market adjustment for 2019, approximately $ 2 million is included in discontinued operations.

The annual pension and OPEB mark-to-market adjustments, (gains) or losses, for the years ended December 31, 2021, 2020, and 2019 were $( 382 ) million, $ 477 million (including $ 423 million in the first quarter of 2020), and $ 676 million, respectively.

Of these annual pension and OPEB mark-to-market amounts, approximately $( 31 ) million, $ 40 million and $ 47 million were allocated to the Transmission Companies and certain of FirstEnergy's utilities under forward-looking formula rates, and expected to be refunded or recovered through formula transmission rates, respectively.

The 2021 pension and OPEB mark-to-market adjustment primarily reflects an approximate 35 bps increase in the discount rate used to measure pension benefit obligations.

Under the approved bankruptcy settlement agreement, upon emergence, FES and FENOC employees ceased earning years of service under the FirstEnergy pension and OPEB plans.

In the fourth quarter 2020, FirstEnergy recognized a $ 54 million pension and OPEB mark-to-market adjustment.

Obligations and Funded Status - Qualified and Non-Qualified Plans 2021 2020 2021 2020

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Plan amendments — 9 — —

Special termination benefits — 14 — —

Medicare retiree drug subsidy — — 1 1

Actuarial loss 1,011 1,535 41 64

Actuarial loss (gain) ( 280 ) 1,011 ( 101 ) 41

Benefits paid ( 597 ) ( 616 ) ( 46 ) ( 43 )

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Year that the rate reaches the ultimate trend rate N/A N/A 2028 2028

Allocation of Plan Assets (as of December 31)

Equity securities 23 % 29 % 55 % 54 %

Fixed Income 35 % 36 % 28 % 30 %

Hedge funds 7 % 9 % — % — %

Insurance-linked securities 4 % 2 % — % — %

Real estate funds 9 % 7 % — % — %

Private equity funds 5 % 4 % — % — %

Cash and short-term securities 17 % 13 % 17 % 16 %

Total 100 % 100 % 100 % 100 %

Components of Net Periodic Benefit Costs for the Years Ended December 31, Pension OPEB

2020 2019 2018 2020 2019 2018

(In millions)

Service cost $ 194 $ 193 $ 224 $ 4 $ 3 $ 5

Interest cost 287 373 372 15 22 25

Expected return on plan assets ( 618 ) ( 540 ) ( 574 ) ( 33 ) ( 29 ) ( 31 )

Amortization of prior service costs (credits) (1)

12 7 7 ( 46 ) ( 36 ) ( 81 )

Special termination costs (2)

— 14 31 — — 8

One-time termination benefits (3)

Pension & OPEB mark-to-market 463 656 227 14 20 ( 82 )

Net periodic benefit costs (credits) $ 346 $ 703 $ 287 $ ( 46 ) $ ( 20 ) $ ( 156 )

The costs are a component of discontinued operations in FirstEnergy’s Consolidated Statements of Income.

(3) Costs represent additional benefits provided to FES and FENOC employees under the approved settlement agreement and are a component of discontinued operations in FirstEnergy’s Consolidated Statements of Income.

Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December (1)

2020 2019 2018 2020 2019 2018

Service cost weighted-average discount rate (2)

3.60 %/ 3.24 %

4.66 % 3.75 % 3.63 %/ 3.29 %

4.67 % 3.50 %

Interest cost weighted-average discount rate (3)

3.27 %/ 2.90 %

4.37 % 3.75 % 2.71 %/ 2.30 %

3.89 % 3.50 %

Expected long-term return on plan assets 7.50 % 7.50 % 7.50 % 7.50 % 7.50 % 7.50 %

Rate of compensation increase 4.10 % 4.10 % 4.20 % N/A N/A N/A

(1) Excludes impact of pension and OPEB mark-to-market adjustment.

(2) Weighted-average discount rates effect from January 1, 2020, through February 26, 2020, were 3.60 % and 3.63 % for pension and OPEB service cost, respectively.

Discount rates were 3.24 % and 3.29 % for pension and OPEB service cost, respectively, for the period February 27, 2020 through December 31, 2020.

(3) Weighted-average discount rates in effect from January 1, 2020, through February 26, 2020, were 3.27 % and 2.71 % for pension and OPEB interest cost, respectively.

Discount rates were 2.90 % and 2.30 % for pension and OPEB interest cost, respectively, for the period February 27, 2020, through December 31, 2020.

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 rates of return on plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy’s pension trusts.

The long-term rate of return is developed considering the portfolio’s asset allocation strategy.

The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy.

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Cash and short-term securities $ — $ 746 $ — $ 746 8 %

Equities 1,903 162 — 2,065 23 %

Public equity 2,867 286 — 3,153 35 %

Fixed income — 2,453 — 2,453 27 %

Corporate bonds — 2,672 — 2,672 31 %

— 387 — 387 4 %

Alternatives:

Derivatives 20 — — 20 — %

$ 2,887 $ 3,485 $ — $ 6,372 70 %

Private equity funds (2)

Private - equity and debt funds (2)

Insurance-linked securities (2)

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(2) Net Asset Value used as a practical expedient to approximate fair value.

(3) Includes insurance annuities, bank loans and emerging markets debt.

December 31, 2020 Asset Allocation

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Cash and short-term securities $ — $ 1,493 $ — $ 1,493 17 %

Equities 1,532 828 — 2,360 29 %

Public equity 1,903 162 — 2,065 23 %

Fixed income — 3,059 — 3,059 35 %

Corporate bonds — 2,064 — 2,064 25 %

— 880 — 880 11 %

Alternatives:

Derivatives ( 13 ) — — ( 13 ) — %

$ 1,890 $ 4,714 $ — $ 6,604 75 %

Private equity funds (2)

Private - equity and debt funds (2)

Insurance-linked securities (2)

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(2) Net Asset Value used as a practical expedient to approximate fair value.

(3) Includes insurance annuities, bank loans and emerging markets debt.

As of December 31, 2021, and 2020, the OPEB trust investments measured at fair value were as follows:

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Cash and short-term securities $ — $ 95 $ — $ 95 17 %

Equity investment:

Domestic 283 — — 283 55 %

Public equity 278 — — 278 51 %

Fixed income — 175 — 175 32 %

Government bonds — 104 — 104 20 %

Corporate bonds — 34 — 34 7 %

Mortgage-backed securities (non-government) 7 — 7 1 %

$ 283 $ 229 $ — $ 512 100 %

(1) Excludes $( 10 ) million as of December 31, 2020, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

Total $ 278 $ 270 $ — $ 548 100 %

December 31, 2020 Asset Allocation

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Cash and short-term securities $ — $ 84 $ — $ 84 17 %

Equity investment:

Domestic 246 — — 246 54 %

Public equity 283 — — 283 55 %

Fixed income:

Government bonds — 100 — 100 22 %

Corporate bonds — 34 — 34 7 %

Mortgage-backed securities (non-government) — 5 — 5 1 %

— 145 — 145 28 %

$ 283 $ 229 $ — $ 512 100 %

(1) Excludes $( 10 ) million as of December 31, 2020, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

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Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements and periodic asset/liability studies.

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.

FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2021 and 2020 are shown in the following table:

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Alternative investments 8 % 8 %

Cash and short-term securities 6 % 6 %

Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets and other payments, net of participant contributions:

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Stock-based compensation costs capitalized $ 47 $ 26 $ 54

There was no stock option expense for the years ended December 31, 2020, 2019 and 2018.

Income tax benefits associated with stock-based compensation plan expense were $ 5 million, $ 3 million and $ 10 million for the years ended December 31, 2021, 2020 and 2019, respectively.

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During 2021, approximately $ 11 million was paid in relation to the cash portion of restricted stock unit obligations that vested in 2021.

The vesting period for the performance-based restricted stock unit awards granted in 2018, 2019 and 2020, were each 3 years.

The vesting period for the performance-based restricted stock unit awards granted in 2019, 2020 and 2021, were each three years .

Dividend equivalents are received on the restricted stock units and are reinvested in additional restricted stock units and subject to the same performance conditions as the underlying award.

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Certain employees receive awards of FE restricted stock (as opposed to "units" with the right to receive shares at the end of the restriction period) subject to restrictions that lapse over a defined period of time or upon achieving performance results.

value of restricted stock is measured based on the average of the high and low prices of FE common stock on the date of grant.

The fair value of restricted stock is measured based on the average of the high and low prices of FE common stock on the date of grant.

Dividends are received on the restricted stock and are reinvested in additional shares of restricted stock, subject to the vesting conditions of the underlying award.

Restricted stock activity for the year ended December 31, 2021, was not material.

Stock Options

Stock options have been granted to certain employees allowing them to purchase a specified number of common shares at a fixed exercise price over a defined period of time.

Stock options generally expire ten years from the date of grant.

There were no stock options granted in 2020.

Stock option activity for the year ended December 31, 2020 was as follows:

Stock Option Activity Number of Shares

(in millions)

Weighted Average Exercise Price (per share)

Balance, January 1, 2020 (all options exercisable) 0.1 $ 37.75

Options exercised — —

Options forfeited ( 0.1 ) 37.75

Balance, December 31, 2020 (all options exercisable) — $ —

Approximately $ 23 million and $ 12 million of cash was received from the exercise of stock options in 2019 and 2018, respectively.

401(k) Savings Plan

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The form of payout as stock or cash vary depending upon the form of the award, the duration of the deferral and other factors.

Certain types of deferrals such as dividend equivalent units, annual incentive awards, and performance share awards are required to be paid in cash.

Until 2015, payouts of the stock accounts typically occurred three years from the date of deferral, although participants could have elected to defer their shares into a retirement stock account that would pay out in cash upon retirement.

In 2015, FirstEnergy amended the EDCP to eliminate the right to receive deferred shares after three years , effective for deferrals made on or after November 1, 2015.

Awards deferred into a retirement stock account will pay out in cash upon separation from service, death or disability.

Interest accrues on the cash allocated to the retirement cash account and the balance will pay out in cash over a time period as elected by the participant.

Under the DCPD, members of FE's Board of Directors can elect to defer all or a portion of their equity retainers to a deferred stock account and their cash retainers to deferred stock or deferred cash accounts.

The net liability recognized for DCPD of approximately $ 7 million and $ 9 million as of December 31, 2020 and December 31, 2019, respectively, is included in the caption “Retirement benefits,” on the Consolidated Balance Sheets.

Under the DCPD, members of the FE Board can elect to defer all or a portion of their equity retainers to a deferred stock account and their cash retainers to deferred stock or deferred cash accounts.

The net liability recognized for DCPD of approximately $ 9 million and $ 7 million as of December 31, 2021 and 2020, respectively, is included in “Retirement benefits,” on the Consolidated Balance Sheets.

FirstEnergy records income taxes in accordance with the liability method of accounting.

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FE and its subsidiaries are party to an intercompany income tax allocation agreement that provides for the allocation of consolidated tax liabilities.

Net tax benefits attributable to FE, excluding any tax benefits derived from interest expense associated with acquisition indebtedness from the merger with GPU, are reallocated to the subsidiaries of FE that have taxable income.

Net tax benefits attributable to FE, excluding any tax benefits derived from certain interest expense, are generally reallocated to the subsidiaries of FE that have taxable income.

That allocation is accounted for as a capital contribution to the company receiving the tax benefit.

Effective as of their emergence from bankruptcy, February 27, 2020, the FES Debtors no longer are part of FirstEnergy's consolidated federal income tax group or the intercompany income tax allocation agreement.

Upon emergence, FirstEnergy paid the FES Debtors

$ 125 million to settle all reconciliations under the Intercompany Tax Allocation Agreement for 2018, 2019 and 2020 tax years, including all issues regarding nondeductible interest.

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 December 27, 2020, President Trump signed into law the Consolidated Appropriations Act, 2021, an additional stimulus package providing financial relief for individuals and small businesses.

The Appropriations Act contains a variety of tax provisions, including full expensing of business meals in 2021 and 2022, extensions of various energy tax incentives (including the ITC), and expansion of the employee retention tax credit.

FirstEnergy does not currently expect the Appropriations Act to have a material tax impact.

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.

On April 9, 2021, West Virginia enacted legislation changing the state’s corporate income tax apportionment rules, including adopting a single sales factor formula and market-based sourcing for sales of services and intangibles, effective for taxable years beginning on or after January 1, 2022.

Enactment of this law triggered a remeasurement of state deferred income taxes for entities included in FirstEnergy’s West Virginia combined unitary return, resulting in a net impact of approximately $ 9 million in additional tax expense in 2021.

For the Years Ended December 31,

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$ 2 $ ( 14 ) $ ( 16 )

State 21 21 24

Deferred, net-

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(1) Income Taxes on Income from Continuing Operations.

(2) Excludes $ 6 million of federal tax expense associated with discontinued operations for the year ended December 31, 2020.

(3) Excludes $ 1 million of state tax expense associated with discontinued operations for the year ended December 31, 2018.

(4) Excludes $ 66 million, $ 9 million and $ 1.3 billion of federal tax benefit associated with discontinued operations for the years ended December 31, 2020, 2019 and 2018, respectively.

(5) Excludes $ 1 million, $ 4 million and $ 12 million of state tax expense associated with discontinued operations for the years ended December 31, 2020, 2019 and 2018, respectively.

(2) Excludes $ 2 million of federal tax benefit and $ 6 million of federal tax expense associated with discontinued operations for the years ended December 31, 2021 and 2020 respectively.

(3) Excludes $ 46 million, $ 66 million and $ 9 million of federal tax benefits associated with discontinued operations for the years ended December 31, 2021, 2020 and 2019, respectively.

(4) Excludes $ 1 million and $ 4 million of state tax expense associated with discontinued operations for the years ended December 31, 2020 and 2019, respectively.

FirstEnergy tax rates are affected by permanent items, such as AFUDC equity and other flow-through items, as well as discrete items that may occur in any given period but are not consistent from period to period.

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Amortization of investment tax credits ( 4 ) ( 14 ) ( 5 )

Remeasurement of deferred taxes — — 24

WV unitary group remeasurement — — 126

Federal tax credits claimed ( 34 ) — —

Nondeductible DPA monetary penalty

Excess deferred tax amortization due to the Tax Act ( 54 ) ( 56 ) ( 74 )

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FirstEnergy's effective tax rate on continuing operations for 2021 and 2020 was 20.5 % and 11.2 %, respectively.

The change in effective tax rate was primarily due to a $ 52 million reduction in valuation allowances from the recognition of deferred gains on prior intercompany generation asset transfers triggered by the FES Debtors’ emergence from bankruptcy and deconsolidation from FirstEnergy’s consolidated federal income tax group in the first quarter of 2020, a $ 10 million benefit from accelerated amortization of certain investment tax credits in the second quarter of 2020, and a $ 40 million benefit related to reversals of certain tax regulatory liabilities resulting from the transfer of TMI-2.

See Note 3, “Discontinued Operations,” for other tax matters relating to the FES Bankruptcy that were recognized in discontinued operations.

The increase in effective tax rate was primarily due to:

• The non-deductibility of the DPA monetary penalty;

• The absence of a $ 52 million benefit for reduction in valuation allowances in 2020 from the recognition of deferred gains on prior intercompany generation asset transfers triggered by the FES Debtors’ emergence from bankruptcy and deconsolidation from FirstEnergy’s consolidated federal income tax group;

• Lower amortization of investment tax credits due to the absence of a $ 10 million benefit from accelerated amortization of certain investment credits in 2020;

• The absence of a $ 40 million benefit related to reversals of certain tax regulatory liabilities resulting from the transfer of TMI-2 in 2020;

• Additional tax expense of $ 9 million as a result of the West Virginia legislation that changed income tax apportionment rules discussed above;

• Partially offset by a net $ 81 million increase in uncertain tax position benefits primarily related to reserves on the worthless stock deduction, nondeductible interest under Section 163(j), and certain federal tax credits, discussed below;

• A $ 34 million benefit in federal tax credits claimed on FirstEnergy’s federal income tax return in 2021.

Accumulated deferred income taxes as of December 31, 2021 and 2020, are as follows:

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Pension and OPEB ( 570 ) ( 769 )

TMI-2 nuclear decommissioning — 89

AROs ( 21 ) ( 28 )

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Deferred compensation ( 155 ) ( 165 )

Estimated worthless stock deduction — ( 1,007 )

Loss carryforwards and AMT credits ( 1,995 ) ( 836 )

Loss carryforwards and tax credits ( 2,040 ) ( 1,995 )

Valuation reserve 484 496

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As of December 31, 2021 and 2020, FirstEnergy's total unrecognized income tax benefits were approximately $ 47 million and $ 139 million, respectively.

The change in unrecognized income tax benefits from the prior year is primarily attributable to a decrease of approximately $ 21 million for reserves on the estimated worthless stock deduction (see Note 3, "Discontinued Operations," for further discussion), as well as decreases of $ 2 million for an effective settlement with certain state taxing authorities and $ 2 million due to the lapse in statute in certain state taxing jurisdictions.

The $ 92 million net decrease in unrecognized income tax benefits is primarily due to:

• Decreases of $ 68 million for reserves related to the worthless stock deduction (see Note 14, "Discontinued Operations," for further discussion) and $ 29 million for reserves attributable to nondeductible interest under Section 163(j), both of which were effectively settled with federal taxing authorities;

• Decrease of $ 7 million to the reserve due to the remeasurement of certain positions for the change in West Virginia deferred taxes resulting from a state law change discussed above and $ 1 million due to other state tax rate changes;

• Decrease of $ 2 million due to the lapse in statue in certain state taxing jurisdictions;

• Partially offset by an increase of $ 15 million for reserves related to certain federal tax credits claimed on FirstEnergy's federal income tax return in 2021.

If ultimately recognized in future years, approximately $ 39 million of unrecognized income tax benefits would impact the effective tax rate.

As of December 31, 2020, it is reasonably possible that approximately $ 57 million of unrecognized tax benefits may be resolved during 2021 as a result of settlements with taxing authorities or the statute of limitations expiring, of which $ 55 million would affect FirstEnergy's effective tax rate.

As of December 31, 2021, it is reasonably possible that approximately $ 31 million of unrecognized tax benefits may be resolved during 2022 as a result of settlements with taxing authorities or the statute of limitations expiring, of which $ 24 million would ultimately affect FirstEnergy's effective tax rate.

The following table summarizes the changes in unrecognized tax positions for the years ended December 31, 2021, 2020 and 2019:

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Decrease for lapse in statute ( 2 )

Effectively settled with taxing authorities

Balance, December 31, 2020 $ 139

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Prior years decreases ( 8 )

Decrease for lapse in statute ( 2 )

Effectively settled with taxing authorities

Decrease for lapse in statute

Balance, December 31, 2021 $ 47

FirstEnergy recognizes interest expense or income and penalties related to uncertain tax positions in income taxes 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.

FirstEnergy's recognition of net interest associated with unrecognized tax benefits in 2021, 2020 and 2019, was not material.

For the years ended December 31, 2021 and 2020, the cumulative net interest payable recorded by FirstEnergy was not material.

FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state taxing authorities.

Tax years 2018 and 2019 are currently under review by the IRS.

FirstEnergy's tax returns for some state jurisdictions are open from 2009-2019.

IRS review of FirstEnergy’s federal income tax returns is complete through the 2020 tax year with no pending adjustments.

FirstEnergy’s tax returns for some state jurisdictions are open from tax years 2009 to 2020.

General Taxes

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FirstEnergy does not have any material leases in which it is the lessor.

FirstEnergy adopted ASU 2016-02, “Leases (Topic 842)” on January 1, 2019, and elected a number of transitional practical expedients provided within the standard.

These included a “package of three” expedients that must be taken together and allowed entities to:

(1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases.

In addition, FirstEnergy elected the option to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods.

Adoption of the standard on January 1, 2019, did not result in a material cumulative effect adjustment upon adoption.

FirstEnergy did not evaluate land easements under the new guidance as they were not previously accounted for as leases.

FirstEnergy also elected not to separate lease components from non-lease components as non-lease components were not material.

FirstEnergy accounts for leases under, "Leases (Topic 842)".

Leases with an initial term of 12 months or less are recognized as lease expense on a straight-line basis over the lease term and not recorded on the balance sheet.

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FirstEnergy’s lease agreements do not contain any material restrictive covenants.

For vehicles leased under master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term.

As of December 31, 2020, the maximum potential loss for these lease agreements at the end of the lease term is approximately $ 16 million.

FirstEnergy has elected a policy to not separate lease components from non-lease components for all asset classes.

For vehicles leased under certain master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term.

If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, FirstEnergy is committed to pay the difference in the actual fair value and the residual value guarantee.

FirstEnergy does not believe it is probable that it will be required to pay anything pertaining to the residual value guarantee, and the lease liabilities and right-of-use assets are measured accordingly.

Finance leases for assets used in regulated operations are recognized in FirstEnergy’s Consolidated Statements of Income such that amortization of the right-of-use asset and interest on lease liabilities equals the expense allowed for ratemaking purposes.

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(1) Includes $ 17 million of short-term lease costs.

For the Year Ended December 31, 2019

(In millions) Vehicles Buildings Other Total

Operating lease costs (1)

$ 28 $ 9 $ 12 $ 49

Finance lease costs:

Amortization of right-of-use assets 15 1 1 17

Interest on lease liabilities 3 3 — 6

Total finance lease cost 18 4 1 23

Total lease cost $ 46 $ 13 $ 13 $ 72

(1) Includes $ 13 million of short-term lease costs.

Supplemental cash flow information related to leases was as follows:

For the Years Ended,

(In millions) December 31, 2020 December 31, 2019

For the Years Ended December 31,

(In millions) 2021 2020 2019

Cash paid for amounts included in the measurement of lease liabilities:

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Lease terms and discount rates were as follows:

As of December 31, 2020 As of December 31, 2019

As of December 31,

2021 2020 2019

Weighted-average remaining lease terms (years)

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2022 $ 54 $ 16 $ 70

2022 49 15 64

Thereafter 133 8 141

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These leases are expected to commence within the next 18 months with lease terms of 2 to 10 years.

INTANGIBLE ASSETS

As of December 31, 2020, intangible assets classified in Other Deferred Charges on FirstEnergy’s Consolidated Balance Sheets include the following:

Intangible Assets Amortization Expense

Actual Estimated

(In millions) Gross Accumulated Amortization Net 2020 2021 2022 2023 2024 2025 Thereafter

NUG contracts (1)

$ 124 $ 51 $ 73 $ 5 $ 5 $ 5 $ 5 $ 5 $ 5 $ 48

Coal contracts (2)

102 102 — 2 — — — — — —

$ 226 $ 153 $ 73 $ 7 $ 5 $ 5 $ 5 $ 5 $ 5 $ 48

(1) NUG contracts are subject to regulatory accounting and their amortization does not impact earnings.

(2) The coal contracts were recorded with a regulatory offset and their amortization does not impact earnings.

FAIR VALUE MEASUREMENTS

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Assets (In millions)

Corporate debt securities $ — $ — $ — $ — $ — $ 135 $ — $ 135

Derivative assets FTRs (1)

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state debt securities — 273 — 273 — 276 — 276

Cash, cash equivalents and restricted cash (2)

1,511 — — 1,511 1,801 — — 1,801

— 42 — 42 — 41 — 41

Total assets $ 1,513 $ 315 $ 9 $ 1,837 $ 1,803 $ 317 $ 3 $ 2,123

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$ — $ — $ ( 1 ) $ ( 1 ) $ — $ — $ — $ —

Derivative liabilities NUG contracts (1)

— — — — — — ( 16 ) ( 16 )

Total liabilities $ — $ — $ ( 1 ) $ ( 1 ) $ — $ — $ — $ —

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

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

(3) Excludes $ 1 million and $( 16 ) million as of December 31, 2020, and December 31, 2019, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

(2) Restricted cash of $ 49 million and $ 67 million as of December 31, 2021 and 2020 respectively, primarily relates to cash collected from JCP&L, MP, PE and the Ohio Companies' customers that is specifically used to service debt of their respective funding companies.

(3) Primarily consists of short-term investments.

(4) Excludes $ 1 million as of December 31, 2020, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the years ended December 31, 2020 and December 31, 2019:

NUG Contracts (1)

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All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value.

Investments other than cash and cash equivalents include equity securities, AFS debt securities and other investments.

Investments other than cash and cash equivalents include AFS debt securities and other investments.

FirstEnergy has no debt securities held for trading purposes.

Generally, unrealized gains and losses on equity securities are recognized in income whereas unrealized gains and losses on AFS debt securities are recognized in AOCI.

However, the NDTs of JCP&L, ME and PN are subject to regulatory accounting with all gains and losses on equity and AFS debt securities offset against regulatory assets.

However, the JCP&L spent nuclear fuel disposal trusts are subject to regulatory accounting with all gains and losses on equity and AFS debt securities offset against regulatory assets.

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.

With the receipt of all required regulatory approvals, the transaction was consummated, including the transfer of external trusts for the decommissioning and environmental remediation of TMI-2, on December 18, 2020.

Please see Note 15, "Commitments, Guarantees and Contingencies," for further information.

Nuclear Decommissioning and Nuclear Fuel Disposal Trusts

JCP&L holds debt securities within the nuclear fuel disposal trust, which are classified as AFS securities, recognized at fair market value.

The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in NDT and nuclear fuel disposal trusts as of December 31, 2020 and December 31, 2019:

Spent Nuclear Fuel Disposal Trusts

JCP&L holds debt securities within the spent nuclear fuel disposal trust, which are classified as AFS securities, recognized at fair market value.

The trust is intended for funding spent nuclear fuel disposal fees to the DOE associated with the previously owned Oyster Creek and TMI-1 nuclear power plants.

The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in nuclear fuel disposal trusts as of December 31, 2021 and 2020:

December 31, 2021 (1)

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(1) Excludes short-term cash investments of $ 11 million.

(2) Excludes short-term cash investments of $ 751 million, of which $ 747 million is classified as held for sale.

(3) Includes $ 135 million classified as held for sale as of December 31, 2019.

Proceeds from the sale of investments in equity and AFS debt securities, realized gains and losses on those sales and interest and dividend income for the years ended December 31, 2020, 2019 and 2018, were as follows:

(2) Excludes short-term cash investments of $ 9 million.

Proceeds from the sale of investments in AFS debt securities, realized gains and losses on those sales and interest and dividend income for the years ended December 31, 2021, 2020 and 2019, were as follows:

For the Years Ended December 31,

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Interest and Dividend Income 11 22 38

(1) Excludes amounts classified as discontinued operations.

(1) Includes amounts associated with NDTs that were previously held by JCP&L, ME, and PN.

See above for additional information.

Other Investments

Other investments include employee benefit trusts, which are primarily invested in corporate-owned life insurance policies, and equity method investments.

Other investments were $ 322 million a nd $ 299 million as of December 31, 2020 and December 31, 2019, respectively, and are excluded from the amounts reported above.

Other investments were $ 371 million and $ 322 million as of December 31, 2021 and 2020, respectively, and are excluded from the amounts reported above.

LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS

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Carrying Value $ 23,946 $ 22,377

$ 22,377 $ 20,066

Fair Value 27,043 25,465

( 1) The carrying value as of December 31, 2020, includes $ 3,425 million of debt issuances and $ 1,114 million of redemptions that occurred during 2020.

The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period.

The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy.

FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of December 31, 2020 and December 31, 2019.

FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of December 31, 2021 and 2020.

See Note 9, "Capitalization," for further information on long-term debt issued during the twelve months ended December 31, 2021.

CAPITALIZATION

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As of December 31, 2021, FirstEnergy had an accumulated deficit of $ 1.6 billion.

Dividends declared in 2020 and 2019 were $ 1.56 and $ 1.53 per share, respectively.

Dividends of $ 0.39 per share and $ 0.38 per share were paid in the first, second, third and fourth quarters in 2020 and 2019, respectively.

On December 15, 2020, the Board of Directors declared a quarterly dividend of $ 0.39 per share to be paid from OPIC in the first quarter of 2021.

The amount and timing of all dividend declarations are subject to the discretion of the Board of Directors and its consideration of business conditions, results of operations, financial condition and other factors.

In addition to paying dividends from retained earnings, OE, CEI, TE, Penn, JCP&L, ME and PN have authorization from FERC to pay cash dividends to FirstEnergy from paid-in capital accounts, as long as their FERC-defined equity-to-total-capitalization ratio remains above 35 %.

In addition, AGC has authorization from FERC to pay cash dividends to its parent from paid-in capital accounts, as long as its FERC-defined equity-to-total-capitalization ratio remains above 45 %.

The articles of incorporation, indentures, regulatory limitations and various other agreements relating to the long-term debt of certain FirstEnergy subsidiaries contain provisions that could further restrict the payment of dividends on their common stock.

None of these provisions materially restricted FirstEnergy’s subsidiaries’ abilities to pay cash dividends to FE as of December 31, 2020.

Dividends declared in 2021 and 2020 totaled $ 1.56 per share in each period.

Dividends of $ 0.39 per share were paid in the first, second, third and fourth quarters in 2021 and 2020, respectively.

On December 21, 2021, the FE Board declared a quarterly dividend of $ 0.39 per share to be paid from OPIC in the first quarter of 2022.

The amount and timing of all dividend declarations are subject to the discretion of the FE Board and its consideration of business conditions, results of operations, financial condition, risks and uncertainties of the government investigations, and other factors.

In addition to paying dividends from retained earnings, the Ohio Companies, Penn, JCP&L, ME and PN have authorization from FERC to pay cash dividends to FE from paid-in capital accounts, as long as their FERC-defined equity-to-total-capitalization ratio remains above 35 %.

In addition, AGC has authorization from FERC to pay cash dividends to its parent, MP, from paid-in capital accounts, as long as its FERC-defined equity-to-total-capitalization ratio remains above 45 %.

The articles of incorporation, indentures, regulatory limitations, FET P&SA, and various other agreements, including those relating to the long-term debt of certain FirstEnergy subsidiaries contain provisions that could further restrict the payment of dividends on their common stock.

None of these provisions materially restricted FirstEnergy subsidiaries’ abilities to pay cash dividends to FE as of December 31, 2021.

Common Stock Issuance

FE issued approximately 1 million shares of common stock in 2021, 2 million shares of common stock in 2020 and 3 million shares of common stock in 2019 to registered shareholders and its directors and the employees of its subsidiaries under its Stock Investment Plan and certain share-based benefit plans.

Additionally, on January 22, 2018, FE entered into a Common Stock Purchase Agreement for the private placement of 30,120,482 shares of FE’s common stock, par value $ 0.10 per share, representing an investment of $ 850 million ($ 3 million of common shares and $ 847 million of OPIC).

Please see below for information on preferred stock converted into shares of common stock during 2018 and 2019.

On November 6, 2021, FE entered into a Common Stock Purchase Agreement with BIP Securities II-B L.P., an affiliate of Blackstone Infrastructure Partners L.P., for the private placement of 25,588,535 shares of FE common stock, par value $ 0.10 per share, at a price of $ 39.08 per share, representing an investment of $ 1.0 billion.

The transaction settled on December 13, 2021.

Issuance costs associated with the transaction were approximately $ 26 million as of December 31, 2021.

PREFERRED AND PREFERENCE STOCK

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18,925 17,575

Unsecured notes - variable rate — 750

Finance lease obligations 36 45

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Total long-term debt and other long-term obligations $ 22,248 $ 22,131

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.

See Note 7, "Leases," for additional information related to finance leases.

During the twelve months ended December 31, 2021, the following long-term debt was issued:

Company Issuance Date Interest Rate Maturity Amount Issuance Type Use of Proceeds

FET 3/19/2021 2.87 % 2028 $ 500 million Unsecured Notes Repay short-term borrowings under the former FET Revolving Facility.

MP 4/9/2021 3.55 % (1)

2027 $ 200 million FMB Fund MP’s ongoing capital expenditures, for working capital needs and for other general corporate purposes.

TE 5/6/2021 2.65 % 2028 $ 150 million Senior Secured Notes Repay short-term borrowings, fund TE’s ongoing capital expenditures and for other general corporate purposes.

MAIT 5/24/2021 4.10 % (2)

2028 $ 150 million Unsecured Notes Repay borrowings outstanding under FirstEnergy’s regulated company money pool, fund MAIT’s ongoing capital expenditures, to fund working capital and for other general corporate purposes.

JCP&L 6/10/2021 2.75 % 2032 $ 500 million Unsecured Notes Repay $ 450 million of short-term debt under the former FE Revolving Facility, storm recovery and restoration costs and expenses, to fund JCP&L’s ongoing capital expenditures, working capital requirements and for other general corporate purposes.

ATSI 12/1/2021 2.65 % 2032 $ 600 million Unsecured Notes Repay outstanding notes and short-term borrowings, to fund ATSI's ongoing capital expenditures, working capital requirements and for other general corporate purposes.

(1) New debt was issued at a premium under a previously issued bond series, resulting in an effective interest rate of 2.06 %.

(2) New debt was issued at a premium under a previously issued note series, resulting in an effective interest rate of 2.55 %.

In December 2021, notice of redemption was provided for all remaining $850 million of FE's 4.25% Notes, Series B, due 2023, which was completed on January 20, 2022, and with a make-whole premium of approximately $38 million.

Due to the redemption, the $850 million in notes is included within currently payable long-term debt on the Consolidated Balance Sheets as of December 31, 2021.

On January 27, 2022, CEI instructed its indenture trustee to provide notice of redemption for all remaining $150 million of CEI's 2.77% Senior Notes, Series A, due 2034, for redemption to occur on March 14, 2022.

Also on January 27, 2022, TE instructed its indenture trustee to provide notice of partial redemption for $25 million of TE's 2.65% Senior Secured Notes, due 2028, for partial redemption which occurred on February 11, 2022.

The following table presents scheduled debt repayments or debt that has been noticed for redemption for outstanding long-term debt, excluding finance leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2021.

(In millions)

Securitized Bonds

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As of December 31, 2021 and 2020, $ 274 million and $ 300 million of environmental control bonds were outstanding, respectively.

Transition Bonds

In August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS.

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s Consolidated Balance Sheets.

The transition bonds are the sole obligations of JCP&L Transition Funding II and are collateralized by its equity and assets, which consist primarily of bondable transition property.

As of December 31, 2020 and 2019, $ 9 million and $ 25 million of the transition bonds were outstanding, respectively.

Phase-In Recovery Bonds

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As of December 31, 2021 and 2020, $ 222 million and $ 245 million of the phase-in recovery bonds were outstanding, respectively.

Other Long-term Debt

The Ohio Companies and Penn each have a first mortgage indenture under which they can issue FMBs secured by a direct first mortgage lien on substantially all of their property and franchises, other than specifically excepted property.

Based on the amount of FMBs authenticated by the respective mortgage bond trustees as of December 31, 2020, the sinking fund requirement for all FMBs issued under the various mortgage indentures was zero.

The following table presents scheduled debt repayments for outstanding long-term debt, excluding finance leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2020.

PCRBs that are scheduled to be tendered for mandatory purchase prior to maturity are reflected in the applicable year in which such PCRBs are scheduled to be tendered.

(In millions)

Certain PCRBs allow bondholders to tender their PCRBs for mandatory purchase prior to maturity.

As of December 31, 2020, MP has a $ 74 million PCRB classified as current portion of long-term debt, which the debt holders may exercise their right to tender in 2021.

Debt Covenant Default Provisions

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Additionally, there are cross-default provisions in a number of the financing arrangements.

These provisions generally trigger a default in the applicable financing arrangement of an entity if it or any of its significant subsidiaries, excluding AE Supply, default under another financing arrangement in excess of a certain principal amount, typically $ 100 million.

Although such defaults by any of the Utilities, ATSI, TrAIL or MAIT would generally cross-default FE financing arrangements containing these provisions, defaults by AE Supply would generally not cross-default to applicable financing arrangements of FE.

These provisions generally trigger a default in the applicable financing arrangement of an entity if it, or any of its significant subsidiaries, default under another financing arrangement in excess of a certain principal amount, typically $ 100 million.

Such defaults by any of the Utilities or Transmission Companies would cross-default certain FE financing arrangements containing these provisions, and a certain FET Financing arrangement, with respect to the Transmission Companies only, such defaults by AE Supply would not cross-default to applicable financing arrangements of FE.

Also, defaults by FE would generally not cross-default applicable financing arrangements of any of FE’s subsidiaries.

Cross-default provisions are not typically found in any of the senior notes or FMBs of FE or the Utilities.

Cross-default provisions are not typically found in any of the senior notes or FMBs of FE or its subsidiaries.

SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT

FirstEnergy had $ 2.2 billion and $ 1.0 billion of short-term borrowings as of December 31, 2020 and 2019, respectively.

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.

As of December 31, 2020, available liquidity under the FE revolving credit facility was $1,296 million (reflecting $4 million of LOCs issued under various terms) and there was no available liquidity under the FET revolving credit facility.

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.

FirstEnergy had no outstanding short-term borrowings as of December 31, 2021 and $ 2.2 billion of outstanding short-term borrowings as of December 31, 2020.

On November 23, 2020, JCP&L, ME, Penn, TE and WP, borrowed $ 950 million in the aggregate under the former FE Revolving Facility, bringing the outstanding principal balance to $ 1.2 billion, with $ 1.3 billion of remaining availability.

On November 23, 2020, FET and ATSI borrowed $ 1 billion in the aggregate under the former FET Revolving Facility, bringing the outstanding principal balance to $ 1 billion, with no remaining availability.

FE, FET and certain of their respective subsidiaries increased their borrowings under the former Revolving Facilities as a proactive measure to increase their respective cash positions and preserve financial flexibility.

These borrowings were repaid in full during 2021.

On October 18, 2021, FE, FET, the Utilities, and the Transmission Companies entered into the 2021 Credit Facilities, which were six separate senior unsecured five-year syndicated revolving credit facilities with JPMorgan Chase Bank, N.A., Mizuho Bank, Ltd.

and PNC Bank, National Association that replaced the FE Revolving Facility and the FET Revolving Facility, and provide for aggregate commitments of $4.5 billion.

The 2021 Credit Facilities are available until October 18, 2026, as follows:

• FE and FET, $1.0 billion revolving credit facility;

• Ohio Companies, $800 million revolving credit facility;

• Pennsylvania Companies, $950 million revolving credit facility;

• JCP&L, $500 million revolving credit facility;

• MP and PE, $400 million revolving credit facility;

• Transmission Companies, $850 million revolving credit facility.

Under the 2021 Credit Facilities, an aggregate amount of $4.5 billion is available to be borrowed, repaid and reborrowed, subject to each borrower's respective sublimit under the respective facilities.

These new credit facilities provide substantial liquidity to support the Regulated Distribution and Regulated Transmission businesses, and each of the operating companies within the businesses.

As of December 31, 2021, available liquidity under the 2021 Credit Facilities was $ 4.5 billion.

Borrowings under the 2021 Credit Facilities may be used for working capital and other general corporate purposes.

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.

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.

Each of the 2021 Credit Facilities contain financial covenants requiring each borrower, with the exception of FE, to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the 2021 Credit Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter.

FE is required under its 2021 Credit Facility to maintain a consolidated interest coverage ratio of not less than 2.50 times, measured at the end of each fiscal quarter for the last four fiscal quarters beginning with the quarter ending December 31, 2021.

Subject to each borrower's sublimit, the amounts noted below are available for the issuance of LOCs (subject to borrowings drawn under the 2021 Credit 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 2021 Credit Facilities and against the applicable borrower's borrowing sublimit.

As of December 31, 2021, FirstEnergy had $4 million in outstanding LOCs.

The 2021 Credit 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 2021 Credit Facilities are related to the credit ratings of the company borrowing the funds.

Additionally, borrowings under each of the 2021 Credit 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, 2021, the borrowers were in compliance with the applicable interest coverage and debt-to-total-capitalization ratio covenants in each case as defined under the respective 2021 Credit Facilities.

FirstEnergy Money Pools

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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.

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.

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Weighted Average Interest Rates

The weighted average interest rates on short-term borrowings outstanding, including borrowings under the FirstEnergy Money Pools, as of December 31, 2020 and 2019, were 1.86 % and 2.88 %, respectively.

The annual weighted average interest rates on short-term borrowings outstanding as of December 31, 2021 and 2020, were 2.42 % and 1.86 %, respectively.

ASSET RETIREMENT OBLIGATIONS

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In addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remediation.

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.

Please see Note 15, "Commitments, Guarantees and Contingencies," for further information.

The following table summarizes the changes to the ARO balances during 2021 and 2020:

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Balance, December 31, 2020 $ 159

Changes in timing and amount of estimated cash flows 8

Liabilities settled ( 1 )

Balance, December 31, 2021 $ 179

(1) Includes $ 691 million related to TMI-2 classified as held for sale for the year ended December 31, 2019.

(1) Includes $ 726 million related to the closing of the asset purchase and sale agreement with TMI-2 Solutions, LLC, a subsidiary of Energy Solutions , LLC, concerning the transfer and dismantlement of TMI-2.

See Note 15, "Commitments, Guarantees and Contingencies," for further information.

REGULATORY MATTERS

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The following table summarizes the key terms of base distribution rate orders in effect for the Utilities as of December 31, 2021:

Company Rates Effective Allowed Debt/Equity Allowed ROE

Company Rates Effective For Customers Allowed Debt/Equity Allowed ROE

CEI May 2009 51 % / 49 %

1 unchanged sentence

MP February 2015 54 % / 46 %

January 2017 55 % / 45 %

JCP&L November 2021 (3)

48.6 % / 51.4 %

OE January 2009 51 % / 49 %

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(3) On October 28, 2020, the NJBPU approved JCP&L's distribution rate case settlement with an allowed ROE of 9.6% and a 48.6% debt / 51.4% 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.

Rates are effective for customers on November 1, 2021, but beginning January 1, 2021, JCP&L offset the impact to customers' bills by amortizing an $86 million regulatory liability.

PE operates under MDPSC approved base rates that were effective as of March 23, 2019.

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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.

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 2021-2023 EmPOWER Maryland program cycles to the extent the MDPSC determines that cost-effective programs and services are available.

PE's approved 2021-2023 EmPOWER Maryland plan continues and expands upon prior years' programs for a projected total investment of approximately $148 million over the three-year period.

PE recovers program investments with a return through an annually reconciled surcharge, with most costs subject to recovery over a five-year period with a return on the unamortized balance.

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.

In 2019, MDPSC issued an order approving PE’s 2018 base rate case filing, which among other things, approved an annual rate increase of $6.2 million, approved three of the four EDIS programs for four years to fund enhanced service reliability programs, 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.

Following the filing of PE’s depreciation study and subsequent filings by the Maryland Office of the People’s Counsel and the staff of the MDPSC, the public utility law judge issued a proposed order reducing PE’s base rates by $2.1 million.

The MDPSC denied PE’s appeal of the proposed order on October 26, 2021, and the proposed order was affirmed.

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.

JCP&L operates under NJBPU approved rates that were effective as of January 1, 2017.

On June 16, 2021, the MDPSC provided PE with approximately $4 million of COVID-19 relief funds that was

allocated by the Maryland General Assembly to be used to reduce certain residential customer utility account receivable arrearages.

J CP&L operates under NJBPU approved rates that were effective for customers as of November 1, 2021.

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.

(ii) allocate savings with 75% retained by the company and 25% allocated to customers;

and (iii) exclude transmission assets of electric distribution companies in the savings calculation.

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 May 17, 2019, the NJ Rate Counsel filed an appeal with the Appellate Division of the Superior Court of New Jersey and on June 7, 2021, the Superior Court issued an order reversing the NJBPU’s CTA rules and remanded the case back to the NJBPU.

Specifically, the Court’s ruling requires 100% of the CTA savings to be credited to customers in lieu of the NJBPU’s current policy requiring 25%.

On December 6, 2021, the NJBPU issued proposed amended rules modifying its current CTA policy in base rate cases consistent with the Superior Court’s June 7, 2021 order.

Once the proposed rules are final, they will be applied on a prospective basis in a future base rate case, however, it is not expected to have a material adverse effect on FirstEnergy’s results or financial condition.

On February 18, 2020, JCP&L submitted a filing with the NJBPU requesting a distribution base rate increase.

On October 28, 2020, the NJBPU approved a stipulated settlement between JCP&L and various parties, providing for, among other things, a $94 million annual base distribution revenues increase for JCP&L based on an ROE of 9.6%, which became effective for customers on November 1, 2021.

Between January 1, 2021 and October 31, 2021, JCP&L amortized 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, be applied to reduce JCP&L’s existing regulatory asset for previously deferred storm costs.

Lastly, the parties agreed that approximately $95 million of Reliability Plus capital investment for projects through December 31, 2020, is included in rate base effective December 31, 2020.

Included in the NJBPU approved-settlement in JCP&L’s distribution rate case on October 28, 2020, was that JCP&L will be subject to a management audit.

The management audit began at the end of May 2021 and is currently ongoing.

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.

As of December 31, 2020, 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 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 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.

With the receipt of all required regulatory approvals, the transaction was consummated on March 5, 2021 and resulted in a $109 million gain within the regulated distribution segment.

As further discussed above, the gain from the transaction was applied against and reduced JCP&L’s existing regulatory asset for previously deferred storm costs and, as a result, was offset by expense in the “Amortization of regulatory assets, net”, line on the Consolidated Statements of Income, resulting in no earnings impact to FirstEnergy or JCP&L.

On August 27, 2020, JCP&L filed an AMI Program with the NJBPU, which proposed 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 then proposed 3-year deployment was part of the 20-year AMI Program that was projected to cost approximately $732 million and proposed a cost recovery mechanism through a separate AMI tariff rider.

On September 14, 2021, JCP&L submitted a supplemental filing, which reflected increases in the AMI Program’s costs.

Under the revised AMI Program, during the first six years of the AMI Program from 2022 through 2027, JCP&L estimates costs of $494 million, consisting of capital expenditures of approximately $390 million, incremental operations and maintenance expenses of approximately $73 million and cost of removal of $31 million.

On February 8, 2022, JCP&L filed with the NJBPU a stipulation entered into with the NJBPU staff, NJ Rate Counsel and others, that, pending NJBPU approval, would affirm the terms of the revised AMI Program.

JCP&L expects a NJBPU order by the end of the first quarter of 2022.

The Stipulation also provided that the revised AMI Program-related capital costs, the legacy meter stranded costs, and the operations and maintenance expense will be deferred and placed in regulatory assets, with such amounts sought to be recovered in the JCP&L’s subsequent base rate cases.

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.

Under the established framework, JCP&L will recover its program investments with a return 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, which consists of 11 energy

efficiency and peak demand reduction programs and subprograms to be run from July 1, 2021, through June 30, 2024.

On April 23, 2021, JCP&L filed a Stipulation of Settlement with the NJBPU for approval of recovery of lost revenues resulting from the programs and a three-year plan including total program costs of $203 million, of which $158 million of investment is recovered over a ten-year amortization period with a return as well as operations and maintenance expenses and financing costs of $45 million recovered on an annual basis.

On April 27, 2021, the NJBPU issued an Order approving the Stipulation of Settlement.

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 and continuing until the New Jersey 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.

Through various executive orders issued by the New Jersey Governor, the moratorium period was extended to December 31, 2021.

On December 21, 2021, the moratorium on residential disconnections for certain entities providing utility service was extended until March 15, 2022.

The moratorium on residential disconnections was not extended for investor-owned electric utilities such as JCP&L, but does require that investor-owned electric public utilities offer qualifying residential customers deferred payment arrangements meeting certain minimum criteria prior to disconnecting service.

Credit rating actions taken by S&P and Fitch on October 28, 2020 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.

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.

Pursuant to an NJBPU order requiring all New Jersey electric distribution companies to file electric vehicle programs, JCP&L filed its program on March 1, 2021.

JCP&L’s proposed electric vehicle program consisted of six sub-programs, including a consumer education and outreach initiative that would begin on January 1, 2022, and continue over a four-year period.

The total proposed budget for the electric vehicle program is approximately $50 million, of which $16 million is capital expenditures and $34 million is for operations and maintenance expenses.

JCP&L is proposing to recover the electric vehicle program costs via a non-bypassable rate clause applicable to all distribution customer rate classes, which became effective on January 1, 2022.

On May 26, 2021, a procedural schedule was set to include evidentiary hearings the week of October 18, 2021.

On July 16, 2021, the procedural schedule was extended by thirty days as requested by JCP&L to continue settlement discussions.

On August 19, 2021, the presiding commissioner issued an order modifying the procedural schedule by extending the procedural schedule by ninety days as requested by JCP&L to continue settlement discussions.

On November 12, 2021, JCP&L filed a letter with the presiding commissioner requesting a suspension of the procedural schedule in order to allow the parties to continue settlement discussion.

On November 23, 2021, the presiding commissioner entered an order suspending the procedural schedule.

JCP&L expects an order from the NJBPU by the end of the first quarter of 2022.

The Ohio Companies operate under PUCO approved base distribution rates that became effective in 2009.

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;

ESP IV also continues the Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $20 million per year from June 1, 2019 through May 31, 2022;

and $15 million per year from June 1, 2022 through May 31, 2024.

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(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;

(2) a goal across FirstEnergy to reduce CO 2 emissions by 90% below 2005 levels by 2045;

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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.

ESP IV further provided for the Ohio Companies to collect DMR revenues, but the SCOH reversed the PUCO’s decision to include DMR in ESP IV.

Subsequently, the PUCO entered an order directing the Ohio Companies to cease further collection through the DMR and credit back to customers a refund of the DMR funds collected since July 2, 2019.

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 include the DMR revenues in the analysis, determine the threshold against which the earned return is measured, and make other necessary determinations.

As further described below, the Ohio Stipulation resolves the Ohio Companies’ 2017 SEET proceeding.

On July 23, 2019, Ohio enacted HB 6, which included provisions supporting nuclear energy, authorizing a decoupling mechanism for Ohio electric utilities and ending current energy efficiency program mandates.

Under HB 6, the energy efficiency program mandates, as well as Ohio electric utilities’ energy efficiency and peak demand reduction cost recovery riders, ended on December 31, 2020, subject to final reconciliation.

Third-parties have challenged the Ohio Companies’ authorization to recover all lost distribution revenue under energy efficiency and peak demand reduction cost recovery riders.

The Ohio Stipulation resolves the issues related to lost distribution revenue with no financial impact to the Ohio Companies.

On March 31, 2021, the Ohio Governor signed HB 128, which, among other things, repealed 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.

HB 128 was effective June 30, 2021.

As FirstEnergy would not have financially benefited from the mechanism to provide support to nuclear energy in Ohio, there is no expected additional impact to FirstEnergy due to the repeal of that provision in HB 6.

On February 2, 2021, the PUCO approved the application.

While the partial settlement with the OAG focused specifically on decoupling, the Ohio Companies elected to forego recovery of lost distribution revenue.

FirstEnergy also committed to pursuing an open dialogue with stakeholders in an appropriate manner with respect to the numerous regulatory proceedings then 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.

The Ohio Stipulation affirms the Ohio Companies’ commitment to not seek recovery of lost distribution revenue through the end of its ESP IV in May 2024.

On March 31, 2021, FirstEnergy announced that the Ohio Companies would refund to customers amounts previously collected under decoupling, with interest, totaling approximately $27 million.

On July 7, 2021, the PUCO issued an order approving the Ohio Companies’ modified application to refund such amounts to customers and directed that all funds collected through CSR be refunded to customers over a single billing cycle beginning August 1, 2021.

In connection with the audit of the Ohio Companies’ Rider DCR for 2017, the PUCO issued an order on June 16, 2021, directing the Ohio Companies to prospectively discontinue capitalizing certain vegetation management costs and reduce the 2017 Rider DCR revenue requirement by $3.7 million associated with these costs.

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.

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 customers through the DMR were only used for the purposes established in ESP IV.

On June 2, 2021, the PUCO selected an auditor.

The auditor filed the final audit report on January 14, 2022, which made findings and recommendations.

The report found that spending of DMR revenues was not required to be tracked, and that DMR revenues, like all rider revenues, are placed into the regulated money pool as a matter of routine, where the funds lose their identify.

Therefore, the report could not suggest that DMR funds were used definitively for direct or indirect support for grid modernization.

The report also concluded that there was no documented evidence that ties revenues from the DMR to lobbying for the passage of HB 6, but also could not rule out with certainty uses of DMR funds to support the passage of HB 6.

The report further recommended that the regulated companies' money pool be audited more frequently and the Ohio Companies adopt formal dividend policies.

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, and 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 customers.

The Ohio Companies initially filed a response stating 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 customers, but on August 6, 2021, filed a supplemental response explaining that, in light of the facts set forth in the DPA and the findings of the Rider DCR audit report further discussed below, political or charitable spending in support of HB 6, or the subsequent referendum effort, affected pole attachment rates paid by approximately $15 thousand.

On October 26, 2021, the OCC filed a motion requesting the PUCO to order an independent external audit to investigate FE’s political and charitable spending related to HB 6, and to appoint an independent review panel to retain and oversee the auditor.

In November and December 2021, parties filed comments and reply comments regarding the Ohio Companies’ original and supplemental responses to the PUCO’s September 15, 2020, show cause directive.

In connection with an ongoing 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 additional audit is for the period from November 2016 through October 2020.

The final audit report was filed on September 13, 2021.

The audit report makes no findings of major non-compliance with Ohio corporate separation requirements, minor non-compliance with eight requirements, and findings of compliance with 23 requirements.

Parties filed comments and reply comments on the audit report, and a PUCO attorney examiner has issued a procedural schedule setting an evidentiary hearing on May 9, 2022.

In the fourth quarter of 2020, motions were filed with the PUCO requesting that the PUCO amend the Ohio Companies’ riders for collecting the OVEC related 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 such provisions of HB 6 are repealed.

The Ohio Companies contested the motions, which are pending before the PUCO.

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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 Note 15, "Commitments, Guarantees and Contingencies" below for additional details on the government investigation and subsequent litigation surrounding the investigation of HB 6.

On December 21, 2021, the Citizens’ Utility Board of Ohio filed a notice of voluntary dismissal of its complaint without prejudice.

The PUCO dismissed the complaint without prejudice on January 12, 2022.

On November 1, 2021, the Ohio Companies, together with the OCC, PUCO Staff, and several other signatories, entered into an Ohio Stipulation with the intent of resolving the ongoing energy efficiency rider audits, various SEET, proceedings, including the Ohio Companies’ 2017 SEET proceeding, and the Ohio Companies’ quadrennial ESP review, each of which was pending before the PUCO.

Specifically, the Ohio Stipulation provides that the Ohio Companies’ current ESP IV passes the required statutory test for their prospective SEET review as part of the Quadrennial Review of ESP IV, and except for limited circumstances, the signatory parties have agreed not to challenge the Ohio Companies’ SEET return on equity calculation methodology for their 2021-2024 SEET proceedings.

The Ohio Stipulation additionally affirms that:

(i) the Ohio Companies’ ESP IV shall continue through its previously authorized term of May 31, 2024;

and (ii) the Ohio Companies will file their next base rate case in May 2024, and further, no signatory party will seek to adjust the Ohio Companies’ base distribution rates before that time, except in limited circumstances.

The Ohio Companies further agreed to refund $96 million to customers in connection with the 2017-2019 SEET cases, and to provide $210 million in future rate reductions for all customers, including $80 million in 2022, $60 million in 2023, $45 million in 2024, and $25 million in 2025.

The PUCO approved the 2017-2019 SEET refunds and 2022 rate reductions December 1, 2021, and refunds began in January 2022.

As a result of the PUCO approval, FirstEnergy recognized a $96 million pre-tax charge in the fourth quarter of 2021 at the regulated distribution segment within Amortization (deferral) of Regulatory Assets, net, on the Consolidated Statements of Income associated with the refund.

The future rate reductions will be recognized as a reduction to regulated distribution segment’s revenue in the Consolidated Statements of Income as they are provided to the Ohio Companies’ customers.

In connection with an ongoing annual audit of the Ohio Companies’ Rider DCR for 2020, and as a result of disclosures in FirstEnergy’s Form 10-K for the year ended December 31, 2020 (filed on February 18, 2021), the PUCO expanded the scope of the audit on March 10, 2021, to include a review of certain transactions that were either improperly classified, misallocated, or lacked supporting documentation, and to determine whether funds collected from customers were used to pay the vendors, and if so, whether or not the funds associated with those payments should be returned to customers through Rider DCR or through an alternative proceeding.

On August 3, 2021, the auditor filed its final report on this phase of the audit, and the parties submitted comments and reply comments on this audit report in October 2021.

Additionally, on September 29, 2021, the PUCO expanded the scope of the audit in this proceeding to determine if the costs of the naming rights for FirstEnergy Stadium have been recovered from the Ohio Companies’ customers.

On November 19, 2021, the auditor filed its final report, in which the auditor concluded that the FirstEnergy Stadium naming rights expenses were not recovered from Ohio customers.

On December 15, 2021, the PUCO further expanded the scope of the audit to include an investigation into an apparent nondisclosure of a side agreement in the Ohio Companies’ ESP IV settlement proceedings, but stayed its expansion of the audit until otherwise ordered by the PUCO.

See Note 13, "Commitments, Guarantees and Contingencies" below for additional details on the government investigations and subsequent litigation surrounding the investigation of HB 6.

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.

On November 18, 2021, the PPUC issued orders to each of the Pennsylvania Companies directing they operate under DSPs for the June 1, 2019 through May 31, 2023 delivery period, which DSPs provide for the competitive procurement of generation supply for customers who do not receive service from an alternative EGS.

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.

On December 14, 2021, the Pennsylvania Companies filed proposed DSPs for provision of generation for the June 1, 2023 through May 31, 2027 delivery period, to be sourced through competitive procurements for customers who do not receive service from an alternative EGS.

Under the 2023-2027 DSPs, supply is proposed to be provided through a mix of 12 and 24-month energy contracts, as well as long-term solar PPAs.

In March 2018, the PPUC approved adjusted customer rates of the Pennsylvania Companies to reflect the net impact of the Tax Act.

As a result, the Pennsylvania Companies established riders that, beginning July 1, 2018, refunded to customers tax savings attributable to the Tax Act as compared to the amounts established in their most recent base rate proceedings on a current and going forward basis.

The amounts recorded as savings for the total period of January 1 through June 30, 2018, were tracked and were to be addressed for treatment in a future proceeding.

On May 17, 2021, the Pennsylvania Companies filed petitions with

the PPUC proposing to refund the net savings for the January through June 2018 period to customers beginning January 1, 2022.

On November 18, 2021, the PPUC approved the Pennsylvania Companies' proposed refunds, but also revised a previous methodology for calculating the net tax savings, which resulted in additional tax savings attributable to the Tax Act to be refunded to customers and directed the Pennsylvania Companies to file new petitions to propose the timing and methodology to provide these additional refunds to customers.

The Pennsylvania Companies recalculated the net impact for 2018 through 2021 under the revised PPUC methodology in comparison to amounts already refunded to customers under the existing riders, which resulted in an additional $61 million in savings, with interest, to be provided to customers.

As a result, FirstEnergy recognized a pre-tax charge of $61 million in the fourth quarter of 2021 at the regulated distribution segment within Amortization (deferral) of Regulatory Assets, net, on the Consolidated Statement of Income associated with the additional refund associated with the November 2021 PPUC order and methodology.

The Pennsylvania Companies are required to file petitions to propose the timing and methodology of the refund of these amounts by March 3, 2022.

Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs.

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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 Pennsylvania Companies’ Phase IV plans were filed November 30, 2020 and subsequently approved by PPUC without modification on March 25, 2021.

Pennsylvania EDCs are permitted to seek PPUC 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 January 16, 2020, the PPUC approved the Pennsylvania Companies’ 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 June 25, 2021, the Pennsylvania OCA filed a complaint against Penn’s quarterly DSIC rate, disputing the recoverability of the Companies’ automated distribution management system investment under the DSIC mechanism.

On January 26, 2022, the parties filed a joint petition for settlement that resolves all issues in this matter pending PPUC approval.

The decision was appealed to the Pennsylvania Supreme Court and in July 2021 the court upheld the Pennsylvania Commonwealth Court’s reversal of the PPUC’s decision and remanded the matter back to the PPUC for determination as to how DSIC calculations shall account for ADIT and state taxes.

The matter awaits further action by the PPUC.

The 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.

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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.

On March 19, 2021, the PPUC entered an order lifting the moratorium in total effective March 31, 2021, subject to certain additional guidelines regarding the duration of payment arrangements and reporting obligations.

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 provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under WVPSC approved rates that became effective in 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.

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.

The filing proposed an annual revenue reduction of $2.6 million, effective January 1, 2022, with reconciliation and any resulting adjustments incorporated into annual ENEC proceedings.

On August 12, 2021, a unanimous settlement was reached with all the parties agreeing to a $7.7 million rate reduction beginning January 1, 2022, with a true-up in the ENEC proceeding each year.

On November 30, 2021, the WVPSC approved the settlement on all terms, except for the proposed effective date of the rate reduction, which was held in abeyance until further notice.

On August 27, 2021, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates of $19.6 million beginning January 1, 2022, which represented a 1.5% increase to the rates currently in effect.

WVPSC issued an order on December 29, 2021, granting the requested $19.6 million increase in ENEC rates.

Among other things, the order requires MP

and PE to refund to its large industrial customers their respective portion of the $7.7 million rate reduction discussed above and also requires MP and PE to negotiate a PPA for its capacity shortfall and a reasonable reserve margin if certain conditions are met.

On November 22, 2021, MP and PE filed with the WVPSC their plan to construct 50 MWs of solar generation at five sites in West Virginia.

The plan includes a tariff to offer solar power to West Virginia customers and cost recovery for MP and PE from other customers through a surcharge for any solar investment not fully subscribed by their customers.

A hearing has been set for March 16, 2022.

The solar generation project is expected to cost approximately $100 million and begin being in-service by the end of 2023 and finalized no later than the end of 2025.

On August 27, 2021, MP and PE filed with the WVPSC a biennial review of the vegetation management surcharge seeking a $16 million annual revenue increase.

A settlement among the parties was reached on December 3, 2021 and on December 27, 2021, the WVPSC approved the settlement, which granted a $16 million increase in rates, and continued the vegetation management program and surcharge for another two years.

Additionally, the WVPSC order added a provision requiring equipment inspections be performed within a reasonable time after vegetation management occurs on a circuit.

On December 17, 2021, MP and PE filed with the WVPSC for approval of environmental compliance projects at the Ft.

Martin and Harrison Power Stations to comply with the EPA’s ELG and operate these plants beyond 2028.

The request includes a surcharge to recover the expected $142 million capital investment and $3 million in annual operation and maintenance expense.

A ruling from the WVPSC is expected in mid-summer 2022, and if approved, construction would be expected to be completed by the end of 2025.

See "Environmental Matters - Clean Water Act" below, for additional details on the EPA's ELG.

FERC REGULATORY MATTERS

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ATSI January 1, 2015 Actual (13-month average) 10.38 %

January 2020 (1)

January 1, 2020 Actual (13-month average) 10.20 %

MP January 1, 2021 (1)(2)

Actual (13-month average) (1)

MP March 21, 2018 (2)(4)

Settled (2)(3)

PE March 21, 2018 (2)(4)

Settled (2)(3)

WP March 21, 2018 (2)(4)

Settled (2)(3)

PE January 1, 2021 (1)(2)

Actual (13-month average) (1)

WP January 1, 2021 (1)(2)

Actual (13-month average) (1)

MAIT July 1, 2017 Lower of Actual (13-month average) or 60 %

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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%.

(1) 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.

(2) See FERC Action 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.

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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.

All of the facilities that FirstEnergy operates are located within RFC.

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.

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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.

FERC’s Division of Audits and Accounting initiated a nonpublic audit of FESC in February 2019.

Among other matters, the audit is evaluating FirstEnergy’s compliance with certain accounting and reporting requirements under various FERC regulations.

On February 4, 2022, FERC filed the final audit report for the period of January 1, 2015 through September 30, 2021, which included several findings and recommendations.

One of the audit report findings and related recommendations state that FirstEnergy may have used an inappropriate methodology for allocation of certain costs to regulatory capital accounts under certain FERC regulations and reporting.

Based on the finding and related recommendations, FirstEnergy is currently performing an analysis of these costs and how it impacted certain wholesale transmission customer rates.

FirstEnergy is unable to predict or estimate the final outcome of this analysis and audit, however, it could result in refunds, with interest, to certain wholesale transmission customers and/or write-offs of previously capitalized costs if they are determined to be nonrecoverable.

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.

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, and certain costs for transmission-related vegetation management programs.

A portion of these costs would have been charged to the Ohio Companies.

Additionally, ATSI proposed certain income tax-related adjustments and certain tariff changes addressing the revenue credit components of the formula rate template.

On June 30, 2020, FERC issued an initial order accepting the tariff amendments subject to refund and setting the matter for hearing and settlement proceedings.

ATSI and the parties to the FERC proceeding subsequently were able to reach settlement, and on October 14, 2021, filed the settlement with FERC.

As a result of the filed settlement, FirstEnergy recognized a $21 million pre-tax charge during the third quarter of 2021, which was recognized in Other Operating Expenses on the FirstEnergy Consolidated Statements of Income.

This $21 million charge reflects the difference between amounts originally recorded as regulatory assets and amounts which will ultimately be recovered as a result of the pending settlement.

From a segment perspective, during the third quarter of 2021, the Regulated Transmission segment recorded a pre-tax charge of $48 million and the Regulated Distribution segment recognized a $27 million reduction to a reserve previously recorded in 2010.

In addition, the settlement provides for partial recovery of future incurred costs allocated to ATSI by MISO for the above-referenced transmission projects that were constructed by other MISO transmission owners, which is not expected to have a material impact on FirstEnergy or ATSI.

The uncontested settlement is pending before FERC for approval.

FERC Actions on Tax Act

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On November 21, 2019, FERC issued a final rule (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;

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;

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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 November 18, 2021, FERC issued an order that:

(i) accepted ATSI proposed tariff amendments to its rate base adjustment mechanism, effective January 27, 2020;

(ii) directed ATSI to make a further compliance filing by January 17, 2022;

and (iii) set the amount of ATSI’s recorded ADIT balances as of December 31, 2017, for hearing and settlement procedures.

ATSI submitted the compliance filing, and is participating in settlement negotiations.

On December 3, 2021, FERC issued an order that (i) accepted MAIT’s proposed tariff amendments to its rate base adjustment mechanism, effective January 27, 2020;

(ii) directed MAIT to make a further compliance filing by February 1, 2022;

and (iii) set the amount of MAIT’s recorded ADIT balances as of December 31, 2017 for hearing and settlement procedures.

MAIT submitted the compliance filing, and is participating in settlement negotiations.

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.

On May 4, 2021, FERC staff requested additional information about PATH’s proposed rate base adjustment mechanism, and PATH submitted the requested information on June 3, 2021.

On July 12, 2021, FERC staff requested additional information about TrAIL’s proposed rate base adjustment mechanism.

TrAIL filed its response on August 6, 2021.

The PATH and TrAIL compliance filings each remain pending before FERC.

MP, WP and PE (as holders of a “stated” transmission rate when Order No.

864 issued) are addressing these requirements in the transmission formula rates amendments that were filed on October 29, 2020, and which have been accepted by FERC effective January 1, 2021, subject to refund, pending further hearing and settlement procedures, MP, WP and PE are engaged in settlement negotiations with other parties to

this proceeding.

JCP&L addressed these requirements as part of its transmission formula rate case, which was resolved by a settlement approved by FERC on April 15, 2021.

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.

Any changes to FERC’s transmission rate ROE and incentive policies would be applied on a prospective basis.

On May 20, 2021, in a case not involving FirstEnergy, FERC issued Opinion No.

575 in which it reiterated the nationwide ROE methodology set forth in 2020 in Opinion Nos.

569-A and 569-B.

Under this methodology, FERC employs three financial models – discounted cash flow, capital-asset pricing, and risk premium – to calculate a composite zone of reasonableness.

As it has done in other recent ROE cases, FERC rejected the use of the expected earnings methodology in calculating the authorized ROE.

A request for clarification or, alternatively, rehearing of Opinion No.

575 was filed on June 21, 2021, and on September 9, 2021, FERC issued an order clarifying aspects of its prior opinion, but affirming the result.

On July 15, 2021, FERC issued another order, addressing ROE for a generation company in New England, which applied a standard consistent with Opinion Nos.

569-A and 569-B.

FERC’s Opinion Nos.

569-A and 569-B, upon which Opinion No.

575 is based, have been appealed to the D.C.

FirstEnergy is not participating in the appeal.

Any changes to FERC’s transmission rate ROE and incentive policies for transmission rates 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.

FirstEnergy submitted comments through EEI and as part of a consortium of PJM Transmission Owners.

In a supplemental rulemaking proceeding that was initiated on April 15, 2021, FERC requested comments on, among other things, whether to require utilities that have been members of an RTO for three years or more and that have been collecting an “RTO membership” ROE incentive adder to file tariff updates that would terminate collection of the incentive adder.

Initial comments on the proposed rule were filed on June 25, 2021, and reply comments were filed on July 26, 2021.

The rulemaking remains pending before FERC.

FirstEnergy is a member of PJM and its transmission subsidiaries could be affected by the supplemental proposed rule.

FirstEnergy participated in comments that were submitted by a group of PJM transmission owners and by various industry trade groups.

If there were to be any changes to FirstEnergy transmission incentive ROE, such changes will be applied on a prospective basis.

JCP&L Transmission Formula Rate

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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.

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, JCP&L filed an offer of settlement with FERC.

On April 15, 2021, FERC approved the settlement agreement as filed, with no changes, effective January 1, 2021.

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.

On October 29, 2020, MP, PE and WP filed tariff amendments with FERC to implement a forward-looking formula transmission rate, to be 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.

These transmission rate filings were accepted for filing by FERC on December 31, 2020, effective January 1, 2021, subject to refund, pending further hearing and settlement procedures and were consolidated into a single proceeding.

MP, PE and WP, and KATCo are engaged in settlement negotiations with the other parties to the formula rate proceedings.

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FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party.

As of December 31, 2020, outstanding guarantees and other assurances aggregated approximately $ 1.7 billion, consisting of parental guarantees on behalf of its consolidated subsidiaries' guarantees ($ 1.1 billion), other guarantees ($ 108 million) and other assurances ($ 490 million).

As of December 31, 2021, outstanding guarantees and other assurances aggregated approximately $ 1.1 billion, consisting of parental guarantees on behalf of its consolidated subsidiaries ($ 0.6 billion) and other assurances ($ 0.5 billion).

COLLATERAL AND CONTINGENT-RELATED FEATURES

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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.

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.

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.

As of December 31, 2021, $ 55 million of collateral has been posted by FE or its subsidiaries and is included in Prepaid taxes and other current assets on FirstEnergy's Consolidated Balance Sheets.

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.

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(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.

Surety Bonds' impact assumes maximum contractual obligations, which is ordinarily 100% of the face amount of the surety bond except with 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.

FE was previously a guarantor under a $ 120 million syndicated senior secured term loan facility due November 12, 2024, which Global Holding repaid during the fourth quarter of 2021, and as a result, FirstEnergy’s guarantee is no longer in effect.

ENVIRONMENTAL MATTERS

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CSAPR allows trading of NOx and SO 2 emission allowances between power plants located in the same state and interstate trading of NOx and SO 2 emission allowances with some restrictions.

Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO 2 emissions from power plants in 13 states, including West Virginia.

This follows the 2014 U.S.

On July 28, 2015, the D.C.

Circuit ordered the EPA to reconsider the CSAPR caps on NOx and SO 2 emissions from power plants in 13 states, including West Virginia.

This followed 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.

The EPA issued a CSAPR Update 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 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 SO 2 , 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.

Circuit remanded the CSAPR Update 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.

Also, during this time, 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 sought suitable emission rate limits for large stationary sources that are allegedly 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.

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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.

On March 15, 2021, the EPA issued a revised CSAPR Update that addresses, among other things, the remands of the CSAPR Update and the New York Section 126 Petition.

Depending on the outcome of any appeals and how the EPA and the states ultimately implement the revised CSAPR Update, 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 SO 2 , specifically retaining the 2010 primary (health-based) 1-hour standard of 75 PPB.

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

Climate Change

There are a number of initiatives to reduce GHG emissions at the state, federal and international level.

There are several 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.

joined in adopting the agreement reached on December 12, 2015, at the United Nations Framework Convention on Climate Change meetings in Paris to reduce GHGs.

The Paris Agreement’s non-binding obligations to limit global warming to below two degrees Celsius became effective on November 4, 2016.

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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 CO 2 emissions from existing fossil fuel fired EGUs and finalized separate regulations imposing CO 2 emission limits for new, modified, and reconstructed fossil fuel fired EGUs.

In November 2020, FirstEnergy published its Climate Story which includes its climate position and strategy, as well as a new comprehensive and ambitious GHG emission goal.

FirstEnergy pledged to achieve carbon neutrality by 2050 and set an interim goal for a 30% reduction in GHGs within FirstEnergy’s direct operational control by 2030, based on 2019 levels.

Future resource plans to achieve carbon reductions, including any determination of retirement dates of the regulated coal-fired generation, will be developed by working collaboratively with regulators in West Virginia.

Determination of the useful life of the regulated coal-fired generation 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 FirstEnergy’s and/or MP’s financial condition, results of operations, and cash flow.

Furthermore, FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO 2 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 GHGs under the Clean Air Act,” concluding that concentrations of several key GHGs constitute 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.

Subsequently, the EPA released its final CPP regulations in August 2015 to reduce CO 2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO 2 emission limits for new, modified, and reconstructed fossil fuel-fired EGUs.

Numerous states and private parties filed appeals and motions to stay the CPP with the D.C.

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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 June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that established guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired generation.

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.

Circuit vacated and remanded the ACE rule declaring that the EPA was “arbitrary and capricious” in its rule making and, 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.

Circuit decision is subject to legal challenge.

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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.

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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.

The EPA is reconsidering the ELG rule with a publicly announced target of issuing a proposed revised rule in the Fall of 2022 and a final rule by the Spring of 2023.

In the interim, the rule issued on August 31, 2020, remains in effect.

Depending on the outcome of appeals and how final rules are ultimately implemented, the compliance with these standards, could require additional capital expenditures or changes in operations at Ft.

Martin and Harrison power stations from what was filed with the WVPSC in December 2021 that seeks approval of environmental compliance projects to comply with the EPA’s ELG.

After the completion of a negotiated settlement, a complaint was filed by the EPA and PA DEP on January 10, 2022 in Federal District Court for the Western District of Pennsylvania, alleging, among other things, that WP violated the CWA in connection with past boron exceedances at WP’s Springdale and Mingo landfills.

On January 11, 2022, WP entered into a consent decree with the EPA and PA DEP resolving the matters addressed in the complaint, which, among other things, requires a civil penalty of $610 thousand.

The consent decree is subject to final approval by the District Court pending public comment.

Regulation of Waste Disposal

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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.

On July 29, 2020, the EPA published a final rule again revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021.

The final rule also 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 of McElroy's Run CCR impoundment facility until 2024, which request is pending technical review by the EPA.

AE Supply continues to operate McElroy’s Run as a disposal facility for FG’s Pleasants Power Station.

FE or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA.

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Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of December 31, 2021, 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.

Total liabilities of approximately $105 million have been accrued through December 31, 2021, of which, approximately $70 million are 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.

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FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020.

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.

On July 21, 2021, FE entered into a three-year DPA with the U.S.

Attorney’s Office that, subject to court proceedings, resolves this matter.

Under the DPA, FE has agreed to the filing of a criminal information charging FE with one count of conspiracy to commit honest services wire fraud.

The DPA requires that FirstEnergy, among other obligations:

(i) continue to cooperate with the U.S.

Attorney’s Office in all matters relating to the conduct described in the DPA and other conduct under investigation by the U.S.

(ii) pay a criminal monetary penalty totaling $230 million within sixty days, which shall consist of (x) $115 million paid by FE to the United States Treasury and (y) $115 million paid by FE to the ODSA to fund certain assistance programs, as determined by the ODSA, for the benefit of low-income Ohio electric utility customers;

(iii) publish a list of all payments made in 2021 to either 501(c)(4) entities or to entities known by FirstEnergy to be operating for the benefit of a public official, either directly or indirectly, and update the same on a quarterly basis during the term of the DPA;

(iv) issue a public statement, as dictated in the DPA, regarding FE’s use of 501(c)(4) entities;

and (v) continue to implement and review its compliance and ethics program, internal controls, policies and procedures designed, implemented and enforced to prevent and detect violations of the U.S.

laws throughout its operations, and to take certain related remedial measures.

The $230 million payment will neither be recovered in rates or charged to FirstEnergy customers nor will FirstEnergy seek any tax deduction related to such payment.

The entire amount of the monetary penalty was recognized as expense in the second quarter of 2021, and paid in the third quarter of 2021.

Under the terms of the DPA, the criminal information will be dismissed after FirstEnergy fully complies with its obligations under the DPA.

Legal Proceedings Relating to United States v.

Larry Householder, et al.

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.

On April 28, 2021, the SEC issued an additional subpoena to FE.

While no contingency has been reflected in its consolidated financial statements, FE believes that it is probable that it will incur a loss in connection with the resolution of the SEC investigation.

Given the ongoing

nature and complexity of the review, inquiries and investigations, FE cannot yet reasonably estimate a loss or range of loss that may arise from the resolution of the SEC investigation.

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.

al.” and the SEC investigation, 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.

The plaintiffs in each of the below cases seek, among other things, to recover an unspecified amount of damages (unless otherwise noted).

Unless otherwise indicated, no contingency has been reflected in FirstEnergy’s consolidated financial statements with respect to these lawsuits as a loss is neither probable, nor is a loss or range of a loss reasonably estimable.

• In re FirstEnergy Corp.

Securities Litigation (Federal District Court, S.D.

on July 28, 2020 and August 21, 2020, purported stockholders of FE filed putative class action lawsuits alleging violations of the federal securities laws.

Those actions have been consolidated and a lead plaintiff, the Los Angeles County Employees Retirement Association, has been appointed by the court.

A consolidated complaint was filed on February 26, 2021.

The consolidated complaint alleges, on behalf of a proposed class of persons who purchased FE securities between February 21, 2017 and July 21, 2020, that FE and certain current or former FE officers violated Sections 10(b) and 20(a) of the Exchange Act by issuing misrepresentations or omissions concerning FE’s business and results of operations.

The consolidated complaint also alleges that FE, certain current or former FE officers and directors, and a group of underwriters violated Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 as a result of alleged misrepresentations or omissions in connection with offerings of senior notes by FE in February and June 2020.

FE believes that it is probable that it will incur a loss in connection with the resolution of this lawsuit.

Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss.

• MFS Series Trust I, et al.

FirstEnergy Corp., et al.

(Federal District Court, S.D.

Ohio) on December 17, 2021, purported stockholders of FE filed a complaint against FE, certain current and former officers, and certain current and former officers of EH.

The complaint alleges that the defendants violated Sections 10(b) and 20(a) of the Exchange Act by issuing alleged misrepresentations or omissions regarding FE’s business and its results of operations, and seeks the same relief as the In re FirstEnergy Corp.

Securities Litigation described above.

FE believes that it is probable that it will incur a loss in connection with the resolution of this lawsuit.

Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss.

• 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, all actions have been consolidated);

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 (the OAG also named FES as a defendant), each alleging civil violations of the Ohio Corrupt Activity Act in connection with the passage of HB 6.

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 (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 cases are stayed pending final resolution of the United States v.

Larry Householder, et al.

criminal proceeding described above, although on August 13, 2021, new defendants were added to the complaint, including two former officers of FirstEnergy.

On November 9, 2021, the OAG filed a motion to lift the agreed-upon stay, which FE opposed on November 19, 2021;

the motion remains pending.

On December 2, 2021, the cities and FE entered a stipulated dismissal with prejudice of the cities’ suit.

FirstEnergy Corp.

et al., Buldas v.

FirstEnergy Corp.

et al., and Hudock and Cameo Countertops, Inc.

FirstEnergy Corp.

(Federal District Court, S.D.

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.

Ohio, all actions have been consolidated);

on July 27, 2020, July 31, 2020, and August 5, 2020, respectively, purported customers of FE filed putative class action lawsuits against FE and FESC, as well as certain current and former FE officers, alleging civil Racketeer Influenced and Corrupt Organizations Act violations and related state law claims.

The court denied FE’s motions to dismiss and stay discovery on February 10 and 11, 2021, respectively, and the defendants submitted answers to the complaint on March 10, 2021.

The plaintiffs moved to certify the case as a class action on June 28, 2021, and moved for leave to amend the complaint to add FES as a defendant on September 27, 2021.

The court granted the motion to amend on November 10, 2021.

On November 9, 2021, the court issued an order granting Plaintiffs' motion for class certification, but vacated that order on November 19, 2021, to allow defendants to take the named plaintiffs’ depositions and to file an opposition to the motion, which they filed on December 14, 2021.

On November 19, 2021, FE and FESC moved for judgment on the pleadings.

One of the individual defendants moved to dismiss the amended complaint on November 24, 2021.

On December 28, 2021, the parties jointly moved the court to stay consideration of the pending motions for class certification, to dismiss, and for judgment on the pleadings for 45 days.

The court granted the motion on December 29, 2021, and the cases are currently stayed.

FE is engaged with the parties in settlement discussions, and believes that it is probable that it will incur a loss in connection with the resolution of these lawsuits.

As a result, FirstEnergy recognized in the fourth quarter of 2021 a pre-tax reserve of $37.5 million in the aggregate with respect to these lawsuits and the Emmons lawsuit below.

FirstEnergy Corp.

(Common Pleas Court, Cuyahoga County, OH);

on August 4, 2020, a purported customer of FirstEnergy filed a putative class action lawsuit against FE, FESC, the Ohio Companies, 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.

On May 4, 2021, the court granted the defendants’ motion to dismiss plaintiffs’ breach of contract claims and denied the remainder of the motions to dismiss.

The defendants submitted answers to the complaint on June 1, 2021.

Discovery is proceeding.

On December 30, 2021, the plaintiff filed a Second Amended Complaint removing one of the named plaintiffs and updating the class definition.

FE is engaged with the parties in settlement discussions, and believes that it is probable that it will incur a loss in connection with the resolution of these lawsuits.

As a result, FirstEnergy recognized in the fourth quarter of 2021 a pre-tax reserve of $37.5 million in the aggregate with respect to this lawsuit and the lawsuits above consolidated with Smith in the S.D.

Ohio alleging, among other things, civil violations of the Racketeer Influenced and Corrupt Organizations Act.

On February 9, 2022, FE, acting through the SLC, agreed to a settlement term sheet to resolve the following shareholder derivative lawsuits relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr.

Householder that were filed in the S.D.

Ohio, the N.D.

Ohio, and the Ohio Court of Common Pleas, Summit County:

• Gendrich v.

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Anderson, et al.

(Common Pleas Court, Summit County, OH);

(Common Pleas Court, Summit County, OH, all actions have been consolidated);

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.

Anderson, et al.

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Anderson, et al.

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.

FirstEnergy Corp.

et al., Buldas v.

FirstEnergy Corp.

et al., and Hudock and Cameo Countertops, Inc.

FirstEnergy Corp.

(Federal District Court, S.D.

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.

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.

The cities of Dayton and Toledo have also been added as plaintiffs to the action.

These actions have been consolidated.

FirstEnergy Corp.

(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.

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.

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:

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.

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.

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.

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 Energy Solutions , 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.

Ohio, all actions have been consolidated);

beginning on August 7, 2020, purported stockholders of FE filed shareholder derivative actions alleging the FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act.

The proposed settlement, which is subject to court approval, will fully resolve the shareholder derivative lawsuits above and stipulates a series of corporate governance enhancements, that is expected to result in the following:

• Six members of the FE Board, Messrs.

Anderson, Donald T.

Misheff, Thomas N.

Mitchell, Christopher D.

Pappas and Luis A.

Reyes, and Ms.

Johnson will not stand for re-election at FE’s 2022 annual shareholder meeting;

• A special FE Board committee of at least three recently appointed independent directors will be formed to initiate a review process of the current senior executive team, to begin within 30 days of the 2022 annual shareholder meeting;

• The FE Board will oversee FE’s lobbying and political activities, including periodically reviewing and approving political and lobbying action plans prepared by management;

• The FE Board will form another committee of recently appointed independent directors to oversee the implementation and third-party audits of the FE Board-approved action plans with respect to political and lobbying activities;

• FE will implement enhanced disclosure to shareholders of political and lobbying activities, including enhanced disclosure in its annual proxy statement;

• FE will further align financial incentives of senior executives to proactive compliance with legal and ethical obligations.

The settlement also includes a payment to FirstEnergy of $180 million, to be paid by insurance after court approval, less any court-ordered attorney’s fees awarded to plaintiffs.

In letters dated January 26, and February 22, 2021, staff of FERC's Division of Investigations notified FirstEnergy that the Division is conducting an investigation of FirstEnergy’s lobbying and governmental affairs activities concerning HB 6, and staff directed FirstEnergy to preserve and maintain all documents and information related to the same as such have been developed as part of an ongoing non-public audit being conducted by FERC's Division of Audits and Accounting.

While no contingency has been reflected in the consolidated financial statements, FirstEnergy believes that it is probable that it will incur a loss in connection with the resolution of the FERC investigation.

Given the ongoing nature and complexity of the review, inquiries and investigations, FirstEnergy cannot yet reasonably estimate a loss or range of loss that may arise from the resolution of the FERC investigation.

The outcome of any of these lawsuits, governmental investigations and audit is uncertain and could have a material adverse effect on FE’s or its subsidiaries’ reputation, business, financial condition, results of operations, liquidity, and cash flows.

Other Legal Matters

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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.

TRANSACTIONS WITH AFFILIATED COMPANIES

FE does not bill directly or allocate any of its costs to any subsidiary company.

Costs are charged to FE's subsidiaries for services received from FESC.

The majority of costs are directly billed or assigned at no more than cost.

The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas developed by FESC.

The current allocation or assignment formulas used and their bases include multiple factor formulas:

each company’s proportionate amount of FirstEnergy’s aggregate direct payroll, number of employees, asset balances, revenues, number of customers, other factors and specific departmental charge ratios.

Intercompany transactions are generally settled under commercial terms within thirty days.

The Utilities and Transmission Companies are parties to an intercompany income tax allocation agreement with FE and its other subsidiaries, that provides for the allocation of consolidated tax liabilities.

Net tax benefits attributable to FE are generally reallocated to the subsidiaries of FirstEnergy that have taxable income.

That allocation is accounted for as a capital contribution to the company receiving the tax benefit (see Note 7, "Taxes").

DISCONTINUED OPERATIONS

On February 27, 2020, the FES Debtors effectuated their plan, emerged from bankruptcy and FirstEnergy tendered the bankruptcy court approved settlement payments totaling $ 853 million and a $ 125 million tax sharing payment to the FES Debtors.

The FES Bankruptcy settlement was conditioned on the FES Debtors confirming and effectuating a plan of reorganization acceptable to FirstEnergy.

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.

During the first quarter of 2020, FG paid AE Supply approximately $ 65 million of cash for related materials and supplies (at book value) and the settlement of FG’s economic interest in Pleasants.

As a result of the FES Debtors’ tax return deconsolidation, FirstEnergy recognized a worthless stock deduction, of approximately $ 4.9 billion, net of unrecognized tax benefits of $ 316 million, for the remaining tax basis in the stock of the FES Debtors.

Based upon completion of the IRS’s review of the 2020 federal income tax return during fourth quarter 2021, FirstEnergy recognized the full tax benefit of the worthless stock deduction of approximately $ 5.2 billion, or $ 1.1 billion on a tax-effected basis, net of valuation allowances recorded against the state tax benefit ($ 21 million), eliminating associated uncertain tax position reserves.

In conjunction with filing the 2020 consolidated federal income tax return during the third quarter of 2021, FirstEnergy computed a final federal NOL allocation between the FES Debtors and FirstEnergy consolidated that resulted in FirstEnergy recording an increase to the consolidated NOL carryforward of approximately $ 289 million ($ 61 million tax-effected).

Summarized Results of Discontinued Operations

Summarized results of discontinued operations for the years ended December 31, 2021, 2020, and 2019 were as follows:

For the Years Ended December 31,

(In millions) 2021 2020 2019

Revenues $ — $ 7 $ 188

Fuel — ( 6 ) ( 140 )

Other operating expenses — ( 6 ) ( 63 )

General taxes — — ( 14 )

Pleasants economic interest (1)

Other expense, net ( 4 ) — ( 2 )

Loss from discontinued operations, before tax ( 4 ) — ( 4 )

Income tax expense (benefit) ( 1 ) — 47

Loss from discontinued operations, net of tax ( 3 ) — ( 51 )

Settlement consideration and services credit — ( 1 ) 7

Accelerated net pension and OPEB prior service credits — 18 —

Gain on disposal of FES and FENOC, before tax — 17 7

Income tax benefits, including worthless stock deduction ( 47 ) ( 59 ) ( 52 )

Gain on disposal of FES and FENOC, net of tax 47 76 59

Income from discontinued operations $ 44 $ 76 $ 8

(1) Reflects the estimated amounts owed from FG for its economic interests in Pleasants effective January 1, 2019.

As discussed above, settlement of the economic interests occurred during the first quarter of 2020.

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 cash flow items from discontinued operations for the years ended December 31, 2021, 2020 and 2019:

For the Years Ended December 31,

(In millions) 2021 2020 2019

CASH FLOWS FROM OPERATING ACTIVITIES:

Income from discontinued operations $ 44 $ 76 $ 8

Gain on disposal, net of tax ( 47 ) ( 76 ) ( 59 )

Deferred income taxes and investment tax credits, net — — 47

SEGMENT INFORMATION

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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.

This segment also controls 3,580 MWs of regulated electric generation capacity located primarily in West Virginia and Virginia.

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.

Included within the segment is $ 882 million of assets classified as held for sale as of December 31, 2019 associated with the asset purchase and sale agreements with TMI-2 Solutions to transfer TMI-2 to TMI-2 Solutions, LLC.

With the receipt of all required regulatory approvals, the transaction was consummated on December 18, 2020.

As a result, during the fourth quarter of 2020 FirstEnergy recognized an after tax-gain of approximately $ 33 million, primarily associated with the write-off of a tax related regulatory liability.

See Note 15, "Commitments, Guarantees and Contingencies" for additional information.

Also included within

the segment is $ 45 million of assets classified as held for sale as of December 31, 2020 associated with the asset purchase agreement with Yards Creek Energy, LLC to transfer JCP&L's 50 % interest in the Yards Creek pumped-storage hydro generation station ( 210 MWs).

The transaction to transfer TMI-2 to TMI-2 Solutions, LLC was consummated on December 18, 2020, and as a result, during the fourth quarter of 2020 FirstEnergy recognized an after-tax gain of approximately $ 33 million, primarily associated with the write-off of a tax related regulatory liability.

Included within the segment is $ 45 million of assets classified as held for sale as of December 31, 2020 associated with the asset purchase agreement with Yards Creek;

see Note 12, "Regulatory Matters," for additional information.

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.

Reconciling adjustments for the elimination of inter-segment transactions and discontinued operations are shown separately in the following table of Segment Financial Information.

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.

The segment's revenues are primarily derived from forward-looking formula rates.

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 rate base and costs.

The segment's results also reflect the net transmission expenses

related to the delivery of electricity on FirstEnergy's transmission facilities.

On November 6, 2021, FirstEnergy, along with FET, entered into the FET P&SA, with Brookfield and Brookfield Guarantors pursuant to which FET agreed to issue and sell to Brookfield at the closing, and Brookfield agreed to purchase from FET, certain newly issued membership interests of FET, such that Brookfield will own 19.9% of the issued and outstanding membership interests of FET, for a purchase price of $2.375 billion.

The transaction is subject to customary closing conditions, including approval from the FERC and review by the CFIUS.

KATCo, which is currently a subsidiary of FET, will become a wholly owned subsidiary of FE prior to the closing of the transaction and will remain in the Regulated Transmission segment.

Corporate/Other reflects corporate support and other costs not charged or attributable to the Utilities or Transmission Companies, 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.

Reconciling adjustments for the elimination of inter-segment transaction are shown separately in the following table of Segment Financial Information.

As of December 31, 2021, 67 MWs of electric generating capacity, representing AE Supply's OVEC capacity entitlement, is included in Corporate/Other.

As of December 31, 2021, Corporate/Other had approximately $ 7.9 billion of FE holding company debt.

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

Financial information for each of FirstEnergy’s business segments and reconciliations to consolidated amounts is presented in the tables below.

FirstEnergy evaluates segment performance based on Income (loss) from continuing operations.

Segment Financial Information

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Provision for depreciation 911 325 3 63 1,302

Amortization (deferral) of regulatory assets, net ( 64 ) 11 — — ( 53 )

Amortization of regulatory assets, net 260 9 — — 269

DPA penalty — — 230 — 230

Miscellaneous income (expense), net 399 41 89 ( 12 ) 517

33 unchanged sentences

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 8. Financial Statements and Supplementary Data