# FIRSTENERGY CORP (FE) FY 2021 MD&A

Verbatim Item 7 Management's Discussion and Analysis from FIRSTENERGY CORP's 10-K for fiscal year 2021.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1031296/000103129622000013/fe-20211231.htm
Accession: 0001031296-22-000013
Filing date: 2022-02-16
Report date: 2021-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Published MD&A gate trimmed front/tail over-capture.
Confidence: high

Company profile: /company/FE/
All MD&A years: /company/FE/mda/
Next year: /company/FE/mda/fy2022/ (FY 2022)

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

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

•The potential liabilities, increased costs and unanticipated developments resulting from government investigations and agreements, including those associated with compliance with or failure to comply with the DPA.

•The risks and uncertainties associated with government investigations and audits regarding HB 6 and related matters, including potential adverse impacts on federal or state regulatory matters, including, but not limited to, matters relating to rates.

•The risks and uncertainties associated with litigation, arbitration, mediation, and similar proceedings, particularly regarding HB 6 related matters, including risks associated with obtaining court approval of the definitive settlement agreement in the derivative shareholder lawsuits.

•Weather conditions, such as temperature variations and severe weather conditions, or other natural disasters affecting future operating results and associated regulatory actions or outcomes in response to such conditions.

•Legislative and regulatory developments, including, but not limited to, matters related to rates, compliance and enforcement activity.

•The ability to accomplish or realize anticipated benefits from our FE Forward initiative and our other strategic and financial goals, including, but not limited to, overcoming current uncertainties and challenges associated with the ongoing government investigations, executing our transmission and distribution investment plans, greenhouse gas reduction goals, controlling costs, improving our credit metrics, growing earnings, strengthening our balance sheet, and satisfying the conditions necessary to close the sale of the minority interest in FET.

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

•Mitigating exposure for remedial activities associated with retired and formerly owned electric generation assets.

•The ability to access the public securities and other capital and credit markets in accordance with our financial plans, the cost of such capital and overall condition of the capital and credit markets affecting us, including the increasing number of financial institutions evaluating the impact of climate change on their investment decisions.

•The extent and duration of the COVID-19 pandemic and the related impacts to our business, operations and financial condition resulting from the outbreak of COVID-19 including, but not limited to, disruption of businesses in our territories, additional costs, workforce impacts and governmental and regulatory responses to the pandemic, such as moratoriums on utility disconnections and workforce vaccination mandates.

•The effectiveness of our pandemic and business continuity plans, the precautionary measures we are taking on behalf of our customers, contractors and employees, our customers’ ability to make their utility payment and the potential for supply-chain disruptions.

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

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

•Changes in customers’ demand for power, including, but not limited to, the impact of climate change or energy efficiency and peak demand reduction mandates.

•Changes in national and regional economic conditions, including recession and inflationary pressure, affecting us and/or our customers and those vendors with which we do business.

•The potential of non-compliance with debt covenants in our credit facilities.

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

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

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

•Labor disruptions by our unionized workforce.

•Changes to significant accounting policies.

•Any changes in tax laws or regulations, or adverse tax audit results or rulings.

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

Dividends declared from time to time on our common stock during any period may in the aggregate vary from prior periods due to circumstances considered by the FE Board at the time of the actual declarations. A security rating is not a recommendation to

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buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.

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

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FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRSTENERGY’S BUSINESS

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

The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey, and Maryland. This segment also controls 3,580 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.

The service areas of, and customers served by, FirstEnergy's regulated distribution utilities as of December 31, 2021, are summarized below:

[[GREPCENT_TABLE]]
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[[/GREPCENT_TABLE]]

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. 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.

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. Additionally, reconciling adjustments for the elimination of inter-segment transactions are included in Corporate/Other. 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.

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EXECUTIVE SUMMARY

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

FirstEnergy's core values encompass what matters most to the company. They guide the decisions we make and the actions we take. FirstEnergy's core values should inspire our actions today and shine a light on who we aspire to be in the future.

FirstEnergy Core Values:

•Integrity: We always act ethically with honesty, humility and accountability.

•Safety: We keep ourselves and others safe.

•Diversity, Equity and Inclusion: We embrace differences, ensure every employee is treated fairly and create a culture where everyone feels they belong.

•Performance Excellence: We pursue excellence and seek opportunities for growth, innovation and continuous improvement.

•Stewardship: We positively impact our customers, communities and other stakeholders, and strive to protect the environment.

Employees are encouraged and expected to have conversations with their leaders and peers about the core values and FirstEnergy's commitment to building a culture centered on integrity.

At FirstEnergy, we are dedicated to staying true to our mission and core values. We understand the impact our company can make in the world around us, which means pursuing initiatives and goals that align with our foundational principles, support our ESG priorities, and positively impact our stakeholders.

To solidify our role as an industry leader, we have developed a long-term strategy with priorities that are centered on our mission statement. These priorities reflect a strong foundation with an unrelenting customer focus that emphasizes modern experiences, new growth and affordable energy bills, and is leading and enabling the energy transition to a clean, resilient and secure electric grid.

We are proud of the steps we’ve already taken to demonstrate our commitment to our strategy and look forward to improving our performance and executing on these strategic priorities.

FirstEnergy's Business

As a fully regulated electric utility, FirstEnergy is focused on stable and predictable earnings and cash flow from its Regulated Distribution and Regulated Transmission businesses that deliver enhanced customer service and reliability.

FirstEnergy's Regulated Distribution business is comprised of a geographically and regulatory diverse collection of electric utilities delivering customer-focused sustainable growth. This business operates in a territory of 65,000 square miles, across the Midwest & Mid-Atlantic regions, one of the largest contiguous territories in the United States, and allows the Utilities to be uniquely positioned for growth through investments that strengthen the grid and enable the clean energy transition, with approximately $9 billion in investment plans (or 53% of the total FirstEnergy investment plan) from 2021 to 2025. Through its investment plan, Regulated Distribution has improved reliability and added operating flexibility to the distribution infrastructure, which provide benefits to the customers and communities those Utilities serve.

In addition to our investments to rebuild critical infrastructure and improve reliability, current and future distribution investment opportunities that support our ESG and strategic priorities include:

•Advanced Metering Infrastructure – install smart meters and related infrastructure;

•Grid Modernization Investments that support distribution automation and voltage and var optimization;

•Installation of electric vehicle charging stations;

•Connected LED Streetlights – strategic goal to convert 100% of streetlights owned by the Utilities to smart LEDs by 2030;

•Alternative Generation that lowers our carbon footprint;

•Information Systems – enhance our core information infrastructure of our distribution systems; and

•Supporting economic development to attract new business.

FirstEnergy's Regulated Transmission business is a premier, high quality transmission business, with over 24,000 miles of transmission lines in operation and one of the largest transmission systems in PJM. The Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) are focused on "Energizing the Future" with investments that support clean-

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energy, improve grid reliability and resiliency and support a carbon neutral future. "Energizing the Future" is the centerpiece of FirstEnergy’s regulated investment strategy with all investments recovered under FERC-regulated forward-looking formula rates, and approximately $8 billion in investment plans (or 45% of the total FirstEnergy investment plan) from 2021 to 2025. FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of over $20 billion beyond those identified through 2025, which are expected to strengthen grid and cyber-security and make the transmission system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility.

In addition to our Energizing the Future investments, current and future transmission investment opportunities that support our ESG and strategic priorities include:

•Transmission Asset Health Center: real-time monitoring to reduce outages and lower expenses;

•Integrating digital technology to enhance equipment monitoring and lower costs;

•Exploring real-time technologies: emerging technologies to enhance data collection; and

•Making smart investments to modernize the grid to integrate future renewables.

On November 6, 2021, FirstEnergy, along with FET, entered into the FET P&SA with Brookfield and the 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 and is expected to close in the second quarter of 2022.

On December 13, 2021, FE privately issued to BIP Securities II-B L.P., an affiliate of Blackstone Infrastructure Partners L.P., 25,588,535 shares of FE’s common stock, par value $0.10 per share, at a price of $39.08 per share, representing an investment of $1.0 billion. In addition, subject to certain regulatory approvals, FE will appoint a Blackstone Infrastructure Partners-selected representative to the FE Board no later than the 2022 annual shareholders’ meeting.

On October 18, 2021, FE, FET, the Utilities, and the Transmission Companies entered into six separate senior unsecured five-year syndicated revolving credit 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. See “Capital Resources and Liquidity" below for additional details.

Together, these transactions enhance FirstEnergy's credit profile, provide funding for the strategic investments discussed above, and address all of FirstEnergy's equity plans, with the exception of annual issuances of up to $100 million under regular dividend reinvestment plans and employee benefit stock investment plans, through at least 2025.

FE Forward

FirstEnergy is also working to transform how it conducts business and serves its customers, to achieve value potential in a sustainable way and help FirstEnergy achieve its strategic priorities. In February 2021, FirstEnergy announced a new initiative to build upon FirstEnergy’s strong operations and business fundamentals and deliver immediate value and resilience, with substantial working capital improvements and capital efficiencies ramping up through 2024. Called "FE Forward," the initiative plays a critical first step in FirstEnergy’s transformation journey as it looks to enhance the organization, focus on performance excellence, and refocus the investment strategy through a range of opportunities, including:

•Align and centralize the organization into 5 strategic areas, optimize distribution operations by transitioning to 5 state-aligned business units with fewer management layers and implement centrally-driven best practices and processes in the areas of planning, scheduling and work management to safely improve frontline productivity and reducing the need for contracted resources;

•Formation of a Senior Vice President of Customer Experience position to drive key digital and productivity initiatives and programs, such as self-service options that enhance and streamline the customer experience reducing call volume by 30-40%;

•Deliver digital and data driven solutions through a ‘Digital Factory and Innovation Center’ and utilize advanced analytics to optimize decision-making in operating expense and capital deployment;

•Create a company-wide, cultural change roadmap to strengthen behaviors around FirstEnergy’s core values;

•Deliver leadership and functional capability training to drive performance excellence and innovation;

•Creation of a Vice President of Transformation Office to drive performance excellence; and

•Optimize spend strategies by expanding resources and capabilities in Supply Chain areas such as strategic sourcing, inventory management and optimized contract terms;

Since launching FE Forward in February 2021, which initially reviewed existing policies and practices, as well as the structure and processes around how decisions are made, the initiative has since reviewed further improvement opportunities and developed detailed, executable plans focusing on who, when, how and at what cost opportunities can be realized. In June 2021, FE Forward began the implementation phase that focused on executing and implementing these findings and opportunities with full-scale effort to drive value. By 2024, FE Forward is projected to generate approximately $380 million in annualized capital expenditure efficiencies, as well as, approximately $250 million in working capital improvements by 2023. This program includes an estimated $150 million of costs to achieve through 2023, which are expected to be self-funded through these efficiencies.

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FirstEnergy plans to redeploy the capital expenditure efficiencies in a more diverse capital program that over the long-term, continues to support our strategy as discussed above and using 2022 as baseline, operating expenses are projected to naturally decline 1% annually allowing for strategic flexibility and customer affordability. FE Forward is not a downsizing effort and there will not be any involuntary employee reductions in connection with this program. FirstEnergy expects that FE Forward will be a significant catalyst to augment its growth potential by taking a more strategic approach to operating expenditures and reinvesting in a more diverse capital program that over the long-term continues to support a smarter and cleaner electric grid, and maintain affordable customer bills. Specifically, FirstEnergy currently expects to redeploy these capital efficiencies into several projects, including, grid modernization, energy efficiency programs, smart meter and electric vehicle charging, and solar generation investments. As part of these efforts, FirstEnergy will evaluate the appropriate cadence to initiate rates cases on a state-by-state basis to best support FirstEnergy’s customer-focused strategic priorities.

[[GREPCENT_TABLE]]
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[[/GREPCENT_TABLE]]

Climate Story

Our long-term strategy reiterates and supports our position that climate change is among the most important issues of our time, and our commitment to doing our part to ensure a bright and sustainable future for the communities we serve. As part of our Climate Strategy, we’re focused on enabling our customers to live more sustainably and thrive in a carbon-neutral future. This includes transmission and distribution investments discussed above, investments in solar generation and supporting clean energy options, our efforts towards electrifying the economy, and driving energy efficiency.

Additionally, we plan to reduce our company-wide GHG emissions within our direct operational control (Scope 1) by 30% by 2030 (from our 2019 baseline), as we work toward carbon neutrality by 2050. Key steps in reducing our emissions and improving the sustainability of our operations include:

•Replacing Aging Equipment: We are responsibly replacing aging equipment on our transmission system that contains SF6, a greenhouse gas commonly used in electric utility equipment;

•Electrifying our Vehicle Fleet: We are targeting 30% electrification of our light-duty and aerial truck fleet by 2030 and 100% electrification by 2050. To reach our electrification goal, we’ve committed to 100% electric or hybrid vehicle purchases for our light-duty and aerial truck fleet moving forward, beginning with the first hybrid electric vehicle additions to the fleet in 2021;

•Using Generation Efficiencies and Flexibility: We are utilizing operational flexibilities, such as heat rate improvements through equipment upgrades, operational monitoring systems, and auxiliary power reductions at our generation facilities that will enable us to reach our interim 2030 goal of a 30% GHG reduction from 2019 levels, while continuing to provide customers with safe and reliable electricity; and

•Transitioning Away from Coal Generation: We expect to thoughtfully transition away from our regulated coal generation fleet no later than 2050 and in 2021, FirstEnergy sought approval to construct a solar generation source of at least 50 MWs in West Virginia. Also in 2021, FirstEnergy filed plans with the WVPSC to comply with EPA ELG rules that would keep MP’s generation plants responsibly operating beyond 2028, however, intends to begin a broad stakeholder dialogue regarding planned operational end dates of 2035 and 2040 for Ft. Martin and Harrison, respectively, which further supports our Climate Strategy.

Future resource plans to achieve carbon reductions, including potential changes in operations or any determination of retirement dates of the regulated coal-fired generating facilities, will be developed by working collaboratively with regulators in West Virginia. Determination of the useful life of the regulated coal-fired generating facilities could result in changes in depreciation, and/or continued collection of net plant in rates after retirement, securitization, sale, impairment or regulatory disallowances. If MP is unable to recover these costs, it could have a material adverse effect on FirstEnergy’s and/or MP’s financial condition, results of operations, and cash flow.

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HB 6 and Related Investigations

On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. Also, on July 21, 2020, and in connection with the investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the S.D. Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020.

On July 21, 2021, FE entered into a three-year DPA with the U.S. Attorney’s Office that, subject to court proceedings, resolves the U.S. Attorney’s Office investigation into FirstEnergy relating to FirstEnergy’s lobbying and governmental affairs activities concerning HB 6, which, among other things required FE to pay a monetary penalty of $230 million, which FE paid in the third quarter of 2021. Under the DPA, FE agreed to the filing of a criminal information charging FE with one count of conspiracy to commit honest services wire fraud. 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. Under the terms of the DPA, the criminal information will be dismissed after FirstEnergy fully complies with its obligations under the DPA.

In addition to the subpoenas referenced above, the OAG, certain FE shareholders and FE customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, each relating to the allegations against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. On February 9, 2022, FE, acting through the SLC, agreed to a settlement term sheet to resolve multiple shareholder derivative lawsuits that were filed in the S.D. Ohio, the N.D. Ohio, and the Ohio Court of Common Pleas, Summit County. The proposed settlement, which is subject to court approval, will fully resolve these shareholder derivative lawsuits and includes a series of corporate governance enhancements, that is expected to result in the following:

•Six members of the FE Board, Messrs. Michael J. Anderson, Donald T. Misheff, Thomas N. Mitchell, Christopher D. Pappas and Luis A. Reyes, and Ms. Julia L. 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; and

•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 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. Subsequently, on April 28, 2021, the SEC issued an additional subpoena to FE. Further, in letters dated January 26, and February 22, 2021, staff of FERC's Division of Investigations notified FirstEnergy that it is investigating FirstEnergy’s lobbying and governmental affairs activities concerning HB 6.

A committee of independent members of the FE Board was put in place to direct an internal investigation related to the ongoing government investigations. In addition, the FE Board formed a sub-committee of the Audit Committee to, together with the FE Board, assess FirstEnergy’s compliance program and implement potential changes, as appropriate. FirstEnergy has taken numerous steps to address challenges posed by the HB 6 investigations and improve its compliance culture, including the termination and separation of certain senior executives, including FirstEnergy’s former Chief Executive Officer, for violations of certain FirstEnergy policies and its code of business conduct, appointment of five new, independent directors to the FE Board in 2021, the hiring of key senior executives committed to supporting transparency and integrity, and strengthening and enhancing FirstEnergy’s compliance culture through the following initiatives:

•In March 2021, certain members of the FE Board met with FirstEnergy’s top 140 leaders to discuss expectations regarding compliance and ethics.

•Performed training on up-the-ladder reporting for the FirstEnergy Legal Department in March 2021.

•In July 2021, enhanced new employee and third-party on-boarding processes to include expectations of FirstEnergy’s code of conduct.

•On July 20, 2021, the FE Board approved and adopted a new Code of Business Conduct, which:

◦Promotes and emphasizes FirstEnergy’s commitment to compliance and ethics;

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◦Establishes a “speak up” culture in which stakeholders are encouraged to report actual or suspected Code of Business Conduct violations without fear of retaliation;

◦Conforms to applicable compliance standards; and

◦Improves readability.

•FirstEnergy completed additional steps toward enhancing the overall compliance program, including:

◦Completion of the Office of Ethics & Compliance charter;

◦Delivered a Chief Ethics & Compliance Officer-led Code Awareness training to senior leaders and individuals with significant roles in FirstEnergy’s control environment;

◦Conducted leader-led training on the Code of Business Conduct for all leaders;

◦Published an Ethics & Compliance Communication Plan; and

◦Selected and began implementation planning for a Governance, Risk and Compliance tool.

Although the outcome of the HB 6 investigations and state regulatory audits remain unknown, FirstEnergy took several proactive steps to reduce regulatory uncertainty affecting the Ohio Companies:

•On January 31, 2021, FirstEnergy reached a partial settlement with the OAG and other parties regarding decoupling. While the partial settlement with the OAG focused specifically on decoupling, the Ohio Companies elected to forego recovery of lost distribution revenue.

•On March 31, 2021, FirstEnergy announced that the Ohio Companies would refund to customers amounts previously collected under the decoupling mechanism, with interest, which totals approximately $27 million. On July 7, 2021, the PUCO approved the Ohio Companies’ proposal, and the amounts previously collected were refunded to customers in August 2021.

•Also 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 electric utilities, and provided for the ending of current energy efficiency program mandates.

•On November 1, 2021, the Ohio Companies, together with the OCC, PUCO Staff, and several other signatories, entered into a unanimous Stipulation and Recommendation (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 on December 1, 2021, and refunds began in January 2022.

Despite the many disruptions FirstEnergy is currently facing, the leadership team remains committed and focused on executing its strategy and running the business. See “Outlook - Other Legal Proceedings” below for additional details on the government investigations, the DPA, and subsequent litigation surrounding the investigation of HB 6. See also “Outlook - State Regulation - Ohio” below for details on the PUCO proceeding reviewing political and charitable spending and legislative activity in response to the investigation of HB 6. The outcome of the government investigations, PUCO proceedings, legislative activity, and any of these lawsuits is uncertain and could have a material adverse effect on FirstEnergy’s financial condition, results of operations and cash flows.

The Form 10-K discusses 2021 and 2020 items and year-over-year comparisons between 2021 and 2020. Discussions of 2019 items and year-over-year comparisons between 2020 and 2019 that are not included in this Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of FirstEnergy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020, filed with the SEC on February 10, 2021.

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RESULTS OF OPERATIONS

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

Net income by business segment was as follows:

[[GREPCENT_TABLE]]
[["(In millions, except per share amounts)","","For the Years Ended December 31,","","Increase (Decrease)"],["","","2021","","2020","","2019","","2021 vs 2020","","2020 vs 2019"],["Net Income By Business Segment:"],["Regulated Distribution","","$","1,288","","","$","959","","","$","1,076","","","$","329","","","","","$","(117)"],["Regulated Transmission","","408","","","464","","","447","","","(56)","","","","","17"],["Corporate/Other","","(457)","","","(420)","","","(619)","","","(37)","","","","","199"],["Income from Continuing Operations","","$","1,239","","","$","1,003","","","$","904","","","$","236","","","","","$","99"],["Discontinued Operations","","44","","","76","","","8","","","(32)","","","","","68"],["Net Income","","$","1,283","","","$","1,079","","","$","912","","","$","204","","","18.9","%","","$","167","","","18.3","%"],["Earnings per share of common stock"],["Basic - Continuing Operations","","$","2.27","","","$","1.85","","","$","1.69","","","$","0.42","","","","","$","0.16"],["Basic - Discontinued Operations","","0.08","","","0.14","","","0.01","","","(0.06)","","","","","0.13"],["Basic - Net Income Attributable to","","$","2.35","","","$","1.99","","","$","1.70","","","$","0.36","","","","","$","0.29"],["Common Stockholders","","","","","","18.1","%","","","17.1","%"],["Earnings per share of common stock"],["Diluted - Continuing Operations","","$","2.27","","","$","1.85","","","$","1.67","","","$","0.42","","","","","$","0.18"],["Diluted - Discontinued Operations","","0.08","","","0.14","","","0.01","","","(0.06)","","","","","0.13"],["Diluted - Net Income Attributable to","","$","2.35","","","$","1.99","","","$","1.68","","","$","0.36","","","","","$","0.31"],["Common Stockholders","","","","","","18.1","%","","","18.5","%"]]
[[/GREPCENT_TABLE]]

32

Summary of Results of Operations — 2021 Compared with 2020

Financial results for FirstEnergy’s business segments for the years ended December 31, 2021 and 2020, were as follows:

[[GREPCENT_TABLE]]
[["2021 Financial Results","","Regulated Distribution","","Regulated Transmission","","","","Corporate/Other and Reconciling Adjustments","","","","FirstEnergy Consolidated"],["","","(In millions)"],["Revenues:"],["Electric","","$","9,498","","","$","1,608","","","","","$","(140)","","","","","$","10,966"],["Other","","213","","","10","","","","","(57)","","","","","166"],["Total Revenues","","9,711","","","1,618","","","","","(197)","","","","","11,132"],["Operating Expenses:"],["Fuel","","481","","","\u2014","","","","","\u2014","","","","","481"],["Purchased power","","2,947","","","\u2014","","","","","17","","","","","2,964"],["Other operating expenses","","2,967","","","358","","","","","(129)","","","","","3,196"],["Provision for depreciation","","911","","","325","","","","","66","","","","","1,302"],["Amortization of regulatory assets, net","","260","","","9","","","","","\u2014","","","","","269"],["General taxes","","789","","","248","","","","","36","","","","","1,073"],["DPA penalty","","\u2014","","","\u2014","","","","","230","","","","","230"],["Gain on sale of Yards Creek","","(109)","","","\u2014","","","","","\u2014","","","","","(109)"],["Total Operating Expenses","","8,246","","","940","","","","","220","","","","","9,406"],["Operating Income (Loss)","","1,465","","","678","","","","","(417)","","","","","1,726"],["Other Income (Expense):"],["Miscellaneous income, net","","399","","","41","","","","","77","","","","","517"],["Pension and OPEB mark-to-market adjustment","","270","","","31","","","","","81","","","","","382"],["Interest expense","","(523)","","","(248)","","","","","(370)","","","","","(1,141)"],["Capitalized financing costs","","41","","","33","","","","","1","","","","","75"],["Total Other Expense","","187","","","(143)","","","","","(211)","","","","","(167)"],["Income (Loss) Before Income Taxes (Benefits)","","1,652","","","535","","","","","(628)","","","","","1,559"],["Income taxes (benefits)","","364","","","127","","","","","(171)","","","","","320"],["Income (Loss) From Continuing Operations","","1,288","","","408","","","","","(457)","","","","","1,239"],["Discontinued Operations, net of tax","","\u2014","","","\u2014","","","","","44","","","","","44"],["Net Income (Loss)","","$","1,288","","","$","408","","","","","$","(413)","","","","","$","1,283"]]
[[/GREPCENT_TABLE]]

33

[[GREPCENT_TABLE]]
[["2020 Financial Results","","Regulated Distribution","","Regulated Transmission","","","","Corporate/Other and Reconciling Adjustments","","","","FirstEnergy Consolidated"],["","","(In millions)"],["Revenues:"],["Electric","","$","9,130","","","$","1,613","","","","","$","(139)","","","","","$","10,604"],["Other","","233","","","17","","","","","(64)","","","","","186"],["Total Revenues","","9,363","","","1,630","","","","","(203)","","","","","10,790"],["Operating Expenses:"],["Fuel","","369","","","\u2014","","","","","\u2014","","","","","369"],["Purchased power","","2,687","","","\u2014","","","","","14","","","","","2,701"],["Other operating expenses","","3,178","","","282","","","","","(169)","","","","","3,291"],["Provision for depreciation","","896","","","313","","","","","65","","","","","1,274"],["Amortization (deferral) of regulatory assets, net","","(64)","","","11","","","","","\u2014","","","","","(53)"],["General taxes","","770","","","232","","","","","44","","","","","1,046"],["Total Operating Expenses","","7,836","","","838","","","","","(46)","","","","","8,628"],["Operating Income (Loss)","","1,527","","","792","","","","","(157)","","","","","2,162"],["Other Income (Expense):"],["Miscellaneous income, net","","332","","","30","","","","","70","","","","","432"],["Pension and OPEB mark-to-market adjustment","","(323)","","","(40)","","","","","(114)","","","","","(477)"],["Interest expense","","(501)","","","(219)","","","","","(345)","","","","","(1,065)"],["Capitalized financing costs","","37","","","39","","","","","1","","","","","77"],["Total Other Expense","","(455)","","","(190)","","","","","(388)","","","","","(1,033)"],["Income (Loss) Before Income Taxes (Benefits)","","1,072","","","602","","","","","(545)","","","","","1,129"],["Income taxes (benefits)","","113","","","138","","","","","(125)","","","","","126"],["Income (Loss) From Continuing Operations","","959","","","464","","","","","(420)","","","","","1,003"],["Discontinued Operations, net of tax","","\u2014","","","\u2014","","","","","76","","","","","76"],["Net Income (Loss)","","$","959","","","$","464","","","","","$","(344)","","","","","$","1,079"]]
[[/GREPCENT_TABLE]]

34

[[GREPCENT_TABLE]]
[["Changes Between 2021 and Financial Results Increase (Decrease)","","Regulated Distribution","","Regulated Transmission","","","","Corporate/Other and Reconciling Adjustments","","","","FirstEnergy Consolidated"],["","","(In millions)"],["Revenues:"],["Electric","","$","368","","","$","(5)","","","","","$","(1)","","","","","$","362"],["Other","","(20)","","","(7)","","","","","7","","","","","(20)"],["Total Revenues","","348","","","(12)","","","","","6","","","","","342"],["Operating Expenses:"],["Fuel","","112","","","\u2014","","","","","\u2014","","","","","112"],["Purchased power","","260","","","\u2014","","","","","3","","","","","263"],["Other operating expenses","","(211)","","","76","","","","","40","","","","","(95)"],["Provision for depreciation","","15","","","12","","","","","1","","","","","28"],["Amortization (deferral) of regulatory assets, net","","324","","","(2)","","","","","\u2014","","","","","322"],["General taxes","","19","","","16","","","","","(8)","","","","","27"],["DPA penalty","","\u2014","","","\u2014","","","","","230","","","","","230"],["Gain on sale of Yards Creek","","(109)","","","\u2014","","","","","\u2014","","","","","(109)"],["Total Operating Expenses","","410","","","102","","","","","266","","","","","778"],["Operating Income (Loss)","","(62)","","","(114)","","","","","(260)","","","","","(436)"],["Other Income (Expense):"],["Miscellaneous income, net","","67","","","11","","","","","7","","","","","85"],["Pension and OPEB mark-to-market adjustment","","593","","","71","","","","","195","","","","","859"],["Interest expense","","(22)","","","(29)","","","","","(25)","","","","","(76)"],["Capitalized financing costs","","4","","","(6)","","","","","\u2014","","","","","(2)"],["Total Other Expense","","642","","","47","","","","","177","","","","","866"],["Income (Loss) Before Income Taxes (Benefits)","","580","","","(67)","","","","","(83)","","","","","430"],["Income taxes (benefits)","","251","","","(11)","","","","","(46)","","","","","194"],["Income (Loss) From Continuing Operations","","329","","","(56)","","","","","(37)","","","","","236"],["Discontinued Operations, net of tax","","\u2014","","","\u2014","","","","","(32)","","","","","(32)"],["Net Income (Loss)","","$","329","","","$","(56)","","","","","$","(69)","","","","","$","204"]]
[[/GREPCENT_TABLE]]

35

Regulated Distribution — 2021 Compared with 2020

Regulated Distribution's net income increased $329 million in 2021, as compared to 2020, primarily resulting from the change in pension and OPEB mark-to-market adjustments, higher customer demand, earnings benefits from capital investment-related riders in Ohio and Pennsylvania and the implementation of the base distribution rate case in New Jersey, lower pension and OPEB expenses and a reduction to a reserve previously recorded in 2010, partially offset by the refund and absence of Ohio decoupling revenues, customer refunds associated with the PUCO-approved Ohio Stipulation, establishment of a regulatory liability to return certain additional Tax Act savings to Pennsylvania customers, higher interest expense, and the absence of deferred gain tax benefits recognized in 2020 that were triggered by the FES Debtors’ emergence from bankruptcy.

Revenues —

The $348 million increase in total revenues resulted from the following sources:

[[GREPCENT_TABLE]]
[["","","For the Years Ended December 31,"],["Revenues by Type of Service","","2021","","2020","","Increase (Decrease)"],["","","(In millions)"],["Distribution services (1)","","$","5,406","","","$","5,302","","","$","104"],["Generation sales:"],["Retail","","3,730","","","3,577","","","153"],["Wholesale","","362","","","251","","","111"],["Total generation sales","","4,092","","","3,828","","","264"],["Other","","213","","","233","","","(20)"],["Total Revenues","","$","9,711","","","$","9,363","","","$","348"]]
[[/GREPCENT_TABLE]]

(1) Includes $(27) million and $43 million of ARP revenues for the years ended December 31, 2021 and 2020. Amounts for 2021 reflect amounts the Ohio Companies refunded to customers that was previously collected under decoupling mechanisms, with interest. See “Outlook,” below for further discussion on Ohio decoupling rates.

Distribution services revenues increased $104 million in 2021, as compared to 2020, primarily resulting from higher customer demand and higher rates associated with riders in Ohio and Pennsylvania including the recovery of capital investment programs and transmission expenses, partially offset by the refund and absence of Ohio decoupling revenues, the elimination of energy efficiency mandates and energy efficiency programs in Ohio, customer refunds associated with the Ohio Stipulation, and the expiration of a NUG contract. Distribution services' electric distribution deliveries by customer class are summarized in the following table:

[[GREPCENT_TABLE]]
[["","","For the Years Ended December 31,"],["(In thousands)","","Actual","","Weather-Adjusted and Leap Year-Adjusted"],["Electric Distribution MWH Deliveries","","2021","","2020","","Increase","","2021","","2020","","Increase (Decrease)"],["Residential","","55,624","","","54,978","","","1.2","%","","55,678","","","56,142","","","(0.8)","%"],["Commercial(1)","","35,599","","","34,811","","","2.3","%","","35,744","","","35,213","","","1.5","%"],["Industrial","","54,027","","","52,034","","","3.8","%","","54,027","","","51,981","","","3.9","%"],["Total Electric Distribution MWH Deliveries","","145,250","","","141,823","","","2.4","%","","145,449","","","143,336","","","1.5","%"]]
[[/GREPCENT_TABLE]]

(1) Includes street lighting.

Distribution deliveries to residential, commercial and industrial customers reflects the cancellation of the state mandated COVID-19 stay-at-home orders and a trend in customer usage back to pre-COVID-19 levels. Residential and commercial deliveries were also impacted by higher weather-related customer usage. Cooling degree days were 4% above 2020 and 17% above normal, while heating degree days were flat to 2020 and 9% below normal. Increases in industrial deliveries were primarily from the steel, manufacturing, and educational sectors.

36

The following table summarizes weather-adjusted distribution services' electric distribution deliveries compared to pre-pandemic levels in 2019:

[[GREPCENT_TABLE]]
[["","","For the Years Ended December 31,"],["(In thousands)","","Weather-Adjusted"],["Electric Distribution MWH Deliveries","","2021","","2019","","Increase (Decrease)"],["Residential","","55,678","","","53,613","","","3.9","%"],["Commercial(1)","","35,744","","","37,720","","","(5.2)","%"],["Industrial","","54,027","","","55,647","","","(2.9)","%"],["Total Electric Distribution MWH Deliveries","","145,449","","","146,980","","","(1.0)","%"]]
[[/GREPCENT_TABLE]]

The following table summarizes the price and volume factors contributing to the $264 million increase in generation revenues in 2021, as compared to 2020:

[[GREPCENT_TABLE]]
[["Source of Change in Generation Revenues","","Increase"],["","","(In millions)"],["Retail:"],["Change in sales volumes","","$","124"],["Change in prices","","29"],["","","153"],["Wholesale:"],["Change in sales volumes","","5"],["Change in prices","","77"],["Capacity revenue","","29"],["","","111"],["Change in Generation Revenues","","$","264"]]
[[/GREPCENT_TABLE]]

The increase in retail generation sales volumes was primarily due to higher weather-related usage and decreased customer shopping in New Jersey and Pennsylvania. Total generation provided by alternative suppliers as a percentage of total MWH deliveries in 2021, as compared to 2020, decreased to 46% from 47% in New Jersey and to 63% from 64% in Pennsylvania. The increase in retail generation prices primarily resulted from higher non-shopping generation auction rates in Pennsylvania and New Jersey, partially offset by a lower ENEC rate in West Virginia.

Wholesale generation revenues increased $111 million in 2021, as compared to 2020, primarily due to an increase in spot market energy prices and higher capacity revenues. The difference between current wholesale generation revenues and certain energy costs incurred are deferred for future recovery or refund, with no material impact to earnings.

Other revenues decreased $20 million in 2021, as compared to 2020, primarily due to lower pole attachment revenue and the lower recovery of refinancing costs associated with the Ohio PIR. Costs associated with the Ohio PIR are deferred for future recovery resulting in no material impact on earnings.

Operating Expenses —

Total operating expenses increased $410 million primarily due to the following:

•Fuel expense increased $112 million in 2021, as compared to 2020, primarily due to higher unit costs and increased generation output. Due to the ENEC, fuel expense has no material impact on current earnings.

•Purchased power costs increased $260 million in 2021, as compared to 2020, primarily due to increased volumes as described above, higher unit costs and increased capacity expenses, partially offset by the expiration of a NUG contract.

37

[[GREPCENT_TABLE]]
[["Source of Change in Purchased Power","","Increase"],["","","(In millions)"],["Purchases"],["Change due to unit costs","","$","42"],["Change due to volumes","","109"],["","","151"],["Capacity expense","","109"],["Change in Purchased Power Costs","","$","260"]]
[[/GREPCENT_TABLE]]

•Other operating expenses decreased $211 million in 2021, as compared to 2020, primarily due to:

•Lower storm restoration costs of $184 million, which were mostly deferred for future recovery, resulting in no material impact on earnings.

•Lower uncollectible expense of $123 million, of which $93 million was deferred for future recovery.

•Lower West Virginia vegetation management spend and energy efficiency program costs of $50 million, which are deferred for future recovery, resulting in no material impact on earnings.

•Lower COVID-19 related expenses of $42 million, of which $12 million was deferred for future recovery.

•Lower expense due to a $27 million reduction to a reserve previously recorded in 2010.

•Higher network transmission expenses of $130 million, which are deferred for future recovery, resulting in no material impact on earnings.

•Higher operating and maintenance expenses in 2021 due to $25 million in incremental strategic spend incurred to enhance customer reliability.

•Higher vegetation management expenses of $26 million in Ohio and Pennsylvania.

•Higher other operating and maintenance expenses of $34 million, primarily due to higher labor costs and lower capital work as compared to 2020, partially offset by fewer planned outages at the regulated generation facilities.

•Depreciation expense increased $15 million in 2021, as compared to 2020, primarily due to a higher asset base, partially offset by a reduction in accretion expense as a result of the TMI-2 transfer, which has no impact to earnings.

•Net amortization of regulatory assets increased $324 million in 2021, as compared to 2020, primarily due to:

•The $109 million reduction of the New Jersey deferred storm cost regulatory asset as a result of the Yards Creek sale,

•Lower deferrals of storm restoration of $174 million,

•Lower uncollectible and COVID-19 related costs of $139 million,

•A $96 million charge for customer refunds associated with the Ohio Stipulation,

•A $61 million charge to establish a regulatory liability to return certain Tax Act savings to Pennsylvania customers,

•A $37 million decrease in deferral of accretion expense as a result of the TMI-2 transfer, partially offset by

•$83 million amortization of a regulatory liability as part of the New Jersey base rate case implementation in 2021,

•$61 million in higher generation-related and transmission-related deferrals,

•$76 million in lower Pennsylvania smart meter amortization, and

•$72 million related to lower other amortization.

•General taxes increased $19 million in 2021, as compared to 2020, primarily due to higher Ohio property and sales-related taxes.

•Gain on sale of the Yards Creek Generating Facility of $109 million was netted against the New Jersey storm deferral, as described above, resulting in no impact to earnings.

Other Expense —

Other expense decreased $642 million in 2021, as compared to 2020, primarily due to a $593 million change in pension and OPEB mark-to-market adjustments and higher net miscellaneous income resulting from lower pension and OPEB non-service costs, partially offset by higher interest expense from increased short-term borrowings under the former FE Revolving Facility and long-term debt issuances since 2020.

38

Income Taxes

Regulated Distribution’s effective tax rate was 22.0% and 10.5% for 2021 and 2020, respectively. The change in the effective tax rate was primarily due to the recognition of $52 million in deferred gains relating to prior intercompany transfers of generation assets that were triggered by the deconsolidation of the FES Debtors from FirstEnergy’s consolidated federal income tax group as a result of their emergence from bankruptcy in the first quarter of 2020.

Regulated Transmission — 2021 Compared with 2020

Regulated Transmission's net income decreased $56 million in 2021, as compared to 2020, primarily due to a charge resulting from the filed ATSI settlement, higher interest expense associated with new debt issuances at FET, increased borrowings under the former FET Revolving Facility, formula rate true-up adjustments and lower rate base at TrAIL, partially offset by the impact of a higher rate base at ATSI and MAIT.

Revenues —

Total revenues decreased $12 million in 2021, as compared to 2020, primarily due to lower pension and OPEB expense recovery and lower rate base at TrAIL, partially offset by the recovery of incremental operating expenses and a higher rate base at ATSI and MAIT.

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

[[GREPCENT_TABLE]]
[["","","For the Years Ended December 31,"],["Revenues by Transmission Asset Owner","","2021","","2020","","Increase (Decrease)"],["","","(In millions)"],["ATSI","","$","801","","","$","809","","","$","(8)"],["TrAIL","","240","","","255","","","(15)"],["MAIT","","289","","","254","","","35"],["JCP&L","","164","","","178","","","(14)"],["MP, PE and WP","","124","","","134","","","(10)"],["Total Revenues","","$","1,618","","","$","1,630","","","$","(12)"]]
[[/GREPCENT_TABLE]]

Operating Expenses —

Total operating expenses increased $102 million in 2021, as compared to 2020, primarily due to a non-recoverable charge resulting from the filed ATSI settlement, higher operation and maintenance costs and increased property taxes and depreciation due to a higher asset base. Nearly all operating expenses are recovered through formula rates, resulting in no material impact on current period earnings.

Other Expense —

Total other expense decreased $47 million in 2021, as compared to 2020, primarily due to a $71 million change in pension and OPEB mark-to-market adjustment, partially offset by higher interest expense associated with new debt issuances at FET and increased borrowings under the former FET Revolving Facility.

Income Taxes —

Regulated Transmission’s effective tax rate was 23.7% and 22.9% for 2021 and 2020, respectively.

Corporate/Other — 2021 Compared with 2020

Financial results from Corporate/Other and reconciling adjustments resulted in a $69 million increase in net loss for 2021 compared to 2020, primarily due to the $230 million DPA monetary penalty, higher interest expense from a higher rate on certain FE holding company debt, higher investigation and other related costs, including a litigation reserve, lower tax benefits from the remeasurement of West Virginia deferred income taxes resulting from a state tax law change passed in 2021, the absence of tax benefits from accelerated amortization of certain investment tax credits recognized in 2020 and a lower gain from discontinued operations, partially offset by a $195 million change in the pension and OPEB mark-to-market adjustment, higher returns on investments and higher other discrete income tax benefits.

39

For the year ended December 31, 2021, FirstEnergy recorded a gain from discontinued operations, net of tax, of $44 million. The gain was primarily due to income tax benefits from the final true-up to the worthless stock deduction and a final federal NOL allocation between the FES Debtors and FirstEnergy resulting from the filing of the 2020 FirstEnergy federal income tax return during 2021.

REGULATORY ASSETS AND LIABILITIES

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

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

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

[[GREPCENT_TABLE]]
[["","","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)","","","$","24"],["Spent nuclear fuel disposal costs","","(101)","","","(102)","","","1"],["Asset removal costs","","(646)","","","(721)","","","75"],["Deferred transmission costs","","(3)","","","319","","","(322)"],["Deferred generation costs","","118","","","17","","","101"],["Deferred distribution costs","","49","","","79","","","(30)"],["Contract valuations","","7","","","41","","","(34)"],["Storm-related costs","","660","","","748","","","(88)"],["Uncollectible and COVID-19 related costs","","56","","","97","","","(41)"],["Energy efficiency program costs","","47","","","42","","","5"],["New Jersey societal benefit costs","","109","","","112","","","(3)"],["Regulatory transition costs","","(18)","","","(20)","","","2"],["Vegetation management","","33","","","22","","","11"],["Other","","(19)","","","(9)","","","(10)"],["Net Regulatory Liabilities included on the Consolidated Balance Sheets","","$","(2,053)","","","$","(1,744)","","","$","(309)"]]
[[/GREPCENT_TABLE]]

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

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

Spent nuclear fuel disposal costs - Reflects amounts collected from customers, and the investment income, losses and changes in fair value of the trusts for spent nuclear fuel disposal costs related to former nuclear generating facilities, Oyster Creek and TMI-1.

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

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

40

Deferred generation costs - Primarily relates to regulatory assets associated with the securitized recovery of certain fuel and purchased power regulatory assets at the Ohio Companies (amortized through 2034) as well as the ENEC at MP and PE. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. The ENEC rate is updated annually.

Deferred distribution costs - Primarily relates to the Ohio Companies' deferral of certain expenses resulting from distribution and reliability related expenditures, including interest (amortized through 2036) in subsequent periods as well as refunds owed to customers associated with the PUCO-approved Ohio Stipulation discussed below.

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

Storm-related costs - Relates to the deferral of storm costs, which vary by jurisdiction. Approximately $148 million and $167 million are currently being recovered through rates as of December 31, 2021 and 2020, respectively.

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

Energy efficiency program costs - Relates to the recovery of costs in excess of revenues associated with energy efficiency programs including, New Jersey energy efficiency and renewable energy programs, the Pennsylvania Companies' EE&C programs, the Ohio Companies' Demand Side Management and Energy Efficiency Rider, and PE's EmPOWER Maryland Surcharge. Investments in certain of these energy efficiency programs earn a long-term return.

New Jersey societal benefit costs - Primarily relates to regulatory assets associated with MGP remediation, universal service and lifeline funds, and consumer education in New Jersey.

Regulatory transition costs - Includes the recovery of PN above-market NUG costs; and JCP&L costs associated with BGS, capacity and ancillary services, net of revenues from the sale of the committed supply in the wholesale market.

Vegetation management - Relates to regulatory assets in New Jersey and West Virginia associated with the recovery of certain distribution vegetation management costs as well as MAIT vegetation management costs (amortized through 2024).

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:

[[GREPCENT_TABLE]]
[["Regulatory Assets by Source Not Earning a","","As of December 31,"],["Current Return","","2021","","2020","","Change"],["","","","","(in millions)"],["Deferred transmission costs","","$","13","","","$","17","","","$","(4)"],["Deferred generation costs","","50","","","5","","","45"],["Storm-related costs","","549","","","654","","","(105)"],["COVID-19 related costs","","65","","","66","","","(1)"],["Regulatory transition costs","","13","","","16","","","(3)"],["Vegetation management","","31","","","22","","","9"],["Other","","11","","","9","","","2"],["Regulatory Assets Not Earning a Current Return","","$","732","","","$","789","","","$","(57)"]]
[[/GREPCENT_TABLE]]

CAPITAL RESOURCES AND LIQUIDITY

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

FE and its distribution and transmission subsidiaries expect their existing sources of liquidity to remain sufficient to meet their respective anticipated obligations. In addition to internal sources to fund liquidity and capital requirements for 2022 and beyond, FE and its distribution and transmission subsidiaries expect to rely on external sources of funds. Short-term cash requirements

41

not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through the issuance of long-term debt by FE and certain of its distribution and transmission subsidiaries to, among other things, fund capital expenditures and other capital-like investments, and refinance short-term and maturing long-term debt, subject to market conditions and other factors.

Investments for 2021 and forecasts for 2022, 2023, 2024, and 2025 by business segment are included below:

[[GREPCENT_TABLE]]
[["Business Segment","","","","2021 Actual","","2022 Forecast","","2023 Forecast (2)","","2024 Forecast (2)","","2025 Forecast (2)"],["","","","(In millions)"],["Regulated Distribution (1)","","","","$","1,733","","","$","1,780","","","$","1,725","","","$","1,775","","","$","1,825"],["Regulated Transmission","","","","1,055","","","1,500","","","1,600","","","1,700","","","1,750"],["Corporate/Other","","","","86","","","70","","","50","","","50","","","50"],["Total","","","","$","2,874","","","$","3,350","","","$","3,375","","","$","3,525","","","$","3,625"],["(1) Includes capital expenditures and capital-like investments that earn a return."],["(2) FirstEnergy expects to update the forecast over the period for items such as regulatory filings and approvals and other changes."]]
[[/GREPCENT_TABLE]]

In alignment with FirstEnergy’s strategy to invest in its Regulated Distribution and Regulated Transmission segments as a fully regulated company, FirstEnergy is focused on maintaining balance sheet strength and flexibility. Specifically, at the regulated businesses, regulatory authority has been obtained for various regulated distribution and transmission subsidiaries to issue and/or refinance debt.

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

On November 6, 2021, FirstEnergy, along with FET, entered into the FET P&SA with Brookfield and the 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 and is expected to close in the second quarter of 2022.

On December 13, 2021, FE privately issued to BIP Securities II-B L.P., an affiliate of Blackstone Infrastructure Partners L.P., 25,588,535 shares of FE’s common stock, par value $0.10 per share, at a price of $39.08 per share, representing an investment of $1.0 billion. In addition, subject to certain regulatory approvals, FE will appoint a Blackstone Infrastructure Partners-selected representative to the FE Board no later than the 2022 annual shareholders’ meeting.

On October 18, 2021, FE, FET, the Utilities, and the Transmission Companies entered into six separate senior unsecured five-year syndicated revolving credit 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. See “Capital Resources and Liquidity" below for additional details.

Together, these transactions enhance FirstEnergy's credit profile, provide funding for the strategic investments discussed above, and address all of FirstEnergy's equity plans, with the exception of annual issuances of up to $100 million under regular dividend reinvestment plans and employee benefit stock investment plans, through at least 2025.

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, 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,

42

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. 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.

As of December 31, 2021, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was primarily due to accounts payable, current portion of long-term debt and accrued interest, taxes, and compensation and benefits. FirstEnergy believes its cash from operations and available liquidity will be sufficient to meet its current working capital needs.

Short-Term Borrowings / Revolving Credit Facilities

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; and

•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.

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 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.

FirstEnergy’s 2021 Credit Facilities bear interest at fluctuating interest rates, primarily based on LIBOR. LIBOR tends to fluctuate based on general interest rates, rates set by the U.S. Federal Reserve and other central banks, the supply of and demand for credit in the London interbank market and general economic conditions. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on LIBOR and other variable interest rates. On July 27, 2017, the FCA (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. Subsequently, on March 5, 2021, IBA (the entity that calculates and publishes LIBOR) and FCA made public statements regarding the future cessation of LIBOR. According to the FCA, IBA will permanently cease to publish each of the LIBOR settings on either December 31, 2021 or June 30, 2023. IBA did not identify any successor administrator in its announcement. The announced final publication date for 1-week and 2-month LIBOR settings and all settings for non-USD LIBOR was December 31, 2021. The announced final publication date for overnight, 1-month, 3-month, 6-month and 12-month LIBOR settings is June 30, 2023. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after such end dates, and there is considerable uncertainty regarding the publication or representativeness of LIBOR beyond such end dates. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is seeking to replace U.S. dollar LIBOR with a newly created index, SOFR, calculated based on repurchase agreements backed by treasury securities. FirstEnergy’s 2021 Credit Facilities provide a mechanism to automatically transition to a SOFR-based benchmark when all United States dollar LIBOR settings are no longer provided or are no longer representative. In addition, FirstEnergy’s 2021 Credit Facilities provide an option for the applicable borrower and lender to jointly elect to transition early to a SOFR-based benchmark, or in certain circumstances, an alternative benchmark replacement. It is not possible to predict the effect of these changes, other reforms or the establishment of alternative reference rates in the United Kingdom, the United States or elsewhere. To the extent these interest rates increase, interest expense will increase. If sources of capital for us are reduced, capital costs could increase materially. Restricted access to capital markets and/or increased borrowing costs could have an adverse effect on FirstEnergy’s results of operations, cash flows, financial condition and liquidity.

43

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. FirstEnergy’s available liquidity from external sources as of February 14, 2022, was as follows:

[[GREPCENT_TABLE]]
[["Revolving Credit Facilities","","Maturity","","Commitment","","Available Liquidity"],["","","","","(In millions)"],["FE and FET","","October 2026","","$","1,000","","","$","997"],["Ohio Companies","","October 2026","","800","","","800"],["Pennsylvania Companies","","October 2026","","950","","","950"],["JCP&L","","October 2026","","500","","","499"],["MP and PE","","October 2026","","400","","","400"],["Transmission Companies","","October 2026","","850","","","850"],["","","Subtotal","","$","4,500","","","$","4,496"],["Cash and Cash equivalents","","\u2014","","","579"],["","","Total","","$","4,500","","","$","5,075"]]
[[/GREPCENT_TABLE]]

The following table summarizes the limitations of each individual entity on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of December 31, 2021:

[[GREPCENT_TABLE]]
[["Individual Borrower","","Regulatory and Other Short-Term Debt Limitations"],["","","(In millions)"],["FE and FET","","N/A"],["OE, CEI, JCP&L, ME, MP, and ATSI","","$","500","","(1)"],["TE and PN","","300","","(1)"],["WP","","200","","(1)"],["PE","","150","","(1)"],["Penn","","100","","(1)"],["TrAIL and MAIT","","400","","(1)"]]
[[/GREPCENT_TABLE]]

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

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.

[[GREPCENT_TABLE]]
[["Revolving Credit Facility","","LOC Availability"],["(In millions)"],["FE and FET","","$","100"],["Ohio Companies","","150"],["Pennsylvania Companies","","200"],["JCP&L","","100"],["MP and PE","","100"],["Transmission Companies","","200"]]
[[/GREPCENT_TABLE]]

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.

44

FirstEnergy Money Pools

FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and FE to meet their short-term working capital requirements. Similar but separate arrangements exist among FirstEnergy’s unregulated companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries. FESC administers these money pools and tracks surplus funds of FE and the respective regulated and unregulated subsidiaries, as the case may be, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2021 was 1.01% per annum for the regulated companies’ money pool and 0.60% per annum for the unregulated companies’ money pool.

Long-Term Debt Capacity

FE's and its subsidiaries' access to capital markets and costs of financing are influenced by the credit ratings of their securities. The following table displays FE’s and its subsidiaries’ credit ratings as of February 14, 2022:

[[GREPCENT_TABLE]]
[["","","Corporate Credit Rating","","Senior Secured","","Senior Unsecured","","Outlook/CreditWatch (1)"],["Issuer","","S&P","","Moody\u2019s","","Fitch","","S&P","","Moody\u2019s","","Fitch","","S&P","","Moody\u2019s","","Fitch","","S&P","","Moody\u2019s","","Fitch"],["FE","","BBB-","","Ba1","","BB+","","\u2014","","\u2014","","\u2014","","BB+","","Ba1","","BB+","","S","","P","","P"],["AGC","","BB+","","Baa2","","BBB-","","\u2014","","\u2014","","\u2014","","\u2014","","\u2014","","\u2014","","S","","S","","P"],["ATSI","","BBB","","A3","","BBB-","","\u2014","","\u2014","","\u2014","","BBB","","A3","","BBB","","S","","S","","P"],["CEI","","BBB","","Baa2","","BBB-","","A-","","A3","","BBB+","","BBB","","Baa2","","BBB","","S","","N","","P"],["FET","","BBB-","","Baa2","","BB+","","\u2014","","\u2014","","\u2014","","BB+","","Baa2","","BB+","","S","","S","","P"],["JCP&L","","BBB","","A3","","BBB-","","\u2014","","\u2014","","\u2014","","BBB","","A3","","BBB","","S","","S","","P"],["ME","","BBB","","A3","","BBB-","","\u2014","","\u2014","","\u2014","","BBB","","A3","","BBB","","S","","S","","P"],["MAIT","","BBB","","A3","","BBB-","","\u2014","","\u2014","","\u2014","","BBB","","A3","","BBB","","S","","S","","P"],["MP","","BBB","","Baa2","","BBB-","","A-","","A3","","BBB+","","BBB","","Baa2","","\u2014","","S","","S","","P"],["OE","","BBB","","A3","","BBB-","","A-","","A1","","BBB+","","BBB","","A3","","BBB","","S","","S","","P"],["PN","","BBB","","Baa1","","BBB-","","\u2014","","\u2014","","\u2014","","BBB","","Baa1","","BBB","","S","","S","","P"],["Penn","","BBB","","A3","","BBB-","","A-","","A1","","BBB+","","\u2014","","\u2014","","\u2014","","S","","S","","P"],["PE","","BBB","","Baa2","","BBB-","","A-","","A3","","BBB+","","\u2014","","\u2014","","\u2014","","S","","S","","P"],["TE","","BBB","","Baa1","","BBB-","","A-","","A2","","BBB+","","\u2014","","\u2014","","\u2014","","S","","N","","P"],["TrAIL","","BBB","","A3","","BBB-","","\u2014","","\u2014","","\u2014","","BBB","","A3","","BBB","","S","","S","","P"],["WP","","BBB","","A3","","BBB-","","A-","","A1","","BBB+","","\u2014","","\u2014","","\u2014","","S","","S","","P"]]
[[/GREPCENT_TABLE]]

(1) S = Stable, N = Negative, P = Positive

On July 23, 2021, S&P revised the CreditWatch implications to positive from negative on the ratings of FE and its subsidiaries.

On July 27, 2021, Moody’s revised the outlook for FE and FET to stable from negative.

On August 25, 2021, Fitch revised the outlook of FE and its subsidiaries to stable from negative.

On October 19, 2021, S&P issued a one-notch upgrade to all applicable ratings for the following subsidiaries: ATSI, CEI, JCP&L, ME, MAIT, MP, OE, PN, Penn, PE, TE, TrAIL, and WP. The CreditWatch positive designation on FE and all subsidiaries is unchanged. The ratings of FE and FET were affirmed.

On November 8, 2021, Moody's outlook for FE was revised from stable to positive. OE’s outlook was revised from negative to stable, while CEI and TE’s outlook remains negative.

Also on November 8, 2021, S&P issued a one-notch upgrade to all applicable ratings and the CreditWatch positive outlook on FE and all subsidiaries was revised to stable.

On November 12, 2021, Fitch's Outlook for FE and all subsidiaries was revised from stable to positive.

The applicable undrawn and drawn margin on the 2021 Credit Facilities are subject to ratings based pricing grids. The applicable fee paid on the undrawn commitments under the 2021 Credit Facilities are based on each borrower's senior unsecured non-

45

credit enhanced debt ratings as determined by S&P and Moody’s. The fee paid on actual borrowings are determined based on each borrower’s senior unsecured non-credit enhanced debt ratings as determined by S&P and Moody’s.

The interest rate payable on approximately $3.0 billion in FE’s senior unsecured notes are subject to adjustments from time to time if the ratings on the notes from any one or more of S&P, Moody’s and Fitch decreases to a rating set forth in the applicable governing documents. Generally a one-notch downgrade by the applicable rating agency may result in a 25 basis points coupon rate increase beginning at BB, Ba1, and BB+ for S&P, Moody’s and Fitch, respectively, to the extent such rating is applicable to the series of outstanding senior unsecured notes, during the next interest period, subject to an aggregate cap of 2% from issuance interest rate.

FE's debt capacity is subject to the consolidated interest coverage ratio in the 2021 Credit Facilities. As of December 31, 2021, FirstEnergy could incur approximately $880 million of incremental interest expense or incur a $2.2 billion reduction to the consolidated interest coverage earnings numerator, as defined under the covenant, and FE would remain within the limitations of the financial covenant required by the 2021 Credit Facilities.

Cash Requirements and Commitments

FirstEnergy has certain obligations and commitments to make future payments under contracts, including contracts executed in connection with certain of the planned construction expenditures.

[[GREPCENT_TABLE]]
[["As of December 31, 2021 (Undiscounted):","","Total","","2022","","2023-2024","","2025-2026","","Thereafter"],["","","(In millions)"],["Long-term debt(1)","","$","23,946","","","$","1,593","","","$","1,590","","","$","3,099","","","$","17,664"],["Interest on long-term debt","","12,482","","","1,041","","","1,923","","","1,661","","","7,857"],["Operating leases(2)","","375","","","54","","","102","","","86","","","133"],["Finance leases(2)","","48","","","16","","","14","","","10","","","8"],["Fuel and purchased power(3)","","2,840","","","593","","","1,045","","","385","","","817"],["Committed investments(4)","","2,451","","","857","","","994","","","600","","","\u2014"],["Total","","$","42,142","","","$","4,154","","","$","5,668","","","$","5,841","","","$","26,479"]]
[[/GREPCENT_TABLE]]

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

(2)See Note 7, "Leases," of the Notes to Consolidated Financial Statements.

(3)Based on estimated annual amounts under contract with fixed or minimum quantities.

(4)Amounts represent committed capital expenditures and other capital-like investments that earn a return.

Excluded from the table above are estimates for the cash outlays from power purchase contracts entered into by most of the Utilities and under which they procure the power supply necessary to provide generation service to their customers who do not choose an alternative supplier. Although actual amounts will be determined by future customer behavior and consumption levels, management currently estimates these cash outlays will be approximately $2.8 billion in 2022.

The table above also excludes regulatory liabilities, AROs, reserves for litigation, injuries and damages and environmental remediation since the amount and timing of the cash payments are uncertain. The table also excludes accumulated deferred income taxes since cash payments for income taxes are determined based primarily on taxable income for each applicable fiscal year.

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

Changes in Cash Position

As of December 31, 2021, FirstEnergy had $1,462 million of cash and cash equivalents and approximately $49 million of restricted cash compared to $1,734 million of cash and cash equivalents and approximately $67 million of restricted cash as of December 31, 2020, on the Consolidated Balance Sheets.

Cash Flows From Operating Activities

FirstEnergy's most significant sources of cash are derived from electric service provided by its distribution and transmission operating subsidiaries. Beyond the cash settlement and tax sharing payments to the FES Debtors in 2020 and the DPA monetary penalty in 2021, the most significant use of cash from operating activities is buying electricity to serve non-shopping customers and paying fuel suppliers, employees, tax authorities, lenders and others for a wide range of materials and services.

46

Net cash provided from operating activities was $2,811 million during 2021, $1,423 million during 2020 and $2,467 million during 2019. Cash flows from operations increased $1,388 million in 2021 as compared with 2020. The increase is primarily due to the absence of a $978 million cash settlement and tax sharing payment made to the FES Debtors upon their emergence in February 2020, higher distribution deliveries, impact of the distribution riders and transmission investment recovery, and improved working capital, partially offset by the DPA monetary penalty paid in 2021. Improvements in working capital were primarily due to reduced customer account receivables, which had grown during 2020 as a result of COVID-19 discussed above, higher cash collateral receipts from certain competitive suppliers that serve customers that shop, and implementation of FE Forward initiatives that optimized certain materials and supplies inventories and accounts payable payment terms.

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:

[[GREPCENT_TABLE]]
[["","","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","","\u2014","","","\u2014","","","47"]]
[[/GREPCENT_TABLE]]

Cash Flows From Financing Activities

Cash provided from (used for) financing activities was $(542) million, $2.6 billion, and $656 million in 2021, 2020, and 2019, respectively. The following table summarizes new debt financing, redemptions, repayments, short-term borrowings and dividends:

[[GREPCENT_TABLE]]
[["","","For the Years Ended December 31,"],["Securities Issued or Redeemed / Repaid","","2021","","2020","","2019"],["","","(In millions)"],["New Issues"],["Unsecured notes","","$","1,750","","","$","3,250","","","$","1,850"],["FMBs","","200","","","175","","","450"],["Senior secured notes","","150","","","\u2014","","","\u2014"],["","","$","2,100","","","$","3,425","","","$","2,300"],["Redemptions / Repayments"],["Unsecured notes","","$","(400)","","","$","(250)","","","$","(725)"],["PCRBs","","(74)","","","\u2014","","","\u2014"],["FMBs","","\u2014","","","(50)","","","(1)"],["Term loan","","\u2014","","","(750)","","","\u2014"],["Senior secured notes","","(58)","","","(64)","","","(63)"],["","","$","(532)","","","$","(1,114)","","","$","(789)"],["Common stock issuance","","$","1,000","","","$","\u2014","","","$","\u2014"],["Short-term borrowings, net","","$","(2,200)","","","$","1,200","","","$","\u2014"],["Preferred stock dividend payments","","$","\u2014","","","$","\u2014","","","$","(6)"],["Common stock dividend payments","","$","(849)","","","$","(845)","","","$","(814)"]]
[[/GREPCENT_TABLE]]

47

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

[[GREPCENT_TABLE]]
[["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\u2019s 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\u2019s 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\u2019s regulated company money pool, fund MAIT\u2019s 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\u2019s 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%."]]
[[/GREPCENT_TABLE]]

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.

    Cash Flows From Investing Activities

Cash used for investing activities in 2021 principally represented cash used for property additions. The following table summarizes investing activities for 2021, 2020 and 2019:

[[GREPCENT_TABLE]]
[["","","For the Years Ended December 31,"],["Cash Used for (Provided from) Investing Activities","","2021","","2020","","2019"],["","","(In millions)"],["Property Additions:"],["Regulated Distribution","","$","1,395","","","$","1,514","","","$","1,473"],["Regulated Transmission","","958","","","1,067","","","1,090"],["Corporate/Other","","92","","","76","","","102"],["Proceeds from sale of Yards Creek","","(155)","","","\u2014","","","\u2014"],["Investments","","53","","","22","","","38"],["Asset removal costs","","226","","","224","","","217"],["Other","","(10)","","","5","","","(47)"],["","","$","2,559","","","$","2,908","","","$","2,873"]]
[[/GREPCENT_TABLE]]

48

GUARANTEES AND OTHER ASSURANCES

FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. The maximum potential amount of future payments FirstEnergy and its subsidiaries could be required to make under these guarantees as of December 31, 2021, was approximately $1.1 billion, as summarized below:

[[GREPCENT_TABLE]]
[["Guarantees and Other Assurances","","Maximum Exposure"],["","","(In millions)"],["FE's Guarantees on Behalf of its Consolidated Subsidiaries"],["Deferred compensation arrangements","","$","512"],["Vehicle leases","","75"],["AE Supply asset sales(1)","","15"],["Other","","7"],["","","609"],["FE's Guarantees on Other Assurances"],["Surety Bonds","","331"],["Deferred compensation arrangements","","136"],["LOCs and other","","9"],["","","476"],["Total Guarantees and Other Assurances","","$","1,085"]]
[[/GREPCENT_TABLE]]

(1)As a condition to closing AE Supply's transfer of Pleasants Power Station and as contemplated under the FES Bankruptcy settlement agreement, FE has provided two guarantees for certain retained liabilities of AE Supply, the first totaling up to $15 million for certain environmental liabilities associated with Pleasants Power Station, and the second being limited solely to environmental liabilities for the McElroy's Run CCR impoundment facility, for which an ARO of $47 million is reflected on FirstEnergy's Consolidated Balance Sheets, and which is not reflected on the table above.

Collateral and Contingent-Related Features

In the normal course of business, FE and its subsidiaries may enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain agreements contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.

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. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of December 31, 2021:

[[GREPCENT_TABLE]]
[["Potential Collateral Obligations","","","","","","Utilities and FET","","FE","","Total"],["","","","","","","(In millions)"],["Contractual Obligations for Additional Collateral"],["Upon Further Downgrade","","","","","","$","44","","","$","\u2014","","","$","44"],["Surety Bonds (collateralized amount)(1)","","","","","","57","","","258","","","315"],["Total Exposure from Contractual Obligations","","","","","","$","101","","","$","258","","","$","359"]]
[[/GREPCENT_TABLE]]

(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 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.

49

Other Commitments and Contingencies

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.

MARKET RISK INFORMATION

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

Commodity Price Risk

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

The valuation of derivative contracts is based on observable market information. As of December 31, 2021, FirstEnergy has a net asset of $8 million in non-hedge derivative contracts that are related to FTRs at certain of the Utilities. FTRs are subject to regulatory accounting and do not impact earnings.

Equity Price Risk

As of December 31, 2021, the FirstEnergy pension plan assets were allocated approximately as follows: 35% in equity securities, 27% in fixed income securities, 7% in hedge funds, 4% in insurance-linked securities, 10% in real estate, 9% in private equity and debt funds, and 8% in cash and short-term securities. FirstEnergy funding policy is based on actuarial computations using the projected unit credit method. As a result of the American Rescue Plan Act of 2021, which, among other things, extended shortfall amortization periods and modifications of the interest rate stabilization rules for single-employer plans, actual pension investment performance returns to date and current assumptions, FirstEnergy does not currently expect to have a required contribution to the pension plan. However, a decline in the value of pension plan assets could result in additional funding requirements, and FirstEnergy may elect to contribute to the pension plan voluntarily. As of December 31, 2021, FirstEnergy's OPEB plan assets were allocated approximately 51% in equity securities, 32% in fixed income securities and 17% in cash and short-term securities. See Note 4, "Pension and Other Post-Employment Benefits," of the Notes to Consolidated Financial Statements for additional details on FirstEnergy's pension and OPEB plans.

During 2021, FirstEnergy's pension and OPEB plan assets gained approximately 7.6% and 13.4%, respectively, as compared to an annual expected return on plan assets of 7.5%.

Interest Rate Risk

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

[[GREPCENT_TABLE]]
[["Comparison of Carrying Value to Fair Value as of December 31, 2021"],["Year of Maturity or Notice of Redemption","","2022","","2023","","2024","","2025","","2026","","There-after","","Total","","Fair Value"],["","","(In millions)"],["Assets:"],["Investments Other Than Cash and Cash Equivalents:"],["Fixed Income","","$","\u2014","","","$","\u2014","","","$","\u2014","","","$","\u2014","","","$","\u2014","","","$","284","","","$","284","","","$","284"],["Average interest rate","","\u2014","%","","\u2014","%","","\u2014","%","","\u2014","%","","\u2014","%","","1.0","%","","1.0","%"],["Liabilities:"],["Long-term Debt:"],["Fixed rate","","$","1,593","","","$","344","","","$","1,246","","","$","2,023","","","$","1,076","","","$","17,664","","","$","23,946","","$","27,043"],["Average interest rate","","4.3","%","","3.7","%","","4.7","%","","3.8","%","","3.5","%","","4.5","%","","4.4","%"]]
[[/GREPCENT_TABLE]]

FirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. A primary factor contributing to these actuarial gains and losses

50

are changes in the discount rates used to value pension and OPEB obligations as of the measurement date and the difference between expected and actual returns on the plans’ assets.

CREDIT RISK

Credit risk is the risk that FirstEnergy would incur a loss as a result of nonperformance by counterparties of their contractual obligations. FirstEnergy maintains credit policies and procedures with respect to counterparty credit (including requirements that counterparties maintain specified credit ratings) and require other assurances in the form of credit support or collateral in certain circumstance in order to limit counterparty credit risk. In addition, in response to the COVID-19 pandemic, FirstEnergy has increased reviews of counterparties, customers and industries that have been negatively impacted, which could affect meeting contractual obligations with FirstEnergy. FirstEnergy has concentrations of suppliers and customers among electric utilities, financial institutions and energy marketing and trading companies. These concentrations may impact FirstEnergy's overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions. In the event an energy supplier of the Ohio Companies, Pennsylvania Companies, JCP&L or PE defaults on its obligation, the affected company would be required to seek replacement power in the market. In general, subject to regulatory review or other processes, it is expected that appropriate incremental costs incurred by these entities would be recoverable from customers through applicable rate mechanisms, thereby mitigating the financial risk for these entities. FirstEnergy's credit policies to manage credit risk include the use of an established credit approval process, daily credit mitigation provisions, such as margin, prepayment or collateral requirements, and surveys to determine negative impacts to essential vendors as a result of the COVID-19 pandemic. FirstEnergy and its subsidiaries may request additional credit assurance, in certain circumstances, in the event that the counterparties' credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit.

PHYSICAL SECURITY AND CYBERSECURITY RISK

FirstEnergy is committed to protecting its customers, employees, facilities, and the ongoing reliability of its electric system. FirstEnergy works closely with state and federal agencies and its peers in the electric utility industry to identify physical and cyber security risks, exchange information, and put safeguards in place to comply with strict reliability and security standards. From a security standpoint, no other industry – including gas pipelines – is as heavily regulated as the electric utility sector. FirstEnergy has comprehensive cyber and physical security plans in place but does not publicly disclose details about these measures that could aid those who want to harm its customers, employees, facilities and the ongoing reliability of its electric system.

The FE Board has identified cybersecurity as a key enterprise risk and prioritizes the mitigation of this risk. The FE Board receives cybersecurity updates from FirstEnergy's Information Technology organization at each of its regularly scheduled meetings. The Audit Committee reviews FirstEnergy's cybersecurity risk management practices and performance, primarily through reports provided by management. The Audit Committee also reviews and discusses with management the steps taken to monitor, control, and mitigate such exposure. Among other things, these reports have focused on incident response management and recent cyber risk and cybersecurity developments.

Security enhancements are also a key component of FirstEnergy’s Energizing the Future transmission investment program. FirstEnergy invests heavily in sophisticated and layered security measures that use both technology and hard defenses to protect critical transmission facilities and its digital communications networks.

Despite security measures and safeguards FirstEnergy has employed, including certain measures implemented pursuant to mandatory NERC Critical Infrastructure Protection standards, its infrastructure may be increasingly vulnerable to such attacks as a result of the rapidly evolving and increasingly sophisticated means by which attempts to defeat security measures and gain access to information technology systems may be made. Also, FirstEnergy, or its vendors and service providers, may be at an increased risk of a cyber-attack and/or data security breach due to the nature of its business.

Any such cyber incident could result in significant lost revenue, the inability to conduct critical business functions and serve customers for a significant period of time, the use of significant management resources, legal claims or proceedings, regulatory penalties, significant remediation costs, increased regulation, increased capital costs, increased protection costs for enhanced cybersecurity systems or personnel, damage to FirstEnergy's reputation and/or the rendering of its internal controls ineffective, all of which could materially adversely affect FirstEnergy's business, results of operations, financial condition and reputation.

OUTLOOK

STATE REGULATION

Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia, ATSI in Ohio, and the Transmission Companies in Pennsylvania are subject to certain regulations of the VSCC, PUCO and PPUC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new

51

transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility.

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

[[GREPCENT_TABLE]]
[["Company","","Rates Effective For Customers","","Allowed Debt/Equity","","Allowed ROE"],["CEI","","May 2009","","51% /49%","","10.5%"],["ME(1)","","January 2017","","48.8% / 51.2%","","Settled(2)"],["MP","","February 2015","","54% / 46%","","Settled(2)"],["JCP&L","","November 2021(3)","","48.6% / 51.4%","","9.6%"],["OE","","January 2009","","51% /49%","","10.5%"],["PE (West Virginia)","","February 2015","","54% / 46%","","Settled(2)"],["PE (Maryland)","","March 2019","","47% / 53%","","9.65%"],["PN(1)","","January 2017","","47.4% /52.6%","","Settled(2)"],["Penn(1)","","January 2017","","49.9% / 50.1%","","Settled(2)"],["TE","","January 2009","","51% / 49%","","10.5%"],["WP(1)","","January 2017","","49.7% / 50.3%","","Settled(2)"]]
[[/GREPCENT_TABLE]]

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

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

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

MARYLAND

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

The EmPOWER Maryland program requires each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings, for the duration of the 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.

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 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.

NEW JERSEY

JCP&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.

52

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 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 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 28, 2020, the NJBPU approved the sale of Yards Creek. 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 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.

53

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. 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.

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.

OHIO

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 Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and (3) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio.

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.

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 (CSR) to zero. On February 2, 2021, the PUCO approved the application. While the partial settlement with the OAG focused specifically on decoupling, the Ohio

54

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. 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. 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. 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.

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

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Companies are contesting the complaint. 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 “Outlook - Other Legal Proceedings” below for additional details on the government investigations and subsequent litigation surrounding the investigation of HB 6.

PENNSYLVANIA

The Pennsylvania Companies operate under rates approved by the PPUC, effective as of January 27, 2017. 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

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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. The Pennsylvania Companies’ Phase III EE&C plans for the June 2016 through May 2021 period, which were approved in March 2016, with expected costs up to $390 million, are designed to achieve the targets established in the PPUC’s Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders. On June 18, 2020, the PPUC entered a Final Implementation Order for a Phase IV EE&C Plan, operating from June 2021 through May 2026. The Final Implementation Order set demand reduction targets, relative to 2007 to 2008 peak demands, at 2.9% MW for ME, 3.3% MW for PN, 2.0% MW for Penn, and 2.5% MW for WP; and energy consumption reduction targets, as a percentage of the Pennsylvania Companies’ historic 2009 to 2010 reference load at 3.1% MWH for ME, 3.0% MWH for PN, 2.7% MWH for Penn, and 2.4% MWH for WP. The Pennsylvania Companies’ Phase IV plans were filed November 30, 2020 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.

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

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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

Under the FPA, FERC regulates rates for interstate wholesale sales, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Utilities, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE, WP and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE, WP and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff.

The following table summarizes the key terms of rate orders in effect for transmission customer billings for FirstEnergy's transmission owner entities as of December 31, 2021:

[[GREPCENT_TABLE]]
[["Company","","Rates Effective","","Capital Structure","","Allowed ROE"],["ATSI","","January 1, 2015","","Actual (13-month average)","","10.38%"],["JCP&L","","January 1, 2020","","Actual (13-month average)","","10.20%"],["MP","","January 1, 2021(1)(2)","","Actual (13-month average)(1)","","11.35%(1)"],["PE","","January 1, 2021(1)(2)","","Actual (13-month average)(1)","","11.35%(1)"],["WP","","January 1, 2021(1)(2)","","Actual (13-month average)(1)","","11.35%(1)"],["MAIT","","July 1, 2017","","Lower of Actual (13-month average) or 60%","","10.3%"],["TrAIL","","July 1, 2008","","Actual (year-end)","","12.7%(TrAIL the Line & Black Oak SVC)11.7% (All other projects)"]]
[[/GREPCENT_TABLE]]

(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.

(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. The Utilities and AE Supply each have been authorized by FERC to sell wholesale power in interstate commerce at market-based rates and have a market-based rate tariff on file with FERC, although in the case of the Utilities major wholesale purchases remain subject to review and regulation by the relevant state commissions.

Federally enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, AE Supply, and the Transmission Companies. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to six regional entities, including RFC. All of the facilities that FirstEnergy operates are located within 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.

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

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FERC Audit

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, 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

On March 15, 2018, FERC initiated proceedings on the question of how to address possible changes to ADIT and bonus depreciation as a result of the Tax Act. Such possible changes could impact FERC-jurisdictional rates, including transmission rates. On November 21, 2019, FERC issued a final rule (Order No. 864). Order No. 864 requires utilities with transmission formula rates to update their formula rate templates to include mechanisms to: (i) deduct any excess ADIT from or add any deficient ADIT to their rate base; (ii) raise or lower their income tax allowances by any amortized excess or deficient ADIT; and (iii) incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT. Per FERC directives, ATSI submitted its compliance filing on May 1, 2020. MAIT submitted its compliance filing on June 1, 2020. 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. 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

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,

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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. Circuit. 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. 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

On October 30, 2019, JCP&L filed tariff amendments with FERC to convert JCP&L’s existing stated transmission rate to a forward-looking formula transmission rate. JCP&L requested that the tariff amendments become effective January 1, 2020. On December 19, 2019, FERC issued its initial order in the case, allowing JCP&L to transition to a forward-looking formula rate as of January 1, 2020 as requested, subject to refund, pending further hearing and settlement proceedings. JCP&L and the parties to the FERC proceeding subsequently were able to reach settlement, and on February 2, 2021, 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 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 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. KATCo will be included in the Regulated Transmission reportable segment.

ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy’s environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition.

Clean Air Act

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

CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. On July 28, 2015, the D.C. Circuit ordered the EPA to reconsider the CSAPR caps on NOx and SO2 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 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 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.

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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. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. On July 14, 2020, the D.C. Circuit reversed and remanded the New York petition to the EPA for further consideration. 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 SO2, 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 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.

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 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. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. On January 20, 2021, President Biden signed an executive order re-adopting the agreement on behalf of the U.S. 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 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 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 CO2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO2 emission limits for new, modified, and reconstructed fossil fuel-fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On 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 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. The D.C. Circuit decision is subject to legal challenge. Depending on the outcomes of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material.

Clean Water Act

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

On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations were to phase-in as permits are renewed on a five-year cycle from 2018 to 2023. However, on April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. On August 31, 2020, the EPA issued a final rule revising the effluent limits

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for discharges from wet scrubber systems, retaining the zero-discharge standard for ash transport water, (with some limited discharge allowances), and extending the deadline for compliance to December 31, 2025 for both. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. 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

Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation.

In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 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. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of December 31, 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 $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.

OTHER LEGAL PROCEEDINGS

United States v. Larry Householder, et al.

On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. Also, on July 21, 2020, and in connection with the investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the S.D. Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020.

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. government; (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

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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.” 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. Householder. 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. Ohio); 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. v. 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.

•Smith v. FirstEnergy Corp. et al., Buldas v. FirstEnergy Corp. et al., and Hudock and Cameo Countertops, Inc. v. FirstEnergy Corp. et al. (Federal District Court, S.D. Ohio, 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

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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.

•Emmons v. FirstEnergy Corp. et al. (Common Pleas Court, Cuyahoga County, OH); on August 4, 2020, a purported customer of FirstEnergy filed a putative class action lawsuit against FE, FESC, 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. Anderson, et al. and Sloan v. Anderson, et al. (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.

•Miller v. Anderson, et al. (Federal District Court, N.D. Ohio); Bloom, et al. v. Anderson, et al.; Employees Retirement System of the City of St. Louis v. Jones, et al.; Electrical Workers Pension Fund, Local 103, I.B.E.W. v. Anderson et al.; Massachusetts Laborers Pension Fund v. Anderson et al.; The City of Philadelphia Board of Pensions and Retirement v. Anderson et al.; Atherton v. Dowling et al.; Behar v. Anderson, et al. (Federal 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 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. Michael J. Anderson, Donald T. Misheff, Thomas N. Mitchell, Christopher D. Pappas and Luis A. Reyes, and Ms. Julia L. 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; and

•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

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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

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 12, “Regulatory Matters.”

FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FE or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FE’s or its subsidiaries’ financial condition, results of operations and cash flows.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Loss Contingencies

FirstEnergy is involved in a number of investigations, litigation, regulatory audits, arbitration, mediation, and similar proceedings, including those surrounding HB 6. FirstEnergy regularly assesses its liabilities and contingencies in connection with asserted or potential matters and establishes reserves when appropriate. In the preparation of the financial statements, FirstEnergy makes judgments regarding the future outcome of contingent events based on currently available information and accrues liabilities when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. Circumstances change over time and actual results may vary significantly from estimates. See Note 12, “Regulatory Matters” and Note 13, “Commitments, Guarantees and Contingencies,” of the Notes to Consolidated Financial Statements for additional information.

Revenue Recognition

The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. FirstEnergy accounts for revenues from contracts with customers under ASC 606, “Revenue from Contracts with Customers.” Revenue from leases, financial instruments, other contractual rights or obligations and other revenues that are not from contracts with customers are outside the scope of the standard and accounted for under other existing GAAP.

Contracts with Customers

FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled sales is recognized. The determination of unbilled sales and revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, applicable billing demands, weather-related impacts, number of days unbilled and tariff rates in effect within each customer class.

The Transmission Companies revenues are primarily derived from forward-looking formula rates. 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. Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time.

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FirstEnergy has elected the optional invoice practical expedient for most of its revenues and utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations. See Note 2, "Revenue," of the Notes to Consolidated Financial Statements for additional information.

Regulatory Accounting

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.

Pension and OPEB Accounting

FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

FirstEnergy pension and OPEB obligations are based on various assumptions in calculating these amounts. These assumptions include discount rates, health care cost trend rates, expected return on plan assets, compensation increases, retirement rates, mortality rates, among others. Actual results that differ from the assumptions and changes in assumptions affect future expenses and obligations.

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. FirstEnergy utilizes a full yield curve approach in the estimation of the service and interest components of net periodic benefit costs for pension and other postretirement benefits by applying specific spot rates along the full yield curve to the relevant projected cash flows.

Expected Return on Plan Assets - 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. The expected return on plan assets for 2022 is 7.50%.

Mortality Rates - The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. 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 utilized to determine the 2021 benefit cost and obligation as of December 31, 2021, for FirstEnergy's pension and OPEB plans. The MP-2021 scale was published in 2021 by the Society of Actuaries.

Health Care Trend Rates - In determining trend rate assumptions, included are the specific provisions of FirstEnergy’s health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in FirstEnergy’s health care plans, and projections of future medical trend rates.

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.

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The following table reflects the portion of pension and OPEB costs that were charged to expense, including any pension and OPEB mark-to-market adjustments, in the three years ended December 31, 2021, 2020, and 2019:

[[GREPCENT_TABLE]]
[["Net Periodic Benefit Costs (Credits)","","2021","","2020","","2019"],["","","(In millions)"],["Pension","","$","(582)","","","$","254","","","$","622"],["OPEB","","(170)","","","(47)","","","(21)"],["Total","","$","(752)","","","$","207","","","$","601"]]
[[/GREPCENT_TABLE]]

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, and $676 million, respectively.

FirstEnergy expects its 2022 pre-tax net periodic benefit credit including amounts capitalized (excluding mark-to-market adjustments) to be approximately $233 million based upon the following assumptions:

[[GREPCENT_TABLE]]
[["Assumptions","","Pension","","OPEB"],["Service cost weighted-average discount rate","","3.28","%","","3.41","%"],["Interest cost weighted-average discount rate","","2.44","%","","2.18","%"],["Expected return on plan assets","","7.50","%","","7.50","%"]]
[[/GREPCENT_TABLE]]

The approximate effects on 2022 pension and OPEB net periodic benefit costs and the 2021 benefit obligation from changes in key assumptions are as follows:

Approximate Effect on 2022 Net Periodic Benefit Costs from Changes in Key Assumptions

[[GREPCENT_TABLE]]
[["Assumption","","Change","","Pension","","OPEB","","Total"],["","","","","(In millions)"],["Discount rate","","Change by 0.25%","","$","370","","","$","13","","","$","383"],["Expected return on plan assets","","Change by 0.25%","","$","22","","","$","1","","","$","23"],["Health care trend rate","","Change by 1.0%","","N/A","","$","10","","","$","10"]]
[[/GREPCENT_TABLE]]

Approximate Effect on 2021 Benefit Obligation from Changes in Key Assumptions

[[GREPCENT_TABLE]]
[["Assumption","","Change","","Pension","","OPEB","","Total"],["","","","","(In millions)"],["Discount rate","","Change by 0.25%","","$","375","","","$","14","","","$","389"],["Health care trend rate","","Change by 1.0%","","N/A","","$","11","","","$","11"]]
[[/GREPCENT_TABLE]]

See Note 4, "Pension and Other Postemployment Benefits," of the Notes to Consolidated Financial Statements for additional information.

Income Taxes

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities such as the interpretation of tax laws and associated regulations. FirstEnergy is required to make judgments regarding the potential tax effects of various transactions and results of operations in order to estimate its obligations to taxing authorities.

Accounting for tax obligations requires judgments, including assessing whether tax benefits are more likely than not to be sustained, and estimating reserves for potential adverse outcomes regarding tax positions that have been taken. FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled.

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Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, forecasted results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities.

See Note 6, "Taxes," of the Notes to Consolidated Financial Statements for additional information on income taxes.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 1, "Organization and Basis of Presentation," of the Notes to Consolidated Financial Statements for a discussion of new accounting pronouncements.