EDGAR 10-K Filing

Company CIK: 1031296
Filing Year: 2023
Filename: 1031296_10-K_2023_0001031296-23-000014.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS
The Companies
FE and its subsidiaries are principally involved in the transmission, distribution, and generation of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving over six million customers in the Midwest and Mid-Atlantic regions. FirstEnergy’s transmission operations include over 24,000 miles of transmission lines and two regional transmission operation centers. AGC and MP control 3,580 MWs of total capacity.
FirstEnergy’s revenues are primarily derived from electric service provided by the Utilities and Transmission Companies.
Regulated Utility Operating Subsidiaries
The Utilities’ combined service areas encompass approximately 65,000 square miles in Ohio, Pennsylvania, West Virginia, Maryland, New Jersey, and New York. The areas they serve have a combined population of approximately 14 million.
OE owns property and does business as an electric public utility in Ohio. OE engages in the distribution and sale of electric energy to communities in central and northeastern Ohio. The area it serves has a population of approximately 2.4 million.
Penn owns property and does business as an electric public utility in Pennsylvania. Penn furnishes electric service to communities in western Pennsylvania. The area it serves has a population of approximately 0.4 million.
CEI does business as an electric public utility in Ohio. CEI engages in the distribution and sale of electric energy in northeastern Ohio. The area it serves has a population of approximately 1.7 million.
TE does business as an electric public utility in Ohio. TE engages in the distribution and sale of electric energy in northwestern Ohio. The area it serves has a population of approximately 0.7 million.
JCP&L owns property and does business as an electric public utility in New Jersey. JCP&L provides transmission and distribution services in northern, western, and east central New Jersey. The area it serves has a population of approximately 2.9 million.
ME owns property and does business as an electric public utility in Pennsylvania. ME provides distribution services in eastern and south central Pennsylvania. The area it serves has a population of approximately 1.3 million.
PN owns property and does business as an electric public utility in Pennsylvania. PN provides distribution services in western, northern, and south central Pennsylvania. The area PN serves has a population of approximately 1.2 million. Also, PN, as lessee of the property of its subsidiary, the Waverly Electric Light & Power Company, serves approximately 4,000 customers in the Waverly, New York vicinity.
PE owns property and does business as an electric public utility in Maryland, Virginia, and West Virginia. PE provides transmission and distribution services in portions of Maryland and West Virginia and provides transmission services in Virginia. The area it serves has a population of approximately 1.0 million.
MP owns property and does business as an electric public utility in West Virginia. MP provides generation, transmission, and distribution services in northern West Virginia. The area it serves has a population of approximately 0.8 million. MP is contractually obligated to provide power to PE to meet its load obligations in West Virginia. MP owns or contractually controls 3,580 MWs of generation capacity that is supplied to its electric utility business, including a 16.25% undivided interest in the Bath County pumped-storage hydroelectric generation facility in Virginia (487 MWs) through its wholly owned subsidiary AGC.
WP owns property and does business as an electric public utility in Pennsylvania. WP provides transmission and distribution services in southwestern, south-central, and northern Pennsylvania. The area it serves has a population of approximately 1.6 million.
FirstEnergy is proceeding with the consolidation of the Pennsylvania Companies into a new, single operating entity. The PA Consolidation will require, among other steps: (a) the transfer of certain Pennsylvania-based transmission assets owned by WP to KATCo, (b) the transfer of Class B equity interests of MAIT currently held by PN and ME to FE (and ultimately transferred to FET as part of the FET Minority Equity Interest Sale), (c) the formation of PA NewCo and (d) the merger of each of the Pennsylvania Companies with and into PA NewCo, with PA NewCo surviving such mergers as the successor-in-interest to all assets and liabilities of the Pennsylvania Companies. Following completion of the PA Consolidation, PA NewCo will be FE’s only regulated utility in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies. Consummation of the PA Consolidation is contingent upon numerous conditions, including the approval of NYPSC, PPUC and FERC. Subject to receipt of such regulatory approvals, FirstEnergy expects that the PA Consolidation will close by early 2024.
Regulated Transmission Operating Subsidiaries
FET, the parent of ATSI, MAIT, PATH, and TrAIL, is a subsidiary of FE which holds 80.1% of its issued and outstanding membership interests. Brookfield owns the remaining 19.9% of the issued and outstanding membership interests of FET. Through its subsidiaries, FET owns and operates high-voltage transmission facilities in the PJM Region. FET's subsidiaries are subject to regulation by FERC and applicable state regulatory authorities.
On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The purchase price will be payable in part by the issuance of a promissory note expected to be in the principal amount of $1.75 billion. The remaining $1.75 billion of the purchase price will be payable in cash at the closing. As a result of the consummation of the transaction, Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1% ownership interests of FET. The transaction is subject to customary closing conditions, including approval from the FERC and certain state utility commissions, and completion of review by the CFIUS. In addition, pursuant to the FET P&SA II, FirstEnergy has agreed to make the necessary filings with the applicable regulatory authorities for the PA Consolidation. The FET Minority Equity Interest Sale is expected to close by early 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s GAAP financial statements.
ATSI owns high-voltage transmission facilities in PJM, which consist of approximately 7,900 circuit miles of transmission lines with nominal voltages of 345 kV, 138 kV and 69 kV in Ohio and Pennsylvania.
TrAIL owns high-voltage transmission facilities in PJM, which consists of approximately 260 circuit miles of transmission lines, including a 500 kV transmission line extending approximately 150 miles from southwestern Pennsylvania through West Virginia to a point of interconnection with VEPCO in northern Virginia.
MAIT owns high-voltage transmission facilities in PJM, which consist of approximately 4,300 circuit miles of transmission lines with nominal voltages of 500 kV, 345 kV, 230 kV, 138 kV, 115 kV, 69 kV and 46 kV in Pennsylvania.
KATCo was formed to accommodate new transmission construction in the WP, MP and PE footprint and currently does not own or operate any transmission assets.
Service Company
FESC provides legal, financial, and other corporate support services at cost, in accordance with its cost allocation manual, to affiliated FirstEnergy companies.
Operating Segments
FirstEnergy's reportable operating segments are comprised of the Regulated Distribution and Regulated Transmission segments.
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 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 I, 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 would own 19.9% of the issued and outstanding membership interests of FET, for a purchase price of $2.375 billion. The transaction closed on May 31, 2022. On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The purchase price will be payable in part by the issuance of a promissory note expected to be in the principal amount of $1.75 billion. The remaining $1.75 billion of the purchase price will be payable in cash at the closing. As a result of the consummation of the transaction, Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1% ownership interests of FET. The transaction is subject to customary closing conditions, including approval from the FERC and certain state utility commissions, and completion of review by the CFIUS. In addition, pursuant to the FET P&SA II, FirstEnergy has agreed to make
the necessary filings with the applicable regulatory authorities for the PA Consolidation. The FET Minority Equity Interest Sale is expected to close by early 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s GAAP financial statements.
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 investments or 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, 2022, 67 MWs of electric generating capacity, representing AE Supply's OVEC capacity entitlement, was also included in Corporate/Other for segment reporting. As of December 31, 2022, Corporate/Other had approximately $5.4 billion of FE holding company debt.
Utility Regulation
Regulatory Accounting
FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to the Utilities and the Transmission Companies since their rates are established by a third-party regulator with the authority to set rates that bind customers, are cost-based and can be charged to and collected from customers.
The Utilities and the Transmission Companies recognize, as regulatory assets and regulatory liabilities, costs which FERC and the various state utility commissions, as applicable, have authorized for recovery from or return to customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets and regulatory liabilities would have been charged or credited to income as incurred. All regulatory assets and liabilities are expected to be recovered from or returned to customers. Based on current ratemaking procedures, the Utilities and the Transmission Companies continue to collect cost-based rates for their transmission and distribution services; accordingly, it is appropriate that the Utilities and the Transmission Companies continue the application of regulatory accounting to those operations. Regulatory accounting is applied only to the parts of the business that meet the above criteria. If a portion of the business applying regulatory accounting no longer meets those requirements, previously recorded regulatory assets and liabilities are removed from the balance sheet in accordance with GAAP.
State Regulation
The following table summarizes the allowed ROE and the aggregate actual ROE of the Regulated Distribution Utilities by state for the year ended December 31, 2022, as determined for regulatory purposes:
State Allowed ROE Actual ROE(1)
Maryland 9.65% 8.8%
New Jersey
9.6% 7.0%
Ohio 10.5% 8.4%
Pennsylvania Settled(2)
8.1%
West Virginia Settled(2)
6.6%
(1) Actual ROE is based on methodology used in last distribution rate case and/or quarterly earnings reports, as applicable. Rate base is for distribution assets only (except West Virginia, which includes generation and transmission assets) and reflects the actual capital structure for Pennsylvania, West Virginia and Maryland, and the allowed capital structure for Ohio. Actual ROEs reflect actual revenue (not weather normalized) and historical results should not be relied upon to estimate the outcome of future rate cases as regulatory assumptions may vary. ROEs may not tie to upcoming rate filings due to items such as updated allocators, taxes, and adjustments.
(2) Commission-approved settlement agreements did not disclose ROE rates.
See "Outlook - State Regulation" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information and discussion.
Federal Regulation
See "Outlook - FERC Regulatory Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information and discussion.
Environmental Matters
See "Outlook - Environmental Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information and discussion.
Capital Requirements
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. See "Capital Resources and Liquidity" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information and discussion.
Supply Plan
Supply Chain
FirstEnergy has continued to experience supply chain challenges due to economic conditions following the global pandemic. Lead times continue to increase across numerous material categories, with some as much as doubling from pre-pandemic lead times. Suppliers continue to struggle with labor shortages and raw material availability, which, along with inflationary pressure, have increased the costs and decreased the availability of certain materials, equipment and contractors. FirstEnergy continues to monitor supply chain risk as it anticipates these challenges continuing into 2023 and is mitigating these risks by:
•Utilizing a cross-functional team to forecast potential impacts to operations and programs;
•Expanding supply base to increase resiliency;
•Enhancing the demand management and material reservation process;
•Evaluating substitute products, reserving production capacity, and buying ahead in targeted categories; and
•Staying updated by participating in discussions with other utilities through EEI, which has a long history of mutual assistance in the electric utility industry.
Default Service
Certain of the Utilities have default service obligations to provide power to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales can vary depending on the level of shopping that occurs and these default service plans vary by state and by service territory. JCP&L’s default service, or BGS supply, is secured through a statewide competitive procurement process approved by the NJBPU. Default service for the Ohio Companies, Pennsylvania Companies and PE's Maryland jurisdiction are provided through a competitive procurement process approved by the PUCO (under ESP IV), PPUC (under the DSP) and MDPSC (under the SOS), respectively. If any supplier fails to deliver power to any one of those Utilities’ service areas, the Utility serving that area may need to procure the required power in the market in their role as the default Load Serving Entity. West Virginia electric generation continues to be regulated by the WVPSC.
Fuel Supply
MP currently has coal contracts with various terms to purchase approximately 7.4 million tons of coal for the year 2023, which, along with its 2022 year-end inventory levels, accounts for nearly all of its forecasted 2023 coal requirements. MP has the ability to acquire additional tonnage through options available in its current contracts, as well as purchases through the spot market. The contracts expire at various times through 2026. This contracted coal is produced primarily from mines located in Pennsylvania, Illinois and West Virginia. In order to meet emission requirements, MP holds contracts for a variety of reagents expiring at various times through 2026, as well as the ability to purchase additional reagents through the spot market. Additionally, MP is granted emission allowances by the EPA and purchases additional allowances as needed to meet emission requirements. See "Outlook - Environmental Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information pertaining to the impact of increased environmental regulations on fuel supply.
System Demand
The maximum hourly demand for each of the Utilities was:
System Demand 2022 2021 2020
(in MWs)
CEI 4,266 4,253 4,188
JCP&L 6,122 5,902 6,056
ME 3,021 2,976 2,974
MP 2,124 2,114 2,121
OE 5,652 5,598 5,494
PE 3,514 2,905 3,609
Penn 944 889 946
PN 2,838 2,908 3,020
TE 2,277 2,265 2,787
WP 3,827 3,827 4,012
Regional Reliability
All of FirstEnergy's facilities are located within PJM and operate under the reliability oversight of a regional entity known as RFC. This regional entity operates under the oversight of NERC in accordance with a delegation agreement approved by FERC.
Competition
Within FirstEnergy’s Regulated Distribution segment, generally there is no competition for electric distribution service in the Utilities’ respective service territories in Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York. Additionally, there has traditionally been no competition for transmission service in PJM. However, pursuant to FERC’s Order No. 1000 and subject to state and local siting and permitting approvals, non-incumbent developers now can compete for certain PJM transmission projects in the service territories of FirstEnergy’s Regulated Transmission segment. This could result in additional competition to build transmission facilities in the Regulated Transmission segment’s service territories while also allowing the Regulated Transmission segment the opportunity to seek to build facilities in non-incumbent service territories.
Seasonality
The sale of electric power is generally a seasonal business, and weather patterns can have a material impact on FirstEnergy’s Regulated Distribution segment operating results. Demand for electricity in our service territories historically peaks during the summer and winter months. Accordingly, FirstEnergy’s annual results of operations and liquidity position may depend disproportionately on its operating performance during the summer and winter. Mild weather conditions may result in lower power sales and consequently lower revenue and earnings.
Human Capital
FirstEnergy focuses on a number of human capital resources, measures and objectives in managing its business, including: integrity, safety, diversity, equity and inclusion, workplace flexibility, employee development and compensation and benefits. During 2022, the company continued to enhance its dedicated focus on employees by providing employees with additional opportunities to improve belonging, inclusion and engagement within our workforce. Collectively, these focus areas may be material to understanding its business under certain circumstances.
Employees and Collective Bargaining Agreements
As of December 31, 2022, FirstEnergy had 12,335 employees, all of whom were located in the United States as follows:
Total
Employees Bargaining
Unit
Employees
FESC 5,099 554
CEI 824 565
JCP&L 1,361 1,052
ME 579 452
MP 1,080 750
OE 1,069 735
PE 501 330
Penn 173 131
PN 694 487
TE 331 253
WP 624 465
Total 12,335 5,774
As of December 31, 2022, the IBEW, the UWUA and the OPEIU unions collectively represented approximately half of FirstEnergy’s employees. There are 15 collective bargaining agreements between FirstEnergy’s subsidiaries and its unions, which have three, four or five- year terms. In 2022, FirstEnergy’s subsidiaries reached new agreements with 3 IBEW locals, covering 620 employees, and 3 UWUA locals, covering 945 employees.
Safety
Safety is a core value of FirstEnergy. FirstEnergy employees have the power and responsibility to keep each other safe and eliminate life-changing events, which are injuries that have life-changing impacts or fatal results. Safety metrics, such as injuries that result in days away or restricted time and life-changing events, are regularly monitored, internally reported, and are included in our annual incentive compensation program to reinforce that a safe work environment is crucial to FirstEnergy’s success.
FirstEnergy has shifted its focus from achieving low OSHA rates to proactively identifying and mitigating life-changing event exposure. This shift in focus strengthens FirstEnergy’s safety-first culture by aligning our leadership around the same goal and driving safer decisions from an engaged workforce who puts safety first. FirstEnergy continues to embed its "Leading with Safety" learnings and experiences and continues to enhance and reinforce leader and employee safety training and exposure control concepts to improve job site exposure identification, communication and mitigation to prevent life changing events. Further, FirstEnergy continues to expand its “Leading with Safety” experiences with its employees to achieve excellence in personal, contractor and public safety.
Diversity, Equity and Inclusion
DEI is a core value, as well as a corporate objective because a diverse, equitable and inclusive work environment delivers better service to customers, strong operational performance, innovation, and a safe, rewarding work experience for employees. FirstEnergy is focused on building a diverse workforce for the future, advancing a culture of equity, inclusion and belonging, and enhancing our diversity focus with our customers, in our communities and with our suppliers.
Affirmative steps taken at FirstEnergy to promote the core value of diversity, equity and inclusion include:
•FirstEnergy sponsors an executive diversity, equity and inclusion council consisting of senior management and other leaders across the company;
•Recently developed FirstEnergy Utilities Operations DEI Council focused on DEI related strategy and initiatives specific to operations employees including a large represented physical work group;
•Holding an annual “Employee Engagement Survey” to capture employees’ perspectives on their work experience and progress toward embracing a more inclusive culture. The survey results are discussed with employees in order to drive initiatives and action plans for improvement. This includes establishing:
▪a cross-functional working group to oversee the development and implementation of diversity, equity and inclusion action plans company-wide;
▪additional teams of employees embedded throughout FirstEnergy to implement local actions supporting diversity, equity and inclusion;
•FirstEnergy’s employees have established multiple employee business resource groups, known as "EBRGs," to further support diversity, equity and inclusion objectives through networking, mentoring, coaching, recruiting, development and community outreach;
•Employees are provided ongoing training and education on a variety of diversity, equity and inclusion topics;
•Enhanced transparency of diversity, equity and inclusion data, talent processes and measurement of progress;
•FirstEnergy has enhanced the recruiting processes to increase the number of diverse candidates considered for open positions and expand the diversity of teams interviewing those candidates. These enhancements include:
▪expanded relationship building with key diverse professional organizations, colleges and universities;
▪a more strategic approach to proactive talent sourcing that ensures increased diversity of candidate slates presented to hiring managers;
▪expanded diversity of teams interviewing those candidates.
•Increase leadership accountability by including diversity, equity and inclusion metrics in FirstEnergy’s annual incentive compensation program.
Workplace Flexibility
FirstEnergy is committed to supporting employees’ work/life balance by providing flexible work arrangements for many of its employees, and encouraging career growth as well as personal balance. In Fall 2022, FirstEnergy formally adopted guidelines to facilitate flexible work arrangements for eligible full-time and part-time non-bargaining employees. Flexible work arrangements, like permitting certain employees to work from alternate locations or to begin and end work at variable times, offer a variety of approaches to the way employees work. These approaches can help employees achieve their priorities and meet customer and business needs while promoting enhanced convenience and balance between work and personal commitments.
Employee Development
FirstEnergy’s employees are empowered to take ownership of their careers with increased openness into FirstEnergy’s internal and external hiring process and greater availability of tools and processes that support career management, talent reviews, succession planning and leadership selection. FirstEnergy is committed to preparing its high-performing workforce for the future and helping employees reach their full potential. That means developing employee skills and competencies and preparing emerging and experienced leaders for future management responsibilities.
Understanding FirstEnergy’s rapidly changing industry and strategy is key to employees’ ability to support FirstEnergy’s mission and meet its customers’ evolving needs. Key FirstEnergy development programs include:
•a mentoring program;
•new supervisor and manager program;
•experienced leader program;
•aspiring leader program;
•external partnership with the Center for Creative Leadership® and BeingFirst® for senior and executive leadership development,
•"Educate to Elevate," which provides access to post-secondary education and a path to both Associate’s and Bachelor’s degrees for employees;
•Power Systems Institute, an award-winning program for recruiting and developing the next generation of highly trained, dedicated and motivated line and substation workers; and
•A pilot apprentice line worker program in Ohio and Pennsylvania that was launched in 2022 and designed to address labor shortages in areas where we have had difficulty attracting talent or have experienced higher-than-average attrition rates.
Compensation and Benefits
FirstEnergy’s total rewards program is designed to attract, motivate, retain and reward employees for their role in the success of FirstEnergy. The base pay program is designed to provide individual base pay levels that balance an employee’s value to FirstEnergy with comparable jobs at peer companies. FirstEnergy is committed to ensuring that our internal policies and processes support pay equity, which was confirmed in a third-party review of our practices in 2019 and continues to be part of our normal ongoing process. Our internal processes ensure pay equity considerations are part of our normal ongoing process. The annual incentive compensation program is designed to reward the achievement of near-term corporate and business unit objectives. Additionally, FirstEnergy’s long-term incentive compensation program is designed to reward eligible executives for FirstEnergy’s achievement of longer-term goals intended to drive shareholder value and growth. In addition to base pay and incentive compensation plans, FirstEnergy offers a comprehensive benefits program, including a 401(k) savings plan and a defined benefit pension plan.
Information About Our Executive Officers (as of February 13, 2023)
Name Age Positions Held During Past Five Years Dates
John W. Somerhalder II 67 Interim Chief Executive Officer (A) 2022-Present
(H) Interim President (B) 2022-Present
Vice Chair and Executive Director (A) 2021-2022
CenterPoint Energy Inc, Interim President & Chief Executive Officer 2020
Samuel L. Belcher 54 Senior Vice President, Operations (B) 2021-Present
(I) President (C) (E) 2018-Present
Senior Vice President and President, FirstEnergy Utilities (B) 2018-2021
President and Chief Nuclear Officer (G) *-2018
Hyun Park 61 Senior Vice President and Chief Legal Officer (A) (B) 2021-Present
Senior Vice President and General Counsel (C) (D) (E) 2021-2022
LimNexus, Partner and General Counsel 2019-2021
Latham & Watkins, Of Counsel *-2019
K. Jon Taylor 49 Senior Vice President, Chief Financial Officer and Strategy (A) (B) 2021-Present
Senior Vice President and Chief Financial Officer (C) (E) 2020-Present
Senior Vice President and Chief Financial Officer (A) (B) 2020-2021
Vice President, Utility Operations (B) 2019-2020
President (D) 2019-2020
President, Ohio Operations (B) 2018-2019
Vice President (C) 2018-2019
Vice President and Controller (C) (E) *-2018
Vice President, Controller and Chief Accounting Officer (A) (B) *-2018
Jason J. Lisowski 41 Vice President, Controller and Chief Accounting Officer (A) (B) 2018-Present
Vice President and Controller (C) (E) 2018-Present
Controller and Treasurer (F) (G) *-2018
Christine L. Walker 57 Senior Vice President, Chief Human Resources Officer and Corporate Services (B) 2021-Present
Senior Vice President and Chief Human Resources Officer (B) 2019-2021
Vice President, Human Resources (B) 2018-2019
Executive Director, Talent Management (B) *-2018
* Indicates position held at least since January 1, 2018
(A) Denotes position held at FE
(B) Denotes position held at FESC
(C) Denotes position held at the Ohio Companies, the Pennsylvania Companies, MP, PE, FET, KATCo, TrAIL and ATSI
(D) Denotes position held at AGC
(E) Denotes position held at MAIT
(F) Denotes position held at FES and FG
(G) Denotes position held at FENOC
(H) Also served as Chair of the FE Board from May 2022 - Present
(I) On January 17, 2023, Samuel L. Belcher notified FirstEnergy of his intent to retire effective May 1, 2023
FirstEnergy Website and Other Social Media Sites and Applications
FirstEnergy's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports, and all other documents filed with or furnished to the SEC pursuant to Section 13(a) of the Exchange Act are made available free of charge on or through the "Investors" page of FirstEnergy’s website at www.firstenergycorp.com. These documents are also available to the public from commercial document retrieval services and the website maintained by the SEC at www.sec.gov.
These SEC filings are posted on the website as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. Additionally, FirstEnergy routinely posts additional important information, including press releases, investor presentations, investor factbooks and notices of upcoming events under the "Investors" section of FirstEnergy’s website and recognizes FirstEnergy’s website as a channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under Regulation FD. Investors may be notified of postings to the website by signing up for email alerts and Rich Site Summary feeds on the "Investors" page of FirstEnergy's website. FirstEnergy also uses Twitter® and Facebook® as additional channels of distribution to reach public investors and as a supplemental means of disclosing material non-public information for complying with its disclosure obligations under Regulation FD. Information contained on FirstEnergy’s website, Twitter® handle or Facebook® page, and any corresponding applications of those sites, shall not be deemed incorporated into, or to be part of, this report.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
We operate in a business environment that involves significant risks, many of which are beyond our control. Management regularly evaluates the most significant risks of its businesses and reviews those risks with the FE Board and appropriate Committees of the FE Board. The following risk factors and all other information contained in this report should be considered carefully when evaluating FirstEnergy. These risk factors could affect our financial results and cause such results to differ materially from those expressed in any forward-looking statements made by or on behalf of us. Below, we have identified risks we consider material. You should not interpret the disclosure of any risk factor to imply that the risk has not already materialized. Although the risks are organized by headings, and each risk is discussed separately, many are interrelated. Additional information on risk factors is included in Item 1, "Business,” Item 7, "Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and in other sections of this Form 10-K that include forward-looking and other statements involving risks and uncertainties that could impact our business and financial results.
Risks Associated with Damage to Our Reputation and HB 6 Related Litigation and Investigations
Damage to our reputation may arise from numerous sources making us vulnerable to negative customer perception, adverse regulatory outcomes, or other consequences, which could materially adversely affect our business, results of operations, and financial condition.
Our reputation is important. Damage to our reputation could materially adversely affect our business, results of operations, and financial condition and may arise from numerous sources further discussed below, including a breach of the DPA, negative outcomes associated with the SEC investigation or other HB 6 litigation or investigations, a significant cyber-attack or data security breach, failure to provide safe and reliable service, and operating coal-fired generation. Any damage to our reputation may lead to negative customer perception, which may make it difficult for us to compete successfully for new opportunities, or could adversely impact our ability to launch new sophisticated technology-driven solutions to meet our customer expectations. Further, a damaged reputation could further result in FERC and the state utility commissions that regulate our rates, and other regulatory and legislative authorities being less likely to view us in a favorable light, and could negatively impact the rates we charge customers or otherwise cause us to be susceptible to unfavorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements.
If We Violate our DPA That We Entered Into on July 20, 2021, It Could Have a Material Adverse Effect on our Reputation and Consolidated Financial Statements
On July 21, 2021, we entered into a three-year DPA with the U.S. Attorney’s Office that, subject to court proceedings, resolves the previously disclosed U.S. Attorney’s Office investigation into us relating to our lobbying and governmental affairs activities concerning HB 6. Under the DPA, the U.S. Attorney’s Office filed a single charge alleging that we conspired to commit honest services wire fraud. The DPA provides that the U.S. Attorney’s Office will defer any prosecution of such conspiracy charge and any other criminal or civil case against us in connection with the matters identified therein for a three-year period subject to certain obligations of ours, including, but not limited to, the following: (i) continued cooperation 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) payment of a criminal monetary penalty totaling $230 million, which was paid in 2021; (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) publication of a public acknowledgement of our conduct, including a statement, as dictated in the DPA, regarding our use of 501(c)(4) entities; and (v) continued implementation and review of our 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. If we are found to have breached the terms of the DPA, the U.S. Attorney’s Office may elect to prosecute, or bring a civil action against, us for conduct alleged in the DPA or known to the government, which could result in fines or penalties and could have a material adverse impact on our reputation or relationships with regulatory and legislative authorities, customers and other stakeholders, as well as our consolidated financial statements. Failure to comply with the DPA, including alleged failures to comply with anti-corruption and anti-bribery laws, may also result in a breach of certain covenants contained in our credit agreements and could result in an event of default under such agreements, and we would not be able to access our credit facilities for additional borrowings and letters of credit during the existence of any such default.
The SEC Investigation and HB 6 Related Litigation Could Have a Material Adverse Effect on our Reputation, Business, Financial Condition, Results of Operations, Liquidity or Cash Flows
Following the announcement by the U.S. Attorney’s Office for the S.D. Ohio of the investigation surrounding HB 6 in July 2020, certain of our stockholders and customers filed several lawsuits against us and certain current and former directors, officers and other employees, including the federal securities class action litigation In re FirstEnergy Corp. Securities Litigation (Federal District Court, S.D. Ohio). The investigations and litigation related to HB 6 could divert management’s focus and have resulted in, and could continue to result in substantial investigation expenses, and the commitment of substantial corporate resources. The outcome, duration, scope, result or related costs of the investigations and related litigation of the government investigations, particularly the SEC investigation and the securities class action lawsuit discussed below, are inherently uncertain. Therefore, any of these risks could impact us significantly beyond expectations. Moreover, we are unable to predict the potential for any
additional investigations or litigation, any of which could exacerbate these risks or expose us to potential criminal or civil liabilities, sanctions or other remedial measures, and could have a material adverse effect on our reputation, business, financial condition, results of operations, liquidity or cash flows.
On August 10, 2020, the SEC, through its Division of Enforcement, issued an order directing an investigation of possible securities laws violations by FirstEnergy, and on September 1, 2020, issued subpoenas to FirstEnergy and certain of its officers. We are cooperating with the SEC in their ongoing investigation. We believe that it is probable that FE will incur a loss in connection with the resolution of the SEC’s investigation. Given the ongoing nature and complexity of such investigation, we cannot yet reasonably estimate a loss or range of loss that may arise from the resolution of the SEC investigation, but such resolution could have a material adverse effect on our reputation, business, financial condition, results of operations, liquidity or cash flows.
We also believe that it is probable that FE will incur a loss in connection with the resolution of In re FirstEnergy Corp. Securities Litigation. Given the ongoing nature and complexity of such litigation, we cannot yet reasonably estimate a loss or range of loss that may arise from its resolution. However, if it is resolved against us substantial monetary damages could result and our reputation, business, financial condition, results of operations, liquidity or cash flows may be materially adversely affected.
These matters are likely to continue to have an adverse impact on the trading prices of our securities. See Note 13, “Commitments, Guarantees and Contingencies,” of the Notes to Consolidated Financial Statements, for additional details on the government investigations and subsequent litigation surrounding HB 6.
The HB 6 Related State Regulatory Investigations Could Have a Material Adverse Effect on our Reputation, Business, Financial Condition, Results of Operations, Liquidity or Cash Flows
There are several state regulatory matters associated with the ongoing governmental investigations including, but not limited to, the following:
•On August 16, 2022, the U.S. Attorney for the Southern District of Ohio requested that the PUCO stay the following pending HB 6 related matters for a period of six months, which request was granted by the PUCO on August 24, 2022:
◦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.
◦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
◦On December 30, 2020, the PUCO 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. The auditor’s report was filed on January 14, 2022 and the parties submitted final comments and responses in the second quarter 2022. See ”Outlook - Ohio” below for additional information regarding the auditor’s findings.
◦On March 10, 2021, the PUCO expanded the scope of an ongoing annual audit of the Ohio Companies’ Rider DCR for 2020 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 May 11, 2021, the Maryland Office of People’s Counsel filed a petition asking the MDPSC to open an investigation regarding several matters including possible impacts to PE as a result of the HB 6 investigations in Ohio. On July 26, 2021, the MDPSC opened a proceeding to allow discovery into: (i) whether the HB 6 investigations in Ohio have impacted or could impact the cost to PE of borrowing funds from the regulated companies money pool; (ii) whether money from PE was used to pay for bribes or other misconduct associated with the HB 6 investigations in Ohio or the legal costs related to those matters; and (iii) whether the Icahn Capital appointed directors would have the ability to assert substantial influence over PE in their roles as FE directors.
While FirstEnergy is committed to pursuing an open dialogue with stakeholders in an appropriate manner with respect to the numerous regulatory proceedings currently underway, the rates our Utilities and Transmission Companies are allowed to charge may be decreased as a result of actions taken by a regulator to which our Utilities and Transmission Companies are subject to jurisdiction, whether as a result of the DPA, any failure to have complied with anti-corruption laws, or otherwise.
We are unable to predict the adverse impacts on such regulatory matters, including with respect to rates, and, therefore, any of these risks could impact us significantly beyond expectations. Moreover, we are unable to predict the potential for any additional regulatory actions, any of which could exacerbate these risks or expose us to adverse outcomes in pending or future rate cases, and could have a material adverse effect on our reputation, business, financial condition, results of operations, liquidity or cash flows.
Risks Associated with the Execution of Recently Announced Strategic Initiatives
The Inability to Close the FET Minority Equity Interest Sale to Brookfield Announced in February 2023 May Have Material Adverse Effects on Our Cash Flows, Liquidity and Financial Condition
As previously disclosed, on November 6, 2021, FirstEnergy, along with FET, entered into the FET P&SA I, 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 would own 19.9% of the issued and outstanding membership interests of FET, for a purchase price of $2.375 billion. The transaction closed on May 31, 2022. On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The purchase price will be payable in part by the issuance of a promissory note expected to be in the principal amount of $1.75 billion. The remaining $1.75 billion of the purchase price will be payable in cash at the closing. As a result of the consummation of the transaction, Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1% ownership interests of FET. The transaction is subject to customary closing conditions, including approval from the FERC and certain state utility commissions, and completion of review by the CFIUS. In addition, pursuant to the FET P&SA II, FirstEnergy has agreed to make the necessary filings with the applicable regulatory authorities for the PA Consolidation. The FET Minority Equity Interest Sale is expected to close by early 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s GAAP financial statements.
This transaction involves various inherent risks, such as our ability to obtain the necessary regulatory and third-party approvals; the timing of and conditions imposed upon us by regulators in connection with such approvals; and our ability to realize the benefits expected from the transaction. In addition, various factors, including prevailing market conditions, could negatively impact the benefits we receive from this transaction. Our failure to consummate this transaction in a timely manner, including satisfying all closing conditions, could have material adverse effects on our cash flows, liquidity and financial condition.
The Consolidation of our Pennsylvania Companies May Not be Completed in a Timely Manner or at All, We May Not Be Able to Obtain the Approvals Required to Complete the PA Consolidation or Such Approvals May Contain Material Restrictions or Conditions Which May Make It Undesirable to Complete the PA Consolidation, and We Could Face Litigation Concerning the PA Consolidation, Whether or Not the PA Consolidation is Consummated
The PA Consolidation, including applicable asset sales is subject to numerous conditions, including the approval of NYPSC, PPUC and FERC, which may not approve one or more of the contemplated steps in the PA Consolidation, or such approvals may impose conditions on the completion, or require changes to the terms of the PA Consolidation, including restrictions on the business, operations or financial performance of the resulting operating company, which could be adverse to FirstEnergy’s interests. These conditions or changes could also delay or increase the cost of the PA Consolidation or limit the net income or financial prospects of the resulting operating company. Our inability to complete the PA Consolidation in a timely manner, or at all, including applicable asset sales, could hinder our ability to close the FET Minority Equity Interest Sale to Brookfield and could negatively affect our share price, as well as our future business and financial results. In addition, the work required to complete the PA Consolidation may place a significant burden on management and internal resources. Management's attention and other company resources may be focused on the PA Consolidation instead of on day-to-day management activities, including pursuing other opportunities beneficial to FirstEnergy.
Risks Associated with Regulation of Our Distribution and Transmission Segments
We are Focusing on Growing Our Regulated Distribution and Regulated Transmission Segments. Whether This Investment Strategy Will Deliver the Desired Result Is Subject to Certain Risks Which Could Adversely Affect Our Results of Operations and Financial Condition
We focus on capitalizing on investment opportunities available to our Regulated Transmission and Regulated Distribution segments as we focus on delivering enhanced customer service and reliability. The success of these efforts will depend, in part, on successful recovery of our transmission investments. Factors that may affect rate recovery of our transmission investments include: (1) FERC’s timely approval of rates to recover such investments; (2) whether the investments are included in PJM's Regional Transmission Expansion Plan; (3) FERC's evolving policies with respect to incentive rates for transmission assets; (4) FERC's evolving policies with respect to the calculation of the base ROE component of transmission rates; (5) consideration and potential impact of the objections of those who oppose such investments and their recovery; and (6) timely development, construction, and operation of the new facilities.
The success of these efforts will also depend, in part, on any future distribution rate cases or other filings seeking cost recovery for distribution system enhancements in the states where our Utilities operate and transmission rate filings at FERC. Any denial of, or delay in, the approval of any future distribution or transmission rate requests could restrict us from fully recovering our cost of service, may impose risks on the Regulated Distribution and Regulated Transmission operations, and could have a material adverse effect on our regulatory strategy, results of operations and financial condition.
Our efforts also could be impacted by our ability to finance the proposed expansion projects while maintaining adequate liquidity. There can be no assurance that our investment strategy in our Regulated Distribution and Regulated Transmission segments will deliver the desired result which could adversely affect our results of operations and financial condition.
Complex and Changing Government Regulations and Actions, Including Those Associated with Rates, Could Have a Negative Impact on Our Business, Financial Condition, Results of Operations and Cash Flows
We are subject to comprehensive regulation by various federal, state and local regulatory agencies that significantly influence our operating environment. Changes in, or reinterpretations of, existing laws or regulations, or the imposition of new laws or regulations, could require us to incur additional costs or change the way we conduct our business, and therefore could have a material adverse impact on our results of operations and financial condition.
Our Utilities and Transmission Companies provide service at rates approved by one or more regulatory commissions. Thus, the rates the Utilities and Transmission Companies are allowed to charge may be decreased as a result of actions taken by FERC or by a state regulatory commission in the states in which our Utilities operate. Also, these rates may not be set to recover such applicable utility's expenses at any given time. Additionally, there may also be a delay between the timing of when costs are incurred and when costs are recovered, if at all. For example, we may be unable to timely recover the costs for our energy efficiency investments or expenses and additional capital or lost revenues resulting from the implementation of aggressive energy efficiency programs. While rate regulation is premised on providing an opportunity to earn a reasonable return on investments and recovery of operating expenses, there can be no assurance that the applicable regulatory commission will determine that all of our costs have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs in a timely manner. Further, there can be no assurance that we will retain the expected recovery in future rate cases.
State Rate Regulation May Delay or Deny Full Recovery of Costs and Impose Risks on Our Operations. Any Denial of or Delay in Cost Recovery Could Have an Adverse Effect on Our Business, Results of Operations, Liquidity, Cash Flows and Financial Condition
Each of the Utilities' retail rates are set by its respective regulatory agency for utilities in the state 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 - through traditional, cost-based regulated utility ratemaking. As a result, any of the Utilities may not be permitted to recover its costs and, even if it is able to do so, there may be a significant delay between the time it incurs such costs and the time it is allowed to recover them. Factors that may affect outcomes in the distribution rate cases include: (i) the value of plant in service; (ii) authorized rate of return; (iii) capital structure (including hypothetical capital structures); (iv) depreciation rates; (v) the allocation of shared costs, including consolidated deferred income taxes and income taxes payable across the Utilities; (vi) regulatory approval of rate recovery mechanisms for capital investment spending programs; and (vii) the accuracy of forecasts used for ratemaking purposes in "future test year" cases.
FirstEnergy can provide no assurance that any base rate request filed by any of the Utilities will be granted in whole or in part. Any denial of, or delay in, any base rate request could restrict the applicable utility from fully recovering its costs of service, may impose risks on its operations, and may negatively impact its results of operations, cash flows and financial condition. In addition, to the extent that any of the Utilities seeks rate increases after an extended period of frozen or capped rates, pressure may be exerted on the applicable legislators and regulators to take steps to control rate increases, including through some form of rate increase moderation, reduction or freeze. Any related public discourse and debate can increase uncertainty associated with the regulatory process, the level of rates and revenues that are ultimately obtained, and the ability of the Utility to recover costs. Such uncertainty may restrict operational flexibility and resources, reduce liquidity and increase financing costs.
Federal Rate Regulation May Delay or Deny Full Recovery of Costs and Impose Risks on Our Operations. Any Denial or Reduction of, or Delay in Cost Recovery Could Have an Adverse Effect on Our Business, Results of Operations, Cash Flows and Financial Condition
FERC policy currently permits recovery of prudently incurred costs associated with cost-of-service-based wholesale power rates and the expansion and updating of transmission infrastructure within its jurisdiction. FERC’s policies on recovery of transmission costs continue to evolve, evidenced by ongoing proceedings to determine an appropriate ROE methodology to determine transmission ROEs, and to determine whether FERC’s existing policies on transmission rate incentives should be revised. If FERC were to adopt a different policy regarding recovery of transmission costs or if there is any resulting delay in cost recovery, our strategy of investing in transmission could be affected. If FERC were to lower the rate of return it has authorized for FirstEnergy's cost-based wholesale power rates or transmission investments and facilities, it could reduce future earnings and cash flows, and adversely impact our financial condition.
We Could be Subject to Higher Costs and/or Penalties Related to Mandatory Reliability Standards Set by NERC/FERC or Changes in the Rules of Organized Markets, Which Could Have an Adverse Effect on our Financial Condition
Owners, operators, and users of the bulk electric system are subject to mandatory reliability standards promulgated by NERC and approved by FERC. The standards are based on the functions that need to be performed to ensure that the bulk electric
system operates reliably. NERC, RFC and FERC can be expected to continue to refine existing reliability standards as well as develop and adopt new reliability standards. Compliance with modified or new reliability standards may subject us to higher operating costs and/or increased investments. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties. FERC has authority to impose penalties up to and including $1.5 million per day for failure to comply with these mandatory electric reliability standards.
In addition to direct regulation by FERC, we are also subject to rules and terms of participation imposed and administered by various RTOs and ISOs that can have a material adverse impact on our business. For example, the independent market monitors of ISOs and RTOs may impose bidding and scheduling rules to curb the perceived potential for exercise of market power and to ensure the markets function appropriately. Such actions may materially affect our ability to sell, and the price we receive for, our energy and capacity. In addition, PJM may direct our transmission-owning affiliates to build new transmission facilities to meet PJM's reliability requirements or to provide new or expanded transmission service under the PJM Tariff.
We may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. We may be required to expand our transmission system according to decisions made by an RTO rather than our own internal planning processes. Various proposals and proceedings before FERC may cause transmission rates to change from time to time. In addition, RTOs have been developing rules associated with the allocation and methodology of assigning costs associated with improved transmission reliability, reduced transmission congestion and firm transmission rights that may have a financial impact on us.
As a member of PJM, which is an RTO, we are subject to certain additional risks, including those associated with the allocation among members of losses caused by unreimbursed defaults of other participants in PJM’s market and those associated with complaint cases filed against PJM that may seek refunds of revenues previously earned by its members.
Risks Related to Business Operations Generally
Temperature Variations as Well as Severe Weather Conditions or Other Natural Disasters Could Have an Adverse Impact on Our Results of Operations and Financial Condition
Weather conditions directly influence the demand for electric power. Demand for power generally peaks during the summer and winter months, with market prices also typically peaking at that time. Overall operating results may fluctuate based on weather conditions. In addition, we have historically sold less power, and consequently received less revenue, when seasonal weather conditions are milder. In addition, severe weather, such as tornadoes, hurricanes, ice or snowstorms, droughts, high winds or other natural disasters, may cause outages and property damage that may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned under these conditions would be particularly burdensome during a peak demand period and could have an adverse effect on our financial condition and results of operations, which adverse effects could be further exacerbated by an increased frequency of such severe weather events.
Cyber-Attacks, Data Security Breaches and Other Disruptions to Our Information Technology Systems, or Those of Third Parties We Do Business With, Could Compromise Our Business Operations, Critical and Proprietary Information and Employee and Customer Data, Which Could Have a Material Adverse Effect on Our Business, Results of Operations, Financial Condition and Reputation
In the ordinary course of our business, we depend on information technology systems that utilize sophisticated operational systems and network infrastructure to run all facets of our regulated generation, transmission and distribution services. Additionally, we store sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers, suppliers, business partners and other individuals in our data centers and on our networks. We may also need to provide sensitive data to vendors and service providers who require access to this information. The secure maintenance of information and information technology systems is critical to our operations.
Over the last several years, there has been an increase in the frequency of cyber-attacks by terrorists, hackers, international activist organizations, countries and individuals. These and other unauthorized parties may attempt to gain access to our network systems or facilities, or those of third parties with whom we do business in many ways, including directly through our network infrastructure or through fraud, trickery, or other forms of deceiving our employees, contractors and temporary staff. Additionally, our information and information technology systems and those of our vendors and service providers may be increasingly vulnerable to data security breaches, damage and/or interruption due to viruses, human error, malfeasance, faulty password management or other malfunctions and disruptions. Further, hardware, software, or applications we develop or procure from third parties may contain defects in design or manufacture or other problems that could unexpectedly compromise information and/or security.
Despite security measures and safeguards we have employed, including certain measures implemented pursuant to mandatory NERC Critical Infrastructure Protection standards, our infrastructure may be increasingly vulnerable to such attacks as a result of the rapidly evolving and increasingly sophisticated means by which attempts to defeat our security measures and gain access to
our information technology systems may be made. Also, we may be at an increased risk of a cyber-attack and/or data security breach due to the nature of our business.
Any such cyber-attack, data security breach, damage, interruption and/or defect could: (i) disable our generation, transmission (including our interconnected regional transmission grid) and/or distribution services for a significant period of time; (ii) delay development and construction of new facilities or capital improvement projects; (iii) adversely affect our customer operations; (iv) corrupt data; and/or (v) result in unauthorized access to the information stored in our data centers and on our networks and those of our vendors and service providers, including, company proprietary information, supplier information, employee data, and personal customer data, causing the information to be publicly disclosed, lost or stolen or result in incidents that could result in economic loss and liability and harmful effects on the environment and human health, including loss of life. Additionally, because our regulated generation, transmission and distribution services are part of an interconnected system, disruption caused by a cybersecurity incident at another utility, electric generator, RTO, or commodity supplier could also adversely affect our operations.
Although we maintain cyber insurance and property and casualty insurance, there can be no assurance that liabilities or losses we may incur, including as a result of cybersecurity-related litigation, will be covered under such policies or that the amount of insurance will be adequate. Further, as cyber threats become more difficult to detect and successfully defend against, there can be no assurance that we can implement adequate preventive measures, accurately assess the likelihood of a cyber-incident or quantify potential liabilities or losses. Also, we may not discover any data security breach and loss of information for a significant period of time after the data security breach occurs particularly those of our vendors and service providers.
For all of these reasons, 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 our reputation and/or the rendering of our internal controls ineffective, all of which could materially adversely affect our business, results of operations, financial condition and reputation.
If Our "FE Forward" Initiative and Other Cost Saving Initiatives Do Not Achieve the Expected Benefits, There Could Be Negative Impacts to FirstEnergy's Business, Results of Operations and Financial Condition
In February 2021, we announced a new initiative, FE Forward, to build upon our strong operations and business fundamentals and deliver immediate value and resilience, with targeted working capital improvements by 2022 and capital efficiencies ramping up through 2024 that would be redeployed in a more diverse capital investment program. In the two years that FE Forward has been active, we have realized working capital improvements and annualized capital expenditure efficiencies in line with our previously disclosed expectations. After assessing our accomplishments and shortfalls, FE Forward has been integrated into our ongoing efforts for continuous improvement, including the strategic reduction of operating expenditures and continued reinvestment in a more diverse capital program in support of our long-term strategy. As such, FirstEnergy has transitioned away from measuring these cash flow metrics and will no longer publish a forecast of these metrics.
In addition to FE Forward, FirstEnergy will leverage other opportunities to reduce costs - such as filling only critical positions, implementing our facility optimization plans, as well as exploring other additional, sustainable opportunities, such as reducing contractor spend. There can be no assurance that FE Forward and our other cost saving initiatives will provide the anticipated benefits to our business, results of operations and financial condition in a timely manner, if at all.
Our ability to achieve the benefits from FE Forward and our other cost saving initiatives is subject to many estimates and assumptions. FirstEnergy could experience unexpected delays and business disruptions resulting from supporting these initiatives, decreased productivity, and higher than anticipated costs, any of which may impair our ability to reduce operating expenditures and to achieve anticipated results or otherwise harm FirstEnergy's business, results of operations and financial condition.
Inflation may negatively impact our financial condition, results of operations, liquidity, and cash flows.
Prices for equipment, materials, supplies, employee labor contractor services, together with the cost of variable-rate debt have increased during 2022, and could continue to increase in 2023 and beyond. Long-term inflationary pressures may result in such prices continuing to increase more quickly than expected. Inflation increases costs for labor, materials and services, and we may be unable to secure these resources on economically acceptable terms or offset such costs with increased revenues, operating efficiencies, or cost savings, which may adversely impact our financial condition, results of operations, liquidity, and cash flows.
Continued Supply Chain Disruptions Could Have an Adverse Effect on Our Results of Operations, Cash Flow and Financial Condition.
We have continued to experience supply chain challenges due to economic conditions that have developed since the start of the COVID-19 pandemic, with order lead times increasing across numerous material categories and with some as much as doubling from pre-pandemic lead times. Some key suppliers have struggled with labor shortages and raw material availability, which along
with increasing inflationary pressure, have increased the costs and decreased the availability of certain materials, equipment and contractors. FirstEnergy has taken steps to mitigate these risks and does not currently expect service disruptions or any material impact on its capital spending plan. However, the situation remains fluid and a prolonged continuation or further increase in supply chain disruptions could have an adverse effect on FirstEnergy’s results of operations, cash flow and financial condition.
We Are Subject to Financial Performance Risks from Regional and General Economic Cycles as Well as Heavy Industries such as Shale Gas, Automotive and Steel
Our business follows economic cycles. Economic conditions, including inflationary pressures, impact the demand for electricity and declines in the demand for electricity will reduce our revenues. The regional economy in which our Utilities operate is influenced by conditions in industries in our business territories, e.g., shale gas, automotive, chemical, steel and other heavy industries, and as these conditions change, our revenues will be impacted.
We Are Subject to Risks Arising from the Operation of Our Power Plants and Transmission and Distribution Equipment Which Could Reduce Revenues, Increase Expenses and Have a Material Adverse Effect on Our Business, Financial Condition and Results of Operations
Operation of generation, transmission and distribution facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, human error in operations or maintenance, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental requirements and governmental interventions, and performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution delivery systems. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.
Capital Investments and Construction Projects May Not be Completed Within Forecasted Budget, Schedule or Scope Parameters or Could be Canceled Which Could Adversely Affect Our Business and Results of Operations
Our business plan calls for extensive capital investments totaling approximately $18 billion from 2021 through 2025, including but not limited to our Energizing the Future transmission expansion program and our distribution grid modernization, resiliency and reliability programs. We may be exposed to the risk of substantial price increases in, or the adequacy or availability of, the costs of labor and materials used in construction, nonperformance of equipment and increased costs due to inflation, delays, including delays relating to the procurement of permits or approvals, adverse weather or environmental matters. We engage numerous contractors and enter into a large number of construction agreements to acquire the necessary materials and/or obtain the required construction-related services. As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us. Such risk could include our contractors’ inabilities to procure sufficient skilled labor as well as potential work stoppages by that labor force. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, with resulting delays in those and other projects. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. Also, because we enter into construction agreements for the necessary materials and to obtain the required construction related services, any cancellation by FirstEnergy of a construction agreement could result in significant termination payments or penalties. Any delays, increased costs or losses, or cancellation of a construction project could adversely affect our business and results of operations, particularly if we are not permitted to recover any such costs in rates.
Physical Acts of War, Terrorism. Sabotage or Other Attacks on any of Our Facilities or Other Infrastructure Could Have an Adverse Effect on Our Business, Results of Operations, Cash Flows and Financial Condition
As a result of the continued threat of physical acts of war, terrorism, sabotage or other attacks in the United States, our electric generation, fuel storage, transmission and distribution facilities and other infrastructure, including power plants, transformer and high voltage lines and substations, or the facilities or other infrastructure of an interconnected company, could be direct targets of, or indirect casualties of, an act of war, terrorism, sabotage or other attack, which could result in disruption of our ability to generate, purchase, transmit or distribute electricity for a significant period of time, otherwise disrupt our customer operations and/or result in incidents that could result in harmful effects on the environment and human health, including loss of life. Any such disruption or incident could result in a significant decrease in revenue, significant additional capital and operating costs, including costs to implement additional security systems or personnel to purchase electricity and to replace or repair our assets over and above any available insurance reimbursement, higher insurance deductibles, higher premiums and more restrictive insurance policies, legal claims or proceedings, greater regulation with higher attendant costs, generally, and significant damage to our reputation, which could have a material adverse effect on our business, results of operations, cash flows and financial condition.
Failure to Provide Safe and Reliable Service and Equipment Could Result in Serious Injury or Loss of Life That May Harm Our Business Reputation and Adversely Affect Our Operating Results
We are committed to providing safe and reliable service and equipment in our franchised service territories. Meeting this commitment requires the expenditure of significant capital resources. However, our employees, contractors and the general public may be exposed to dangerous environments due to the nature of our operations. Failure to provide safe and reliable service and equipment due to various factors, including equipment failure, accidents and weather, could result in serious injury or loss of life that may harm our business reputation and adversely affect our operating results through reduced revenues, increased capital and operating costs, litigation or the imposition of penalties/fines or other adverse regulatory outcomes.
The Outcome of Litigation, Arbitration, Mediation, and Similar Proceedings Involving Our Business, or That of One or More of Our Operating Subsidiaries, Is Unpredictable and an Adverse Decision in Any Material Proceeding Could Have a Material Adverse Effect on Our Financial Condition and Results of Operations
We are involved in a number of litigation, arbitration, mediation, and similar proceedings. These and other matters may divert financial and management resources that would otherwise be used to benefit our operations. Further, no assurances can be given that the resolution of these matters will be favorable to us. If certain matters were ultimately resolved unfavorably to us, the results of operations and financial condition of FirstEnergy could be materially adversely impacted.
In addition, we are sometimes subject to investigations and inquiries by various state and federal regulators due to the heavily regulated nature of our industry. Any material inquiry or investigation could potentially result in an adverse ruling against us, which could have a material adverse impact on our financial condition and operating results.
We Face Certain Human Resource Risks Associated with Potential Labor Disruptions and/or with the Availability of Trained and Qualified Labor to Meet Our Future Staffing Requirements
We are continually challenged to find ways to balance the retention of our aging skilled workforce while recruiting new talent to mitigate losses in critical knowledge and skills due to retirements. Workforce demographic issues challenge employers nationwide and are of particular concern to the electric utility industry. Over the next three years, 34% percent of our current employees will meet the eligibility requirements to retire. Our costs, including costs for contractors to replace employees and productivity costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business. If we are unable to successfully recruit and retain an appropriately qualified workforce, our results of operations could be negatively affected.
Additionally, a significant number of our physical workforce are represented by unions. While we believe that our relations with our employees are generally fair, we cannot provide assurances that the company will be completely free of labor disruptions such as work stoppages, work slowdowns, union organizing campaigns, strikes, lockouts or that any labor disruption will be favorably resolved. Mitigating these risks could require additional financial commitments and the failure to prevent labor disruptions and retain and/or attract trained and qualified labor could have an adverse effect on our business.
Significant Increases in Our Operation and Maintenance Expenses, Including Our Health Care and Pension Costs, Could Adversely Affect Our Future Earnings and Liquidity
We continually focus on limiting and reducing where possible, our operation and maintenance expenses. However, we expect to continue to face increased cost pressures related to operation and maintenance expenses, including in the areas of health care and pension costs. We have experienced health care cost inflation in recent years, and we expect our cash outlay for health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken requiring employees and retirees to bear a higher portion of the costs of their health care benefits. The measurement of our expected future health care and pension obligations and costs is highly dependent on a variety of assumptions, many of which relate to factors beyond our control. These assumptions include investment returns, interest rates, discount rates, health care cost trends, benefit design changes, salary increases, the demographics of plan participants and regulatory requirements. While we anticipate that our operation and maintenance expenses will continue to increase, if actual results differ materially from our assumptions, our costs could be significantly higher than expected which could adversely affect our results of operations, financial condition and liquidity.
Changes in Technology and Regulatory Policies May Make Our Facilities Significantly Less Competitive and Adversely Affect Our Results of Operations
Traditionally, electricity is generated at large, central station generation facilities. This method results in economies of scale and lower unit costs than newer generation technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in newer generation technologies will make newer generation technologies more cost-effective, or that legislation addressing climate change at the federal or state level together with changes in regulatory policy will create incentives or benefits that otherwise make these newer generation technologies even more competitive with central station electricity production. To the extent that newer generation technologies are connected directly to load, bypassing the transmission and distribution systems, potential impacts could include decreased transmission and distribution revenues, stranded assets and
increased uncertainty in load forecasting and integrated resource planning and could adversely affect our business and results of operations.
Energy Companies are Subject to Adverse Publicity Causing Less Favorable Regulatory and Legislative Outcomes Which Could Have an Adverse Impact on Our Business
Energy companies, including the Utilities and Transmission Companies, have been the subject of criticism on matters including the reliability of their distribution services and the speed with which they are able to respond to power outages, such as those caused by storm damage. Adverse publicity of this nature, as well as negative publicity associated with the operation of coal-fired generation or proceedings seeking regulatory recoveries may cause less favorable legislative and regulatory outcomes and damage our reputation, which could have an adverse impact on our business.
Risks Associated with Environmental Matters
We Have Coal-Fired Generation Capacity, Which Exposes Us to Risk from Regulations Relating to Coal, GHGs and CCRs and Could Lead to Increased Costs or the Need to Spend Significant Resources to Defend Allegations of Violation
Historically, coal-fired generation has greater exposure to the costs of complying with federal, state and local environmental statutes, rules and regulations relating to air emissions, including GHGs and CCR disposal, than other types of electric generation facilities. These legal requirements and any future initiatives could impose substantial additional costs and, in the case of GHG requirements, could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities and could require our coal-fired generation to curtail generation or cease to generate. Failure to comply with any such existing or future legal requirements may also result in the assessment of fines and penalties. Significant resources also may be expended to defend against allegations of violations of any such requirements.
We Have a Minority Ownership Stake in a Coal Mine That Requires Governmental Permits and Approvals to Operate and a Failure of the Coal Mine to Renew and Maintain Such Permits and Approvals May Adversely Affect Our Results of Operations and Cash Flow
FEV currently holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales predominantly in international markets. The viability of our investment depends upon several factors beyond our control, including, but not limited to: Signal Peak’s ability to renew and maintain governmental permits and approvals and remain in compliance with federal, state, and local safety and environmental statutes, rules, and regulations affecting the coal mining industry. Failure by Signal Peak to renew and maintain necessary permits and approvals, and to comply with any such statutes, rules and regulations, may impair its operations and the ability to generate cash flows necessary for Global Holding to pay future dividends and contribute to FirstEnergy’s earnings.
Signal Peak operates a single underground coal mine in south-central Montana and must obtain numerous governmental permits and approvals that impose strict conditions and obligations relating to, among other things, various environmental and safety matters in connection with its mining and coal transportation operations. The rules applicable to these permits and approvals are complex and can change over time. Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. In addition, the public has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention. Limitations on Signal Peak’s ability to conduct its mining operations due to its inability to obtain or renew necessary permits or similar approvals could materially reduce or even halt production at the mine resulting in an adverse effect on our balance sheet, results of operations and cash flow.
Signal Peak is currently a party to litigation that is challenging the validity of its permit to expand its mine into adjacent leased federal coal reserves. After receiving initial approval in 2015 from the OSMRE to expand the mine, environmental non-governmental organizations filed suit in the United States District Court for the District of Montana the same year challenging OSMRE’s environmental assessment, which was a finding of no significant impact, and the expansion approval. The District Court affirmed OSMRE’s conclusions, and the environmental non-governmental organizations appealed to the U.S. Court of Appeals for the Ninth Circuit. In April 2022, the Ninth Circuit Court reversed the District Court’s ruling affirming the expansion approval and remanded the case back to the District Court. On February 10, 2023, the District Court vacated the permit issued by OSMRE, which would restrict Signal Peak’s ability to mine federal coal until OSMRE completes an environmental impact statement and reissues the permit. While the District Court’s ruling is not expected to materially impede Signal Peak’s ability to conduct its mining operations over the next 12-24 months, the inability to successfully obtain the permit from OSMRE would prohibit Signal Peak from mining those adjacent leased federal coal reserves and could further adversely impact Signal Peak from efficiently and economically conducting its mining operations thus reducing its production, cash flow and profitability.
Costs of Compliance with Environmental Laws are Significant, and the Cost of Compliance with New Environmental Laws, Including Limitations on GHG Emissions Related to Climate Change, Could Adversely Affect Our Cash Flows and Financial Condition
Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations. Compliance with these legal requirements requires us to incur costs for, among other things, installation and operation of pollution control
equipment, emissions monitoring and fees, remediation and permitting at our facilities. These expenditures have been significant in the past and may increase in the future. We may be forced to shut down other facilities or change their operating status, either temporarily or permanently, if we are unable to comply with these or other existing or new environmental requirements, or if the expenditures required to comply with such requirements are unreasonable.
Moreover, new environmental laws or regulations including, but not limited to GHG Emissions, CWA effluent limitations imposing more stringent water discharge regulations, or other changes to existing environmental laws or regulations may materially increase our costs of compliance or accelerate the timing of capital expenditures or other capital-like investments. Our compliance strategy, including but not limited to, our assumptions regarding estimated compliance costs, although reasonably based on available information, may not successfully address future relevant standards and interpretations. If we fail to comply with environmental laws and regulations or new interpretations of longstanding requirements, even if caused by factors beyond our control, that failure could result in the assessment of civil or criminal liability and fines. In addition, any alleged violation of environmental laws and regulations may require us to expend significant resources to defend against any such alleged violations. Due to the uncertainty of control technologies available to reduce GHG emissions, any legal obligation that requires substantial reductions of GHG emissions could result in substantial additional costs, adversely affecting cash flows and profitability, and raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities.
The EPA is Conducting NSR Investigations at Generating Plants that We Currently or Formerly Owned, Which Could Result in the Imposition of Fines
We may be subject to risks from changing or conflicting interpretations of existing laws and regulations, including, for example, the applicability of the EPA's NSR programs. Under the CAA, modification of our existing and former generation facilities in a manner that results in increased emissions could subject our existing generation facilities to the far more stringent new source standards applicable to new generation facilities.
The EPA has taken the view that many companies, including many energy producers, have been modifying emissions sources in violation of NSR standards during work considered by the companies to be routine maintenance. The EPA has investigated alleged violations of the NSR standards at certain of our existing and former generating facilities. We intend to vigorously pursue and defend our position, but we are unable to predict their outcomes, which could include the possible imposition of fines.
We Are or May Be Subject to Environmental Liabilities, Including Costs of Remediation of Environmental Contamination at Current or Formerly Owned Facilities, Which Could Have a Material Adverse Effect on Our Results of Operations and Financial Condition
We may be subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned or operated by us and of property contaminated by hazardous substances that we may have generated regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. We are currently involved in a number of proceedings relating to sites where hazardous substances have been released and we may be subject to additional proceedings in the future. We also have current or previous ownership interests in sites associated with the production of gas and the production and delivery of electricity for which we may be liable for additional costs related to investigation, remediation and monitoring of these sites. Remediation activities associated with our former MGP operations are one source of such costs. Citizen groups or others may bring litigation over environmental issues including claims of various types, such as property damage, personal injury, and citizen challenges to compliance decisions on the enforcement of environmental requirements, such as opacity and other air quality standards, which could subject us to penalties, injunctive relief and the cost of litigation. We cannot predict the amount and timing of all future expenditures (including the potential or magnitude of fines or penalties) related to such environmental matters, although we expect that they could be material. In addition, there can be no assurance that any liabilities, losses or expenditures we may incur related to such environmental liabilities or contamination will be covered under any applicable insurance policies or that the amount of insurance will be adequate.
In some cases, a third party who has acquired assets including operating and deactivated nuclear power stations from us has assumed the liability we may otherwise have for environmental matters related to the transferred property. If the transferee fails to discharge the assumed liability or disputes its responsibility, a regulatory authority or injured person could attempt to hold us responsible, and our remedies against the transferee may be limited by the financial resources of the transferee.
We Could be Exposed to Private Rights of Action Relating to Environmental Matters Seeking Damages Under Various State and Federal Law Theories Which Could Have an Adverse Impact on Our Results of Operations, Financial Condition, Cash Flows and Business Operations
Private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other relief. For example, claims have been made against certain energy companies alleging that CO2 emissions from power generating facilities constitute a public nuisance under federal and/or state common law. While FirstEnergy is not a party to this litigation, it, and/or one of its subsidiaries, could be named in other actions making similar allegations. An unfavorable ruling in any such case could result in the need to make modifications to our coal-fired generation or reduce emissions, suspend operations or pay money damages or penalties. Adverse rulings in these or other types of actions could
have an adverse impact on our results of operations, cash flows and financial condition and could significantly impact our business operations.
We Are and May Become Subject to Legal Claims Arising from the Presence of Asbestos or Other Regulated Substances at Some of Our Facilities that May Have an Adverse Impact on Our Business Operations, Financial Condition and Cash Flows
We have been named as a defendant in pending asbestos litigations involving multiple plaintiffs and multiple defendants, in several states. The majority of these claims arise out of alleged past exposures by contractors (and in Pennsylvania, former employees) at both currently and formerly owned electric generation plants. In addition, asbestos and other regulated substances are, and may continue to be, present at currently owned facilities where suitable alternative materials are not available. We believe that any remaining asbestos at our facilities is contained and properly identified in accordance with applicable governmental regulations, including OSHA. The continued presence of asbestos and other regulated substances at these facilities, however, could result in additional actions being brought against us. This is further complicated by the fact that many diseases, such as mesothelioma and cancer, have long latency periods in which the disease process develops, thus making it impossible to accurately predict the types and numbers of such claims in the near future. While insurance coverages exist for many of these pending asbestos litigations, others have no such coverages, resulting in FirstEnergy being responsible for all defense expenditures, as well as any settlements or verdict payouts.
Risks Associated with Climate Change Matters
Transition Risks Associated with Climate Change, Including Those Related to Regulatory Mandates Could Negatively Impact Our Financial Results
Where federal or state legislation mandates the use of renewable fuel sources, such as wind and solar and such legislation does not also provide for adequate cost recovery, it could result in significant changes in our business, including material increases in renewable energy credit purchase costs, purchased power costs and capital investments. Such mandatory renewable portfolio requirements may have an adverse effect on our financial condition and results of operations.
A number of regulatory and legislative bodies have introduced requirements and/or incentives to reduce peak demand and energy consumption. Such conservation programs could result in load reduction and adversely impact our financial results in different ways. We currently have energy efficiency riders in place in certain of our states to recover the cost of these programs either at or near a current recovery time frame in the states where we operate.
In our regulated operations, energy conservation could negatively impact us depending on the regulatory treatment of the associated impacts. Should we be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact. In the past, we have been adversely impacted by reduced electric usage due in part to energy conservation efforts such as the use of efficient lighting products such as compact fluorescent lights, halogens and light emitting diodes. We are unable to determine what impact, if any, conservation will have on our financial condition or results of operations.
Additionally, failure to meet regulatory or legislative requirements to reduce energy consumption or otherwise increase energy efficiency could result in penalties that could adversely affect our financial results.
Financial and Reputational Risks Associated with Owning Coal-Fired Generation and a Minority-Interest in a Coal Mine May Have an Adverse Impact on Our Business Operations, Financial Condition and Cash Flows
MP's fleet consists of 3,093 MWs of coal-fired generation and FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. Certain members of the investment community have adopted investment policies promoting the divestment of, or otherwise limiting new investments in, coal-fired generation and coal mining. The impact of such efforts may adversely affect the demand for and price of our common stock and impact our and MP's access to the capital and financial markets. Further, certain insurance companies have established policies limiting coal-related underwriting and investment. Consequently, these policies aimed at coal-fired generation could have a material adverse impact on our reputation, business operations, financial condition, and cash flows.
The Physical Risks Associated with Climate Change May Have an Adverse Impact on Our Business Operations, Financial Condition and Cash Flows
Physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, and other related phenomena, could affect some, or all, of our operations. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Utilities' service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Further, as extreme weather conditions increase system stress, we may incur costs relating to additional system backup or service interruptions, and in some instances, we may be unable to recover such costs. For all of these reasons, these physical risks could have an adverse financial impact on our
business operations, financial condition and cash flows. Climate change poses other financial risks as well. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes. Increased energy use due to weather changes may require us to invest in additional system assets and purchase additional power. Additionally, decreased energy use due to weather changes may affect our financial condition through decreased rates, revenues, margins or earnings.
Risks Associated with Markets and Financial Matters
Our Results of Operations and Financial Condition May be Adversely Affected by the Volatility in Pension and OPEB Investments and Obligations Due to Capital Market Performance and Other Changes
FirstEnergy recognizes in income the change in the fair value of plan assets and net actuarial gains and losses for its pension and OPEB plans. This adjustment is recognized in the fourth quarter of each year and whenever a plan is determined to qualify for a remeasurement, resulting in greater volatility in pension and OPEB expenses and may materially impact our results of operations.
Our financial statements reflect the values of the assets held in trust to satisfy our obligations under pension and OPEB plans. Certain of the assets held in these trusts do not have readily determinable market values. Changes in the estimates and assumptions inherent in the value of these assets could affect the value of the trusts. If the value of the assets held by the trusts declines by a material amount, our funding obligation to the trusts could materially increase. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. Forecasting investment earnings and costs to pay future pension and other obligations requires significant judgment and actual results may differ significantly from current estimates. Capital market conditions that generate investment losses or that negatively impact the discount rate and increase the present value of liabilities may increase our future pension and OPEB expenses and further may have significant impacts on the value of the pension and other trust funds, which could require significant additional funding and negatively impact our results of operations and financial position.
Our Results of Operations and Financial Condition May be Adversely Affected by Certain Risks Related to our Minority Interest in a Coal Mine
FEV currently holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales predominantly in international markets. In the second quarter of 2022, FEV received its first dividend of $20 million after more than ten years of equity ownership in the joint venture and received total dividends in 2022 of $170 million. Additionally, during 2022, FirstEnergy recognized approximately $168 million of pre-tax earnings (approximately $128 million after-tax) from its investment in Global Holding. Global Holding’s ability to positively affect our results of operations or pay future dividends depends upon several factors beyond our control, including, but not limited to: the market price of coal, the availability and reliability of transportation facilities and other systems, and Global Holding’s ability to renew and maintain governmental permits and approvals and remain in compliance with safety and environmental regulations affecting the coal mining industry.
The price for Signal Peak’s coal depends upon factors beyond our control, including: overall global economic conditions, the effect of worldwide energy consumption, including the impact of technological advances on energy consumption; international developments impacting the supply of coal; international developments impacting the supply of oil & gas; and the impact of domestic and foreign governmental laws and regulations, including environmental and climate change regulations. Any adverse change in these factors could result in weaker demand and lower prices for Global Holding’s products, and, as a result, could impact Global Holding’s ability to pay future dividends or adversely affect our cash flow and results of operations.
Failure to Comply with Debt Covenants in Our Credit Agreements or Conditions Could Adversely Affect Our Ability to Execute Future Borrowings and/or Require Early Repayment, and Could Restrict our Ability to Obtain Additional or Replacement Financing on Acceptable Terms or at All
Our debt and credit agreements contain various financial and other covenants including a requirement for FE 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, and that each other borrower maintain a consolidated debt to total capitalization ratio of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter.
Our credit agreements contain certain negative and affirmative covenants. Our ability to comply with the covenants and restrictions contained in 2021 Credit Facilities has been and may, in the future, be affected by events related to the ongoing government investigations or otherwise, including a failure to comply with the terms of the DPA.
A breach of any of the covenants contained in our credit agreements, including any breach related to alleged failures to comply with anti-corruption and anti-bribery laws, could result in an event of default under such agreements, and we would not be able to access our credit facilities for additional borrowings and letters of credit while any default exists. Upon the occurrence of such an event of default, any amounts outstanding under our credit facilities could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under our credit facilities is accelerated,
there can be no assurance that we will have sufficient assets to repay the indebtedness. In addition, certain events, including but not limited to any covenant breach related to alleged failures to comply with anti-corruption and anti-bribery laws, an event of default under our credit agreements, and the acceleration of applicable commitments under such facilities could restrict our ability to obtain additional or replacement financing on acceptable terms or at all. The operating and financial restrictions and covenants in our credit facilities and any future financing agreements may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.
Interest Rates and/or a Credit Rating Downgrade Could Negatively Affect Our or Our Subsidiaries' Financing Costs, Ability to Access Capital and Requirement to Post Collateral
We have near-term exposure to interest rates from outstanding indebtedness indexed to variable interest rates, and we have exposure to future interest rates to the extent we seek to raise debt in the capital markets to meet maturing debt obligations and fund construction or other investment opportunities. Past disruptions in capital and credit markets have resulted in higher interest rates on new publicly issued debt securities, increased costs for variable interest rate debt securities and failed remarketing of variable interest rate tax-exempt debt issued to finance certain of our former facilities. Disruptions in capital and credit markets could result in higher interest rates on new publicly issued debt securities and increase our financing costs and adversely affect our results of operations. Also, interest rates could change as a result of economic or other events that are beyond our risk management processes. As a result, we cannot always predict the impact that our risk management decisions may have if actual events lead to greater losses or costs than our risk management positions were intended to hedge. Although we employ risk management techniques to hedge against interest rate volatility, significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results of operations.
We rely on access to bank and capital markets as sources of liquidity for cash requirements not satisfied by cash from operations. Additional downgrades in FirstEnergy or FirstEnergy subsidiaries' credit ratings from the nationally recognized credit rating agencies, particularly to levels below investment grade, could negatively affect our ability to access the bank and capital markets, especially in a time of uncertainty in either of those markets, and may require us to post cash collateral to support outstanding commodity positions in the wholesale market, as well as available letters of credit and other guarantees. Furthermore, additional downgrades could increase the cost of such capital by causing us to incur higher interest rates and fees associated with such capital. Additional rating downgrades would further increase our interest expense on certain of FirstEnergy's long-term debt obligations and would also further increase the fees we pay on our various existing credit facilities, thus increasing the cost of our working capital. Such additional rating downgrades could also negatively impact our ability to grow our regulated businesses or execute our business strategies by substantially increasing the cost of, or limiting access to, capital.
In addition, events related to the ongoing government investigations may expose us to higher interest rates for additional indebtedness, whether as a result of ratings downgrades or otherwise, and could restrict our ability to obtain additional or replacement financing on acceptable terms or at all. See “Failure to Comply with Debt Covenants in our Credit Agreements or Conditions Could Adversely Affect our Ability to Execute Future Borrowings and/or Require Early Repayment, and Could Restrict our Ability to Obtain Additional or Replacement Financing on Acceptable Terms or at All.”
In the Event of Volatility or Unfavorable Conditions in the Capital and Credit Markets, Our Business, Including the Immediate Availability and Cost of Short-Term Funds for Liquidity Requirements, Our Ability to Meet Long-Term Commitments and the Competitiveness and Liquidity of Energy Markets May be Adversely Affected, Which Could Negatively Impact Our Results of Operations, Cash Flows and Financial Condition
We rely on the capital markets to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use LOCs provided by various financial institutions to support our hedging operations. We also deposit cash in short-term investments. In the event of volatility in the capital and credit markets, our ability to draw on our credit facilities and cash may be adversely affected. Our access to funds under those credit facilities is dependent on the ability of the financial institutions that are parties to the facilities to meet their funding commitments. Those institutions may not be able to meet their funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. Any delay in our ability to access those funds, even for a short period of time, could have a material adverse effect on our results of operations and financial condition.
Should there be fluctuations in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant foreign or domestic financial institutions or foreign governments, our access to liquidity needed for our business could be adversely affected. Unfavorable conditions could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures or other capital-like investments, changing hedging strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash.
Energy markets depend heavily on active participation by multiple counterparties, which could be adversely affected should there be disruptions in the capital and credit markets. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to our business. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those
markets or attempts to replace those market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on our results of operations and cash flows.
The IRA of 2022 Could Change the Rate of Taxes Imposed On Us and Could Negatively Affect Our Cash Flows and Financial Condition
On August 16, 2022, the U.S. President signed into law the IRA of 2022 which, among other things, imposes a new 15% corporate AMT based on AFSI, applicable to corporations with a three-year average AFSI over $1 billion. The AMT is effective for the 2023 tax year and, if applicable, corporations must pay the greater of the regular corporate income tax or the AMT. Although NOL carryforwards created through the regular corporate income tax system cannot be used to reduce the AMT, financial statement net operating losses can be used to reduce AFSI and the amount of AMT owed. The IRA of 2022 as enacted requires the U.S. Treasury to provide regulations and other guidance necessary to administer the AMT, including further defining allowable adjustments to determine AFSI, which directly impacts the amount of AMT to be paid. Based on interim guidance issued by U.S. Treasury in late December 2022, FirstEnergy continues to believe that it is more likely than not it will be subject to the AMT beginning in 2023. Until final U.S. Treasury guidance is issued, the amount of AMT FirstEnergy would pay could be significantly different than current estimates or it may not be a payer at all. The regulatory treatment of the impacts of this legislation will also be subject to the discretion of the FERC and state public utility commissions. Any adverse development in this legislation, including guidance from U.S. Treasury and/or the IRS or unfavorable regulatory treatment, could reduce future cash flows and impact financial condition.
Changes in Local, State or Federal Tax Laws Applicable to Us or Adverse Audit Results or Tax Rulings, and Any Resulting Increases in Taxes and Fees, May Adversely Affect Our Results of Operations, Financial Condition and Cash Flows
FirstEnergy is subject to various local, state and federal taxes, including income, franchise, real estate, sales and use and employment-related taxes. We exercise significant judgment in calculating such tax obligations, booking reserves as necessary to reflect potential adverse outcomes regarding tax positions we have taken and utilizing tax benefits, such as carryforwards and credits. Additionally, various tax rate and fee increases may be proposed or considered in connection with such changes in local, state or federal tax law. We cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, or whether any such legislation or regulation will be passed by legislatures or regulatory bodies. Any such changes, or any adverse tax audit results or adverse tax rulings on positions taken by FirstEnergy or its subsidiaries could have a negative impact on its results of operations, financial condition and cash flows.
We cannot predict whether, when or to what extent new U.S. tax laws, regulations, interpretations or rulings will be issued. A reform of U.S. tax laws may be enacted in a manner that negatively impacts our cash flow, results of operations, and financial condition.
The Transition from LIBOR to SOFR Could Adversely Affect our Financial Results
A portion of FirstEnergy’s indebtedness bears interest at fluctuating interest rates, primarily based on LIBOR. LIBOR tends to fluctuate based on general interest rates, rates set by the U.S. Federal Reserve and other central banks, the supply of and demand for credit in the London interbank market and general economic conditions. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on LIBOR and other variable interest rates. On July 27, 2017, the FCA (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021, and according to the FCA, IBA will permanently cease to publish overnight, 1-month, 3-month, 6-month and 12-month LIBOR settings on June 30, 2023. FirstEnergy’s 2021 Credit Facilities provide a mechanism to automatically transition to a SOFR-based benchmark when all U.S. 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 FirstEnergy are reduced, capital costs could increase materially. Restricted access to capital markets and/or increased borrowing costs could have an adverse effect on our results of operations, cash flows, financial condition and liquidity.
We Must Rely on Cash from Our Subsidiaries and Any Restrictions on the Utilities and Transmission Companies’ Ability to Pay Dividends or Make Cash Payments to Us May Adversely Affect Our Cash Flows and Financial Condition
We are a holding company and our investments in our subsidiaries are our primary assets. Substantially all of our business is conducted by our subsidiaries. Consequently, our cash flow, including our ability to pay dividends and service debt, is dependent on the operating cash flows of our subsidiaries and their ability to upstream cash to the holding company. Any inability of our subsidiaries to pay dividends or make cash payments to us may adversely affect our cash flows and financial condition.
Additionally, the Utilities and Transmission Companies are regulated by various state utility and federal commissions that generally possess broad powers to ensure that the needs of utility customers are being met. Those state and federal
commissions could attempt to impose restrictions on the ability of the Utilities and Transmission Companies to pay dividends or otherwise restrict cash payments to us.
We Cannot Assure Common Shareholders that Future Dividend Payments Will be Made, or if Made, in What Amounts They May be Paid
The FE Board will continue to regularly evaluate our common stock dividend and determine whether to declare a dividend, and an appropriate amount thereof, each quarter taking into account such factors as, among other things, our earnings, financial condition and cash flows from subsidiaries, as well as general economic and competitive conditions. We cannot assure common shareholders that dividends will be paid in the future, or that, if paid, dividends will be at the same amount or with the same frequency as in the past.
The Tax Characterization of Our Distributions to Shareholders Will Fluctuate
When we make distributions to shareholders, we are required to subsequently determine and report the tax characterization of those distributions for purposes of shareholders’ income taxes. Whether a distribution is characterized as a dividend or a return of capital (and possible capital gain) depends upon an internal tax calculation to determine earnings and profits for income tax purposes (E&P). E&P should not be confused with earnings or net income under GAAP. Further, after we report the expected tax characterization of distributions we have paid, the actual characterization could vary from our expectation with the result that holders of our common stock could incur different income tax liabilities than expected.
In general, distributions are characterized as dividends to the extent the amount of such distributions do not exceed our calculation of current or accumulated E&P. Distributions in excess of current and accumulated E&P may be treated as a non-taxable return of capital. Generally, a non-taxable return of capital will reduce an investor’s basis in our stock for federal tax purposes, which will impact the calculation of gain or loss when the stock is sold.
Our internal calculation of E&P can be impacted by a variety of factors. FirstEnergy exhausted its accumulated E&P in the second half of the 2019 tax year. This elimination of accumulated E&P will make it more likely that at least a portion of our current or future distributions will be characterized for shareholders’ tax purposes as a return of capital. Upon such characterization, shareholders are urged to consult their own tax advisors regarding the income tax treatment of our distributions to them.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES
The first mortgage indentures for the Ohio Companies, Penn, MP, PE and WP constitute direct first liens on substantially all of the respective physical property, subject only to excepted encumbrances, as defined in the first mortgage indentures. See Note 10, "Capitalization," of the Notes to Consolidated Financial Statements for information concerning financing encumbrances affecting certain of the Utilities’ properties.
FirstEnergy controls the following generation sources as of December 31, 2022, shown in the table below, and operates in PJM. Except for the OVEC participation referenced in the footnotes to the table, the Regulated Distribution segment generating units are owned by MP.
Plant (Location) Unit Total Corp/Other Regulated Distribution
Net Demonstrated Capacity (MW)
Super-critical Coal-fired:
Harrison (Haywood, WV) 1-3 1,984 - 1,984
Fort Martin (Maidsville, WV) 1-2 1,098 - 1,098
3,082 - 3,082
Sub-critical and Other Coal-fired:
OVEC (Cheshire, OH) (Madison, IN) 1-11 78 (1) 67 11
Pumped-storage Hydro:
Bath County (Warm Springs, VA) 1-6 487 (2) - 487
Total 3,647 67 3,580
(1) Represents AE Supply's 3.01% and MP's 0.49% entitlement based on their participation in OVEC.
(2) Represents AGC's 16.25% undivided interest in Bath County. The station is operated by VEPCO.
As of December 31, 2022, FirstEnergy’s distribution and transmission circuit miles are located in PJM and were as follows:
Distribution
Line Miles(1)
Transmission
Line Miles
ATSI - 7,921
CEI 33,118 -
JCP&L 24,191 2,600
MAIT - 4,278
ME 19,117 -
MP 22,832 2,607
OE 68,145 -
PE 20,828 2,087
Penn 13,683 -
PN 28,120 -
TE 19,220 -
TrAIL - 269
WP 25,264 4,318
Total 274,518 24,080
(1) Includes overhead pole line and underground conduit carrying primary, secondary and street lighting circuits

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
Reference is made to Note 12, "Regulatory Matters," and Note 13, "Commitments, Guarantees and Contingencies," of the Notes to Consolidated Financial Statements for a description of certain legal proceedings involving FirstEnergy.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
COMMON STOCK
The common stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol “FE” and is traded on other registered exchanges.
HOLDERS OF COMMON STOCK
There were 60,610 holders of 572,130,932 shares of FE’s common stock as of December 31, 2022, and 60,340 holders of 572,245,184 shares of FE's common stock as of January 31, 2023. FE has historically paid quarterly cash dividends on its common stock. Dividend payments are subject to declaration by the FE Board and future dividend decisions determined by the FE Board may be impacted by earnings growth, cash flows, credit metrics, risks and uncertainties of the government investigations and other business conditions. Information regarding retained earnings available for payment of cash dividends is given in Note 10, "Capitalization," of the Notes to Consolidated Financial Statements.
SHAREHOLDER RETURN
The following graph shows the total cumulative return from a $100 investment on December 31, 2017, in FE’s common stock compared with the total cumulative returns of EEI’s Index of Investor-Owned Electric Utility Companies and the S&P 500.
FirstEnergy had no transactions regarding purchases of FE common stock during the fourth quarter of 2022.
FirstEnergy does not have any publicly announced plan or program for share purchases.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [RESERVED]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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 dismissal of the derivative shareholder lawsuits.
•Changes in national and regional economic conditions, including recession, inflationary pressure, supply chain disruptions, higher energy costs, and workforce impacts, affecting us and/or our customers and those vendors with which we do business.
•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, cybersecurity, and climate change.
•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.
•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 FET Minority Equity Interest Sale.
•Changing market conditions affecting the measurement of certain liabilities and the value of assets held in our pension trusts may negatively impact our forecasted growth rate, results of operations, and may also cause us to make contributions to our pension sooner or in amounts that are larger than currently anticipated.
•Mitigating exposure for remedial activities associated with retired and formerly owned electric generation assets.
•Changes to environmental laws and regulations, including, but not limited to, those related to climate change.
•Changes in customers’ demand for power, including, but not limited to, economic conditions, the impact of climate change, or energy efficiency and peak demand reduction mandates.
•The ability to access the public securities and other capital and credit markets in accordance with our financial plans, the cost of such capital and overall condition of the capital and credit markets affecting us, including the increasing number of financial institutions evaluating the impact of climate change on their investment decisions.
•Actions that may be taken by credit rating agencies that could negatively affect either our access to or terms of financing or our financial condition and liquidity.
•Changes in assumptions regarding 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.
•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.
•Human capital management challenges, including among other things, attracting and retaining appropriately trained and qualified employees and labor disruptions by our unionized workforce.
•Changes to significant accounting policies.
•Any changes in tax laws or regulations, including, but not limited to, the IRA of 2022, 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 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.
Forward-looking and other statements in this Annual Report on Form 10-K regarding our Climate Strategy, including our GHG emission reduction goals, are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current and forward-looking statements regarding climate matters, including GHG emissions, may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve and assumptions that are subject to change in the future.
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.
FirstEnergy is proceeding with the consolidation of the Pennsylvania Companies into a new, single operating entity. The PA Consolidation will require, among other steps: (a) the transfer of certain Pennsylvania-based transmission assets owned by WP to KATCo, (b) the transfer of Class B equity interests of MAIT currently held by PN and ME to FE (and ultimately transferred to FET as part of the FET Minority Equity Interest Sale), (c) the formation of PA NewCo and (d) the merger of each of the Pennsylvania Companies with and into PA NewCo, with PA NewCo surviving such mergers as the successor-in-interest to all assets and liabilities of the Pennsylvania Companies. Following completion of the PA Consolidation, PA NewCo will be FE’s only regulated utility in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies. Consummation of the PA Consolidation is contingent upon numerous conditions, including the approval of NYPSC, PPUC and FERC. Subject to receipt of such regulatory approvals, FirstEnergy expects that the PA Consolidation will close by early 2024.
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, 2022, are summarized below:
Company Area Served Customers Served
(In thousands)
JCP&L Northern, Western and East Central New Jersey 1,158
OE Central and Northeastern Ohio 1,068
CEI Northeastern Ohio 755
WP Southwest, South Central and Northern Pennsylvania 737
PN Western Pennsylvania and Western New York 588
ME Eastern Pennsylvania 587
PE Western Maryland and Eastern West Virginia 439
MP Northern, Central and Southeastern West Virginia 396
TE Northwestern Ohio 315
Penn Western Pennsylvania 171
6,214
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 I, 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 would own 19.9% of the issued and outstanding membership interests of FET, for a purchase price of $2.375 billion. The transaction closed on May 31, 2022.
On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The purchase price will be payable in part by the issuance of a promissory note expected to be in the principal amount of $1.75 billion. The remaining $1.75 billion of the purchase price will be payable in cash at the closing. As a result of the consummation of the transaction, Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1% ownership interests of FET. The transaction is subject to customary closing conditions, including approval from the FERC and certain state utility commissions, and completion of review by the CFIUS. In addition, pursuant to the FET P&SA II, FirstEnergy has agreed to make the necessary filings with the applicable regulatory
authorities for the PA Consolidation. The FET Minority Equity Interest Sale is expected to close by early 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s GAAP financial statements.
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 investments or 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, 2022, 67 MWs of electric generating capacity, representing AE Supply's OVEC capacity entitlement, was also included in Corporate/Other for segment reporting. As of December 31, 2022, Corporate/Other had approximately $5.4 billion of FE holding company debt.
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 EESG and strategic 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 a customer-centered focus that emphasizes modern experiences, new growth and affordable energy bills, and enables the energy transition to a clean, resilient and secure electric grid.
We are proud of the steps we have 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 more than $9 billion in investment plans (or 53% of the total FirstEnergy investment plan) from 2021 to 2025. Through its investment plan, Regulated Distribution is focused on improving 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 EESG 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;
•Energy efficiency and demand response initiatives that assist customers in lowering their overall energy bills while also helping us to reduce peak system demand;
•Utility-Scale Solar Generation that lowers our carbon footprint;
•Pilot program to install battery storage systems;
•Information Systems - enhance our core information infrastructure of our distribution systems; and
•Supporting economic development to attract new business.
FirstEnergy expects to file base rate cases in Maryland, New Jersey, and West Virginia in 2023 and in Ohio in 2024.
FirstEnergy's Regulated Transmission business is a premier, high quality transmission business, with approximately 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 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 is a continued long-term pipeline of investment opportunities for its existing transmission infrastructure 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 EESG 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;
•JCP&L awarded approximately $723 million to connect clean energy generated by New Jersey's offshore wind farms to the power grid;
•Exploring real-time technologies: emerging technologies to enhance data collection; and
•Making smart investments to modernize the grid to integrate future renewables.
On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The purchase price will be payable in part by the issuance of a promissory note expected to be in the principal amount of $1.75 billion. The remaining $1.75 billion of the purchase price will be payable in cash at the closing. As a result of the consummation of the transaction, Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1% ownership interests of FET. The transaction is subject to customary closing conditions, including approval from the FERC and certain state utility commissions, and completion of review by the CFIUS. In addition, pursuant to the FET P&SA II, FirstEnergy has agreed to make the necessary filings with the applicable regulatory authorities for the PA Consolidation. The FET Minority Equity Interest Sale is expected to close by early 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s GAAP financial statements.
FirstEnergy is proceeding with the consolidation of the Pennsylvania Companies into a new, single operating entity. The PA Consolidation will require, among other steps: (a) the transfer of certain Pennsylvania-based transmission assets owned by WP to KATCo, (b) the transfer of Class B equity interests of MAIT currently held by PN and ME to FE (and ultimately transferred to FET as part of the FET Minority Equity Interest Sale), (c) the formation of PA NewCo and (d) the merger of each of the Pennsylvania Companies with and into PA NewCo, with PA NewCo surviving such mergers as the successor-in-interest to all assets and liabilities of the Pennsylvania Companies. Following completion of the PA Consolidation, PA NewCo will be FE’s only regulated utility in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies. Consummation of the PA Consolidation is contingent upon numerous conditions, including the approval of NYPSC, PPUC and FERC. Subject to receipt of such regulatory approvals, FirstEnergy expects that the PA Consolidation will close by early 2024.
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. On April 21, 2022, FERC approved the Blackstone representative’s ability to participate as a voting member of the FE Board. Sean T. Klimczak, the Blackstone Infrastructure Partners-selected representative, was elected to the FE Board at 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. Also, as with the recently completed FET transaction, premium valuations of our distribution and transmission businesses, together with growth in cash flow from operations resulting from the investment opportunities described above, could provide FirstEnergy future optionality to accelerate further strengthening of the balance sheet and enhance shareholder value.
On September 15, 2022, FirstEnergy announced that the FE Board had appointed Mr. John W. Somerhalder II to serve as Interim President and Chief Executive Officer of FirstEnergy, effective as of September 16, 2022. In connection with his appointment as Interim President and Chief Executive Officer, Mr. Somerhalder will continue to serve as Chair of the FE Board. The FE Board is conducting a search of external candidates to identify a permanent President and Chief Executive Officer of FirstEnergy. Mr. Somerhalder’s appointment follows the decision of Mr. Steven E. Strah on September 15, 2022, to retire as Director and President and Chief Executive Officer of FirstEnergy, effective as of September 16, 2022.
FE Forward
In February 2021, FirstEnergy announced a new transformation initiative, FE Forward, to build upon FirstEnergy’s strong operations and business fundamentals and deliver immediate value and resilience, with targeted working capital improvements by 2022, and capital efficiencies ramping up through 2024 that would be redeployed in a more diverse capital investment program. In the two years that FE Forward has been active, we have built new solutions to serve our customers, changed how we plan and execute work in the field, established a “digital factory” within our information technology organization to automate and modernize our business solutions, reorganized the company to enable more efficiency and collaboration, and realized working capital improvements and annualized capital expenditures in line with our previously published expectations. After assessing our accomplishments and shortfalls, including the continuing challenges from inflation and supply chain disruptions, FE Forward has been integrated into our ongoing efforts for continuous improvement, including the strategic reduction of operating expenditures and continued reinvestment in a more diverse capital program in support of our long-term strategy. As such, FirstEnergy has transitioned away from measuring these cash flow metrics and will no longer publish a forecast of these metrics.
In addition to FE Forward, FirstEnergy will leverage other opportunities to reduce costs - such as filling only critical positions, implementing our facility optimization plans, as well as exploring other additional, sustainable opportunities, such as reducing contractor spend. Similar to our PA Consolidation discussed above, FirstEnergy is also evaluating the legal, financial, operational, and branding benefits of consolidating the Ohio Companies into a single Ohio operating entity.
The result of our combined efforts will help build a stronger, more sustainable company for the near and long term.
Climate Strategy
Our commitment to climate is a significant component of our company’s overarching strategy, especially our desire to enable the transition to a clean energy future. Executing our Climate Strategy and advancing the transition to clean energy requires addressing, among other things: emerging federal and state decarbonization goals; physical risks of climate change; industry trends and technology advancements; and customer expectations for cleaner energy, increased usage control, and more sustainable alternatives in transportation, manufacturing and industrial processes. Through our investment plan, we aim to enhance the resiliency, reliability and security of the electric system and support the integration of renewables, electric vehicles, grid modernization improvements and other emerging technologies.
As part of our Climate Strategy, we are also committed to reducing GHG emissions. We’ve pledged to achieve carbon neutrality by 2050, with an interim 30% reduction in GHGs within our direct operational control (Scope 1) by 2030 based on 2019 levels. This Scope 1 GHG goal encompasses company-wide emissions across our transmission, distribution and regulated generation operations.
Key steps in working toward carbon neutrality by 2050 include:
•Reducing Sulfur hexafluoride Emissions: We're working to repair or replace, as appropriate, transmission breakers that leak Sulfur hexafluoride, which is a gas commonly used by energy companies as an electrical insulating material and arc extinguisher in high-voltage circuit breakers and switchgear. If escaped to the atmosphere, it acts as a potent GHG with a global warming potential significantly greater than CO2.
•Electrifying our Vehicle Fleet: We’re targeting 30% electrification of our light-duty and aerial truck fleet by 2030 and 100% electrification by 2050. To reach our electrification goal, we’re striving for 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.
•Transitioning Away from Coal Generation: We've committed to moving beyond our two coal-fired generating plants no later than 2050. Our commitment is consistent with the depreciation rates filing we submitted to the WVPSC, in which we proposed end-of-life dates for the Fort Martin (2035) and Harrison (2040) plants. We intend to engage in a broad stakeholder dialogue and work closely with the WVPSC as we develop and seek approval for that future transition plan.
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.
HB 6 and Related Investigations
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 related to the federal criminal allegations made in July 2020, against former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. Among other things, the DPA 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. The criminal information will be dismissed after FirstEnergy fully complies with its obligations under the DPA.
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. On March 11, 2022, the parties executed a stipulation and agreement of settlement, and filed a motion the same day requesting preliminary settlement approval in the S.D. Ohio. On August 23, 2022, the S.D. Ohio granted final approval of the settlement. On September 20, 2022, a purported FE stockholder filed a motion for reconsideration of the S.D. Ohio’s final settlement approval. The parties filed oppositions to that motion on October 11, 2022 and the motion is under consideration by the S.D. Ohio. The N.D. Ohio matter remains pending. The settlement agreement is expected to fully resolve these shareholder derivative lawsuits and includes a series of corporate governance enhancements, that have resulted in the following:
•Six then-members of the FE Board did 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 was formed to initiate a review process of the then current senior executive team. The review of the senior executive team by the special FE Board committee and the FE Board was completed in September 2022;
•The FE Board will oversee FE’s lobbying and political activities, including periodically reviewing and approving political and lobbying action plans prepared by management;
•An FE Board committee of recently appointed independent directors will 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 FE of $180 million, to be paid by insurance after the judgment has become final, less $36 million in 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, and July 11, 2022, the SEC issued additional subpoenas 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. On December 30, 2022, FERC approved a Stipulation and Consent Agreement that resolves the investigation. The agreement obligates FE to pay a civil penalty of $3.86 million, which was paid in January 2023, and to submit two annual compliance monitoring reports to FERC’s Office of Enforcement regarding improvements to FirstEnergy’s compliance programs.
FirstEnergy has taken numerous steps to address challenges posed by the HB 6 investigations and improve its compliance culture, including the refreshment of the FE Board, the hiring of key senior executives committed to supporting transparency and integrity, and strengthening and enhancing FirstEnergy’s compliance culture through several initiatives. Although the outcome of the HB 6 investigations and state regulatory audits remain unknown, FirstEnergy has also taken several proactive steps to reduce regulatory uncertainty affecting the Ohio Companies.
FE terminated Charles E. Jones as its chief executive officer effective October 29, 2020. As a result of Mr. Jones’ termination, and due to the determination of a committee of independent members of the FE Board that Mr. Jones violated certain FirstEnergy policies and its code of conduct, all grants, awards and compensation under FirstEnergy’s short-term incentive compensation program and long-term incentive compensation program with respect to Mr. Jones that were outstanding on the date of termination were forfeited. In November 2021, after a determination by the Compensation Committee of the FE Board that a demand for recoupment was warranted pursuant to the Recoupment Policy, FE made a recoupment demand to Mr. Jones of compensation previously paid to him totaling approximately $56 million, the maximum amount permissible under the Recoupment Policy. As such, any amounts payable to Mr. Jones under the EDCP will be set off against FE’s recoupment demand. There can be no assurance that the efforts to seek recoupment from Mr. Jones will be successful.
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 2022 and 2021 items and year-over-year comparisons between 2022 and 2021. Discussions of 2020 items and year-over-year comparisons between 2021 and 2020 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, 2021, filed with the SEC on February 16, 2022.
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 14, "Segment Information," of the Notes to Consolidated Financial Statements.
Net income by business segment was as follows:
(In millions, except per share amounts) For the Years Ended December 31, Increase (Decrease)
2022 2021 2020 2022 vs 2021 2021 vs 2020
Net Income By Business Segment:
Regulated Distribution $ 957 $ 1,288 $ 959 $ (331) $ 329
Regulated Transmission 394 408 464 (14) (56)
Corporate/Other (912) (457) (420) (455) (37)
Income from Continuing Operations $ 439 $ 1,239 $ 1,003 $ (800) $ 236
Discontinued Operations - 44 76 (44) (32)
Net Income $ 439 $ 1,283 $ 1,079 $ (844) (65.8) % $ 204 18.9 %
Income attributable to noncontrolling interest (continuing operations) 33 - - 33 -
Earnings attributable to FE $ 406 $ 1,283 $ 1,079 $ (877) (68.4) % $ 204 18.9 %
EPS Attributable to FE:
Income from continuing operations, basic $ 0.71 $ 2.27 $ 1.85 $ (1.56) $ 0.42
Discontinued operation, basic - 0.08 0.14 (0.08) (0.06)
Basic EPS $ 0.71 $ 2.35 $ 1.99 $ (1.64) (69.8) % $ 0.36 18.1 %
Income from continuing operations, diluted $ 0.71 $ 2.27 $ 1.85 $ (1.56) $ 0.42
Discontinued operation, diluted - 0.08 0.14 (0.08) (0.06)
Diluted EPS $ 0.71 $ 2.35 $ 1.99 $ (1.64) (69.8) % $ 0.36 18.1 %
Summary of Results of Operations - 2022 Compared with 2021
Financial results for FirstEnergy’s business segments for the years ended December 31, 2022 and 2021, were as follows:
2022 Financial Results Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated
(In millions)
Revenues:
Electric $ 10,596 $ 1,863 $ (159) $ 12,300
Other 205 5 (51) 159
Total Revenues 10,801 1,868 (210) 12,459
Operating Expenses:
Fuel 730 - - 730
Purchased power 3,843 - 20 3,863
Other operating expenses 3,404 616 (203) 3,817
Provision for depreciation 967 335 73 1,375
Deferral of regulatory assets, net (362) (3) - (365)
General taxes 831 255 43 1,129
Total Operating Expenses 9,413 1,203 (67) 10,549
Operating Income (Loss) 1,388 665 (143) 1,910
Other Income (Expense):
Debt redemption costs - - (171) (171)
Equity method investment earnings - - 168 168
Miscellaneous income, net 361 36 18 415
Pension and OPEB mark-to-market adjustment (50) (15) 137 72
Interest expense (526) (230) (283) (1,039)
Capitalized financing costs 35 48 1 84
Total Other Expense (180) (161) (130) (471)
Income (Loss) Before Income Taxes (Benefits) 1,208 504 (273) 1,439
Income taxes (benefits) 251 110 639 1,000
Net Income (Loss) $ 957 $ 394 $ (912) $ 439
Income attributable to noncontrolling interest - 33 - 33
Earnings (Loss) Attributable to FE $ 957 $ 361 $ (912) $ 406
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 - - 481
Purchased power 2,947 - 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 - 269
General taxes 789 248 36 1,073
DPA Penalty - - 230 230
Gain on sale of Yards Creek (109) - - (109)
Total Operating Expenses 8,246 940 220 9,406
Operating Income (Loss) 1,465 678 (417) 1,726
Other Income (Expense):
Debt redemption costs (1) (1) - (2)
Equity method investment earnings - - 31 31
Miscellaneous income, net 399 41 46 486
Pension and OPEB mark-to-market adjustment 270 31 81 382
Interest expense (522) (247) (370) (1,139)
Capitalized financing costs 41 33 1 75
Total Other Expense 187 (143) (211) (167)
Income (Loss) from Continuing Operations 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 - - 44 44
Net Income (Loss) $ 1,288 $ 408 $ (413) $ 1,283
Changes Between 2022 and 2021
Financial Results
Increase (Decrease) Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments FirstEnergy Consolidated
(In millions)
Revenues:
Electric $ 1,098 $ 255 $ (19) $ 1,334
Other (8) (5) 6 (7)
Total Revenues 1,090 250 (13) 1,327
Operating Expenses:
Fuel 249 - - 249
Purchased power 896 - 3 899
Other operating expenses 437 258 (74) 621
Provision for depreciation 56 10 7 73
Amortization (deferral) of regulatory assets, net (622) (12) - (634)
General taxes 42 7 7 56
DPA penalty - - (230) (230)
Gain on sale of Yards Creek 109 - - 109
Total Operating Expenses 1,167 263 (287) 1,143
Operating Income (Loss) (77) (13) 274 184
Other Income (Expense):
Debt redemption costs 1 1 (171) (169)
Equity method investment earnings - - 137 137
Miscellaneous income, net (38) (5) (28) (71)
Pension and OPEB mark-to-market adjustment (320) (46) 56 (310)
Interest expense (4) 17 87 100
Capitalized financing costs (6) 15 - 9
Total Other Expense (367) (18) 81 (304)
Income (Loss) from Continuing Operations Before Income Taxes (Benefits) (444) (31) 355 (120)
Income taxes (benefits) (113) (17) 810 680
Income (Loss) From Continuing Operations (331) (14) (455) (800)
Discontinued Operations, net of tax - - (44) (44)
Net Income (Loss) $ (331) $ (14) $ (499) $ (844)
Income attributable to noncontrolling interest (continuing operations) - 33 - 33
Earnings (Loss) Attributable to FE $ (331) $ (47) $ (499) $ (877)
Regulated Distribution - 2022 Compared with 2021
Regulated Distribution's net income decreased $331 million in 2022, as compared to 2021, primarily resulting from higher other operating expenses, customer rate credits associated with the PUCO-approved Ohio Stipulation, change in pension and OPEB mark-to-market adjustments, and higher pension and OPEB expenses, partially offset by higher weather-related usage, rider revenues from capital investment programs, as well as the absence of a $27 million refund for previously collected decoupling revenues in Ohio, with interest.
Revenues -
The $1,090 million increase in total revenues resulted from the following sources:
For the Years Ended December 31,
Revenues by Type of Service 2022 2021 Increase (Decrease)
(In millions)
Distribution services (1)
$ 5,261 $ 5,406 $ (145)
Generation sales:
Retail 4,841 3,730 1,111
Wholesale 494 362 132
Total generation sales 5,335 4,092 1,243
Other 205 213 (8)
Total Revenues $ 10,801 $ 9,711 $ 1,090
(1) Includes $(27) million of ARP revenues for the year ended December 31, 2021, which is related to the Ohio Companies refund to customers that was previously collected under decoupling mechanisms, with interest.
Distribution services revenues decreased $145 million in 2022, as compared to 2021, primarily resulting from customer rate credits associated with the PUCO-approved Ohio Stipulation, as well as adjusted customer rates of the Pennsylvania Companies associated with the Tax Act and lower transmission recovery, which has no material impact to current period earnings, partially offset by higher weather-related usage, the absence of a $27 million refund for previously collected decoupling revenues in Ohio with interest, and higher rates associated with riders in Ohio, Pennsylvania and New Jersey for the recovery of certain capital investment programs.
Distribution services by customer class are summarized in the following table:
For the Years Ended December 31,
(In thousands) Actual Weather-Adjusted
Electric Distribution MWH Deliveries 2022 2021 Increase 2022 2021 Increase (Decrease)
Residential 55,995 55,624 0.7 % 55,081 55,678 (1.1) %
Commercial(1)
36,317 35,599 2.0 % 36,024 35,744 0.8 %
Industrial 55,169 54,027 2.1 % 55,169 54,027 2.1 %
Total Electric Distribution MWH Deliveries 147,481 145,250 1.5 % 146,274 145,449 0.6 %
(1) Includes street lighting.
Residential and commercial distribution deliveries were impacted by higher weather-related customer usage. Cooling degree days were 2.9% below 2021 and 11.5% above normal. Heating degree days were 8.4% above 2021 and 1.0% below normal. Increases in industrial deliveries were primarily from the primary and fabricated metal and transportation equipment manufacturing sectors.
Compared to pre-pandemic levels in 2019, weather-adjusted residential distribution deliveries for the year ended December 31, 2022 increased 2.7%, while commercial and industrial deliveries decreased 4.5% and 0.9%, respectively.
The following table summarizes the price and volume factors contributing to the $1,243 million increase in generation revenues in 2022, as compared to 2021:
Source of Change in Generation Revenues Increase (Decrease)
(In millions)
Retail:
Change in sales volumes $ 466
Change in prices 645
1,111
Wholesale:
Change in sales volumes (15)
Change in prices 184
Capacity revenue (37)
Change in Generation Revenues $ 1,243
The increase in retail generation sales volumes was primarily due to higher weather-related usage and decreased customer shopping in New Jersey, Ohio and Pennsylvania. Total generation provided by alternative suppliers as a percentage of total MWH deliveries in 2022, as compared to 2021, decreased to 41% from 46% in New Jersey, to 78% from 86% in Ohio, and to 60% from 63% in Pennsylvania. The increase in retail generation prices primarily resulted from higher non-shopping generation auction rates. Retail generation sales, excluding those in West Virginia, have no material impact to earnings.
Wholesale generation revenues increased $132 million in 2022, as compared to 2021, primarily due to an increase in spot market energy prices, partially offset by lower capacity revenues and sales volumes. The difference between current wholesale generation revenues and certain energy costs incurred are deferred for future recovery or refund, with no material impact to current period earnings.
Operating Expenses -
Total operating expenses increased $1,167 million primarily due to the following:
•Fuel expense increased $249 million in 2022, as compared to 2021, 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 $896 million in 2022, as compared to 2021, primarily due to higher market prices and increased volumes as described above.
Source of Change in Purchased Power Increase (Decrease)
(In millions)
Purchases
Change due to unit costs $ 611
Change due to volumes 314
Capacity expense (29)
Change in Purchased Power Costs $ 896
•Other operating expenses increased $437 million in 2022, as compared to 2021, primarily due to:
•Higher network transmission expenses of $99 million. These costs are deferred for future recovery, resulting in no material impact on current period earnings.
•Higher expenses of $65 million resulting from lower capitalization of vegetation management costs.
•Higher expenses of $59 million resulting from lower capitalization of corporate support costs.
•Higher vegetation management in West Virginia, energy efficiency and other state mandated program costs of $94 million, which are deferred for future recovery, resulting in no material impact on current period earnings.
•Higher expenses of $19 million resulting from higher regulated generation planned outage spend.
•Higher expenses of $18 million resulting from accelerated maintenance activities into 2022.
•Higher other operating and maintenance expenses of $60 million, primarily associated with higher materials, contractor and labor costs.
•Higher expense due to the absence of a $27 million reduction to a reserve recognized in the third quarter of 2021.
•Lower uncollectible expenses of $4 million, which was deferred.
•Depreciation expense increased $56 million in 2022, as compared to 2021, primarily due to a higher asset base.
•Amortization (deferral) of regulatory assets, net decreased $622 million in 2022, as compared to 2021, primarily due to:
•$170 million decrease due to the return of certain Tax Act savings to Pennsylvania customers,
•$197 million decrease due to transmission and generation related deferrals primarily as a result of lower recovery of transmission related expenses,
•$112 million decrease due to customer refunds associated with the Ohio Stipulation,
•$109 million decrease due to the absence of the reduction of the New Jersey storm cost regulatory asset as a result of the Yards Creek sale, and
•$34 million decrease due to lower recovery of previously deferred uncollectible expenses as a result of a return to pre-pandemic levels
•General taxes increased $42 million in 2022, as compared to 2021, primarily due to higher gross receipts and kWh taxes, and Ohio property taxes, partially offset by lower West Virginia Business and Occupation taxes as a result of a state tax law change that became effective July 2021.
•The absence of the gain on sale of the Yards Creek Generating Facility of $109 million, which was netted against the New Jersey storm deferral, as described above, resulting in no impact to earnings.
Other Expense -
Other expense increased $367 million in 2022, as compared to 2021, primarily due to a $320 million change in pension and OPEB mark-to-market adjustments, higher pension and OPEB non-service costs, higher interest from borrowings under the regulated money pool and lower capitalized interest, partially offset by lower borrowings under the revolving credit facilities.
Income Taxes
Regulated Distribution’s effective tax rate was 20.8% and 22.0% for 2022 and 2021, respectively.
Regulated Transmission - 2022 Compared with 2021
Regulated Transmission's net income decreased $14 million in 2022, as compared to 2021, primarily due to a charge resulting from the filed settlement by MP, PE and WP with FERC in January 2023, as well as expected customer refunds associated with the FERC Audit, as further discussed below, partially offset by higher rate base and lower net financing costs.
Revenues -
Total revenues increased $250 million in 2022, as compared to 2021, primarily due to the recovery of higher recoverable expenses and a higher rate base, partially offset by expected customer refunds associated with the FERC Audit, as further discussed below.
Revenues by transmission asset owner are shown in the following table:
For the Years Ended December 31,
Revenues by Transmission Asset Owner 2022 2021 Increase
(In millions)
ATSI $ 912 $ 801 $ 111
TrAIL 275 240 35
MAIT 340 289 51
JCP&L 203 164 39
MP, PE and WP 138 124 14
Total Revenues $ 1,868 $ 1,618 $ 250
Operating Expenses -
Total operating expenses increased $263 million in 2022, as compared to 2021, primarily due to the reclassification of certain transmission capital assets to operating expenses as a results of the FERC Audit, as further discussed below, higher operating and maintenance expenses and a charge resulting from the filed settlement with FERC in January 2023, partially offset by a charge in the third quarter of 2021 resulting from the filed ATSI settlement. Other than the customer refunds and write-off of nonrecoverable transmission assets, nearly all operating expenses are recovered through formula rates, resulting in no material impact on current period earnings.
Other Expense -
Total other expense increased $18 million in 2022, as compared to 2021, primarily due to a $46 million change in the pension and OPEB mark-to-market adjustment, partially offset by lower interest on long-term debt and borrowings under the revolving credit facilities, higher unregulated money pool interest income at ATSI, MAIT and TrAIL, and higher capitalized financing cost.
Income Taxes -
Regulated Transmission’s effective tax rate was 21.8% and 23.7% for 2022 and 2021, respectively.
Corporate/Other - 2022 Compared with 2021
Financial results from Corporate/Other and reconciling adjustments resulted in a $499 million increase in net loss for 2022 compared to 2021, primarily due to higher income tax expense resulting from an income tax charge of $752 million in 2022 representing the deferred tax liability associated with the deferred tax gain on the 19.9% sale of FET membership interests to Brookfield that closed in May 2022, as well as expenses associated with the FE debt redemptions. These were partially offset by the absence of the $230 million DPA monetary penalty, higher net investment income on certain equity method and other investments and the change in pension and OPEB mark-to-market adjustments.
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, 2022 and December 31, 2021, and the changes during the year ended December 31, 2022:
As of December 31,
Net Regulatory Assets (Liabilities) by Source 2022 2021 Change
(In millions)
Customer payables for future income taxes $ (2,463) $ (2,345) $ (118)
Spent nuclear fuel disposal costs (83) (101) 18
Asset removal costs (675) (646) (29)
Deferred transmission costs 50 (3) 53
Deferred generation costs 235 118 117
Deferred distribution costs 164 49 115
Storm-related costs 683 660 23
Uncollectible and pandemic-related costs 63 56 7
Energy efficiency program costs 94 47 47
New Jersey societal benefit costs 94 109 (15)
Vegetation management costs 63 33 30
Other (39) (30) (9)
Net Regulatory Liabilities included on the Consolidated Balance Sheets $ (1,814) $ (2,053) $ 239
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 federal and state tax rate changes such as the Tax Act and Pennsylvania House Bill 1342. 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 - Reflects differences between revenues earned based on actual costs for the formula-rate Transmission Companies and the amounts billed, including amounts expected to be refunded to, or recoverable from, wholesale transmission customers resulting from the FERC Audit, as further described below, which amounts are recorded as a regulatory asset or liability and recovered or refunded, respectively, in subsequent periods. Also included is the recovery of non-market based costs or fees charged to certain of the Utilities by various regulatory bodies including FERC and RTOs, which can include PJM charges and credits for service including, but not limited to, procuring transmission services and transmission enhancement.
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. Generally, the ENEC rate is updated annually.
Deferred distribution costs - Primarily relates to the Ohio Companies' deferral of certain distribution-related expenses, including interest (amortized through 2034).
Storm-related costs - Relates to the deferral of storm costs, which vary by jurisdiction. Approximately $206 million and $148 million are currently being recovered through rates as of December 31, 2022 and 2021, respectively.
Uncollectible and pandemic-related costs - Includes the deferral of incremental costs arising from the pandemic and in some cases including uncollectible expenses.
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' Energy Efficiency and Conservation 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 the New Jersey Clean Energy Program.
Vegetation management costs - Relates to regulatory assets associated with the recovery of certain distribution vegetation management costs in New Jersey and West Virginia as well as certain transmission vegetation management costs at MAIT, ATSI and WP/PE (amortized through 2024, 2030 and 2036, respectively).
The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2022 and 2021, of which approximately $511 million and $228 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral and the jurisdiction:
Regulatory Assets by Source Not Earning a As of December 31,
Current Return 2022 2021 Change
(In millions)
Deferred transmission costs $ 8 $ 13 $ (5)
Deferred generation costs 262 63 199
Deferred distribution costs 27 2 25
Storm-related costs 568 549 19
Pandemic-related costs 70 65 5
Vegetation management 52 31 21
Other 10 9 1
Regulatory Assets Not Earning a Current Return $ 997 $ 732 $ 265
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 2023 and beyond, FE and its distribution and transmission subsidiaries expect to rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through the issuance of long-term debt by FE and certain of its distribution and transmission subsidiaries to, among other things, fund capital expenditures and other capital-like investments, and refinance short-term and maturing long-term debt, subject to market conditions and other factors.
Investments for 2022 and forecasts for 2023, 2024, and 2025 by business segment are included below:
Business Segment 2022
Actual
Forecast
2024 Forecast (2)
2025 Forecast (2)
(In millions)
Regulated Distribution (1)
$ 1,764 $ 1,650 $ 2,000 $ 2,175
Regulated Transmission 1,394 1,675 1,800 1,850
Corporate/Other 86 85 75 70
Total $ 3,244 $ 3,410 $ 3,875 $ 4,095
(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.
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 February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The purchase price will be payable in part by the issuance of a promissory note expected to be in the principal amount of $1.75 billion. The remaining $1.75 billion of the purchase price will be payable in cash at the closing. As a result of the consummation of the transaction, Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1% ownership interests of FET. The transaction is subject to customary closing conditions, including approval from the FERC and certain state utility commissions, and completion of review by the CFIUS. In addition, pursuant to the FET P&SA II, FirstEnergy has agreed to make the necessary filings with the applicable regulatory authorities for the PA Consolidation. The FET Minority Equity Interest Sale is expected to close by early 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s GAAP financial statements.
FirstEnergy is proceeding with the consolidation of the Pennsylvania Companies into a new, single operating entity. The PA Consolidation will require, among other steps: (a) the transfer of certain Pennsylvania-based transmission assets owned by WP to KATCo, (b) the transfer of Class B equity interests of MAIT currently held by PN and ME to FE (and ultimately transferred to FET as part of the FET Minority Equity Interest Sale), (c) the formation of PA NewCo and (d) the merger of each of the Pennsylvania Companies with and into PA NewCo, with PA NewCo surviving such mergers as the successor-in-interest to all assets and liabilities of the Pennsylvania Companies. Following completion of the PA Consolidation, PA NewCo will be FE’s only regulated utility in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies. Consummation of the PA Consolidation is contingent upon numerous conditions, including the approval of NYPSC, PPUC and FERC. Subject to receipt of such regulatory approvals, FirstEnergy expects that the PA Consolidation will close by early 2024.
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. On April 21, 2022, FERC approved the Blackstone representative’s ability to participate as a voting member of the FE Board. Sean T. Klimczak, the Blackstone Infrastructure Partners-selected representative, was elected to the FE Board at 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.
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. Also, as with the recently completed FET transaction, premium valuations of our distribution and transmission businesses, together with growth in cash flow from operations resulting from the investment opportunities described above, could provide FirstEnergy future optionality to accelerate further strengthening of the balance sheet and enhance shareholder value.
Economic conditions following the global pandemic, have increased lead times across numerous material categories, with some as much as doubling from pre-pandemic lead times. Some key suppliers have struggled with labor shortages and raw material availability, which along with increasing inflationary pressure, have increased costs and decreased the availability of certain materials, equipment and contractors. FirstEnergy has taken steps to mitigate these risks and does not currently expect service disruptions or any material impact on its capital spending plan. However, the situation remains fluid and a prolonged continuation or further increase in supply chain disruptions could have an adverse effect on FirstEnergy’s results of operations, cash flow and financial condition.
As of December 31, 2022, 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. IBA permanently ceased publication for 1-week and 2-month LIBOR settings and all settings for non-U.S. dollar LIBOR on December 31, 2021. According to the FCA, IBA will permanently cease to publish overnight, 1-month, 3-month, 6-month and 12-month LIBOR settings on June 30, 2023. FirstEnergy’s 2021 Credit Facilities provide a mechanism to automatically transition to a SOFR-based benchmark when all U.S. 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. During 2022, interest rates have increased significantly, which has caused the rate and interest expense on borrowings under the 2021 Credit Facilities to be significantly higher. 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.
FirstEnergy had $100 million of short-term borrowings as of December 31, 2022. As of December 31, 2021, FirstEnergy had no outstanding short-term borrowings. FirstEnergy’s available liquidity from external sources as of February 10, 2023, was as follows:
Revolving Credit Facilities Maturity Commitment Available Liquidity
(In millions)
FE and FET October 2026 $ 1,000 $ 897
Ohio Companies October 2026 800 650
Pennsylvania Companies October 2026 950 800
JCP&L October 2026 500 499
MP and PE October 2026 400 400
Transmission Companies October 2026 850 850
Subtotal $ 4,500 $ 4,096
Cash and Cash equivalents - 224
Total $ 4,500 $ 4,320
The following table summarizes the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of December 31, 2022:
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, PN and WP 300 (1)
PE and Penn 150 (1)
TrAIL and MAIT 400 (1)
(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, 2022, FirstEnergy had $4 million in outstanding LOCs.
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
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, 2022, the borrowers were in compliance with the applicable interest coverage and debt-to-total-capitalization ratio covenants in each case as defined under the 2021 Credit Facilities.
FirstEnergy Money Pools
FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and FE to meet their short-term working capital requirements. Similar but separate arrangements exist among FirstEnergy’s unregulated companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries. FESC administers these money pools and tracks surplus funds of FE and the respective regulated and unregulated subsidiaries, as the case may be, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. During 2022, interest rates have increased significantly, which has caused the rate and interest on borrowings and lending under the money pools to be significantly higher. The average interest rate for borrowings in 2022 was 2.27% per annum for the regulated companies’ money pool, as compared to 1.01% in 2021, and 2.14% per annum for the unregulated companies’ money pool, as compared to 0.60% in 2021.
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 10, 2023:
Corporate Credit Rating Senior Secured Senior Unsecured Outlook/CreditWatch (1)
Issuer S&P Moody’s Fitch S&P Moody’s Fitch S&P Moody’s Fitch S&P Moody’s Fitch
FE BBB- Ba1 BBB- - - - BB+ Ba1 BBB- P P S
AGC BB+ Baa2 BBB - - - - - - P S S
ATSI BBB A3 BBB - - - BBB A3 BBB+ P S S
CEI BBB Baa3 BBB A- Baa1 A- BBB Baa3 BBB+ P S S
FET BBB- Baa2 BBB- - - - BB+ Baa2 BBB- P S S
JCP&L BBB A3 BBB - - - BBB A3 BBB+ P S S
ME BBB A3 BBB - - - BBB A3 BBB+ P S S
MAIT BBB A3 BBB - - - BBB A3 BBB+ P S S
MP BBB Baa2 BBB A- A3 A- BBB Baa2 - S S S
OE BBB A3 BBB A- A1 A- BBB A3 BBB+ P S S
PN BBB Baa1 BBB - - - BBB Baa1 BBB+ P S S
Penn BBB A3 BBB A- A1 - - - - P S S
PE BBB Baa2 BBB A- A3 A- - - - S S S
TE BBB Baa2 BBB A- A3 A- - - - P S S
TrAIL BBB A3 BBB - - - BBB A3 BBB+ P S S
WP BBB A3 BBB A- A1 A- - - - P S S
(1) S = Stable, P = Positive
On July 22, 2022, Fitch issued a one notch upgrade to all applicable ratings for FE and its subsidiaries and revised the outlook to stable.
On September 13, 2022, Moody’s issued a one notch downgrade to all applicable ratings for CEI and TE and revised their outlooks to stable.
On February 10, 2023, S&P revised the outlook for FE and its subsidiaries, except MP and PE, to positive from stable.
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-credit enhanced debt ratings as determined by S&P and Moody’s. The fees 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 rates payable on approximately $2.1 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 point coupon rate increase beginning at BB, Ba1, and BB+ for S&P, Moody’s and Fitch, respectively, to the extent such rating is applicable to the series of outstanding senior unsecured notes, during the next interest period, subject to an aggregate cap of 2% from issuance interest rate.
Debt capacity is subject to the consolidated interest coverage ratio in the 2021 Credit Facilities. As of December 31, 2022, FirstEnergy could incur approximately $780 million of incremental interest expense or incur an approximate $1.9 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.
As of December 31, 2022 (Undiscounted): Total 2023 2024-2025 2026-2027 Thereafter
(In millions)
Long-term debt(1)
$ 21,641 $ 344 $ 3,269 $ 3,079 $ 14,949
Short-term borrowings 100 100 - - -
Interest on long-term debt 10,669 925 1,690 1,458 6,596
Operating leases(2)
346 56 101 84 105
Finance leases(2)
33 9 10 9 5
Fuel and purchased power(3)
2,883 635 962 555 731
Committed investments(4)
3,767 1,393 1,246 1,128 -
Pension funding(5)
2,287 - 250 675 1,362
Total $ 41,726 $ 3,462 $ 7,528 $ 6,988 $ 23,748
(1) Excludes unamortized discounts and premiums, fair value accounting adjustments and finance leases.
(2) See Note 8, "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
(5) As discussed below, FirstEnergy does not expect to have a required contribution to the pension plan until 2025.
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, consumption levels and power prices, management currently estimates these cash outlays will be approximately $4.3 billion in 2023.
The table above also excludes 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.
FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. 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 until 2025, which, based on various assumptions, including annual expected rate of return on assets of 8.0% in 2023, is expected to be approximately $250 million. However, FirstEnergy may elect to contribute to the pension plan voluntarily.
Changes in Cash Position
As of December 31, 2022, FirstEnergy had $160 million of cash and cash equivalents and $46 million of restricted cash compared to $1,462 million of cash and cash equivalents and $49 million of restricted cash as of December 31, 2021, on the Consolidated Balance Sheets.
Cash Flows From Operating Activities
FirstEnergy’s most significant sources of cash are derived from electric service provided by its distribution and transmission operating subsidiaries. The most significant use of cash from operating activities is buying electricity to serve non-shopping customers and paying fuel suppliers, employees, tax authorities, lenders and others for a wide range of materials and services.
Net cash provided from operating activities was $2,683 million during 2022, $2,811 million during 2021, and $1,423 million during 2020. The decrease from 2021 to 2022 is primarily due to:
•Rate refunds and rate credits provided to Ohio customers during 2022 under the PUCO-approved Ohio Stipulation,
•Higher operating expenses from lower capitalization of certain vegetation management and corporate support costs,
•Higher materials supplies inventory, primarily due to increased coal and fuel supply inventories to support regulated generation plant operations,
•The absence of accounts receivable working capital improvements in 2021, when collection activity improved since the start of the pandemic. Accounts receivable working capital was also impacted by higher generation prices charged to customers and higher customer usage and demands, partially offset by,
•Higher cash flow generated from regulated capital investments made since 2021,
•Higher cash collateral receipts primarily from certain generation suppliers that serve shopping customers due to the rise in power prices,
•Higher cash dividend distributions received by FEV from its equity investment in Global Holding, and
•Improvements in accounts payable working capital, primarily from the implementation of certain FE Forward initiatives and higher purchased power costs.
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, 2022, 2021 and 2020:
For the Years Ended December 31,
(In millions) 2022 2021 2020
CASH FLOWS FROM OPERATING ACTIVITIES:
Income from discontinued operations $ - $ 44 $ 76
Gain on disposal, net of tax - (47) (76)
Cash Flows From Financing Activities
Cash provided from (used for) financing activities was $(912) million, $(542) million, and $2.6 billion in 2022, 2021, and 2020, respectively. The following table summarizes financing activities for the years ended 2022, 2021, and 2020.
For the Years Ended December 31,
Financing Activities 2022 2021 2020
(In millions)
New Issues
Unsecured notes $ 300 $ 1,750 $ 3,250
FMBs 400 200 175
Senior secured notes - 150 -
700 2,100 3,425
Redemptions / Repayments
Unsecured notes (2,737) (400) (250)
Pollution control revenue bonds - (74) -
FMBs (200) - (50)
Term loan - - (750)
Senior secured notes (68) (58) (64)
(3,005) (532) (1,114)
Proceeds from FET minority interest sale, net of transaction costs 2,348 - -
Distributions to FET minority interest (21) - -
Capital Call from FET minority interest 9 - -
Discounts (premiums) on debt issuances and redemptions, net (151) 27 (4)
Common stock issuance - 1,000 -
Short-term borrowings, net 100 (2,200) 1,200
Common stock dividend payments (891) (849) (845)
Other (1) (88) (55)
$ (912) $ (542) $ 2,607
During the year ended December 31, 2022, FirstEnergy had the following redemptions and issuances:
Company Type Redemption/Issuance Date Interest Rate Maturity Amount
(in Millions) Description
Redemptions
FE Unsecured Notes January, 2022 4.25% 2023 $850 In December 2021, FE provided notice of redemption with a make-whole premium of approximately $38 million ($30 million after-tax).
TE Senior Secured Notes February, 2022 2.65% 2028 $25 On January 27, 2022, TE instructed its indenture trustee to provide notice of partial redemption.
CEI Senior Notes, Series A March, 2022 2.77% 2034 $150 On February 11, 2022, CEI instructed its indenture trustee to provide notice of full redemption.
WP FMBs April, 2022 3.34% 2022 $100 WP redeemed FMBs that became due.
FE Unsecured Notes June, 2022 2.85% 2022 $500 On May 23, 2022 FE provided notice of redemption.
FE Unsecured Notes June, 2022 7.375% 2031 $715 On May 25, 2022, FE commenced an offer to purchase for cash a portion of its 2031 Notes and 2047 Notes, which had $1.5 billion and $1 billion principal amounts outstanding, respectively. A portion of these notes were redeemed for approximately $1.1 billion, including a tender premium of approximately $101 million ($80 million after-tax). In addition, FE recognized approximately $7 million ($5 million after-tax) of deferred cash flow hedge losses and $10 million ($8 million after-tax) in other unamortized debt costs and fees associated with the FE debt redemptions.
FE Unsecured Notes June, 2022 4.85% 2047 $284
Penn FMBs June, 2022 6.09% 2022 $100 Penn redeemed FMBs that became due.
FE Unsecured Notes August-November 2022 7.375% 2031 $128 Beginning in the third quarter of 2022, FE repurchased a portion of the principal amount of its 2031 Notes and 2047 Notes through the open market for approximately $249 million including a premium of approximately $11 million ($9 million after tax). In addition, FE recognized approximately $3 million ($2 million after-tax) in other unamortized debt costs related to the FE open market repurchases.
FE Unsecured Notes August-September 2022 4.85% 2047 $110
Issuances
OE Senior Unsecured Notes September, 2022 5.50% 2033 $300 Proceeds were used to repay borrowings outstanding under the regulated money pool, to finance capital expenditures, to fund working capital needs and for other general corporate purposes.
Penn FMBs November, 2022 3.79% 2032 $150 Proceeds were used to repay short-term borrowings.
WP FMBs November, 2022 5.29% 2033 $250 Proceeds were used to repay short-term borrowings.
On November 29, 2022, WP issued $300 million of 5.29% FMBs due 2033. $250 million was funded on December 13, 2022, and the remaining $50 million was funded on January 10, 2023. Proceeds of the issuance of the FMBs were used to repay short term borrowings.
FE or its affiliates may, from time to time, seek to retire or purchase outstanding debt through open-market purchases, privately negotiated transactions or otherwise. Such repurchases, if any, will be upon such terms and at such prices as FE or its affiliates may determine, and will depend on prevailing market conditions, liquidity requirements, contractual restrictions and other factors.
Cash Flows From Investing Activities
Cash used for investing activities in 2022 principally represented cash used for property additions. The following table summarizes cash used for (received from) investing activities for the years ended 2022, 2021 and 2020:
For the Years Ended December 31,
Investing Activities 2022 2021 2020
(In millions)
Property Additions:
Regulated Distribution $ 1,513 $ 1,395 $ 1,514
Regulated Transmission 1,192 958 1,067
Corporate/Other 51 92 76
Proceeds from sale of Yards Creek - (155) -
Investments 103 53 22
Asset removal costs 213 226 224
Other 4 (10) 5
$ 3,076 $ 2,559 $ 2,908
Cash used for investing activities during 2022 increased $517 million, compared to 2021, primarily due to the absence of proceeds from the sale of Yards Creek received in the first quarter of 2021 as well as planned project spend at Regulated Distribution and Transmission.
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 LOCs, 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, 2022, was approximately $1.0 billion, as summarized below:
Guarantees and Other Assurances Maximum Exposure
(In millions)
FE's Guarantees on Behalf of its Consolidated Subsidiaries
Deferred compensation arrangements $ 445
Vehicle leases 75
Other 8
FE's Guarantees on Other Assurances
Surety Bonds 326
Deferred compensation arrangements 119
LOCs 4
Total Guarantees and Other Assurances $ 977
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, 2022, $50 million of net cash 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. FE or its subsidiaries are holding $206 million of net cash collateral as of December 31, 2022, from certain generation suppliers, primarily due to the rise in power prices, and such amount is included in "Other current liabilities" 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, 2022:
Potential Collateral Obligations Utilities and Transmission Companies FE Total
(In millions)
Contractual Obligations for Additional Collateral
Upon Further Downgrade $ 70 $ - $ 70
Surety Bonds (collateralized amount)(1)
61 249 310
Total Exposure from Contractual Obligations $ 131 $ 249 $ 380
(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.
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 FirstEnergy.
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 Risk Management Department and Enterprise Risk Management Committee are responsible for promoting the effective design and implementation of sound risk management programs and overseeing 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, 2022, FirstEnergy has a net asset of $9 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, 2022, the FirstEnergy pension plan assets were allocated approximately as follows: 33% in public equity securities, 15% in fixed income securities, 9% in hedge funds, 3% in insurance-linked securities, 13% in real estate funds, 17% in private equity and debt funds, a net derivative liability of 1% and 11% in cash and short-term securities. Due to the American Rescue Plan Act of 2021, under current assumptions, including an expected annual return on assets of 8.0% in 2023, FirstEnergy does not currently expect to have a required contribution to the pension plan until 2025. 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, 2022, FirstEnergy's OPEB plan assets were allocated approximately 47% in equity securities, 34% in fixed income securities and 19% in cash and short-term securities. See Note 5, "Pension and Other Post-Employment Benefits," of the Notes to Consolidated Financial Statements for additional details on FirstEnergy's pension and OPEB plans.
During 2022, FirstEnergy's pension and OPEB plan assets have lost approximately $1,760 million or 19.5%, and $70 million or 13.7%, respectively, as compared to the 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. During 2022, interest rates have increased significantly, which has caused the rate and interest expense on borrowings under the 2021 Credit Facilities and refinanced debt to be significantly higher.
Comparison of Carrying Value to Fair Value as of December 31, 2022
Year of Maturity or Notice of Redemption 2023 2024 2025 2026 2027 There-after Total Fair Value
(In millions)
Assets:
Investments Other Than Cash and Cash Equivalents:
Fixed Income $ - $ - $ - $ - $ - $ 266 $ 266 $ 266
Average interest rate - % - % - % - % - % 1.3 % 1.3 %
Liabilities:
Long-term Debt:
Fixed rate $ 344 $ 1,246 $ 2,023 $ 1,076 $ 2,003 $ 14,949 $ 21,641 $ 19,784
Average interest rate 3.7 % 4.7 % 3.8 % 3.5 % 4.2 % 4.4 % 4.3 %
FirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. A primary factor contributing to these actuarial gains and losses are changes in the discount rates used to value pension and OPEB obligations as of the measurement date and the difference between expected and actual returns on the plans’ assets.
The remaining components of pension and OPEB expense, primarily service costs, interest cost on obligations, expected return on plan assets and amortization of prior service costs, are set at the beginning of the calendar year and are recorded on a monthly basis. Changes in asset performance and discount rates will not impact these pension costs during the year, however, future years could be impacted by changes in the market.
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. During 2022, interest rates have increased significantly, which has caused the rate and interest expense on borrowings under the 2021 Credit Facilities to be significantly higher.
Economic Conditions
Economic conditions following the global pandemic, have increased lead times across numerous material categories, with some as much as doubling from pre-pandemic lead times. Some key suppliers have struggled with labor shortages and raw material availability, which along with increasing inflationary pressure, have increased costs and decreased the availability of certain materials, equipment and contractors. FirstEnergy has taken steps to mitigate these risks and does not currently expect service disruptions or any material impact on its capital spending plan. However, the situation remains fluid and a prolonged continuation or further increase in supply chain disruptions could have an adverse effect on FirstEnergy’s results of operations, cash flow and financial condition.
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. 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 in Maryland 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. 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, the electric utility sector is one of the most regulated industries. 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 Operations and Safety Committee reviews FirstEnergy's cybersecurity risk management practices and performance, primarily through reports provided by management, including the Chief Information Security Officer. The Operations and Safety 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
INCOME TAXES
On August 16, 2022, President Biden signed into law the IRA of 2022, which, among other things, imposes a new 15% corporate AMT based on AFSI applicable to corporations with a three-year average AFSI over $1 billion. The AMT is effective for the 2023 tax year and, if applicable, corporations must pay the greater of the regular corporate income tax or the AMT. Although NOL carryforwards created through the regular corporate income tax system cannot be used to reduce the AMT, financial statement net operating losses can be used to reduce AFSI and the amount of AMT owed. The IRA of 2022 as enacted requires the U.S. Treasury to provide regulations and other guidance necessary to administer the AMT, including further defining allowable adjustments to determine AFSI, which directly impacts the amount of AMT to be paid. Based on interim guidance issued by the U.S. Treasury in late December 2022, FirstEnergy continues to believe that it is more likely than not it will be subject to the AMT beginning 2023. Until final U.S. Treasury guidance is issued, the amount of AMT FirstEnergy would pay could be significantly different than current estimates or it may not be a payer at all. The regulatory treatment of the impacts of this legislation will also be subject to the discretion of the FERC and state public utility commissions. Any adverse development in this legislation, including guidance from the U.S. Treasury and/ or the IRS or unfavorable regulatory treatment, could reduce future cash flows and impact financial condition.
STATE REGULATION
Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia, ATSI in Ohio, and the Transmission Companies in Pennsylvania are subject to certain regulations of the VSCC, PUCO and PPUC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility.
The following table summarizes the key terms of base distribution rate orders in effect for the Utilities as of December 31, 2022:
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)
(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) Rates were 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. On August 16, 2022, the MDPSC ordered each utility to file, by October 28, 2022, a set of plans for paying down all amortization balances by
the scheduled expiration of the EmPOWER program on December 31, 2029. PE submitted its required plan on October 28, 2022, and, at the direction of the MDPSC, filed a revised plan on January 11, 2023. 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.
NEW JERSEY
JCP&L operates under NJBPU approved rates that took effect as of January 1, 2021, and 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.
JCP&L has instituted energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act as approved by the NJBPU in April 2021. The NJBPU approved plans include 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.
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 September 19, 2022, the NJBPU issued a notice to re-adopt its rules of practice, including proposed changes to the rules regarding CTA policy in base rate cases consistent with the Superior Court’s June 7, 2021 order. Once the proposed rules of practice 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 October 28, 2020, the NJBPU approved a stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for distribution base rate increase. The settlement provided for 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. The settlement additionally provided that JCP&L would be subject to a management audit, which began in May 2021 and is currently ongoing. JCP&L is currently waiting for issuance of the final report.
On September 14, 2021, JCP&L submitted a supplemental filing with the NJBPU to revise a previously filed AMI Program, which proposed the deployment of approximately 1.2 million advanced meters. 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 investments 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. The Stipulation, which was approved by NJBPU order on February 23, 2022, also provides 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 July 2, 2020, the NJBPU issued an order allowing New Jersey utilities to track and create a regulatory asset for future recovery of all prudently incurred incremental costs arising from the COVID-19 pandemic beginning March 9, 2020 and continuing until the New Jersey Governor issues an order stating that the COVID-19 pandemic is no longer in effect. New Jersey utilities can request recovery of such regulatory asset in a stand-alone COVID-19 regulatory asset filing or future base rate case. On 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. No moratorium on residential disconnections remains in effect for investor-owned electric utilities such as JCP&L, but investor-owned electric public utilities are required to offer qualifying residential customers deferred payment arrangements meeting certain minimum criteria prior to disconnecting service. Additionally, new legislation was enacted on March 25, 2022, prohibiting utilities from disconnecting electric service to customers that have applied for utility bill assistance before June 15, 2022 until such time as the state agency administering the assistance program makes a decision on the application and further requiring that all utilities offer a deferred payment arrangement meeting certain minimum criteria after the state agency’s decision on the application has been made.
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. On May 2, 2022, JCP&L filed with the NJBPU a stipulation entered into with the NJBPU staff, NJ Rate Counsel and others that provided a total budget of approximately $40 million for JCP&L’s electric vehicle program, including investments of approximately $29 million and operations and maintenance expenses of approximately $11 million. Electric vehicle related capital and operations and
maintenance costs shall be deferred and placed in separate regulatory assets for recovery in JCP&L’s next base rate case. The stipulation was approved without modification by the NJBPU on June 8, 2022.
On September 17, 2022, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US and EDF Renewables North America, JCP&L submitted a proposal to the NJBPU and PJM to build transmission infrastructure connecting offshore wind-generated electricity to the New Jersey power grid. On October 26, 2022, the JCP&L proposal was accepted in an order issued by NJBPU. The proposal included approximately $723 million in investments to both build new and upgrade existing transmission infrastructure. JCP&L’s proposal projects an investment ROE of 10.2% and includes the option for JCP&L to acquire up to a 20% equity stake in Mid-Atlantic Offshore Development, LLC. The resulting rates associated with the project are expected to be shared among the ratepayers of all New Jersey electric utilities. Construction is expected to begin in 2025.
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.
On May 16, 2022, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2021, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings.
On July 15, 2022, the Ohio Companies filed an application with the PUCO for approval of phase two of their distribution grid modernization plan that would, among other things, provide for the installation of an additional 700,000 smart meters, distribution automation equipment on approximately 240 distribution circuits, voltage regulating equipment on approximately 220 distribution circuits, and other investments and pilot programs in related technologies designed to provide enhanced customer benefits. The Ohio Companies propose that phase two will be implemented over a four-year budget period with estimated capital investments of approximately $626 million and operations and maintenance expenses of approximately $144 million over the deployment period. Under the proposal, costs of phase two of the grid modernization plan would be recovered through the Ohio Companies’ AMI rider, pursuant to the terms and conditions approved in ESP IV. On December 27, 2022, the Ohio Companies filed a motion with the PUCO requesting a procedural schedule that would facilitate the issuance of an order by year-end 2023.
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 on December 1, 2021, and refunds began in December 2021. Current and future rate reductions are 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.
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 and the auditor filed the final audit report on January 14, 2022, which made certain 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 identity. 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. Final comments and responses were filed by parties during the second quarter of 2022.
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. On May 4, 2022, the PUCO selected a third-party auditor to determine whether the show cause demonstration submitted by the Ohio Companies is sufficient to ensure that the cost of any political or charitable spending in support of HB 6 or the subsequent referendum effort was not included, directly or indirectly, in any rates or charges paid by ratepayers.
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.
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.
On August 16, 2022, the U.S. Attorney for the Southern District of Ohio requested that the PUCO stay the above pending HB 6- related matters for a period of six months, which request was granted by the PUCO on August 24, 2022. Unless otherwise ordered by the PUCO, the four cases are stayed in their entirety, including discovery and motions, and all related procedural schedules are vacated.
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 to provide for refunds in the event such provisions of HB 6 are repealed. Neither the Ohio Companies nor FE benefit from the OVEC-related charges the Ohio Companies collect. Instead, the Ohio Companies are further required by HB 6 to remit all the OVEC-related charges they collect to non-FE Ohio electric distribution utilities. The Ohio Companies contested the motions, which are pending before 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. An evidentiary hearing was held on April 13, 2022, and on April 20, 2022, the parties filed a partial settlement with the PPUC resolving certain of the issues in the proceeding and setting aside the remainder of the issues to be resolved through briefing. PPUC approved the partial settlement, without modification, on August 4, 2022. 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, associated with the additional refund and based on the November 2021 PPUC order and methodology. The Pennsylvania Companies filed petitions to propose the timing and methodology of the refund of these amounts on February 17, 2022. The Pennsylvania Companies’ petitions and the proposed refunds addressed within were approved by the PPUC on June 16, 2022, without modification, effective July 1, 2022, and which refunds were fully completed by December 31, 2022.
Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, the Pennsylvania Companies implemented energy efficiency and peak demand reduction programs with 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.
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 Office of Consumer Advocate 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, which was approved by the PPUC without modification on April 14, 2022.
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 PPUC issued the order as directed, which was challenged by an intervening party. All parties have briefed the issue and await a ruling from the PPUC. Neither the PPUC’s determination or the underlying order are expected to result in a material impact to FirstEnergy.
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 29, 2021, the WVPSC issued an order granting MP and PE’s requested $19.6 million increase in ENEC rates, requiring, among other things, that MP and PE 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. By order dated March 2, 2022, the WVPSC reopened the case to determine whether rates should be increased to recover growing ENEC under-recoveries. On May 17, 2022, the WVPSC issued an order approving an interim rate increase of $94 million, effective for customer rates on May 18, 2022, subject to a prudence review during MP and PE’s 2022 ENEC case.
On August 25, 2022, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates of $183.8 million beginning January 1, 2023, which represents a 12.2% increase to the rates then in effect. The increase was driven by an
underrecovery during the review period (July 1, 2021 to June 30, 2022) of $144.9 million due to higher coal, reagent, and allowance expenses. This filing additionally addresses, among other things, the WVPSC’s May 2022 request for a prudence review of current rates. At a hearing on December 8, 2022, the parties in the case presented a unanimous settlement to increase rates by approximately $92 million, effective January 1, 2023, and carry over to MP and PE’s 2023 ENEC case, approximately $92 million at a carrying charge of 4%. In an order dated December 30, 2022, the WVPSC approved the settlement with respect to the proposed rate increase, but MP and PE rates remain subject to a prudence review in their 2023 ENEC case. The order also instructs MP to evaluate the feasibility of purchasing the Pleasants Power Station and file a summary of the evaluation by March 31, 2023.
On December 27, 2021, the WVPSC approved a settlement granting MP and PE a $16 million increase in rates effective January 1, 2022, and permitting the continuation of the vegetation management program and surcharge for another two years. WVPSC additionally ordered MP and PE to perform equipment inspections within a reasonable time after vegetation management occurs on a circuit.
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 was held in mid-March 2022 and on April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, the requested tariff and requiring MP and PE to subscribe at least 85% of the planned 50 MWs before seeking final tariff approval. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in excess of the approved tariff. The first solar generation site is expected to be in-service by the end of 2023 and all construction completed at the other sites no later than the end of 2025 at a total investment cost of approximately $110 million.
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. MP and PE reached a settlement agreement with WVPSC staff and all intervenors, recommending: (i) approval of the ELG compliance plan submitted by MP and PE and (ii) recovery of costs through a surcharge. A ruling approving the settlement without modification was issued by the WVPSC on September 12, 2022, and construction is expected to be completed by the end of 2025.
On January 13, 2023, MP and PE filed a request with the WVPSC seeking approval of new depreciation rates for existing and future capital assets. Specifically, MP and PE are seeking to increase depreciation expense of $75.5 million per year, primarily for regulated generation-related assets. Any depreciation rates approved by the WVPSC would not become effective until new base rates were established.
FERC REGULATORY MATTERS
Under the FPA, FERC regulates rates for interstate wholesale sales and transmission of electric power, regulatory accounting and reporting under the Uniform System of Accounts, 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, 2022:
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)
Actual (13-month average)(1)
11.35%(1)
PE January 1, 2021(1)
Actual (13-month average)(1)
11.35%(1)
WP January 1, 2021(1)
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)
(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. On January 18, 2023, MP, PE, and WP submitted an uncontested settlement to FERC, which is subject to FERC approval, which includes an allowed ROE of 10.45% and a capital structure of the lower of actual (13-month average) or 56%.
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 Electric Reliability Organization designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to six regional entities, including RFC. All of the facilities that FirstEnergy operates are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC.
FirstEnergy believes that it is in material compliance with all currently effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations, and cash flows.
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 that FirstEnergy has accepted. The audit report included a finding and related recommendation on FirstEnergy’s methodology for allocation of certain corporate support costs to regulatory capital accounts under certain FERC regulations and reporting. Effective in the first quarter of 2022 and in response to the finding, FirstEnergy had implemented a new methodology for the allocation of these corporate support costs to regulatory capital accounts for its regulated distribution and transmission companies on a prospective basis. With the assistance of an independent outside firm, FirstEnergy completed an analysis during the third quarter of 2022 of these costs and how it impacted certain FERC-jurisdictional wholesale transmission customer rates for the audit period of 2015 through 2021. As a result of this analysis, FirstEnergy recorded in the third quarter of 2022 approximately $45 million ($34 million after-tax) in expected customer refunds, plus interest, due to its wholesale transmission customers and reclassified approximately $195 million of certain transmission capital assets to operating expenses for the audit period, of which $90 million ($67 million after-tax) are not expected to be recoverable and impacted FirstEnergy’s earnings since they relate to costs capitalized during stated transmission rate time periods. These reclassifications also resulted in a reduction to the Regulated Transmission segment’s rate base by approximately $160 million, which is not expected to materially impact FirstEnergy or the segment’s future earnings. The expected wholesale transmission customer refunds were recognized as a reduction to revenue, and the amount of reclassified transmission capital assets that are not expected to be recoverable were recognized within “Other operating expenses” at the Regulated Transmission segment and on FirstEnergy’s Consolidated Statements of Income.
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 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 was approved by FERC on March 24, 2022 without modification. ATSI’s compliance filing to implement the terms of the settlement was accepted by FERC without modification on June 23, 2022.
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; to maintain rate base neutrality (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’s 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 following settlement negotiations, filed an uncontested settlement agreement with FERC on October 18, 2022. There is no timetable for FERC to rule on the settlement agreement. 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 following settlement negotiations, filed an uncontested settlement agreement with FERC on October 18, 2022. There is no timetable for FERC to rule on the settlement agreement. 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. On March 31, 2022, FERC issued an order, ruling that TrAIL’s compliance filing partially complied with the requirements of Order No. 864 and directing TrAIL to submit a further compliance filing to address certain additional items that according to FERC will further enhance transparency. TrAIL submitted the compliance filing on May 31, 2022, and FERC accepted the compliance filing by letter order dated August 30, 2022. On April 27, 2022, FERC issued an order on PATH’s compliance filing, ruling that it partially complied with the requirements of Order No. 864 and directing PATH to submit a further compliance filing to address certain additional items. PATH submitted the compliance filing on June 27, 2022, and FERC accepted the compliance filing by letter order dated November 14, 2022. MP, WP and PE - as holders of a “stated” transmission rate when Order No. 864 issued - addressed these requirements as part of the transmission rates amendments that were filed with FERC on October 29, 2020. An uncontested settlement of all issues in that case was filed for FERC approval on January 18, 2023.
ATSI ROE - Ohio Consumers Counsel v. ATSI, et al.
On February 24, 2022, the OCC filed a complaint with FERC against ATSI, AEP’s Ohio affiliates and AEPSC, and Duke Energy Ohio, LLC asserting that FERC should reduce the ROE utilized in the utilities’ transmission formula rates by eliminating the 50 basis point adder associated with RTO membership, effective February 24, 2022. The OCC contends that this result is required because Ohio law mandates that transmission owning utilities join an RTO and that the 50 basis point adder is applicable only where RTO membership is voluntary. ATSI disagrees with the OCC’s characterization and set forth its reasons for such disagreement in a combined motion to dismiss and answer that was filed with FERC on March 31, 2022. On that same date, AEP and Duke filed separate motions to dismiss and answers to the OCC complaint, and several other parties filed comments. ATSI filed a response to certain intervenors’ filings on April 28, 2022. On December 15, 2022, FERC denied the complaint as to ATSI and Duke, but granted it as to AEP. On January 17, 2023, AEP and the OCC filed requests for rehearing and on February 1, 2023, FirstEnergy filed an answer to the OCC’s rehearing request. FirstEnergy is unable to predict the outcome of this proceeding, but it is not expected to have a material impact.
Transmission ROE Incentive
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 on the supplemental rulemaking 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's transmission incentive ROE, such changes will be applied on a prospective basis.
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 filed uncontested settlement agreements with FERC on January 18, 2023. There is no timetable for FERC to rule on the settlement agreements. Also on January 25, 2023, the FERC Chief Administrative Law Judge granted a motion of MP, PE, and WP for interim rates to implement certain aspects of the settled rate retroactive to January 1, 2023. As a result of the filed settlement, FirstEnergy recognized a $25 million pre-tax charge during the fourth quarter of 2022, which reflects the difference between amounts originally recorded as assets and amounts which will ultimately be recovered from customers as a result of the pending settlement.
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 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.
Also 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 National Ambient Air Quality Standards. 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 prior CSAPR Update and the New York Section 126 petition. In December 2021, MP purchased NOx emissions allowances to comply with 2021 ozone season requirements. On April 6, 2022, the EPA published proposed rules seeking to impose further significant reductions in EGU NOx emissions in 25 states, including West Virginia. The EPA held a virtual public hearing regarding the proposed rules on April 21, 2022, and MP submitted written comments on June 21, 2022. 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.
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. Vacating the ACE Rule had the unintended effect of reinstating the CPP because the repeal of the CPP was a provision within the ACE Rule. The D.C. Circuit decision was appealed by several states and interested parties, including West Virginia, arguing that the EPA did not have the authorization under Section 111(d) of the Clean Air Act to require “generation shifting” as a way to limit GHGs. On June 30, 2022, the U.S. Supreme Court held that the EPA’s regulation of GHGs under Section 111(d) of the Clean Air Act was not authorized by Congress and remanded the Rule to the EPA for further reconsideration.
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 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 Spring of 2023 and a final rule later in 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 operation at the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to comply with the ELG rule.
Regulation of Waste Disposal
Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act, 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 cease accepting waste date for the 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, 2022, 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 $97 million have been accrued through December 31, 2022, of which, approximately $62 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 Southern District 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 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, and July 11, 2022, the SEC issued additional subpoenas to FE, with which FE has complied. 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 (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. The class certification hearing is scheduled to take place on March 17, 2023. 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. and Brighthouse Funds II - MFS Value Portfolio, et al. v. FirstEnergy Corp., et al. (S.D. Ohio) on December 17, 2021 and February 21, 2022, purported stockholders of FE filed complaints against FE, certain current and former officers, and certain current and former officers of EH. The complaints allege 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 seek the same relief as the In re FirstEnergy Corp. Securities Litigation described above. FE believes that it is probable that it will incur losses in connection with the resolution of these lawsuits. 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 (Conservation Support Rider) 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. (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. FE agreed to a class settlement to resolve these claims on April 11, 2022. In the fourth quarter of 2021, FirstEnergy recognized a pre-tax reserve of $37.5 million in the aggregate with respect to these lawsuits and the Emmons lawsuit below. On June 22, 2022, the court preliminarily approved the class settlement and the final fairness hearing was held on November 9, 2022. On December 5, 2022, the court issued an order memorializing its final approval of the class settlement. The settlement amount was satisfied on December 7, 2022.
•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. FE agreed to a class settlement to resolve these claims on April 11, 2022. In the fourth quarter of 2021, FirstEnergy recognized 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 June 22, 2022, the court preliminarily approved the class settlement and the final fairness hearing was held on November 9, 2022. The S.D. Ohio issued a final written order approving the settlement on December 5, 2022. The settlement amount was satisfied on December 7, 2022.
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. (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. (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.
On March 11, 2022, the parties executed a stipulation and agreement of settlement, and filed a motion the same day requesting preliminary settlement approval in the S.D. Ohio, which the S.D Ohio granted on May 9, 2022. Subsequently, following a hearing on August 4, 2022, the S.D. Ohio granted final approval of the settlement on August 24, 2022. The settlement agreement is expected to resolve fully these shareholder derivative lawsuits and includes a series of corporate governance enhancements, that have resulted in the following:
•Six then-members of the FE Board did 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 was formed to initiate a review process of the then current senior executive team. The review of the senior executive team by the special FE Board committee and the FE Board was completed in September 2022;
•The FE Board will oversee FE’s lobbying and political activities, including periodically reviewing and approving political and lobbying action plans prepared by management;
•An FE Board committee of recently appointed independent directors will 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 FE of $180 million, to be paid by insurance after the judgment has become final, less $36 million in court-ordered attorney’s fees awarded to plaintiffs. On September 20, 2022, a purported FE stockholder filed a motion for reconsideration of the S.D. Ohio’s final settlement approval. The parties filed oppositions to that motion on October 11, 2022 and the motion is under consideration by the S.D. Ohio. The N.D. Ohio matter remains pending. On June 2, 2022, the N.D. Ohio entered an order to show cause why the court should not appoint new plaintiffs’ counsel, and thereafter, on June 10, 2022, the parties filed a joint motion to dismiss the matter without prejudice, which the N.D. Ohio denied on July 5, 2022. On August 15, 2022, the N.D. Ohio issued an order stating its intention to appoint one group of applicants as new plaintiffs’ counsel, and on August 22, 2022, the N.D. Ohio ordered that any objections to the appointment be submitted by August 26, 2022. The parties filed their objections by that deadline, and on September 2, 2022, the applicants responded to those objections. In the meantime, on August 25, 2022, a purported FE stockholder represented by the applicants filed a motion to intervene, attaching a proposed complaint-in-intervention purporting to assert claims that the FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act as well as a claim against a third party for professional negligence and malpractice. The parties filed oppositions to that motion to intervene on September 8, 2022, and the proposed intervenor's reply in support of his motion to intervene was filed on September 22, 2022.
On August 24, 2022, the parties filed a joint motion to dismiss the action pending in the N.D. Ohio based upon and in light of the approval of the settlement by the S.D. Ohio. On August 30, 2022, the parties filed a joint motion to dismiss the state court action, which the court granted on September 2, 2022.
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. On December 30, 2022, FERC approved a Stipulation and Consent Agreement that resolves the investigation. The agreement includes a FirstEnergy admission of violating FERC’s “duty of candor” rule and related laws, and obligates FirstEnergy to pay a civil penalty of $3.86 million, and to submit two annual compliance monitoring reports to FERC’s Office of Enforcement regarding improvements to FirstEnergy’s compliance programs.
FE terminated Charles E. Jones as its chief executive officer effective October 29, 2020. As a result of Mr. Jones’ termination, and due to the determination of a committee of independent members of the FE Board that Mr. Jones violated certain FirstEnergy policies and its code of conduct, all grants, awards and compensation under FirstEnergy’s short-term incentive compensation program and long-term incentive compensation program with respect to Mr. Jones that were outstanding on the date of termination were forfeited. In November 2021, after a determination by the Compensation Committee of the FE Board that a demand for recoupment was warranted pursuant to the Recoupment Policy, FE made a recoupment demand to Mr. Jones of compensation previously paid to him totaling approximately $56 million, the maximum amount permissible under the Recoupment Policy. As such, any amounts payable to Mr. Jones under the EDCP will be set off against FE’s recoupment demand. There can be no assurance that the efforts to seek recoupment from Mr. Jones will be successful.
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 financial instruments, derivatives, late payment charges and 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 guidance.
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 Regulated Distribution segment 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.
Regulated Transmission segment 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 rate base and costs. Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time.
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, the historical performance of risk-based and fixed income securities and other factors. 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 pension and OPEB assets for 2023 is 8.0% and 7.0%, respectively.
.
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 due to the ongoing impact of COVID-19 was utilized to determine the 2023 benefit cost and obligation as of December 31, 2022, for FirstEnergy's pension and OPEB plans. The MP-2021 scale was published in 2021 by the Society of Actuaries.
Health Care Trend Rates - Included in determining trend rate assumptions 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 (Credits) - 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.
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, 2022, 2021, and 2020:
Net Periodic Benefit Costs (Credits) 2022 2021 2020
(In millions)
Pension $ (389) $ (582) $ 254
OPEB (12) (170) (47)
Total $ (401) $ (752) $ 207
The annual pension and OPEB mark-to-market adjustments, (gains) or losses, for the years ended December 31, 2022, 2021, and 2020 were $(72) million, $(382) million and $477 million, respectively.
FirstEnergy expects its 2023 pre-tax net periodic benefit expense including amounts capitalized (excluding mark-to-market adjustments) to be approximately $46 million based upon the following assumptions:
Assumption Pension OPEB
Effective rate for interest on benefit obligations 5.10 % 5.06 %
Effective rate for service costs 5.34 % 5.41 %
Effective rate for interest on service costs 5.22 % 5.33 %
Expected return on plan assets 8.00 % 7.00 %
Rate of compensation increase 4.30 % N/A
The approximate effects on 2023 pension and OPEB net periodic benefit costs and the 2022 benefit obligation from changes in key assumptions are as follows:
Approximate Effect on 2023 Net Periodic Benefit Costs from Changes in Key Assumptions
Assumption Change Pension OPEB Total
(In millions)
Discount rate Change by 0.25% (1)
$ 230 $ 9 $ 239
Expected return on plan assets Change by 0.25% $ 16 $ 1 $ 17
Health care trend rate Change by 1.0% N/A $ 6 $ 6
(1) Assumes a parallel shift in yield curve.
Approximate Effect on 2022 Benefit Obligation from Changes in Key Assumptions
Assumption Change Pension OPEB Total
(In millions)
Discount rate Change by 0.25% (1)
$ 233 $ 9 $ 242
Health care trend rate Change by 1.0% N/A $ 6 $ 6
(1) Assumes a parallel shift in yield curve.
See Note 5, "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.
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 7, "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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by Item 7A relating to market risk is set forth in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations."

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The consolidated financial statements and supplementary data of FirstEnergy required in this item are set forth beginning on page 73.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of FirstEnergy Corp.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of FirstEnergy Corp. and its subsidiaries (the “Company”) as of December 31, 2022 and 2021, and the related consolidated statements of income, of comprehensive income, of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2022, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or
complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Rate Regulation
As described in Note 1 to the consolidated financial statements, the Company’s Regulated Distribution and Regulated Transmission segments are subject to regulation that sets the prices (rates) the Company is permitted to charge customers based on costs that the regulatory agencies determine are permitted to be recovered. At times, regulatory agencies permit the future recovery of costs that would be currently charged to expense by an unregulated company. The ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows. Management reviews the probability of recovery of regulatory assets, and settlement of regulatory liabilities, at each balance sheet date and whenever new events occur. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order, or passage of new legislation. Upon material changes to these factors, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that currently recorded regulatory assets and liabilities will be recovered or settled in future rates. As of December 31, 2022, there were $33 million of regulatory assets and $1,847 million of regulatory liabilities.
The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a critical audit matter are the significant audit effort in assessing the impact of regulation on accounting for regulatory assets and liabilities and in evaluating the complex audit evidence related to whether the regulatory assets will be recovered and liabilities settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the accounting for regulatory matters, including controls over the evaluation of the recoverability and settlement of existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s assessment regarding regulatory guidance, proceedings, and legislation and the related accounting implications, and calculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Cleveland, Ohio
February 13, 2023
We have served as the Company’s auditor since 2002.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,
(In millions, except per share amounts) 2022 2021 2020
REVENUES:
Distribution services and retail generation $ 9,916 $ 9,009 $ 8,688
Transmission 1,863 1,608 1,613
Other 680 515 489
Total revenues(1)
12,459 11,132 10,790
OPERATING EXPENSES:
Fuel 730 481 369
Purchased power 3,863 2,964 2,701
Other operating expenses 3,817 3,196 3,291
Provision for depreciation 1,375 1,302 1,274
Amortization (deferral) of regulatory assets, net (365) 269 (53)
General taxes 1,129 1,073 1,046
DPA penalty (Note 13)
- 230 -
Gain on sale of Yards Creek (Note 14)
- (109) -
Total operating expenses 10,549 9,406 8,628
OPERATING INCOME 1,910 1,726 2,162
OTHER INCOME (EXPENSE):
Debt redemption costs (Note 10)
(171) (2) -
Equity method investment earnings (Note 1) 168 31 2
Miscellaneous income, net 415 486 430
Pension and OPEB mark-to-market adjustment 72 382 (477)
Interest expense (1,039) (1,139) (1,065)
Capitalized financing costs 84 75 77
Total other expense (471) (167) (1,033)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 1,439 1,559 1,129
INCOME TAXES 1,000 320 126
INCOME FROM CONTINUING OPERATIONS 439 1,239 1,003
Discontinued operations (Note 15)(2)
- 44 76
NET INCOME $ 439 $ 1,283 $ 1,079
Income attributable to noncontrolling interest (continuing operations) 33 - -
EARNINGS ATTRIBUTABLE TO FIRSTENERGY CORP. $ 406 $ 1,283 $ 1,079
EARNINGS PER SHARE ATTRIBUTABLE TO FIRSTENERGY CORP.
Basic - Continuing Operations $ 0.71 $ 2.27 $ 1.85
Basic - Discontinued Operations - 0.08 0.14
Basic - Earnings Per Share Attributable to FirstEnergy Corp. $ 0.71 $ 2.35 $ 1.99
Diluted - Continuing Operations $ 0.71 $ 2.27 $ 1.85
Diluted - Discontinued Operations - 0.08 0.14
Diluted - Earnings Per Share Attributable to FirstEnergy Corp. $ 0.71 $ 2.35 $ 1.99
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic 571 545 542
Diluted 572 546 543
(1) Includes excise and gross receipts tax collections of $406 million, $374 million and $362 million in 2022, 2021 and 2020, respectively.
(2) Net of income tax benefit of $48 million and $59 million in 2021 and 2020, respectively.
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31,
(In millions) 2022 2021 2020
NET INCOME $ 439 $ 1,283 $ 1,079
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs (9) (14) (34)
Amortized losses on derivative hedges 9 1 1
Other comprehensive loss - (13) (33)
Income tax benefits on other comprehensive loss
(1) (3) (8)
Other comprehensive income (loss), net of tax 1 (10) (25)
COMPREHENSIVE INCOME $ 440 $ 1,273 $ 1,054
Comprehensive income attributable to noncontrolling interest 33 - -
COMPREHENSIVE INCOME ATTRIBUTABLE TO FIRSTENERGY CORP. $ 407 $ 1,273 $ 1,054
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts) December 31,
2022 December 31,
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 160 $ 1,462
Restricted cash 46 49
Receivables-
Customers 1,455 1,192
Less - Allowance for uncollectible customer receivables 137 159
1,318 1,033
Other, net of allowance for uncollectible accounts of $11 in 2022 and $10 in 2021
253 246
Materials and supplies, at average cost 421 260
Prepaid taxes and other 217 187
2,415 3,237
PROPERTY, PLANT AND EQUIPMENT:
In service 47,850 46,002
Less - Accumulated provision for depreciation 13,258 12,672
34,592 33,330
Construction work in progress 1,693 1,414
36,285 34,744
INVESTMENTS AND OTHER NONCURRENT ASSETS
Goodwill 5,618 5,618
Investments (Note 9)
622 655
Regulatory assets 33 71
Other 1,135 1,107
7,408 7,451
$ 46,108 $ 45,432
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 351 $ 1,606
Short-term borrowings 100 -
Accounts payable 1,503 943
Accrued interest 254 283
Accrued taxes 668 647
Accrued compensation and benefits 272 313
Dividends payable (Note 10)
223 222
Customer deposits 223 214
Other 364 188
3,958 4,416
CAPITALIZATION:
Stockholders’ equity-
Common stock, $0.10 par value, authorized 700,000,000 shares - 572,130,932 and 570,261,104 shares outstanding as of December 31, 2022 and 2021, respectively
57 57
Other paid-in capital 11,322 10,238
Accumulated other comprehensive loss (14) (15)
Accumulated deficit (1,199) (1,605)
Total common stockholders' equity 10,166 8,675
Noncontrolling interest 477 -
Total equity 10,643 8,675
Long-term debt and other long-term obligations 21,203 22,248
31,846 30,923
NONCURRENT LIABILITIES:
Accumulated deferred income taxes 4,202 3,437
Retirement benefits 2,335 2,669
Regulatory liabilities 1,847 2,124
Other 1,920 1,863
10,304 10,093
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13)
$ 46,108 $ 45,432
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Common Stock OPIC AOCI Accumulated Deficit Total Common Stockholders' Equity
(In millions) Shares Amount NCI Total Equity
Balance, January 1, 2020 541 $ 54 $ 10,868 $ 20 $ (3,967) $ 6,975 $ - $ 6,975
Net income 1,079 1,079 1,079
Other comprehensive loss, net of tax (25) (25) (25)
Cash dividends declared on common stock (1)
(846) (846) (846)
Stock Investment Plan and share-based benefit plans 2 - 54 54 54
Balance, December 31, 2020 543 54 10,076 (5) (2,888) 7,237 - 7,237
Net income 1,283 1,283 1,283
Other comprehensive loss, net of tax (10) (10) (10)
Cash dividends declared on common stock (1)
(859) (859) (859)
Common stock issuance (Note 10)
26 3 971 974 974
Stock Investment Plan and share-based benefit plans 1 50 50 50
Balance, December 31, 2021 570 57 10,238 (15) (1,605) 8,675 - 8,675
Net income 406 406 33 439
Other comprehensive income, net of tax 1 1 1
Cash dividends declared on common stock (1)
(892) (892) (892)
Stock Investment Plan and share-based benefit plans 2 - 98 98 98
FET minority interest sale, net of transaction costs (Note 1) 1,887 1,887 451 2,338
Distribution to FET minority interest - (21) (21)
Capital contribution from FET minority interest - 9 9
Consolidated tax benefit allocation (5) (5) 5 -
Other (4) (4) (4)
Balance, December 31, 2022 572 $ 57 $ 11,322 $ (14) $ (1,199) $ 10,166 $ 477 $ 10,643
(1) Dividends declared for each share of common stock were $1.56 during 2022, 2021 and 2020.
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
(In millions) 2022 2021 2020
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 439 $ 1,283 $ 1,079
Adjustments to reconcile net income to net cash from operating activities-
Depreciation, amortization, and impairments 1,317 1,664 1,199
Retirement benefits, net of payments (378) (417) (301)
Pension and OPEB mark-to-market adjustments (72) (382) 477
Deferred income taxes and investment tax credits, net 989 297 113
Transmission revenue collections, net 79 182 (32)
Gain on sale of Yards Creek - (109) -
Settlement agreement and tax sharing payments to the FES Debtors - - (978)
Gain on disposal, net of tax (Note 15)
- (47) (76)
Changes in current assets and liabilities-
Receivables (292) 160 (129)
Materials and supplies (161) 57 (32)
Prepaid taxes and other current assets (28) 18 6
Accounts payable 560 117 (138)
Accrued taxes 22 7 159
Accrued interest (29) - 33
Other current liabilities 21 (52) 81
Cash collateral, net 111 31 (12)
Other 105 2 (26)
Net cash provided from operating activities 2,683 2,811 1,423
CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Long-term debt 700 2,100 3,425
Short-term borrowings, net 100 - 1,200
Common stock issuance - 1,000 -
Redemptions and repayments-
Long-term debt (3,005) (532) (1,114)
Short-term borrowings, net - (2,200) -
Discounts (premiums) on debt issuances and redemptions, net (151) 27 (4)
Proceeds from FET minority interest sale, net of transaction costs 2,348 - -
Distributions to FET minority interest (21) - -
Capital contributions from FET minority interest 9 - -
Common stock dividend payments (891) (849) (845)
Other (1) (88) (55)
Net cash provided from (used for) financing activities (912) (542) 2,607
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (2,756) (2,445) (2,657)
Proceeds from sale of Yards Creek - 155 -
Sales of investment securities held in trusts 48 48 186
Purchases of investment securities held in trusts (59) (59) (208)
Asset removal costs (213) (226) (224)
Other (96) (32) (5)
Net cash used for investing activities (3,076) (2,559) (2,908)
Net change in cash, cash equivalents and restricted cash (1,305) (290) 1,122
Cash, cash equivalents, and restricted cash at beginning of period 1,511 1,801 679
Cash, cash equivalents, and restricted cash at end of period $ 206 $ 1,511 $ 1,801
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid (received) during the year-
Interest (net of amounts capitalized) $ 1,021 $ 1,085 $ 970
Income taxes, net of refunds $ 21 $ (7) $ 6
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note
Number
Page
Number
Organization and Basis of Presentation
2 Revenue 85
3 Earnings Per Share 89
4 Accumulated Other Comprehensive Income 91
5 Pension and Other Postemployment Benefits
6 Stock-Based Compensation Plans 91
7 Taxes 93
8 Leases 97
9 Fair Value Measurements 100
10 Capitalization 102
11 Short-Term Borrowings and Bank Lines of Credit 105
12 Regulatory Matters 107
13 Commitments, Guarantees and Contingencies 115
14 Segment Information 120
15 Discontinued Operations 123
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary of Terms.
FE was incorporated under Ohio law in 1996. FE’s principal business is the holding, directly or indirectly, of all of the outstanding equity of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FESC, MP, AGC (a wholly owned subsidiary of MP), PE, WP, and FET and its principal subsidiaries (ATSI, MAIT and TrAIL). In addition, FE holds all of the outstanding equity of other direct subsidiaries including FEV which currently holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations.
FE does not bill directly or allocate any of its costs to any subsidiary company. Costs are charged to FE's subsidiaries for services received from FESC either through direct billing or through an allocation process. Allocated costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas developed by FESC. Intercompany transactions are generally settled under commercial terms within thirty days.
FE and its subsidiaries are principally involved in the transmission, distribution, and generation of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving over six million customers in the Midwest and Mid-Atlantic regions. FirstEnergy’s transmission operations include over 24,000 miles of transmission lines and two regional transmission operation centers. AGC and MP control 3,580 MWs of total capacity.
PN, as lessee of the property of its subsidiary, the Waverly Electric Light & Power Company, serves approximately 4,000 customers in the Waverly, New York vicinity. On February 10, 2021, PN entered into an agreement to transfer its customers and the related assets in Waverly, New York to Tri-County Rural Electric Cooperative. PN and Tri-County Rural Electric Cooperative have jointly decided not to move forward with the transfer. As a result, on September 30, 2022 both parties notified the NYPSC that the transaction would not occur.
The accompanying consolidated financial statements have been prepared in accordance with GAAP and the rules and regulations of the SEC. FE and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not necessarily indicative of results of operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued.
FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation as appropriate and permitted pursuant to GAAP. As further discussed below, FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary. Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income.
Certain prior year amounts have been reclassified to conform to the current year presentation.
Economic Conditions
Economic conditions following the global pandemic, have increased lead times across numerous material categories, with some as much as doubling from pre-pandemic lead times. Some key suppliers have struggled with labor shortages and raw material availability, which along with increasing inflationary pressure, have increased costs and decreased the availability of certain materials, equipment and contractors. FirstEnergy has taken steps to mitigate these risks and does not currently expect service disruptions or any material impact on its capital spending plan. However, the situation remains fluid and a prolonged continuation or further increase in supply chain disruptions could have an adverse effect on FirstEnergy’s results of operations, cash flow and financial condition.
Sale of Minority Equity Interest in FirstEnergy Transmission, LLC
On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The purchase price will be payable in part by the issuance of a promissory note expected to be in the principal amount of $1.75 billion. The remaining $1.75 billion of the purchase price will be payable in
cash at the closing. As a result of the consummation of the transaction, Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1% ownership interests of FET. The transaction is subject to customary closing conditions, including approval from the FERC and certain state utility commissions, and completion of review by the CFIUS. In addition, pursuant to the FET P&SA II, FirstEnergy has agreed to make the necessary filings with the applicable regulatory authorities for the PA Consolidation. The FET Minority Equity Interest Sale is expected to close by early 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s GAAP financial statements.
Pursuant to the terms of the FET P&SA II, in connection with the closing, Brookfield, FET and FE will enter into the A&R FET LLC Agreement, which will amend and restate in its entirety the current limited liability company agreement of FET. The A&R FET LLC Agreement, among other things, provides for the governance, exit, capital and distribution, and other arrangements for FET from and following the closing. Under the A&R FET LLC Agreement, at the closing, the FET Board will consist of five directors, two appointed by Brookfield and three appointed by FE. Each of Brookfield’s and FE’s respective appointment rights are subject to such party maintaining certain minimum ownership percentages. The A&R FET LLC Agreement contains certain investor protections, including, among other things, requiring Brookfield's approval for FET and its subsidiaries to take certain major actions. Under the terms of the A&R FET LLC Agreement, for so long as Brookfield holds at least a 30.0% interest in FET, Brookfield’s consent is required for FET or any of its subsidiaries to, among other things, undertake certain acquisitions or dispositions in excess of certain dollar thresholds, establish or amend the annual budget, incur cost overruns on certain capital expenditures projects during any fiscal year in excess of a certain percentage overage of the budgeted amounts or incur cost overruns on the aggregate capital expenditure budget of FET’s subsidiaries during any fiscal year in excess of a certain percentage overage of the aggregated budgeted amount, make material decisions relating to litigation where either the potential liability exposure is in excess of a certain threshold dollar amount or such proceeding would reasonably be expected to have an adverse effect on Brookfield or FET, make certain material regulatory filings, incur or refinance indebtedness by FET or its subsidiaries, which, in the case of its subsidiaries, would reasonably be expected to cause such subsidiary to deviate from its targeted capital structure, enter into joint ventures, appoint or replace any member of its transmission leadership team, amend the accounting policies of FET or its subsidiaries (but only if FirstEnergy Corp is no longer the majority owner of FET), take any action that would reasonably be expected to cause a default or breach of any material contract of FET or any of its subsidiaries, create certain material liens (excluding certain permitted liens), or cause any reorganization of FET or any of its subsidiaries. The A&R FET LLC Agreement also includes provisions relating to the resolution of disputes and to address deadlocks.
Consolidation of Pennsylvania Companies
FirstEnergy is proceeding with the consolidation of the Pennsylvania Companies into a new, single operating entity. The PA Consolidation will require, among other steps: (a) the transfer of certain Pennsylvania-based transmission assets owned by WP to KATCo, (b) the transfer of Class B equity interests of MAIT currently held by PN and ME to FE (and ultimately transferred to FET as part of the FET Minority Equity Interest Sale), (c) the formation of PA NewCo and (d) the merger of each of the Pennsylvania Companies with and into PA NewCo, with PA NewCo surviving such mergers as the successor-in-interest to all assets and liabilities of the Pennsylvania Companies. Following completion of the PA Consolidation, PA NewCo will be FE’s only regulated utility in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies. Consummation of the PA Consolidation is contingent upon numerous conditions, including the approval of NYPSC, PPUC and FERC. Subject to receipt of such regulatory approvals, FirstEnergy expects that the PA Consolidation will close by early 2024.
ACCOUNTING FOR THE EFFECTS OF REGULATION
FirstEnergy’s Regulated Distribution and Regulated Transmission segments are subject to regulation that sets the prices (rates) the Utilities and the Transmission Companies are permitted to charge customers based on costs that the regulatory agencies determine are permitted to be recovered. At times, regulatory agencies permit the future recovery of costs that would be currently charged to expense by an unregulated company. The ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows.
FirstEnergy reviews the probability of recovery of regulatory assets, and settlement of regulatory liabilities, at each balance sheet date and whenever new events occur. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order, or passage of new legislation. Upon material changes to these factors, where applicable, FirstEnergy will record new regulatory assets or liabilities and will assess whether it is probable that currently recorded regulatory assets and liabilities will be recovered or settled in future rates. If recovery of a regulatory asset is no longer probable, FirstEnergy will write-off that regulatory asset as a charge against earnings. FirstEnergy considers the entire regulatory asset balance as the unit of account for the purposes of balance sheet classification rather than the next years recovery and as such net regulatory assets and liabilities are presented in the non-current section on the FirstEnergy Consolidated Balance Sheets. See Note 12, "Regulatory Matters," of the Notes to Consolidated Financial Statements for additional information.
The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2022 and 2021, and the changes during the year ended December 31, 2022:
As of December 31,
Net Regulatory Assets (Liabilities) by Source 2022 2021 Change
(In millions)
Customer payables for future income taxes $ (2,463) $ (2,345) $ (118)
Spent nuclear fuel disposal costs (83) (101) 18
Asset removal costs (675) (646) (29)
Deferred transmission costs 50 (3) 53
Deferred generation costs 235 118 117
Deferred distribution costs 164 49 115
Storm-related costs 683 660 23
Uncollectible and pandemic-related costs 63 56 7
Energy efficiency program costs 94 47 47
New Jersey societal benefit costs 94 109 (15)
Vegetation management 63 33 30
Other (39) (30) (9)
Net Regulatory Liabilities included on the Consolidated Balance Sheets $ (1,814) $ (2,053) $ 239
The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2022 and 2021, of which approximately $511 million and $228 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral and the jurisdiction:
Regulatory Assets by Source Not Earning a As of December 31,
Current Return 2022 2021 Change
(In millions)
Deferred transmission costs $ 8 $ 13 $ (5)
Deferred generation costs 262 63 199
Deferred distribution costs 27 2 25
Storm-related costs 568 549 19
Pandemic-related costs 70 65 5
Vegetation management 52 31 21
Other 10 9 1
Regulatory Assets Not Earning a Current Return $ 997 $ 732 $ 265
DERIVATIVES
FirstEnergy is exposed to limited financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, coal and energy transmission. To manage the volatility related to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy may use a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchases and normal sales criteria. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance.
EQUITY METHOD INVESTMENTS
Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and reflected in "Investments". The percentage of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income and reflected in “Miscellaneous Income, net”. Equity method investments are assessed for impairment annually or whenever events and changes
in circumstances indicate that the carrying amount of the investment may not be recoverable. If the decline in value is considered to be other than temporary, the investment is written down to its estimated fair value, which establishes a new cost basis in the investment.
Equity method investments included within "Investments" on the Consolidated Balance Sheets were $90 million and $88 million as of December 31, 2022 and 2021, respectively.
Global Holdings - FEV currently holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales primarily focused on international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint ventures economic performance. FEV's ownership interest is subject to the equity method of accounting. For the years ended December 31, 2022, 2021 and 2020, pre-tax income related to FEV’s ownership in Global Holding was $168 million, $29 million and $2 million, respectively. FEV’s pre-tax equity earnings and investment in Global Holding are included in Corporate/Other for segment reporting.
As of December 31, 2022 and 2021, the carrying value of the equity method investment was $57 million and $59 million, respectively. During 2022, FEV received cash dividends from Global Holding totaling $170 million, which were classified with “Cash from Operating Activities” on FirstEnergy’s Consolidated Statements of Cash Flow.
PATH WV - PATH, a proposed transmission line from West Virginia through Virginia into Maryland which PJM cancelled in 2012, is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of FE owns 100% of the Allegheny Series (PATH-Allegheny) and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of PATH-WV. FirstEnergy's ownership interest in PATH-WV is subject to the equity method of accounting. As of December 31, 2022 and 2021, the carrying value of the equity method investment was $18 million. FirstEnergy's pre-tax equity earnings in PATH-WV were immaterial for the years ended December 31, 2022, 2021 and 2020
VARIABLE INTEREST ENTITIES
FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has: (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance; and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary.
In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance.
Consolidated VIEs
VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial statements):
•Ohio Securitization - In June 2013, SPEs formed by the Ohio Companies issued approximately $445 million of pass-through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets.
•MP and PE Environmental Funding Companies - Bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE which issued environmental control bonds.
See Note 10, “Capitalization,” for additional information on securitized bonds.
Unconsolidated VIEs
FirstEnergy is not the primary beneficiary of its equity method investments in Global Holding and PATH WV, as further discussed above, or its PPAs.
FirstEnergy evaluated its PPAs and determined that certain NUG entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy maintains six long-term PPAs with NUG entities that were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, any of these entities. FirstEnergy has determined that for all but one of these NUG entities, it does not have a variable interest, or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold a variable interest in the remaining one entity; however, it applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.
Because FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred at its Regulated Distribution segment to be recovered from customers. Purchased power costs related to the contract that may contain a variable interest were $119 million, $111 million and $113 million, respectively, during the years ended December 31, 2022, 2021 and 2020.
GOODWILL
In a business combination, the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise. In evaluating goodwill for impairment, FirstEnergy assesses qualitative factors to determine whether it is more likely than not (that is, likelihood of more than 50%) that the fair value of a reporting unit is less than its carrying value (including goodwill). If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then no further testing is required. However, if FirstEnergy concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying value or bypasses the qualitative assessment, then the quantitative goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized, if any.
As of July 31, 2022, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission reporting units' goodwill, assessing economic, industry and market considerations in addition to the reporting units' overall financial performance. Key factors used in the assessment included: growth rates, interest rates, expected investments, utility sector market performance, regulatory and legal developments, and other market considerations. It was determined that the fair values of these reporting units were, more likely than not, greater than their carrying values and a quantitative analysis was not necessary.
FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution and Regulated Transmission. The following table presents goodwill by reporting unit as of December 31, 2022:
(In millions) Regulated Distribution Regulated Transmission Consolidated
Goodwill $ 5,004 $ 614 $ 5,618
INVENTORY
Materials and supplies inventory primarily includes emission allowances, fuel inventory and the distribution, transmission and generation plant materials, net of reserve for excess and obsolete inventory. Materials charged to inventory are at weighted average cost when purchased and expensed or capitalized, as appropriate, when used or installed. Fuel inventory is accounted for at weighted average cost when purchased and recorded to fuel expense when consumed. Emission allowances are accounted for at cost when purchased and charged to expense monthly based on each month’s emissions.
NONCONTROLLING INTEREST
FirstEnergy maintains a controlling financial interest in certain less than wholly owned subsidiaries. As a result, FirstEnergy presents the third-party investors’ ownership portion of FirstEnergy's net income, net assets and comprehensive income as noncontrolling interest. Noncontrolling interest is included as a component of equity on the Consolidated Balance Sheets.
On November 6, 2021, FirstEnergy, along with FET, entered into the FET P&SA I, 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 would own 19.9% of the issued and outstanding membership interests of FET, for a purchase price of $2.375 billion. The transaction closed on May 31, 2022. The difference between the cash consideration received, net of transaction costs of approximately $37 million, and the carrying value of the noncontrolling interest of $451 million was recorded as an increase to OPIC. KATCo, which was a subsidiary of FET, became a wholly owned subsidiary of FE prior to the closing of the transaction and remains in the Regulated Transmission segment.
Pursuant to the terms of the FET P&SA I, on May 31, 2022, Brookfield, FET and FE entered into the FET LLC Agreement. The FET LLC Agreement, among other things, provides for the governance, exit, capital and distribution, and other arrangements for FET from and following the closing. Under the FET LLC Agreement, Brookfield is entitled to appoint a number of directors to the FET Board, in approximate proportion to Brookfield’s ownership percentage in FET (rounded to the next whole number). The FET Board now consists of five directors, one appointed by Brookfield and four appointed by FE. The FET LLC Agreement contains certain investor protections, including, among other things, requiring Brookfield's approval for FET and its subsidiaries to take certain major actions. Under the terms of the FET LLC Agreement, for so long as Brookfield holds a 9.9% interest in FET, Brookfield’s consent is required for FET or any of its subsidiaries to incur indebtedness (other than the refinancing of existing indebtedness on commercially reasonable terms reflecting then-current credit market conditions) that would reasonably be expected to result in FET’s consolidated Debt-to-Capital Ratio (as defined in the FET LLC Agreement) equaling or exceeding (i) prior to the fifth anniversary of the effective date, 65%, and (ii) thereafter, 70%. As discussed above in Sale of Minority Equity Interest in FirstEnergy Transmission, LLC within Note 1, "Organization and Basis of Presentation," pursuant to the terms of the
FET P&SA II and in connection with the closing thereof, Brookfield, FET and FE will enter into the A&R FET LLC Agreement, which will amend and restate in its entirety the FET LLC Agreement.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment reflects original cost (net of any impairments recognized), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and financing costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy recognizes liabilities for planned major maintenance projects as they are incurred. Property, plant and equipment balances by segment as of December 31, 2022 and 2021, were as follows:
December 31, 2022
Property, Plant and Equipment In Service(1)
Accum. Depr. Net Plant CWIP Total
(In millions)
Regulated Distribution $ 32,257 $ (9,636) $ 22,621 $ 828 $ 23,449
Regulated Transmission 14,468 (2,978) 11,490 818 12,308
Corporate/Other 1,125 (644) 481 47 528
Total $ 47,850 $ (13,258) $ 34,592 $ 1,693 $ 36,285
December 31, 2021
Property, Plant and Equipment In Service(1)
Accum. Depr. Net Plant CWIP Total
(In millions)
Regulated Distribution $ 31,154 $ (9,284) $ 21,870 $ 774 $ 22,644
Regulated Transmission 13,744 (2,789) 10,955 580 11,535
Corporate/Other 1,104 (599) 505 60 565
Total $ 46,002 $ (12,672) $ 33,330 $ 1,414 $ 34,744
(1) Includes finance leases of $105 million and $143 million as of December 31, 2022 and 2021, respectively.
Regulated Distribution has approximately $2.2 billion of total regulated generation property, plant and equipment as of December 31, 2022.
FirstEnergy provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite depreciation rates for FirstEnergy were approximately 2.7% in each 2022, 2021 and 2020.
For the years ended December 31, 2022, 2021 and 2020, capitalized financing costs on FirstEnergy's Consolidated Statements of Income include $56 million, $48 million and $49 million, respectively, of allowance for equity funds used during construction and $28 million, $27 million and $28 million, respectively, of capitalized interest.
Asset Impairments
FirstEnergy evaluates long-lived assets classified as held and used for impairment when events or changes in circumstances indicate the carrying value of the long-lived assets may not be recoverable. First, the estimated undiscounted future cash flows attributable to the assets is compared with the carrying value of the assets. If the carrying value is greater than the undiscounted future cash flows, an impairment charge is recognized equal to the amount the carrying value of the assets exceeds its estimated fair value.
Asset Retirement Obligations
FirstEnergy recognizes an ARO for its legal obligation to perform asset retirement activities associated with its long-lived assets. The ARO liability represents an estimate of the fair value of FirstEnergy's current obligation such that the ARO is accreted monthly to reflect the time value of money.
A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FirstEnergy uses an expected cash flow approach to measure the fair value of the remediation AROs, considering the expected timing of settlement of the ARO based on the expected economic useful life of associated asset and/or regulatory requirements. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset. In certain circumstances, FirstEnergy has recovery of asset retirement costs and, as such, certain accretion and depreciation is offset against regulatory assets. Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of
settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not the timing of the liability recognition.
FirstEnergy has recognized applicable legal obligations for AROs and their associated cost, including reclamation of sludge disposal ponds, closure of coal ash disposal sites, underground and above-ground storage tanks and wastewater treatment lagoons. In addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remediation.
The following table summarizes the changes to the ARO balances during 2022 and 2021:
ARO Reconciliation (In millions)
Balance, January 1, 2021 $ 159
Changes in timing and amount of estimated cash flows 8
Liabilities settled (1)
Accretion 13
Balance, December 31, 2021 $ 179
Changes in timing and amount of estimated cash flows (2)
Liabilities settled (6)
Accretion 14
Balance, December 31, 2022 $ 185
Jointly Owned Plants
FE, through its subsidiary, AGC, owns an undivided 16.25% interest (487 MWs) in the 3,003 MW Bath County pumped-storage, hydroelectric station in Virginia, operated by the 60% owner, VEPCO, a non-affiliated utility. Total property, plant and equipment includes $153 million representing AGC's share in this facility as of December 31, 2022. AGC is obligated to pay its share of the costs of this jointly owned facility in the same proportion as its ownership interests using its own financing. AGC's share of direct expenses of the joint plant is included in operating expenses on FirstEnergy's Consolidated Statements of Income. AGC provides the generation capacity from this facility to its owner, MP.
NEW ACCOUNTING PRONOUNCEMENTS
Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting.
ASU 2022-03, "Fair Value Measurements of Equity Securities Subject to Contractual Sale Restrictions " (Issued in June 2022): ASU 2022-03 clarifies current guidance in Topic 820, Fair Value Measurement, when measuring the fair value of an equity security subject to contractual restrictions that prohibit the sale of an equity security, and introduces new disclosure requirements for those equity securities subject to contractual restrictions. For FirstEnergy, the guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2023, with early adoption permitted.
2. REVENUE
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.
FirstEnergy has elected to exclude sales taxes and other similar taxes collected on behalf of third parties from revenue as prescribed in the standard. As a result, tax collections and remittances are excluded from recognition in the income statement and instead recorded through the balance sheet. Excise and gross receipts taxes that are assessed on FirstEnergy are not subject to the election and are included in revenue. 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.
FirstEnergy’s revenues are primarily derived from electric service provided by the Utilities and Transmission Companies.
Regulated Distribution
The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies and also controls 3,580 MWs of regulated electric generation capacity located primarily in West Virginia and Virginia. Each of the Utilities earns revenue from state-regulated rate tariffs under which it provides distribution services to residential, commercial and industrial customers in its service territory. The Utilities are obligated under the regulated construct to deliver power to customers reliably, as it is needed, which creates an implied monthly contract with the end-use customer. See Note 12, “Regulatory Matters,” for additional information on rate recovery mechanisms. Distribution and electric revenues are recognized over time as electricity is distributed and delivered to the customer and the customers consume the electricity immediately as delivery occurs.
Retail generation sales relate to POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland, as well as generation sales in West Virginia that are regulated by the WVPSC. Certain of the Utilities have default service obligations to provide power to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales varies depending on the level of shopping that occurs. Supply plans vary by state and by service territory. Default service for the Ohio Companies, Pennsylvania Companies, JCP&L and PE’s Maryland jurisdiction are provided through a competitive procurement process approved by each state’s respective commission. Retail generation revenues are recognized over time as electricity is delivered and consumed immediately by the customer.
Wholesale sales primarily consist of generation and capacity sales into the PJM market from FirstEnergy’s regulated electric generation capacity and NUGs. Certain of the Utilities may also purchase power in the PJM markets to supply power to their customers. Generally, these power sales from generation and purchases to serve load are netted hourly and reported as either revenues or purchased power on the Consolidated Statements of Income based on whether the entity was a net seller or buyer each hour. Capacity revenues are recognized ratably over the PJM planning year at prices cleared in the annual PJM Reliability Pricing Model Base Residual Auction and Incremental Auctions. Capacity purchases and sales through PJM capacity auctions are reported within revenues on the Consolidated Statements of Income. Certain capacity income (bonuses) and charges (penalties) related to the availability of units that have cleared in the auctions are unknown and not recorded in revenue until, and unless, they occur.
The Utilities’ distribution customers are metered on a cycle basis. An estimate of unbilled revenues is calculated to recognize electric service provided from the last meter reading through the end of the month. This estimate includes many factors, among which are historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, the Utilities accrue the estimated unbilled amount as revenue and reverse the related prior period estimate. Customer payments vary by state but are generally due within 30 days.
ASC 606 excludes industry-specific accounting guidance for recognizing revenue from ARPs as these programs represent contracts between the utility and its regulators, as opposed to customers. Therefore, revenues from these programs are not within the scope of ASC 606 and regulated utilities are permitted to continue to recognize such revenues in accordance with existing practice but are presented separately from revenue arising from contracts with customers. FirstEnergy had ARPs in Ohio primarily for shared savings in 2020, and has reflected refunds of decoupling revenue owed to customers as reductions to ARPs in 2021.
Regulated Transmission
The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment's revenues are derived from forward-looking formula rates. See Note 12, “Regulatory Matters,” for additional information.
Forward-looking formula rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on rate base and actual costs. Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time.
The following represents a disaggregation of revenue from contracts with customers for the years ended December 31, 2022, 2021 and 2020:
For the Years Ended December 31,
(In millions) 2022 2021 2020
Regulated Distribution
Retail generation and distribution services (1)
Residential $ 6,180 $ 5,713 $ 5,539
Commercial 2,499 2,284 2,140
Industrial 1,338 1,091 1,076
Other 85 75 81
Wholesale 494 362 251
Other revenue from contracts with customers 104 119 140
Total revenues from contracts with customers 10,700 9,644 9,227
ARP(2)
- (27) 43
Other revenue unrelated to contracts with customers 101 94 93
Total Regulated Distribution $ 10,801 $ 9,711 $ 9,363
Regulated Transmission
ATSI $ 912 $ 799 $ 804
TrAIL 270 233 247
MAIT 340 288 250
JCP&L 203 164 178
MP, PE and WP 138 124 134
Total revenues from contracts with customers 1,863 1,608 1,613
Other revenue unrelated to contracts with customers 5 10 17
Total Regulated Transmission $ 1,868 $ 1,618 $ 1,630
Corporate/Other and Reconciling Adjustments(3)
Wholesale $ 27 $ 14 $ 9
Retail generation and distribution services (3)
(186) (154) (148)
Other revenue unrelated to contracts with customers (3)
(51) (57) (64)
Total Corporate/Other and Reconciling $ (210) $ (197) $ (203)
FirstEnergy Total Revenues $ 12,459 $ 11,132 $ 10,790
(1) Includes approximately $58 million and $38 million as of December 31, 2022 and 2021, respectively, of customer refunds associated with the Ohio Stipulation that became effective in December 2021. See Note 12, “Regulatory Matters,” for further discussion.
(2) Reflects amount the Ohio Companies refunded to customers that was previously collected under decoupling mechanisms, with interest.
(3) Includes eliminations and reconciling adjustments of inter-segment revenues.
Other revenue unrelated to contracts with customers includes revenue from late payment charges of $38 million, $36 million and $31 million, respectively, for the years ended December 31, 2022, 2021 and 2020. Other revenue unrelated to contracts with customers also includes revenue from derivatives of $15 million, $11 million and $14 million, respectively, for the years ended December 31, 2022, 2021 and 2020.
RECEIVABLES
Receivables from contracts from customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers of the Utilities. There was no material concentration of receivables as of December 31, 2022 and 2021, with respect to any particular segment of FirstEnergy’s customers. Billed and unbilled customer receivables as of December 31, 2022 and 2021, are included below.
As of December 31,
Customer Receivables 2022 2021
(In millions)
Billed(1)
$ 674 $ 616
Unbilled 781 576
1,455 1,192
Less: Uncollectible Reserve 137 159
Total Customer Receivables $ 1,318 $ 1,033
(1) Includes approximately $290 million and $318 million as of December 31, 2022 and 2021, respectively, that are past due by greater than 30 days.
The allowance for uncollectible customer receivables is based on historical loss information comprised of a rolling 36-month average net write-off percentage of revenues, in conjunction with a qualitative assessment of elements that impact the collectability of receivables to determine if allowances for uncollectible accounts should be further adjusted in accordance with the accounting guidance for credit losses.
FirstEnergy reviews its allowance for uncollectible customer receivables utilizing a quantitative and qualitative assessment. Management contemplates available current information such as changes in economic factors, regulatory matters, industry trends, customer credit factors, amount of receivable balances that are past-due, payment options and programs available to customers, and the methods that the Utilities are able to utilize to ensure payment. This analysis includes consideration of the outbreak of the pandemic and the impact on customer receivable balances outstanding and write-offs since the pandemic began and subsequent economic slowdown. FirstEnergy’s uncollectible risk on PJM receivables, resulting from transmission and wholesale sales, is minimal due to the nature of PJM’s settlement process whereby members of PJM legally agree to share the cost of defaults and as a result there is no allowance for doubtful accounts.
During 2021, arrears levels continued to be elevated above 2019 pre-pandemic levels. Various regulatory actions impacted the growth and recovery of past due balances including extensions on moratoriums, significant restrictions regarding disconnections, and extended installment plans. FirstEnergy experienced a reduction in the amount of receivables that are past due by greater than 30 days since the end of 2020. While total customer arrears balances continued to decrease in 2021, balances over 120 days past due continued to be elevated. FirstEnergy considered other factors as part of its qualitative assessment, such as certain federal stimulus and state funding being made available to assist with past due utility bills. As a result of this qualitative analysis, FirstEnergy did not recognize any incremental uncollectible expense during 2021.
During 2022, various regulatory actions including extensions on moratoriums, certain restrictions on disconnections and extended installment plan offerings continue to impact the level of past due balances in certain states. However, certain states have resumed normal collections activity and arrears levels have declined towards pre-pandemic levels. As a result, FirstEnergy recognized a $25 million decrease in its allowance for uncollectible customer receivables during the first quarter of 2022, of which $15 million was applied to existing deferred regulatory assets. As a result of certain customer installment or extended payment plans, inflationary pressures on customers and the economic slowdown, there were no material changes to the allowance for uncollectible customer receivables during the remainder of 2022. Additionally, as a result of the pandemic-related moratoriums and certain customer installment or extended payment plans offered, which caused the extension of when certain write offs would have otherwise occurred, the allowance for uncollectible accounts on receivables remains elevated above 2019 pre-pandemic levels.
Activity in the allowance for uncollectible accounts on receivables for the years ended December 31, 2022, 2021 and 2020 are as follows:
(In millions) 2022 2021 2020(3)
Customer Receivables
Beginning of year balance $ 159 $ 164 $ 46
Charged to income (1)
59 54 174
Charged to other accounts (2)
62 42 46
Write-offs (143) (101) (102)
End of year balance $ 137 $ 159 $ 164
Other Receivables
Beginning of year balance $ 10 $ 26 $ 21
Charged to income 4 3 7
Charged to other accounts (2)
4 3 10
Write-offs (7) (22) (12)
End of year balance $ 11 $ 10 $ 26
(1) Customer receivable amounts charged to income for the years ended December 31, 2022, 2021, and 2020 include approximately $11 million, $12 million, and $103 million respectively, deferred for future recovery. 2020 amounts charged to income includes $121 million of incremental expense due to pandemic conditions.
(2) Represents recoveries and reinstatements of accounts previously written off for uncollectible accounts.
(3) As a result of the FES Debtors’ emergence from bankruptcy in February 2020, FirstEnergy wrote off $1.1 billion in affiliated companies receivables in 2020, which were included in discontinued operations. There was no affiliated companies receivables at the end of 2022, 2021 or 2020.
3. EARNINGS PER SHARE OF COMMON STOCK
EPS is calculated by dividing earnings attributable to FE by the weighted average number of common shares outstanding.
Basic EPS is computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted EPS of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised.
Diluted EPS reflects the dilutive effect of potential common shares from share-based awards. The dilutive effect of outstanding share-based awards was computed using the treasury stock method, which assumes any proceeds that could be obtained upon the exercise of the award would be used to purchase common stock at the average market price for the period.
The following table reconciles basic and diluted EPS attributable to FE:
For the Years Ended December 31,
Reconciliation of Basic and Diluted EPS of Common Stock 2022 2021 2020
(In millions, except per share amounts)
Earnings Attributable to FE - continuing operations $ 406 $ 1,239 $ 1,003
Earnings Attributable to FE - discontinued operations, net of tax - 44 76
Earnings Attributable to FE $ 406 $ 1,283 $ 1,079
Share Count information:
Weighted average number of basic shares outstanding 571 545 542
Assumed exercise of dilutive share based awards 1 1 1
Weighted average number of diluted shares outstanding 572 546 543
EPS Attributable to FE:
Income from continuing operations, basic $ 0.71 $ 2.27 $ 1.85
Discontinued operations, basic - 0.08 0.14
Basic EPS $ 0.71 $ 2.35 $ 1.99
Income from continuing operations, diluted $ 0.71 $ 2.27 $ 1.85
Discontinued operations, diluted - 0.08 0.14
Diluted EPS $ 0.71 $ 2.35 $ 1.99
For the years ended December 31, 2022, 2021 and 2020, there were no material amount of shares excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.
4. ACCUMULATED OTHER COMPREHENSIVE INCOME
The changes in AOCI for the years ended December 31, 2022, 2021 and 2020, for FirstEnergy are shown in the following table:
Gains & Losses on Cash Flow Hedges (1)
Defined Benefit Pension & OPEB Plans (2)(3)
Total
(In millions)
AOCI Balance, January 1, 2020 $ (9) $ 29 $ 20
Amounts reclassified from AOCI 1 (34) (33)
Other comprehensive income (loss) 1 (34) (33)
Income tax (benefits) on other comprehensive income (loss) - (8) (8)
Other comprehensive income (loss), net of tax 1 (26) (25)
AOCI Balance, December 31, 2020 $ (8) $ 3 $ (5)
Amounts reclassified from AOCI 1 (14) (13)
Other comprehensive income (loss) 1 (14) (13)
Income tax (benefits) on other comprehensive income (loss) - (3) (3)
Other comprehensive income (loss), net of tax 1 (11) (10)
AOCI Balance, December 31, 2021 $ (7) $ (8) $ (15)
Amounts reclassified from AOCI 9 (9) -
Other comprehensive income (loss) 9 (9) -
Income tax (benefits) on other comprehensive income (loss) 2 (3) (1)
Other comprehensive income (loss), net of tax 7 (6) 1
AOCI Balance, December 31, 2022 $ - $ (14) $ (14)
(1) Relates to previous cash flow hedges used to hedge fixed rate long-term debt securities prior to their issuance. Amounts reclassified from AOCI affects Interest expense line item in Consolidated Statements of Income.
(2) Prior-service costs are reported within Miscellaneous income, net within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income. Components are included in the computation of net periodic cost (credits), see Note 5, "Pension and Other Post-Employment Benefits," for additional details.
(3) Income tax (benefits) on other comprehensive income (loss) affects Income taxes line item in Consolidated Statements of Income.
5. PENSION AND OTHER POST-EMPLOYMENT BENEFITS
FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. Under the cash-balance portion of the pension plan (for employees hired on or after January 1, 2014), FirstEnergy makes contributions to eligible employee retirement accounts based on a pay credit and an interest credit. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. 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 until 2025, which, based on various assumptions, including annual expected rate of return on assets of 8.0% in 2023, is expected to be approximately $250 million. However, FirstEnergy may elect to contribute to the pension plan voluntarily.
Pension and OPEB costs are affected by employee demographics (including age, compensation levels and employment periods), the level of contributions made to the plans and earnings on plan assets. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. FirstEnergy uses a December 31 measurement date for its pension and OPEB plans. The fair value of the plan assets represents the actual market value as of the measurement date.
Actuarial Assumptions Pension OPEB
2022 2021 2020 (2)
2022 2021 2020 (2)
Assumptions Related to Benefit Obligations:
Discount rate 5.23 % 3.02 % 2.67 % 5.16 % 2.84 % 2.45 %
Rate of compensation increase 4.30 % 4.10 % 4.10 % N/A N/A N/A
Cash balance weighted average interest crediting rate 4.04 % 2.57 % 2.57 % N/A N/A N/A
Assumptions Related to Benefit Costs:(1)
Effective rate for interest on benefit obligations 2.44 % 1.94 % 2.89%/2.48%
2.18 % 1.66 % 2.71%/2.30%
Effective rate for service costs 3.28 % 3.10 % 3.60%/3.24%
3.41 % 3.03 % 3.63%/3.29%
Effective rate for interest on service costs 2.96 % 2.58 % 3.27%/2.90%
3.24 % 2.83 % 3.43%/3.06%
Expected return on plan assets 7.50 % 7.50 % 7.50 % 7.50 % 7.50 % 7.50 %
Rate of compensation increase 4.10 % 4.10 % 4.10 % N/A N/A N/A
Assumed Health Care Cost Trend Rates:
Health care cost trend rate assumed (pre/post-Medicare) N/A N/A N/A 6.00%-
5.50%
5.75%-
5.25%
6.00%-
5.50%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate) N/A N/A N/A 4.50 % 4.50 % 4.50 %
Year that the rate reaches the ultimate trend rate N/A N/A N/A 2029 2028 2028
(1) Excludes impact of pension and OPEB mark-to-market adjustment.
(2) As a result of the interim plan remeasurement during 2020 there were different rates in effect from January 1, 2020, through February 26, 2020 compared to February 27, 2020 through December 31, 2020.
Discount Rate - In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and OPEB obligations. The assumed rates of return on plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy’s pension trusts. The long-term rate of return is developed considering the portfolio’s asset allocation strategy. FirstEnergy utilizes a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the relevant projected cash flows.
Expected Return on Plan Assets - FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the pension trusts. In 2022, FirstEnergy’s qualified pension and OPEB plan assets experienced losses of $1,830 million or (19.1)%, compared to gains of $689 million, or 7.9% in 2021, and gains of $1,225 million, or 14.7% in 2020 and assumed a 7.50% rate of return on plan assets in 2022, 2021 and 2020, which generated $696 million, $688 million and $651 million of expected returns on plan assets, respectively. The expected return on pension and OPEB assets is based on input from investment consultants, including the trusts’ asset allocation targets, the historical performance of risk-based and fixed income securities and other factors. The gains or losses generated as a result of the difference between expected and actual returns on plan assets is recognized as a pension and OPEB mark-to-market adjustment in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for remeasurement.
Mortality Rates - During 2022, the Society of Actuaries elected not to release a new mortality improvement scale due to data available being severely impacted by COVID-19. It was determined that the Pri-2012 mortality table with projection scale MP-2021, actuarially adjusted to reflect increased mortality due to the ongoing impact of COVID-19 was most appropriate and such was utilized to determine the obligation as of December 31, 2022, for the FirstEnergy pension and OPEB plans. This adjustment acknowledges COVID-19 cannot be eradicated and assumes reductions in other causes will not offset future COVID-19 deaths enough to produce a normal level of improvements. The impact of using the Pri-2012 mortality table with projection scale MP-2021 (adjusted by FirstEnergy's actuary for COVID-19 impacts) resulted in a decrease to the projected benefit obligation of approximately $23 million for the pension plans and was included in the 2022 pension and OPEB mark-to-market adjustment.
Net Periodic Benefit Costs (Credits) - In addition to service costs, interest on obligations, expected return on plan assets, and prior service costs, FirstEnergy recognizes in net periodic benefit costs a pension and OPEB mark-to-market adjustment for the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. Service costs, net of capitalization, are reported within Other operating expenses on FirstEnergy’s Consolidated Statements of Income. Non-service costs, other than the pension and OPEB mark-to-market adjustment, which is separately shown, are reported within Miscellaneous income, net, within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income.
Components of Net Periodic Benefit Costs (Credits) for the Years Ended December 31, Pension OPEB
2022 2021 2020 2022 2021 2020
(In millions)
Service cost (1)
$ 184 $ 195 $ 194 $ 3 $ 4 $ 4
Interest cost 273 226 287 11 11 15
Expected return on plan assets (657) (652) (618) (39) (36) (33)
Amortization of prior service costs (credits) (2)
2 3 12 (11) (17) (46)
One-time termination benefits (3)
- - 8 - - -
Pension & OPEB mark-to-market (98) (253) 463 26 (129) 14
Net periodic benefit costs (credits) $ (296) $ (481) $ 346 $ (10) $ (167) $ (46)
(1) Includes amounts capitalized.
(2) 2020 includes the acceleration of approximately $18 million in net credits as a result of the FES Debtors’ emergence during the first quarter of 2020 and is a component of discontinued operations in FirstEnergy’s Consolidated Statements of Income.
(3) Costs represent additional benefits provided to FES and FENOC employees under the approved settlement agreement and are a component of discontinued operations.
Approximately $15 million, $(31) million and $40 million of the annual pension and OPEB mark-to-market charges (credits) were allocated to the Regulated Transmission companies under forward-looking formula rates, and expected to be refunded or recovered through formula transmission rates, respectively. The 2022 pension and OPEB mark-to-market adjustment primarily reflects a 221 bps increase in the discount rate used to measure pension benefit obligations partially offset by lower than expected asset returns.
Pension OPEB
Obligations/Funded Status - Qualified and Non-Qualified Plans 2022 2021 2022 2021
(In millions)
Change in benefit obligation:
Benefit obligation as of January 1 $ 11,479 $ 11,935 $ 549 $ 676
Service cost 184 195 3 4
Interest cost 273 226 11 11
Plan participants’ contributions - - 3 4
Medicare retiree drug subsidy - - 1 1
Actuarial loss (gain) (2,515) (280) (83) (101)
Benefits paid (593) (597) (45) (46)
Benefit obligation as of December 31 $ 8,828 $ 11,479 $ 439 $ 549
Change in fair value of plan assets:
Fair value of plan assets as of January 1 $ 9,020 $ 8,968 $ 548 $ 502
Actual return on plan assets (1,760) 625 (70) 64
Company contributions 26 24 24 24
Plan participants’ contributions - - 3 4
Benefits paid (593) (597) (45) (46)
Fair value of plan assets as of December 31 $ 6,693 $ 9,020 $ 460 $ 548
Funded Status:
Qualified plan $ (1,734) $ (1,974) $ - $ -
Non-qualified plans (401) (485) - -
Funded Status (Net liability as of December 31) $ (2,135) $ (2,459) $ 21 $ (1)
Accumulated benefit obligation $ 8,500 $ 10,927 $ - $ -
Amounts Recognized in AOCI:
Prior service cost (credit) $ 6 $ 9 $ (10) $ (21)
The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy. See Note 9, "Fair Value Measurements," for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2022 and 2021.
December 31, 2022 Asset Allocation
Level 1 Level 2 Level 3 Total
(In millions)
Cash and short-term securities $ - $ 714 $ - $ 714 11 %
Public equity 1,871 216 - 2,087 33 %
Fixed income - 942 - 942 15 %
Derivatives (38) 2 - (36) (1) %
Total (1)
$ 1,833 $ 1,874 $ - $ 3,707 58 %
Private - equity and debt funds (2)
1,061 17 %
Insurance-linked securities (2)
159 3 %
Hedge funds (2)
563 9 %
Real estate funds (2)
853 13 %
Total Investments $ 6,343 100 %
(1) Excludes $350 million as of December 31, 2022, of receivables, payables, taxes, cash collateral for derivatives and accrued income associated with financial instruments reflected within the fair value table.
(2) Net Asset Value used as a practical expedient to approximate fair value.
December 31, 2021 Asset Allocation
Level 1 Level 2 Level 3 Total
(In millions)
Cash and short-term securities $ - $ 746 $ - $ 746 8 %
Public equity 2,867 286 - 3,153 35 %
Fixed income - 2,453 - 2,453 27 %
Derivatives 20 - - 20 - %
Total (1)
$ 2,887 $ 3,485 $ - $ 6,372 70 %
Private - equity and debt funds (2)
811 9 %
Insurance-linked securities (2)
320 4 %
Hedge funds (3)
678 7 %
Real estate funds (2)
886 10 %
Total Investments $ 9,067 100 %
(1) Excludes $(47) million as of December 31, 2021, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
(2) Net Asset Value used as a practical expedient to approximate fair value.
As of December 31, 2022, and 2021, the OPEB trust investments measured at fair value were as follows:
December 31, 2022 Asset Allocation
Level 1 Level 2 Level 3 Total
(In millions)
Cash and short-term securities $ - $ 87 $ - $ 87 19 %
Public equity 217 - - 217 47 %
Fixed income - 157 - 157 34 %
Total (1)
$ 217 $ 244 $ - $ 461 100 %
(1) Excludes $(1) million as of December 31, 2022, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
December 31, 2021 Asset Allocation
Level 1 Level 2 Level 3 Total
(In millions)
Cash and short-term securities $ - $ 95 $ - $ 95 17 %
Public equity 278 - - 278 51 %
Fixed income: - 175 - 175 32 %
Total $ 278 $ 270 $ - $ 548 100 %
FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2022 were as follows:
Target Asset Allocations
Pension OPEB
Equities 36 % 50 %
Fixed income 22.5 % 50 %
Alternative investments 5 % - %
Real estate 10 % - %
Private - equity and debt funds 20 % - %
Cash and derivatives 6.5 % - %
100 % 100 %
FirstEnergy follows a total return investment approach using a mix of equities, fixed income and other available investments while taking into account the pension plan liabilities to optimize the long-term return on plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalization funds. Other assets such as real estate and private equity are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements and periodic asset/liability studies.
Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets and other payments, net of participant contributions:
OPEB
Pension Benefit Payments Subsidy Receipts
(In millions)
2023 $ 583 $ 44 $ (1)
2024 587 42 (1)
2025 597 40 (1)
2026 605 39 -
2027 612 37 -
Years 2028-2031 3,120 167 (2)
6. STOCK-BASED COMPENSATION PLANS
FirstEnergy grants stock-based awards through the ICP 2020, primarily in the form of restricted stock and performance-based restricted stock units. There are also awards currently outstanding issued through the ICP 2015 primarily in the form of restricted stock and performance-based restricted stock units. The ICP 2020 and ICP 2015 include shareholder authorization to each issue 10 million shares of common stock or their equivalent. As of December 31, 2022, approximately 11.9 million shares were available for future grants under the ICP 2020 assuming maximum performance metrics are achieved for the outstanding cycles of restricted stock units. No shares are available for future grants under ICP 2015. Shares not issued due to forfeitures or cancellations originally granted through the ICP 2015 may be added back to the ICP 2020. Shares granted under the ICP 2020 and ICP 2015 are issued from authorized but unissued common stock. Vesting periods for stock-based awards range from less than a year to ten years, with the majority of awards having a vesting period of three years. FirstEnergy also issues stock through its 401(k) savings plan, EDCP, and DCPD. Currently, FirstEnergy records the compensation costs for stock-based compensation
awards that will be paid in stock over the vesting period based on the fair value on the grant date. FirstEnergy accounts for forfeitures as they occur.
FirstEnergy adjusts the compensation costs for stock-based compensation awards that will be paid in cash based on changes in the fair value of the award as of each reporting date. FirstEnergy records the actual tax benefit realized from tax deductions when awards are exercised or settled. Actual income tax benefits realized during the years ended December 31, 2022, 2021 and 2020, were $8 million, $10 million and $20 million, respectively. The income tax effects of awards are recognized in the income statement when the awards vest, are settled or are forfeited.
Stock-based compensation costs and the amount of stock-based compensation costs capitalized related to FirstEnergy plans for the years ended December 31, 2022, 2021 and 2020, are included in the following tables:
For the Years Ended December 31,
Stock-based Compensation Plan 2022 2021 2020
(In millions)
Restricted stock units $ 55 $ 40 $ 22
Restricted stock 3 2 1
401(k) savings plan 36 35 33
EDCP & DCPD 7 13 (5)
Total $ 101 $ 90 $ 51
Stock-based compensation costs, net of amounts capitalized $ 54 $ 43 $ 25
Income tax benefits associated with stock-based compensation plan expense were $8 million, $5 million and $3 million for the years ended December 31, 2022, 2021 and 2020, respectively.
Restricted Stock Units
Two-thirds of each performance-based restricted stock unit award will be paid in stock and one-third will be paid in cash. Restricted stock units payable in stock provide the participant the right to receive, at the end of the period of restriction, a number of shares of common stock equal to the number of stock units set forth in the agreement, subject to adjustment based on FirstEnergy's performance relative to financial and operational performance targets applicable to each award. The grant date fair market value of the stock portion of the restricted stock unit award is measured based on the average of the high and low prices of FE common stock on the date of grant. Beginning with awards granted in 2018, restricted stock units include a performance metric consisting of a relative total shareholder return modifier utilizing the S&P 500 Utility Index as a comparator group. The estimated grant date fair value for these awards is calculated using the Monte Carlo simulation method. Beginning with awards granted in 2022, restricted stock units include a relative total shareholder return as a performance metric, utilizing the S&P 500 Utility Index as a comparator group. The estimated grant date fair value for these awards is also calculated using the Monte Carlo simulation method. In addition, outstanding awards are subject to an absolute total shareholder return, if FirstEnergy's is negative for the three-year cumulative performance period, restricted stock unit awards will be capped at a of payout 100%.
Restricted stock units payable in cash provide the participant the right to receive cash based on the number of stock units set forth in the agreement and value of the equivalent number of shares of FE common stock as of the vesting date. The cash portion of the restricted stock unit award is considered a liability award, which is remeasured each period based on FE's stock price and projected performance adjustments. The liability recorded for the portion of performance-based restricted stock units payable in cash in the future as of December 31, 2022, was $20 million. During 2022, approximately $9 million was paid in relation to the cash portion of restricted stock unit obligations that vested in 2022.
The vesting period for the performance-based restricted stock unit awards granted in 2020, 2021 and 2022, were each three years. Dividend equivalents are received on the restricted stock units and are reinvested in additional restricted stock units and subject to the same performance conditions as the underlying award.
Restricted stock unit activity for the year ended December 31, 2022, was as follows:
Restricted Stock Unit Activity Shares
(in millions)
Weighted-Average Grant Date Fair Value (per share)
Nonvested as of January 1, 2022 1.8 $ 41.89
Granted in 2022 1.0 41.19
Forfeited in 2022 (0.3) 39.58
Vested in 2022(1)
(0.6) 41.57
Nonvested as of December 31, 2022 1.9 $ 41.57
(1) Excludes dividend equivalents of approximately 80 thousand shares earned during vesting period.
The weighted-average fair value per share of awards granted in 2022, 2021 and 2020 was $41.19, $35.50 and $44.42 per share, respectively. For the years ended December 31, 2022, 2021, and 2020, the fair value of restricted stock units vested was $26 million, $34 million, and $80 million, respectively. As of December 31, 2022, there was approximately $27 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted for restricted stock units, which is expected to be recognized over a period of approximately three years.
Restricted Stock
Certain employees receive awards of FE restricted stock (as opposed to "units" with the right to receive shares at the end of the restriction period) subject to restrictions that lapse over a defined period of time or upon achieving performance results. The fair value of restricted stock is measured based on the average of the high and low prices of FE common stock on the date of grant. Dividends are received on the restricted stock and are reinvested in additional shares of restricted stock, subject to the vesting conditions of the underlying award. Restricted stock activity for the year ended 2022, was not material.
401(k) Savings Plan
In 2022 and 2021, approximately 1 million shares of FE common stock, respectively, were issued and contributed to employee participants' accounts.
EDCP
Under the EDCP, certain employees can defer a portion of their compensation, including base salary, annual incentive awards and/or long-term incentive awards, into unfunded accounts. Annual incentive and long-term incentive awards may be deferred in FE stock accounts. Base salary and annual incentive awards may be deferred into a retirement cash account which earns interest. Dividends are calculated quarterly on stock units outstanding and are credited in the form of additional stock units. Awards deferred into a retirement stock account will pay out in cash upon separation, including retirement, death or disability. Interest accrues on the cash allocated to the retirement cash account and the balance will pay out in cash over a time period as elected by the participant. The liability recognized for EDCP of approximately $193 million and $201 million as of December 31, 2022 and 2021, respectively, is included in “Retirement benefits,” on the Consolidated Balance Sheets.
DCPD
Under the DCPD, members of the FE Board can elect to defer all or a portion of their equity retainers to a deferred stock account and their cash retainers to deferred stock or deferred cash accounts. The net liability recognized for DCPD of approximately $8 million and $9 million as of December 31, 2022 and 2021, respectively, is included in “Retirement benefits,” on the Consolidated Balance Sheets.
7. TAXES
FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled.
FE and its subsidiaries are party to an intercompany income tax allocation agreement that provides for the allocation of consolidated tax liabilities. Prior to 2022, net tax benefits attributable to FE, excluding any tax benefits derived from certain interest expense, were generally reallocated to the subsidiaries of FE that have taxable income. Effective January 1, 2022, the intercompany income tax allocation agreement was amended and revised whereas FE no longer reallocates such tax benefits to the FE subsidiaries.
On August 16, 2022, President Biden signed into law the IRA of 2022, which, among other things, imposes a new 15% corporate AMT based on AFSI applicable to corporations with a three-year average AFSI over $1 billion. The AMT is effective for the 2023 tax year and, if applicable, corporations must pay the greater of the regular corporate income tax or the AMT. Although NOL carryforwards created through the regular corporate income tax system cannot be used to reduce the AMT, financial statement net operating losses can be used to reduce AFSI and the amount of AMT owed. The IRA of 2022 as enacted requires the U.S. Treasury to provide regulations and other guidance necessary to administer the AMT, including further defining allowable adjustments to determine AFSI, which directly impacts the amount of AMT to be paid. Based on interim guidance issued by the U.S. Treasury in late December 2022, FirstEnergy continues to believe that it is more likely than not it will be subject to the AMT beginning 2023. Until final U.S. Treasury guidance is issued, the amount of AMT FirstEnergy would pay could be significantly different than current estimates or it may not be a payer at all. The regulatory treatment of the impacts of this legislation will also be subject to the discretion of the FERC and state public utility commissions. Any adverse development in this legislation,
including guidance from the U.S. Treasury and/ or the IRS or unfavorable regulatory treatment, could reduce future cash flows and impact financial condition.
As discussed above, FirstEnergy expects to close on the sale of an additional 30% interest in FET in 2024, at which time FirstEnergy expects to realize an approximate $7.1 billion tax gain from the combined sale of 49.9% of the membership interests of FET, approximately $3.5 billion of which is attributable to the sale of 30% and the remainder being gain deferred from the sale of 19.9% in 2022, including consideration received and recapture of negative tax basis in FET. Upon closing in 2024, FET will be deconsolidated from FirstEnergy’s consolidated federal income tax group, however, FET will continue to be consolidated in FirstEnergy’s GAAP financial statements. As of December 31, 2022, FirstEnergy had approximately $7.1 billion of federal NOL carryforwards, all of which it expects to utilize by the end of 2024 to mostly offset taxable income and the tax gains associated with the combined 49.9% sales in FET. As a result of the expected additional sale in FET, FirstEnergy recognized a charge to income tax expense in the fourth quarter of 2022 of approximately $752 million, representing the deferred tax liability associated with the deferred tax gain on the 19.9% sale closed in May 2022. Additionally, FirstEnergy recognized a $54 million benefit to income tax expense in the fourth quarter of 2022 associated with reversal of certain valuation allowances on state income tax NOL carryforwards that are now expected to be utilized as a result of the tax gain associated with the transaction. See Note 1, "Organization, Basis of Presentation and Significant Accounting Policies", for further discussion of the additional minority interest sale in FET.
On July 8, 2022, Pennsylvania’s Governor signed into law Pennsylvania House Bill 1342, which reduces Pennsylvania’s corporate net income tax rate from 9.99% to 8.99% beginning January 1, 2023, and an additional 0.5% annually through 2031, when it reaches 4.99%. As of December 31, 2022, FirstEnergy recorded a $230 million net decrease to FirstEnergy’s ADIT liabilities, with a corresponding increase in regulatory liabilities of $236 million, which are expected to be settled through future customer rates, and a $6 million increase in income tax expense. The decrease in the Pennsylvania income tax rate is not expected to have a material impact to FirstEnergy’s future financial statements.
During 2022, FirstEnergy recognized an income statement benefit of approximately $38 million from remeasurement of a valuation allowance previously recorded on business interest expense carryforwards from the 2018 and 2019 tax years. The business interest expense could not be deducted previously due to certain limitations imposed on interest expense from non-utility operations under section 163(j) of the Tax Act. As provided by the Tax Act, the nondeductible interest expense can be carried forward, indefinitely, and deducted against income from non-utility operations. Due primarily to the realized and expected future earnings from FEV’s equity ownership in Global Holding, FirstEnergy expects to utilize a portion of the interest expense carryforward on its consolidated federal income tax return.
For the Years Ended December 31,
INCOME TAXES(1)
2022 2021 2020
(In millions)
Currently payable (receivable)-
Federal (2)
$ - $ 2 $ (14)
State 11 21 21
11 23 7
Deferred, net-
Federal(3)
946 174 171
State(4)
47 127 (38)
993 301 133
Investment tax credit amortization (4) (4) (14)
Total income taxes $ 1,000 $ 320 $ 126
(1) Income Taxes on Income from Continuing Operations.
(2) Excludes $2 million of federal tax benefit associated with discontinued operations for the years ended December 31, 2021.
(3) Excludes $46 million and $66 million of federal tax benefits associated with discontinued operations for the years ended December 31, 2021 and 2020, respectively.
(4) Excludes $1 million of state tax expense associated with discontinued operations for the year ended December 31, 2020.
FirstEnergy tax rates are affected by permanent items, such as AFUDC equity and other flow-through items, as well as discrete items that may occur in any given period but are not consistent from period to period. The following tables provide a reconciliation of federal income tax expense (benefit) at the federal statutory rate to the total income taxes (benefits) for the years ended December 31, 2022, 2021 and 2020:
For the Years Ended December 31,
2022 2021 2020
(In millions)
Income from Continuing Operations, before income taxes $ 1,439 $ 1,559 $ 1,129
Federal income tax expense at statutory rate (21%) $ 302 $ 327 $ 237
Increases (reductions) in taxes resulting from-
State and municipal income taxes, net of federal tax benefit 56 122 75
AFUDC equity and other flow-through (26) (29) (38)
Amortization of investment tax credits (4) (4) (14)
Deferred gain on 19.9% FET minority interest sale
752 - -
Federal tax credits claimed (3) (34) -
Nondeductible DPA monetary penalty
- 52 -
Excess deferred tax amortization due to the Tax Act (51) (54) (56)
TMI-2 reversal of tax regulatory liabilities
- - (40)
Uncertain tax positions 2 (82) (1)
Valuation allowances (47) 17 (49)
Other, net 19 5 12
Total income taxes $ 1,000 $ 320 $ 126
Effective income tax rate 69.5 % 20.5 % 11.2 %
Accumulated deferred income taxes as of December 31, 2022 and 2021, are as follows:
As of December 31,
2022 2021
(In millions)
Property basis differences $ 5,528 $ 5,670
Pension and OPEB (496) (570)
AROs (22) (21)
Regulatory asset/liability 432 322
Deferred compensation (149) (155)
Deferred gain on 19.9% FET minority interest sale
752 -
Loss carryforwards and tax credits (2,073) (2,040)
Valuation reserve 440 484
All other (210) (253)
Net deferred income tax liability $ 4,202 $ 3,437
FirstEnergy has recorded as deferred income tax assets the effect of federal NOLs and tax credits that will more likely than not be realized through future operations and through the reversal of existing temporary differences. As of December 31, 2022, FirstEnergy's loss carryforwards primarily consisted of $7.1 billion ($1.5 billion, net of tax) of federal NOL carryforwards, $5 billion ($1 billion, net of tax) which have no expiration and the remainder that will begin to expire in 2031, and federal general business tax credits of $51 million that begin to expire in 2030. As discussed above, FirstEnergy expects to utilize all the federal NOL carryforwards by the end of 2024 to mostly offset taxable income and the tax gain recognized from the combined sale of the 49.9% equity interest in FET.
The table below summarizes pre-tax NOL carryforwards and their respective anticipated expirations for state and local income tax purposes of approximately $12.6 billion ($568 million, net of tax) for FirstEnergy, of which approximately $3.9 billion ($199 million, net of tax) is expected to be utilized based on current estimates and assumptions. The ultimate utilization of these NOLs may be impacted by statutory limitations on the use of NOLs imposed by state and local tax jurisdictions, changes in statutory tax rates, and changes in business which, among other things, impact both future profitability and the manner in which future taxable income is apportioned to various state and local tax jurisdictions.
Expiration Period State Local
(In millions)
2023-2027 $ 2,479 $ 4,317
2028-2032 1,603 -
2033-2037 876 -
2038-2042 935 -
Indefinite 2,351 -
$ 8,244 $ 4,317
The following table summarizes the changes in valuation allowances on federal, state and local DTAs related to disallowed interest and certain employee remuneration, in addition to state and local NOLs discussed above for the years ended December 31, 2022, 2021 and 2020:
(In millions) 2022 2021 2020
Beginning of year balance $ 484 $ 496 $ 441
Charged to income (44) (12) 55
Charged to other accounts - - -
Write-offs - - -
End of year balance $ 440 $ 484 $ 496
FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. A recognition threshold and measurement attribute are utilized for financial statement recognition and measurement of tax positions taken or expected to be taken on the tax return. If ultimately recognized in future years, approximately $41 million of unrecognized income tax benefits would impact the effective tax rate.
As of December 31, 2022, it is reasonably possible that approximately $25 million of unrecognized tax benefits may be resolved during 2023 as a result of settlements with taxing authorities or the statute of limitations expiring, of which $24 million would ultimately affect FirstEnergy's effective tax rate.
The following table summarizes the changes in unrecognized tax positions for the years ended December 31, 2022, 2021 and 2020:
(In millions)
Balance, January 1, 2020 $ 164
Current year increases 7
Prior year decreases (28)
Effectively settled with taxing authorities
(2)
Decrease for lapse in statute
(2)
Balance, December 31, 2020 $ 139
Current year increases 15
Prior year decreases (8)
Effectively settled with taxing authorities
(97)
Decrease for lapse in statute
(2)
Balance, December 31, 2021 $ 47
Prior years increases 2
Decrease for lapse in statute
(7)
Balance, December 31, 2022 $ 42
FirstEnergy recognizes interest expense or income and penalties related to uncertain tax positions in income taxes by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken, or expected to be taken, on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. FirstEnergy's recognition of net interest associated with unrecognized tax benefits in 2022, 2021 and 2020, was not material. For the years ended December 31, 2022 and 2021, the cumulative net interest payable recorded by FirstEnergy was not material.
IRS review of FirstEnergy’s federal income tax returns is complete through the 2020 tax year with no pending adjustments. FirstEnergy’s tax returns for some state jurisdictions are open from tax years 2009 to 2020.
General Taxes
General tax expense for the years ended December 31, 2022, 2021 and 2020, recognized in continuing operations is summarized as follows:
For the Years Ended December 31,
2022 2021 2020
(In millions)
kWh excise $ 191 $ 189 $ 183
State gross receipts 219 190 182
Real and personal property 596 571 541
Social security and unemployment 105 103 112
Other 18 20 28
Total general taxes $ 1,129 $ 1,073 $ 1,046
8. LEASES
FirstEnergy primarily leases vehicles as well as building space, office equipment, and other property and equipment under cancellable and non-cancelable leases. FirstEnergy does not have any material leases in which it is the lessor.
FirstEnergy accounts for leases under, "Leases (Topic 842)". Leases with an initial term of 12 months or less are recognized as lease expense on a straight-line basis over the lease term and not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms that can extend the lease term from 1 to 40 years, and certain leases include options to terminate. The exercise of lease renewal options is at FirstEnergy’s sole discretion. Renewal options are included within the lease liability if they are reasonably certain based on various factors relative to the contract. Certain leases also include options to purchase the leased property. The depreciable life of leased assets and leasehold improvements are limited by the expected lease term unless there is a transfer of title or purchase option reasonably certain of exercise. FirstEnergy’s lease agreements do not contain any material restrictive covenants. FirstEnergy has elected a policy to not separate lease components from non-lease components for all asset classes.
For vehicles leased under certain master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, FirstEnergy is committed to pay the difference in the actual fair value and the residual value guarantee. FirstEnergy does not believe it is probable that it will be required to pay anything pertaining to the residual value guarantee, and the lease liabilities and right-of-use assets are measured accordingly.
Finance leases for assets used in regulated operations are recognized in FirstEnergy’s Consolidated Statements of Income such that amortization of the right-of-use asset and interest on lease liabilities equals the expense allowed for ratemaking purposes. Finance leases for regulated and non-regulated operations are accounted for as if the assets were owned and financed, with associated expense recognized in Interest expense and Provision for depreciation on FirstEnergy’s Consolidated Statements of Income, while all operating lease expenses are recognized in Other operating expense. The components of lease expense were as follows:
For the Year Ended December 31, 2022
(In millions) Vehicles Buildings Other Total
Operating lease costs (1)
$ 50 $ 8 $ 15 $ 73
Finance lease costs:
Amortization of right-of-use assets 10 1 2 13
Interest on lease liabilities - 3 - 3
Total finance lease cost 10 4 2 16
Total lease cost $ 60 $ 12 $ 17 $ 89
(1) Includes $19 million of short-term lease costs.
For the Year Ended December 31, 2021
(In millions) Vehicles Buildings Other Total
Operating lease costs (1)
$ 44 $ 9 $ 18 $ 71
Finance lease costs:
Amortization of right-of-use assets 12 1 1 14
Interest on lease liabilities 1 3 - 4
Total finance lease cost 13 4 1 18
Total lease cost $ 57 $ 13 $ 19 $ 89
(1) Includes $21 million of short-term lease costs.
For the Year Ended December 31, 2020
(In millions) Vehicles Buildings Other Total
Operating lease costs (1)
$ 35 $ 8 $ 17 $ 60
Finance lease costs:
Amortization of right-of-use assets 14 - 1 15
Interest on lease liabilities 2 3 - 5
Total finance lease cost 16 3 1 20
Total lease cost $ 51 $ 11 $ 18 $ 80
(1) Includes $17 million of short-term lease costs.
Supplemental cash flow information related to leases was as follows:
For the Years Ended December 31,
(In millions) 2022 2021 2020
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases $ 56 $ 64 $ 44
Operating cash flows from finance leases 3 4 4
Finance cash flows from finance leases 12 13 15
Right-of-use assets obtained in exchange for lease obligations:
Operating leases $ 26 $ 60 $ 67
Finance leases - 5 -
Lease terms and discount rates were as follows:
As of December 31,
2022 2021 2020
Weighted-average remaining lease terms (years)
Operating leases 7.30 7.97 8.55
Finance leases 11.33 8.12 7.74
Weighted-average discount rate (1)
Operating leases 4.22 % 4.16 % 4.21 %
Finance leases 14.77 % 12.22 % 11.58 %
(1) When an implicit rate is not readily determinable, an incremental borrowing rate is utilized, determining the present value of lease payments. The rate is determined based on expected term and information available at the commencement date.
Supplemental balance sheet information related to leases was as follows:
As of December 31,
(In millions) Financial Statement Line Item 2022 2021
Assets
Operating lease (1)
Deferred charges and other assets $ 262 $ 279
Finance lease (2)
Property, plant and equipment 45 48
Total leased assets $ 307 $ 327
Liabilities
Current:
Operating Other current liabilities $ 48 $ 39
Finance Currently payable long-term debt 6 13
Noncurrent:
Operating Other noncurrent liabilities 247 271
Finance Long-term debt and other long-term obligations 17 23
Total leased liabilities $ 318 $ 346
(1) Operating lease assets are recorded net of accumulated amortization of $114 million and $79 million as of December 31, 2022 and 2021, respectively.
(2) Finance lease assets are recorded net of accumulated amortization of $60 million and $95 million as of December 31, 2022 and 2021, respectively.
Maturities of lease liabilities as of December 31, 2022, were as follows:
(In millions) Operating Leases Finance Leases Total
2023 $ 56 $ 9 $ 65
2024 52 5 57
2025 49 5 54
2026 45 5 50
2027 39 4 43
Thereafter 105 5 110
Total lease payments (1)
346 33 379
Less imputed interest 51 10 61
Total net present value $ 295 $ 23 $ 318
(1) Operating lease payments for certain leases are offset by sublease receipts of $9 million over 10 years.
As of December 31, 2022, additional operating leases agreements, primarily for vehicles, that have not yet commenced are $1 million. These leases are expected to commence within the next 18 months with lease terms of 2 to 10 years.
9. FAIR VALUE MEASUREMENTS
RECURRING FAIR VALUE MEASUREMENTS
Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows:
Level 1 - Quoted prices for identical instruments in active market
Level 2 - Quoted prices for similar instruments in active market
- Quoted prices for identical or similar instruments in markets that are not active
- Model-derived valuations for which all significant inputs are observable market data
Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.
Level 3 - Valuation inputs are unobservable and significant to the fair value measurement
FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast are used to measure fair value.
FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term PJM auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent PJM auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement.
FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of December 31, 2022, from those used as of December 31, 2021. The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk was not significant to the fair value measurements.
The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy:
December 31, 2022 December 31, 2021
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (In millions)
Derivative assets FTRs(1)
$ - $ - $ 11 $ 11 $ - $ - $ 9 $ 9
Equity securities 2 - - 2 2 - - 2
U.S. state debt securities - 266 - 266 - 273 - 273
Cash, cash equivalents and restricted cash(2)
206 - - 206 1,511 - - 1,511
Other(3)
- 40 - 40 - 42 - 42
Total assets $ 208 $ 306 $ 11 $ 525 $ 1,513 $ 315 $ 9 $ 1,837
Liabilities
Derivative liabilities FTRs(1)
$ - $ - $ (2) $ (2) $ - $ - $ (1) $ (1)
Total liabilities $ - $ - $ (2) $ (2) $ - $ - $ (1) $ (1)
Net assets (liabilities) $ 208 $ 306 $ 9 $ 523 $ 1,513 $ 315 $ 8 $ 1,836
(1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings.
(2) Restricted cash of $46 million and $49 million as of December 31, 2022 and 2021 respectively, primarily relates to cash collected from JCP&L, MP, PE and the Ohio Companies' customers that is specifically used to service debt of their respective funding companies. See Note 10, Capitalization for additional information.
(3) Primarily consists of short-term investments.
INVESTMENTS
All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include AFS debt securities and other investments. FirstEnergy has no debt securities held for trading purposes.
Generally, unrealized gains and losses on equity securities are recognized in income whereas unrealized gains and losses on AFS debt securities are recognized in AOCI. However, the JCP&L spent nuclear fuel disposal trusts are subject to regulatory accounting with all gains and losses on equity and AFS debt securities offset against regulatory assets.
Spent Nuclear Fuel Disposal Trusts
JCP&L holds debt securities within the spent nuclear fuel disposal trust, which are classified as AFS securities, recognized at fair market value. The trust is intended for funding spent nuclear fuel disposal fees to the United States Department of Energy associated with the previously owned Oyster Creek and TMI-1 nuclear power plants.
The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in nuclear fuel disposal trusts as of December 31, 2022 and 2021:
December 31, 2022(1)
December 31, 2021(2)
Cost Basis Unrealized Gains Unrealized Losses Fair Value Cost Basis Unrealized Gains Unrealized Losses Fair Value
(In millions)
Debt securities $ 294 $ - $ (28) $ 266 $ 280 $ 2 $ (9) $ 273
(1) Excludes short-term cash investments of $5 million.
(2) Excludes short-term cash investments of $11 million.
Proceeds from the sale of investments in AFS debt securities, realized gains and losses on those sales and interest and dividend income for the years ended December 31, 2022, 2021 and 2020, were as follows:
For the Years Ended December 31,
2022 2021 2020(1)
(In millions)
Sale Proceeds $ 48 $ 48 $ 186
Realized Gains 8 - 12
Realized Losses (13) (3) (8)
Interest and Dividend Income 11 11 22
(1) Includes amounts associated with Nuclear Decommissioning Trusts that were previously held by JCP&L, ME, and PN. See above for additional information.
Other Investments
Other investments include employee benefit trusts, which are primarily invested in corporate-owned life insurance policies and equity method investments. Earnings and losses associated with corporate-owned life insurance policies and equity method investments are reflected in the “Miscellaneous Income, net” line of FirstEnergy’s Consolidated Statements of Income. Other investments were $351 million and $371 million as of December 31, 2022 and 2021, respectively, and are excluded from the amounts reported above. See Note 1, "Organization and Basis of Presentation," for additional information on FirstEnergy's equity method investments.
For the years ended December 31, 2022, 2021 and 2020, pre-tax income (expense) related to corporate-owned life insurance policies were $(20) million, $13 million and $20 million, respectively. Corporate-owned life insurance policies are valued using the cash surrender value and any changes in value during the period are recognized as income or expense.
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt, which excludes finance lease obligations and net unamortized debt issuance costs, unamortized fair value adjustments, premiums and discounts as of December 31, 2022 and 2021:
As of December 31,
2022 2021
(In millions)
Carrying Value $ 21,641 $ 23,946
Fair Value 19,784 27,043
The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of December 31, 2022 and 2021.
See Note 10, "Capitalization," for further information on long-term debt issued and redeemed during the twelve months ended December 31, 2022.
10. CAPITALIZATION
COMMON STOCK
Retained Earnings and Dividends
As of December 31, 2022, FirstEnergy had an accumulated deficit of $1 billion. Dividends declared in 2022 and 2021 totaled $1.56 per share in each period. Dividends of $0.39 per share were paid in the first, second, third and fourth quarters in 2022 and 2021, respectively. On December 13, 2022, the FE Board declared a quarterly dividend of $0.39 per share to be paid from OPIC in the first quarter of 2023. The amount and timing of all dividend declarations are subject to the discretion of the FE Board and its consideration of business conditions, results of operations, financial condition, risks and uncertainties of the government investigations, and other factors.
In addition to paying dividends from retained earnings, the Ohio Companies, Penn, JCP&L, ME and PN have authorization from FERC to pay cash dividends to FE from paid-in capital accounts, as long as their FERC-defined equity-to-total-capitalization ratio remains above 35%. In addition, AGC has authorization from FERC to pay cash dividends to its parent, MP, from paid-in capital accounts, as long as its FERC-defined equity-to-total-capitalization ratio remains above 45%. The articles of incorporation, indentures, regulatory limitations, FET P&SA I and FET P&SA II, and various other agreements, including those relating to the long-term debt of certain FirstEnergy subsidiaries contain provisions that could further restrict the payment of dividends on their common stock. None of these provisions materially restricted FirstEnergy subsidiaries’ abilities to pay cash dividends to FE as of December 31, 2022.
Common Stock Issuance
FE issued approximately 2 million shares of common stock in 2022, 1 million shares of common stock in 2021 and 2 million shares of common stock in 2020 to registered shareholders and its directors and the employees of its subsidiaries under its Stock Investment Plan and certain share-based benefit plans.
On November 6, 2021, FE entered into a Common Stock Purchase Agreement with BIP Securities II-B L.P., an affiliate of Blackstone Infrastructure Partners L.P., for the private placement of 25,588,535 shares of FE common stock, par value $0.10 per share, at a price of $39.08 per share, representing an investment of $1.0 billion. The transaction settled on December 13, 2021. Issuance costs associated with the transaction were approximately $26 million as of December 31, 2021.
PREFERRED AND PREFERENCE STOCK
FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2022, as follows:
Preferred Stock Preference Stock
Shares Authorized Par Value Shares Authorized Par Value
FE 5,000,000 $ 100
OE 6,000,000 $ 100 8,000,000 no par
OE 8,000,000 $ 25
Penn 1,200,000 $ 100
CEI 4,000,000 no par 3,000,000 no par
TE 3,000,000 $ 100 5,000,000 $ 25
TE 12,000,000 $ 25
JCP&L 15,600,000 no par
ME 10,000,000 no par
PN 11,435,000 no par
MP 940,000 $ 100
PE 10,000,000 $ 0.01
WP 32,000,000 no par
As of December 31, 2022 and 2021, there were no preferred stock or preference stock outstanding.
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
The following tables present outstanding long-term debt and finance lease obligations for FirstEnergy as of December 31, 2022 and 2021:
As of December 31, 2022 As of December 31,
(Dollar amounts in millions) Maturity Date Interest Rate 2022 2021
FMBs and secured notes - fixed rate 2023-2059 2.650% - 8.250%
$ 5,153 $ 5,021
Unsecured notes - fixed rate 2023-2050 1.600% - 7.375%
16,488 18,925
Finance lease obligations 23 36
Unamortized debt discounts (5) (8)
Unamortized debt issuance costs (110) (126)
Unamortized fair value adjustments 5 6
Currently payable long-term debt (351) (1,606)
Total long-term debt and other long-term obligations $ 21,203 $ 22,248
See Note 8, "Leases," for additional information related to finance leases.
FirstEnergy had the following redemptions and issuances during the twelve months ended December 31, 2022:
Company Type Redemption/Issuance Date Interest Rate Maturity Amount
(in Millions) Description
Redemptions
FE Unsecured Notes January, 2022 4.25% 2023 $850 In December 2021, FE provided notice of redemption with a make-whole premium of approximately $38 million ($30 million after-tax).
TE Senior Secured Notes February, 2022 2.65% 2028 $25 On January 27, 2022, TE instructed its indenture trustee to provide notice of partial redemption.
CEI Senior Notes, Series A March, 2022 2.77% 2034 $150 On February 11, 2022, CEI instructed its indenture trustee to provide notice of full redemption.
WP FMBs April, 2022 3.34% 2022 $100 WP redeemed FMBs that became due.
FE Unsecured Notes June, 2022 2.85% 2022 $500 On May 23, 2022 FE provided notice of redemption.
FE Unsecured Notes June, 2022 7.375% 2031 $715 On May 25, 2022, FE commenced an offer to purchase for cash a portion of its 2031 Notes and 2047 Notes, which had $1.5 billion and $1 billion principal amounts outstanding, respectively. A portion of these notes were redeemed for approximately $1.1 billion, including a tender premium of approximately $101 million ($80 million after-tax). In addition, FE recognized approximately $7 million ($5 million after-tax) of deferred cash flow hedge losses and $10 million ($8 million after-tax) in other unamortized debt costs and fees associated with the FE debt redemptions.
FE Unsecured Notes June, 2022 4.85% 2047 $284
Penn FMBs June, 2022 6.09% 2022 $100 Penn redeemed FMBs that became due.
FE Unsecured Notes August-November 2022 7.375% 2031 $128 Beginning in the third quarter of 2022, FE repurchased a portion of the principal amount of its 2031 Notes and 2047 Notes through the open market for approximately $249 million including a premium of approximately $11 million ($9 million after tax). In addition, FE recognized approximately $3 million ($2 million after-tax) in other unamortized debt costs related to the FE open market repurchases.
FE Unsecured Notes August-September 2022 4.85% 2047 $110
Issuances
OE Senior Unsecured Notes September, 2022 5.50% 2033 $300 Proceeds were used to repay borrowings outstanding under the regulated money pool, to finance capital expenditures, to fund working capital needs and for other general corporate purposes.
Penn FMBs November, 2022 3.79% 2032 $150 Proceeds were used to repay short-term borrowings.
WP FMBs November, 2022 5.29% 2033 $250 Proceeds were used to repay short-term borrowings.
On November 29, 2022, WP issued $300 million of 5.29% FMBs due 2033. $250 million was funded on December 13, 2022, and the remaining $50 million was funded on January 10, 2023. Proceeds of the issuance of the FMBs were used to repay short term borrowings.
The following table presents scheduled debt repayments or debt that has been noticed for redemption for outstanding long-term debt, excluding finance leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2022.
(In millions) 2023 2024 2025 2026 2027
Scheduled debt repayments $344 $1,246 $2,023 $1,076 $2,003
Securitized Bonds
Environmental Control Bonds
The consolidated financial statements of FirstEnergy include environmental control bonds issued by two bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE. Proceeds from the bonds were used to construct environmental control facilities. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the limited liability company SPEs, have no recourse to any assets or revenues of the special purpose limited liability companies. As of December 31, 2022 and 2021, $247 million and $274 million of environmental control bonds were outstanding, respectively.
Phase-In Recovery Bonds
In June 2013, the SPEs formed by the Ohio Companies issued approximately $445 million of pass-through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of December 31, 2022 and 2021, $206 million and $222 million of the phase-in recovery bonds were outstanding, respectively.
FMBs
The Ohio Companies and Penn each have a first mortgage indenture under which they can issue FMBs secured by a direct first mortgage lien on substantially all of their property and franchises, other than specifically excepted property.
Debt Covenant Default Provisions
FirstEnergy has various debt covenants under certain financing arrangements, including its revolving credit facilities and term loans. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on such debt and the maintenance of certain financial ratios. The failure by FirstEnergy to comply with the covenants contained in its financing arrangements could result in an event of default, which may have an adverse effect on its financial condition. As of December 31, 2022, FirstEnergy remains in compliance with all debt covenant provisions.
Additionally, there are cross-default provisions in a number of the financing arrangements. These provisions generally trigger a default in the applicable financing arrangement of an entity if it, or any of its significant subsidiaries, default under another financing arrangement in excess of a certain principal amount, typically $100 million. Such defaults by any of the Utilities or Transmission Companies would cross-default certain FE financing arrangements containing these provisions, and a certain FET Financing arrangement, with respect to the Transmission Companies only, such defaults by AE Supply would not cross-default to applicable financing arrangements of FE. Also, defaults by FE would generally not cross-default applicable financing arrangements of any of FE’s subsidiaries. Cross-default provisions are not typically found in any of the senior notes or FMBs of FE or its subsidiaries.
11. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT
FirstEnergy had $100 million of short-term borrowings as of December 31, 2022. As of December 31, 2021, FirstEnergy had no outstanding short-term borrowings.
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.
As of December 31, 2022, available liquidity under the 2021 Credit Facilities was $4.5 billion.
Borrowings under the 2021 Credit Facilities may be used for working capital and other general corporate purposes. Generally, borrowings under each of the credit facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the 2021 Credit Facilities contain financial covenants requiring each borrower, with the exception of FE, to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the 2021 Credit Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. FE is required under its 2021 Credit Facility to maintain a consolidated interest coverage ratio of not less than 2.50 times, measured at the end of each fiscal quarter for the last four fiscal quarters beginning with the quarter ending December 31, 2021.
Subject to each borrower’s sublimit, certain amounts 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, 2022, FirstEnergy had $4 million in outstanding LOCs.
The 2021 Credit Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the 2021 Credit Facilities are related to the credit ratings of the company borrowing the funds. Additionally, borrowings under each of the 2021 Credit Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million.
As of December 31, 2022, the borrowers were in compliance with the applicable interest coverage and debt-to-total-capitalization ratio covenants in each case as defined under the 2021 Credit Facilities.
FirstEnergy Money Pools
FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and FE to meet their short-term working capital requirements. Similar but separate arrangements exist among FirstEnergy’s unregulated companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries. FESC administers these money pools and tracks surplus funds of FE and the respective regulated and unregulated subsidiaries, as the case may be, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. During 2022, interest rates have increased significantly, which has caused the rate and interest on borrowings and lending under the money pools to be significantly higher. The average interest rate for borrowings in 2022 was 2.27% per annum for the regulated companies’ money pool, as compared to 1.01% in 2021, and 2.14% per annum for the unregulated companies’ money pool, as compared to 0.60% in 2021.
Weighted Average Interest Rates
The annual weighted average interest rates on short-term borrowings outstanding as of December 31, 2022 and 2021, were 3.93% and 2.42%, respectively.
12. REGULATORY MATTERS
STATE REGULATION
Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia, ATSI in Ohio, and the Transmission Companies in Pennsylvania are subject to certain regulations of the VSCC, PUCO and PPUC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility.
The following table summarizes the key terms of base distribution rate orders in effect for the Utilities as of December 31, 2022:
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)
(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) Rates were 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. On August 16, 2022, the MDPSC ordered each utility to file, by October 28, 2022, a set of plans for paying down all amortization balances by the scheduled expiration of the EmPOWER program on December 31, 2029. PE submitted its required plan on October 28, 2022, and, at the direction of the MDPSC, filed a revised plan on January 11, 2023. 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.
NEW JERSEY
JCP&L operates under NJBPU approved rates that took effect as of January 1, 2021, and 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.
JCP&L has instituted energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act as approved by the NJBPU in April 2021. The NJBPU approved plans include 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.
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 September 19, 2022, the NJBPU issued a notice to re-adopt its rules of practice, including proposed changes to the rules regarding CTA policy in base rate cases consistent with the Superior Court’s June 7, 2021 order. Once the proposed rules of practice 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 October 28, 2020, the NJBPU approved a stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for distribution base rate increase. The settlement provided for 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. The settlement additionally provided that JCP&L would be subject to a management audit, which began in May 2021 and is currently ongoing. JCP&L is currently waiting for issuance of the final report.
On September 14, 2021, JCP&L submitted a supplemental filing with the NJBPU to revise a previously filed AMI Program, which proposed the deployment of approximately 1.2 million advanced meters. 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 investments 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. The Stipulation, which was approved by NJBPU order on February 23, 2022, also provides 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 July 2, 2020, the NJBPU issued an order allowing New Jersey utilities to track and create a regulatory asset for future recovery of all prudently incurred incremental costs arising from the COVID-19 pandemic beginning March 9, 2020 and continuing until the New Jersey Governor issues an order stating that the COVID-19 pandemic is no longer in effect. New Jersey utilities can request recovery of such regulatory asset in a stand-alone COVID-19 regulatory asset filing or future base rate case. On 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. No moratorium on residential disconnections remains in effect for investor-owned electric utilities such as JCP&L, but investor-owned electric public utilities are required to offer qualifying residential customers deferred payment arrangements meeting certain minimum criteria prior to disconnecting service. Additionally, new legislation was enacted on March 25, 2022, prohibiting utilities from disconnecting electric service to customers that have applied for utility bill assistance before June 15, 2022 until such time as the state agency administering the assistance program makes a decision on the application and further requiring that all utilities offer a deferred payment arrangement meeting certain minimum criteria after the state agency’s decision on the application has been made.
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. On May 2, 2022, JCP&L filed with the NJBPU a stipulation entered into with the NJBPU staff, NJ Rate Counsel and others that provided a total budget of approximately $40 million for JCP&L’s electric vehicle program, including investments of approximately $29 million and operations and maintenance expenses of approximately $11 million. Electric vehicle related capital and operations and maintenance costs shall be deferred and placed in separate regulatory assets for recovery in JCP&L’s next base rate case. The stipulation was approved without modification by the NJBPU on June 8, 2022.
On September 17, 2022, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US and EDF Renewables North America, JCP&L submitted a proposal to the NJBPU and PJM to build transmission infrastructure connecting offshore wind-generated electricity to the New Jersey power grid. On October 26, 2022, the JCP&L proposal was accepted in an order issued by NJBPU. The proposal included approximately $723 million in investments to both build new and upgrade existing transmission infrastructure. JCP&L’s proposal projects an investment ROE of 10.2% and includes the option for JCP&L to acquire up to a 20% equity stake in Mid-Atlantic Offshore Development, LLC. The resulting rates associated with the project are expected to be shared among the ratepayers of all New Jersey electric utilities. Construction is expected to begin in 2025.
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.
On May 16, 2022, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2021, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings.
On July 15, 2022, the Ohio Companies filed an application with the PUCO for approval of phase two of their distribution grid modernization plan that would, among other things, provide for the installation of an additional 700,000 smart meters, distribution automation equipment on approximately 240 distribution circuits, voltage regulating equipment on approximately 220 distribution circuits, and other investments and pilot programs in related technologies designed to provide enhanced customer benefits. The Ohio Companies propose that phase two will be implemented over a four-year budget period with estimated capital investments of approximately $626 million and operations and maintenance expenses of approximately $144 million over the deployment period. Under the proposal, costs of phase two of the grid modernization plan would be recovered through the Ohio Companies’ AMI rider, pursuant to the terms and conditions approved in ESP IV. On December 27, 2022, the Ohio Companies filed a motion with the PUCO requesting a procedural schedule that would facilitate the issuance of an order by year-end 2023.
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 on December 1, 2021, and refunds began in December 2021. Current and future rate reductions are 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.
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 and the auditor filed the final audit report on January 14, 2022, which made certain 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 identity. 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. Final comments and responses were filed by parties during the second quarter of 2022.
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. On May 4, 2022, the PUCO selected a third-party auditor to determine whether the show cause demonstration submitted by the Ohio Companies is sufficient to ensure that the cost of any political or charitable spending in support of HB 6 or the subsequent referendum effort was not included, directly or indirectly, in any rates or charges paid by ratepayers.
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.
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.
On August 16, 2022, the U.S. Attorney for the Southern District of Ohio requested that the PUCO stay the above pending HB 6- related matters for a period of six months, which request was granted by the PUCO on August 24, 2022. Unless otherwise ordered by the PUCO, the four cases are stayed in their entirety, including discovery and motions, and all related procedural schedules are vacated.
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 to provide for refunds in the event such provisions of HB 6 are repealed. Neither the Ohio Companies nor FE benefit from the OVEC-related charges the Ohio Companies collect. Instead, the Ohio Companies are further required by HB 6 to remit all the OVEC-related charges they collect to non-FE Ohio electric distribution utilities. The Ohio Companies contested the motions, which are pending before the PUCO.
See Note 13, "Commitments, Guarantees and Contingencies" below for additional details on the government investigations and subsequent litigation surrounding the investigation of HB 6.
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. An evidentiary hearing was held on April 13, 2022, and on April 20, 2022, the parties filed a partial settlement with the PPUC resolving certain of the issues in the proceeding and setting aside the remainder of the issues to be resolved through briefing. PPUC approved the partial settlement, without modification, on August 4, 2022. 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, associated with the additional refund and based on the November 2021 PPUC order and methodology. The Pennsylvania Companies filed petitions to propose the timing and methodology of the refund of these amounts on February 17, 2022. The Pennsylvania Companies’ petitions and the proposed refunds addressed within were approved by the PPUC on June 16, 2022, without modification, effective July 1, 2022, and which refunds were fully completed by December 31, 2022.
Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, the Pennsylvania Companies implemented energy efficiency and peak demand reduction programs with 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.
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 Office of Consumer Advocate 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, which was approved by the PPUC without modification on April 14, 2022.
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 PPUC issued the order as directed, which was challenged by an intervening party. All parties have briefed the issue and await a ruling from the PPUC. Neither the PPUC’s determination or the underlying order are expected to result in a material impact to FirstEnergy.
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 29, 2021, the WVPSC issued an order granting MP and PE’s requested $19.6 million increase in ENEC rates, requiring, among other things, that MP and PE 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. By order dated March 2, 2022, the WVPSC reopened the case to determine whether rates should be increased to recover growing ENEC under-recoveries. On May 17, 2022, the WVPSC issued an order approving an interim rate increase of $94 million, effective for customer rates on May 18, 2022, subject to a prudence review during MP and PE’s 2022 ENEC case.
On August 25, 2022, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates of $183.8 million beginning January 1, 2023, which represents a 12.2% increase to the rates then in effect. The increase was driven by an underrecovery during the review period (July 1, 2021 to June 30, 2022) of $144.9 million due to higher coal, reagent, and allowance expenses. This filing additionally addresses, among other things, the WVPSC’s May 2022 request for a prudence review of current rates. At a hearing on December 8, 2022, the parties in the case presented a unanimous settlement to increase rates by approximately $92 million, effective January 1, 2023, and carry over to MP and PE’s 2023 ENEC case, approximately $92 million at a carrying charge of 4%. In an order dated December 30, 2022, the WVPSC approved the settlement with respect to the proposed rate increase, but MP and PE rates remain subject to a prudence review in their 2023 ENEC case. The order also instructs MP to evaluate the feasibility of purchasing the Pleasants Power Station and file a summary of the evaluation by March 31, 2023.
On December 27, 2021, the WVPSC approved a settlement granting MP and PE a $16 million increase in rates effective January 1, 2022, and permitting the continuation of the vegetation management program and surcharge for another two years. WVPSC additionally ordered MP and PE to perform equipment inspections within a reasonable time after vegetation management occurs on a circuit.
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 was held in mid-March 2022 and on April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, the requested tariff and requiring MP and PE to subscribe at least 85% of the planned 50 MWs before seeking final tariff approval. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in excess of the approved tariff. The first solar generation site is expected to be in-service by the end of 2023 and all construction completed at the other sites no later than the end of 2025 at a total investment cost of approximately $110 million.
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. MP and PE reached a settlement agreement with WVPSC staff and all intervenors, recommending: (i) approval of the ELG compliance plan submitted by MP and PE and (ii) recovery of costs through a surcharge. A ruling approving the settlement without modification was issued by the WVPSC on September 12, 2022, and construction is expected to be completed by the end of 2025. See Note 13, “Commitments, Guarantees and Contingencies - Environmental Matters - Clean Water Act" below, for additional details on the EPA's ELG.
On January 13, 2023, MP and PE filed a request with the WVPSC seeking approval of new depreciation rates for existing and future capital assets. Specifically, MP and PE are seeking to increase depreciation expense of $75.5 million per year, primarily for regulated generation-related assets. Any depreciation rates approved by the WVPSC would not become effective until new base rates were established.
FERC REGULATORY MATTERS
Under the FPA, FERC regulates rates for interstate wholesale sales and transmission of electric power, regulatory accounting and reporting under the Uniform System of Accounts, 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, 2022:
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)
Actual (13-month average)(1)
11.35%(1)
PE January 1, 2021(1)
Actual (13-month average)(1)
11.35%(1)
WP January 1, 2021(1)
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)
(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. On January 18, 2023, MP, PE, and WP submitted an uncontested settlement to FERC, which is subject to FERC approval, which includes an allowed ROE of 10.45% and a capital structure of the lower of actual (13-month average) or 56%.
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 Electric Reliability Organization designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to six regional entities, including RFC. All of the facilities that FirstEnergy operates are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC.
FirstEnergy believes that it is in material compliance with all currently effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations, and cash flows.
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 that FirstEnergy has accepted. The audit report included a finding and related recommendation on FirstEnergy’s methodology for allocation of certain corporate support costs to regulatory capital accounts under certain FERC regulations and reporting. Effective in the first quarter of 2022 and in response to the finding, FirstEnergy had implemented a new methodology for the allocation of these corporate support costs to regulatory capital accounts for its regulated distribution and transmission companies on a prospective basis. With the assistance of an independent outside firm, FirstEnergy completed an analysis during the third quarter of 2022 of these costs and how it impacted certain FERC-jurisdictional wholesale transmission customer rates for the audit period of 2015 through 2021. As a result of this analysis, FirstEnergy recorded in the third quarter of 2022 approximately $45 million ($34 million after-tax) in expected customer refunds, plus interest, due to its wholesale transmission customers and reclassified approximately $195 million of certain transmission capital assets to operating expenses for the audit period, of which $90 million ($67 million after-tax) are not expected to be recoverable and impacted FirstEnergy’s earnings since they relate to costs capitalized during stated transmission rate time periods. These reclassifications also resulted in a reduction to the Regulated Transmission segment’s rate base by approximately $160 million, which is not expected to materially impact FirstEnergy or the segment’s future earnings. The expected wholesale transmission customer refunds were recognized as a reduction to revenue, and the amount of reclassified transmission capital assets that are not expected to be recoverable were recognized within “Other operating expenses” at the Regulated Transmission segment and on FirstEnergy’s Consolidated Statements of Income.
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 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 was approved by FERC on March 24, 2022 without modification. ATSI’s compliance filing to implement the terms of the settlement was accepted by FERC without modification on June 23, 2022.
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; to maintain rate base neutrality (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’s 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 following settlement negotiations, filed an uncontested
settlement agreement with FERC on October 18, 2022. There is no timetable for FERC to rule on the settlement agreement. 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 following settlement negotiations, filed an uncontested settlement agreement with FERC on October 18, 2022. There is no timetable for FERC to rule on the settlement agreement. 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. On March 31, 2022, FERC issued an order, ruling that TrAIL’s compliance filing partially complied with the requirements of Order No. 864 and directing TrAIL to submit a further compliance filing to address certain additional items that according to FERC will further enhance transparency. TrAIL submitted the compliance filing on May 31, 2022, and FERC accepted the compliance filing by letter order dated August 30, 2022. On April 27, 2022, FERC issued an order on PATH’s compliance filing, ruling that it partially complied with the requirements of Order No. 864 and directing PATH to submit a further compliance filing to address certain additional items. PATH submitted the compliance filing on June 27, 2022, and FERC accepted the compliance filing by letter order dated November 14, 2022. MP, WP and PE - as holders of a “stated” transmission rate when Order No. 864 issued - addressed these requirements as part of the transmission rates amendments that were filed with FERC on October 29, 2020. An uncontested settlement of all issues in that case was filed for FERC approval on January 18, 2023.
ATSI ROE - Ohio Consumers Counsel v. ATSI, et al.
On February 24, 2022, the OCC filed a complaint with FERC against ATSI, AEP’s Ohio affiliates and AEPSC, and Duke Energy Ohio, LLC asserting that FERC should reduce the ROE utilized in the utilities’ transmission formula rates by eliminating the 50 basis point adder associated with RTO membership, effective February 24, 2022. The OCC contends that this result is required because Ohio law mandates that transmission owning utilities join an RTO and that the 50 basis point adder is applicable only where RTO membership is voluntary. ATSI disagrees with the OCC’s characterization and set forth its reasons for such disagreement in a combined motion to dismiss and answer that was filed with FERC on March 31, 2022. On that same date, AEP and Duke filed separate motions to dismiss and answers to the OCC complaint, and several other parties filed comments. ATSI filed a response to certain intervenors’ filings on April 28, 2022. On December 15, 2022, FERC denied the complaint as to ATSI and Duke, but granted it as to AEP. On January 17, 2023, AEP and the OCC filed requests for rehearing and on February 1, 2023, FirstEnergy filed an answer to the OCC’s rehearing request. FirstEnergy is unable to predict the outcome of this proceeding, but it is not expected to have a material impact.
Transmission ROE Incentive
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 on the supplemental rulemaking 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's transmission incentive ROE, such changes will be applied on a prospective basis.
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 filed uncontested settlement agreements with FERC on January 18, 2023. There is no timetable for FERC to rule on the settlement agreements. Also on January 25, 2023, the FERC Chief Administrative Law Judge granted a motion of MP, PE, and WP for interim rates to implement certain aspects of the settled rate retroactive to January 1, 2023. As a result of the filed settlement, FirstEnergy recognized a $25 million pre-tax charge during the fourth quarter of 2022, which reflects the difference between amounts originally recorded as assets and amounts which will ultimately be recovered from customers as a result of the pending settlement.
13. COMMITMENTS, GUARANTEES AND CONTINGENCIES
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 LOCs, 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.
As of December 31, 2022, outstanding guarantees and other assurances aggregated approximately $1.0 billion, consisting of parental guarantees on behalf of its consolidated subsidiaries ($528 million) and other assurances ($449 million).
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, 2022, $50 million of net cash 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. FE or its subsidiaries are holding $206 million of net cash collateral as of December 31, 2022, from certain generation suppliers, primarily due to the rise in power prices, and such amount is included in "Other current liabilities" 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, 2022:
Potential Collateral Obligations Utilities and Transmission Companies FE Total
(In millions)
Contractual Obligations for Additional Collateral
Upon Further Downgrade $ 70 $ - $ 70
Surety Bonds (collateralized amount)(1)
61 249 310
Total Exposure from Contractual Obligations $ 131 $ 249 $ 380
(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.
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 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.
Also 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 National Ambient Air Quality Standards. 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 prior CSAPR Update and the New York Section 126 petition. In December 2021, MP purchased NOx emissions allowances to comply with 2021 ozone season requirements. On April 6, 2022, the EPA published proposed rules seeking to impose further significant reductions in EGU NOx emissions in 25 states, including West Virginia. The EPA held a virtual public hearing regarding the proposed rules on April 21, 2022, and MP submitted written comments on June 21, 2022. 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.
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. Vacating the ACE Rule had the unintended effect of reinstating the CPP because the repeal of the CPP was a provision within the ACE Rule. The D.C. Circuit decision was appealed by several states and interested parties, including West Virginia, arguing that the EPA did not have the authorization under Section 111(d) of the Clean Air Act to require “generation shifting” as a way to limit GHGs. On June 30, 2022, the U.S. Supreme Court held that the EPA’s regulation of GHGs under Section 111(d) of the Clean Air Act was not authorized by Congress and remanded the Rule to the EPA for further reconsideration.
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 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 Spring of 2023 and a final rule later in 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 operation at the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to comply with the ELG rule.
Regulation of Waste Disposal
Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act, 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 cease accepting waste date for the 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, 2022, 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 $97 million have been accrued through December 31, 2022, of which, approximately $62 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 Southern District 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 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, and July 11, 2022, the SEC issued additional subpoenas to FE, with which FE has complied. 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 (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. The class certification hearing is scheduled to take place on March 17, 2023. 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. and Brighthouse Funds II - MFS Value Portfolio, et al. v. FirstEnergy Corp., et al. (S.D. Ohio) on December 17, 2021 and February 21, 2022, purported stockholders of FE filed complaints against FE, certain current and former officers, and certain current and former officers of EH. The complaints allege 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 seek the same relief as the In re FirstEnergy Corp. Securities Litigation described above. FE believes that it is probable that it will incur losses in connection with the resolution of these lawsuits. 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 (Conservation Support Rider) 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. (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. FE agreed to a class settlement to resolve these claims on April 11, 2022. In the fourth quarter of 2021, FirstEnergy recognized a pre-tax reserve of $37.5 million in the aggregate with respect to these lawsuits and the Emmons lawsuit below. On June 22, 2022, the court preliminarily approved the class settlement and the final fairness hearing was held on November 9, 2022. On December 5, 2022, the court issued an order memorializing its final approval of the class settlement. The settlement amount was satisfied on December 7, 2022.
•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. FE agreed to a class settlement to resolve these claims on April 11, 2022. In the fourth quarter of 2021, FirstEnergy recognized 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 June 22, 2022, the court preliminarily approved the class settlement and the final fairness hearing was held on November 9, 2022. The S.D. Ohio issued a final written order approving the settlement on December 5, 2022. The settlement amount was satisfied on December 7, 2022.
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. (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. (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.
On March 11, 2022, the parties executed a stipulation and agreement of settlement, and filed a motion the same day requesting preliminary settlement approval in the S.D. Ohio, which the S.D Ohio granted on May 9, 2022. Subsequently, following a hearing on August 4, 2022, the S.D. Ohio granted final approval of the settlement on August 24, 2022. The settlement agreement is expected to resolve fully these shareholder derivative lawsuits and includes a series of corporate governance enhancements, that have resulted in the following:
•Six then-members of the FE Board did 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 was formed to initiate a review process of the then current senior executive team. The review of the senior executive team by the special FE Board committee and the FE Board was completed in September 2022;
•The FE Board will oversee FE’s lobbying and political activities, including periodically reviewing and approving political and lobbying action plans prepared by management;
•An FE Board committee of recently appointed independent directors will 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 FE of $180 million, to be paid by insurance after the judgment has become final, less $36 million in court-ordered attorney’s fees awarded to plaintiffs. On September 20, 2022, a purported FE stockholder filed a motion for reconsideration of the S.D. Ohio’s final settlement approval. The parties filed oppositions to that motion on October 11, 2022 and the motion is under consideration by the S.D. Ohio. The N.D. Ohio matter remains pending. On June 2, 2022, the N.D. Ohio entered an order to show cause why the court should not appoint new plaintiffs’ counsel, and thereafter, on June 10, 2022, the parties filed a joint motion to dismiss the matter without prejudice, which the N.D. Ohio denied on July 5, 2022. On August 15, 2022, the N.D. Ohio issued an order stating its intention to appoint one group of applicants as new plaintiffs’ counsel, and on August 22, 2022, the N.D. Ohio ordered that any objections to the appointment be submitted by August 26, 2022. The parties filed their objections by that deadline, and on September 2, 2022, the applicants responded to those objections. In the meantime, on August 25, 2022, a purported FE stockholder represented by the applicants filed a motion to intervene, attaching a proposed complaint-in-intervention purporting to assert claims that the FE Board and officers breached their fiduciary duties and committed
violations of Section 14(a) of the Exchange Act as well as a claim against a third party for professional negligence and malpractice. The parties filed oppositions to that motion to intervene on September 8, 2022, and the proposed intervenor's reply in support of his motion to intervene was filed on September 22, 2022.
On August 24, 2022, the parties filed a joint motion to dismiss the action pending in the N.D. Ohio based upon and in light of the approval of the settlement by the S.D. Ohio. On August 30, 2022, the parties filed a joint motion to dismiss the state court action, which the court granted on September 2, 2022.
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. On December 30, 2022, FERC approved a Stipulation and Consent Agreement that resolves the investigation. The agreement includes a FirstEnergy admission of violating FERC’s “duty of candor” rule and related laws, and obligates FirstEnergy to pay a civil penalty of $3.86 million, and to submit two annual compliance monitoring reports to FERC’s Office of Enforcement regarding improvements to FirstEnergy’s compliance programs.
FE terminated Charles E. Jones as its chief executive officer effective October 29, 2020. As a result of Mr. Jones’ termination, and due to the determination of a committee of independent members of the FE Board that Mr. Jones violated certain FirstEnergy policies and its code of conduct, all grants, awards and compensation under FirstEnergy’s short-term incentive compensation program and long-term incentive compensation program with respect to Mr. Jones that were outstanding on the date of termination were forfeited. In November 2021, after a determination by the Compensation Committee of the FE Board that a demand for recoupment was warranted pursuant to the Recoupment Policy, FE made a recoupment demand to Mr. Jones of compensation previously paid to him totaling approximately $56 million, the maximum amount permissible under the Recoupment Policy. As such, any amounts payable to Mr. Jones under the EDCP will be set off against FE’s recoupment demand. There can be no assurance that the efforts to seek recoupment from Mr. Jones will be successful.
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.
14. SEGMENT INFORMATION
FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity through its reportable segments, Regulated Distribution and Regulated Transmission. FirstEnergy evaluates segment performance based on Earnings attributable to FE.
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 transaction to transfer TMI-2 to TMI-2 Solutions, LLC was consummated on December 18, 2020, and as a result, during the fourth quarter of 2020 FirstEnergy recognized an after-tax gain of approximately $33 million, primarily associated with the write-off of a tax related regulatory liability.
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. 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 in the first quarter of 2021. 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 (deferral) of regulatory assets, net”, line on the Consolidated Statements of Income, resulting in no earnings impact to FirstEnergy or JCP&L.
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 I, 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 would own 19.9% of the issued and outstanding membership interests of FET, for a purchase price of $2.375 billion. The transaction closed on May 31, 2022. On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The purchase price will be payable in part by the issuance of a promissory note expected to be in the principal amount of $1.75 billion. The remaining $1.75 billion of the purchase price will be payable in cash at the closing. As a result of the consummation of the transaction, Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1% ownership interests of FET. The transaction is subject to customary closing conditions, including approval from the FERC and certain state utility commissions, and completion of review by the CFIUS. In addition, pursuant to the FET P&SA II, FirstEnergy has agreed to make the necessary filings with the applicable regulatory authorities for the PA Consolidation. The FET Minority Equity Interest Sale is expected to close by early 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s GAAP financial statements. KATCo, which was a subsidiary of FET, became a wholly owned subsidiary of FE prior to the closing of the FET P&SA I and remains in the Regulated Transmission segment.
Corporate/Other reflects corporate support and other costs not charged or attributable to the Utilities or Transmission Companies, including FE's retained Pension and OPEB assets and liabilities of the FES Debtors, interest expense on FE’s holding company debt and other investments or businesses that do not constitute an operating segment. Reconciling adjustments for the elimination of inter-segment transactions are shown separately in the following table of Segment Financial Information. As of December 31, 2022, 67 MWs of electric generating capacity, representing AE Supply's OVEC capacity entitlement, was also included in Corporate/Other for segment reporting. As of December 31, 2022, Corporate/Other had approximately $5.4 billion of FE holding company debt.
Financial information for FirstEnergy’s business segments and reconciliations to consolidated amounts is presented below:
For the Years Ended December 31,
(In millions) 2022 2021 2020
External revenues
Regulated Distribution $ 10,569 $ 9,510 $ 9,168
Regulated Transmission 1,863 1,608 1,613
Corporate/Other 27 14 9
Reconciling Adjustments - - -
Total external revenues $ 12,459 $ 11,132 $ 10,790
Internal revenues
Regulated Distribution $ 232 $ 201 $ 195
Regulated Transmission 5 10 17
Corporate/Other - - -
Reconciling Adjustments (237) (211) (212)
Total internal revenues $ - $ - $ -
Total revenues $ 12,459 $ 11,132 $ 10,790
Depreciation
Regulated Distribution $ 967 $ 911 $ 896
Regulated Transmission 335 325 313
Corporate/Other 7 3 4
Reconciling Adjustments 66 63 61
Total depreciation $ 1,375 $ 1,302 $ 1,274
Amortization (deferral) of regulatory assets, net
Regulated Distribution $ (362) $ 260 $ (64)
Regulated Transmission (3) 9 11
Corporate/Other - - -
Reconciling Adjustments - - -
Total amortization (deferral) of regulatory assets, net $ (365) $ 269 $ (53)
DPA penalty
Corporate/Other $ - $ 230 $ -
Total DPA penalty $ - $ 230 $ -
Miscellaneous income (expense), net
Regulated Distribution $ 361 $ 399 $ 332
Regulated Transmission 36 41 30
Corporate/Other 85 58 81
Reconciling Adjustments (67) (12) (13)
Total miscellaneous income (expense), net $ 415 $ 486 $ 430
Interest expense
Regulated Distribution $ 526 $ 522 $ 501
Regulated Transmission 230 247 219
Corporate/Other 350 382 358
Reconciling Adjustments (67) (12) (13)
Total interest expense $ 1,039 $ 1,139 $ 1,065
Income taxes (benefits)
Regulated Distribution $ 251 $ 364 $ 113
Regulated Transmission 110 127 138
Corporate/Other 639 (171) (125)
Reconciling Adjustments - - -
Total income taxes (benefits) $ 1,000 $ 320 $ 126
For the Years Ended December 31,
(In millions) 2022 2021 2020
Net income (loss)
Regulated Distribution $ 957 $ 1,288 $ 959
Regulated Transmission 394 408 464
Corporate/Other (912) (413) (344)
Reconciling Adjustments - - -
Total net income (loss) $ 439 $ 1,283 $ 1,079
Income attributable to noncontrolling interest
Regulated Transmission $ 33 $ - $ -
Total income attributable to noncontrolling interest $ 33 $ - $ -
Earnings attributable to FE
Regulated Distribution $ 957 $ 1,288 $ 959
Regulated Transmission 361 408 464
Corporate/Other (912) (413) (344)
Reconciling Adjustments - - -
Total earnings attributable to FE $ 406 $ 1,283 $ 1,079
Property additions
Regulated Distribution $ 1,513 $ 1,395 $ 1,514
Regulated Transmission 1,192 958 1,067
Corporate/Other 51 92 76
Reconciling Adjustments - - -
Total property additions $ 2,756 $ 2,445 $ 2,657
As of December 31,
(In millions) 2022 2021
Assets
Regulated Distribution $ 31,749 $ 30,812
Regulated Transmission 13,835 13,237
Corporate/Other 524 1,383
Reconciling Adjustments - -
Total assets $ 46,108 $ 45,432
Goodwill
Regulated Distribution $ 5,004 $ 5,004
Regulated Transmission 614 614
Corporate/Other - -
Reconciling Adjustments - -
Total goodwill $ 5,618 $ 5,618
15. DISCONTINUED OPERATIONS
On March 31, 2018, the FES Debtors announced that, in order to facilitate an orderly financial restructuring, they filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code with the Bankruptcy Court. On February 27, 2020, the FES Debtors effectuated their plan, emerged from bankruptcy and FirstEnergy tendered the bankruptcy court approved settlement payments totaling $853 million and a $125 million tax sharing payment to the FES Debtors. The FES Bankruptcy settlement was conditioned on the FES Debtors confirming and effectuating a plan of reorganization acceptable to FirstEnergy.
As contemplated under the FES Bankruptcy settlement agreement, AE Supply entered into an agreement on December 31, 2018, to transfer the 1,300 MW Pleasants Power Station and related assets to FG, while retaining certain specified liabilities. Under the terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply operated Pleasants until ownership was transferred on January 30, 2020. AE Supply will continue to provide access to the McElroy's Run CCR impoundment facility, which was not transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR impoundment facility. During the first quarter of 2020, FG
paid AE Supply approximately $65 million of cash for related materials and supplies (at book value) and the settlement of FG’s economic interest in Pleasants.
By eliminating a significant portion of its competitive generation fleet with the deconsolidation of the FES Debtors, FirstEnergy has concluded the FES Debtors meet the criteria for discontinued operations, as this represents a significant event in management’s strategic review to exit commodity-exposed generation and transition to a fully regulated company.
Income Taxes
As a result of the FES Debtors’ tax return deconsolidation, FirstEnergy recognized a worthless stock deduction, of approximately $4.9 billion, net of unrecognized tax benefits of $316 million, for the remaining tax basis in the stock of the FES Debtors. Based upon completion of the IRS’s review of the 2020 federal income tax return during fourth quarter 2021, FirstEnergy recognized the full tax benefit of the worthless stock deduction of approximately $5.2 billion, or $1.1 billion on a tax-effected basis, net of valuation allowances recorded against the state tax benefit ($21 million), eliminating associated uncertain tax position reserves.
Upon emergence, FirstEnergy paid the FES Debtors $125 million to settle all reconciliations under the Intercompany Tax Allocation Agreement for 2018, 2019 and 2020 tax years, including all issues regarding nondeductible interest.
In conjunction with filing the 2020 consolidated federal income tax return during the third quarter of 2021, FirstEnergy computed a final federal NOL allocation between the FES Debtors and FirstEnergy consolidated that resulted in FirstEnergy recording an increase to the consolidated NOL carryforward of approximately $289 million ($61 million tax-effected).
Summarized Results of Discontinued Operations
Summarized results of discontinued operations for the years ended December 31, 2022, 2021, and 2020 were as follows:
For the Years Ended December 31,
(In millions) 2022 2021 2020
Revenues $ - $ - $ 7
Fuel - - (6)
Other operating expenses - - (6)
Pleasants economic interest(1)
- - 5
Other expense, net - (4) -
Loss from discontinued operations, before tax - (4) -
Income tax expense (benefit) - (1) -
Loss from discontinued operations, net of tax - (3) -
Settlement consideration and services credit - - (1)
Accelerated net pension and OPEB prior service credits - - 18
Gain on disposal of FES and FENOC, before tax - - 17
Income tax benefits, including worthless stock deduction - (47) (59)
Gain on disposal of FES and FENOC, net of tax - 47 76
Income from discontinued operations (2)
$ - $ 44 $ 76
(1) Reflects the estimated amounts owed from FG for its economic interests in Pleasants effective January 1, 2019. As discussed above, settlement of the economic interests occurred during the first quarter of 2020.
(2) Income from discontinued operations are included in Corporate/Other for segment reporting.
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, 2022, 2021 and 2020:
For the Years Ended December 31,
(In millions) 2022 2021 2020
CASH FLOWS FROM OPERATING ACTIVITIES:
Income from discontinued operations $ - $ 44 $ 76
Gain on disposal, net of tax - (47) (76)

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
FirstEnergy has established disclosure controls and procedures to ensure that information is accumulated and communicated to management, including the interim chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure, and ensure that information required to be disclosed in the reports FirstEnergy files or submits under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.
The management of FirstEnergy, with the participation of the interim chief executive officer and chief financial officer, have evaluated the effectiveness of its disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of December 31, 2022. Based on that evaluation, the interim chief executive officer and chief financial officer of FirstEnergy have concluded that its disclosure controls and procedures were effective as of December 31, 2022.
Management’s Report on Internal Control over Financial Reporting
Management of FirstEnergy is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. FirstEnergy’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management conducted an evaluation of the effectiveness of FirstEnergy's internal control over financial reporting as of December 31, 2022, based on the framework in "Internal Control-Integrated Framework" (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on that evaluation, management concluded that FirstEnergy's internal control over financial reporting was effective as of December 31, 2022.
The effectiveness of FirstEnergy’s internal control over financial reporting as of December 31, 2022 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report, which is included herein.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2022, there were no changes in internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, FirstEnergy's internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
On February 9, 2023, the FE Board approved a new service-based restricted shares award in the amount of $2 million for Mr. K. Jon Taylor that will be granted on March 1, 2023. The number of shares subject to the award will be determined as of March 1, 2023, based on the FE’s average high and low stock price as of that date. The shares will generally vest over a four-year period from March 1, 2023, with 25% of the award vesting after two years, another 25% vesting after a third year, and the remaining amount of the award vesting after the fourth year, generally subject to Mr. Taylor’s continued employment with the FirstEnergy. The award will have other terms and conditions based on FE’s 2020 Incentive Compensation Plan and will be consistent with the form of Restricted Stock Agreement attached to this Annual Report on Form 10-K as Exhibit 10-53.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by Item 10 is incorporated herein by reference to FirstEnergy's 2023 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Exchange Act.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated herein by reference to FirstEnergy’s 2023 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Exchange Act.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The Item 403 of Regulation S-K information required by Item 12 is incorporated herein by reference to FirstEnergy's 2023 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Exchange Act.
The following table contains information as of December 31, 2022, regarding compensation plans for which shares of FE common stock may be issued.
Plan category Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in First Column)
Equity compensation plans approved by security holders 3,297,942 (1) $ - (2) 11,912,070 (3)
Equity compensation plans not approved by security holders(4)
- $ - -
Total 3,297,942 $ - 11,912,070
(1) This number includes 1,427,058 shares subject to outstanding awards of stock based RSUs granted under the ICP 2015 and ICP 2020 if paid at target for the three outstanding cycles, as well as 1,427,058 additional shares assuming maximum performance metrics are achieved for the 2020-2022, 2021-2023, and 2022-2024 cycles of stock based RSUs, and 443,826 shares related to the DCPD that will be paid in stock.
(2) There are no outstanding options, therefore, no consideration is required from participants for the exercise or vesting of any outstanding equity compensation awards.
(3) Represents shares available for issuance, assuming maximum performance metrics are achieved (or approximately 4,844,747 under ICP 2015 and 8,494,381 under ICP 2020, available assuming performance at target) for the 2020-2022, 2021-2023, and 2022-2024 cycles of stock-based RSUs, with respect to future awards under the ICP 2020 and future accruals of dividends on awards outstanding under ICP 2015 or ICP 2020. Additional shares may become available under the ICP 2015 or ICP 2020 due to cancellations, forfeitures, cash settlements or other similar circumstances with respect to outstanding awards.
(4) All equity compensation plans have been approved by security holders.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by Item 13 is incorporated herein by reference to FirstEnergy’s 2023 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Exchange Act.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
A summary of the audit and all other fees for services rendered by PricewaterhouseCoopers LLP are as follows:
For the Years Ended December 31,
2022 2021
(in thousands)
Audit Fees(1)
$ 7,523 $ 7,902
Audit-Related Fees(2)
190 70
Tax-Related Fees(3)
220 -
All Other Fees(4)
720 217
Total Fees $ 8,653 $ 8,189
(1) Professional services rendered for the audits of FirstEnergy's annual financial statements and reviews of unaudited financial statements included in FirstEnergy's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters, agreed upon procedures and consents for financings and filings made with the SEC.
(2) Audit-related fees in 2022 and 2021 were related to services rendered for EESG reporting assessments.
(3) Tax-related fees in 2022 were primarily related to the performance of tax services in conjunction with the FET P&SA I.
(4) All other fees in 2022 primarily reflect certain costs incurred as a result of system implementation quality assurance services, the ongoing SEC investigation and software subscription fees. All other fees in 2021 primarily reflect the ongoing SEC investigation, software subscription fees and accounting research license costs.
Additional information required by this item is incorporated herein by reference to FirstEnergy’s 2023 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Exchange Act.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE
(a) The following documents are filed as a part of this report on Form 10-K:
1. Financial Statements:
Management’s Report on Internal Control Over Financial Reporting for FirstEnergy Corp. is listed under Item 9A, "Controls and Procedures" herein.
Report of Independent Registered Public Accounting Firm (PCAOB ID 238) for FirstEnergy Corp. is listed under Item 8, "Financial Statements and Supplementary Data," herein.
The financial statements filed as a part of this report for FirstEnergy Corp. are listed under Item 8, "Financial Statements and Supplementary Data," herein.
2. Financial Statement Schedules:
N/A - Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto.
3. Exhibits
Exhibit
Number
3-1 Amended and Restated Articles of Incorporation of FirstEnergy Corp. (incorporated by reference to FE’s Form 10-Q filed July 23, 2019, Exhibit 3-1, File No. 333-21011).
3-2 Third Amended and Restated Code of Regulations of FirstEnergy Corp., effective May 17, 2022 (incorporated by reference to FE’s Form 8-K on May 23, 2022, Exhibit 3.1, File No. 333-21011).
4-1 Indenture, dated November 15, 2001, between FirstEnergy Corp. and The Bank of New York Mellon, as Trustee (incorporated by reference to FE’s Form S-3 filed September 21, 2001, Exhibit 4(a), File No. 333-69856).
4-2 Officer’s Certificate relating to FirstEnergy Corp.'s 2.85% Notes, Series A, due 2022, 3.90% Notes, Series B, due 2027 and 4.85% Notes, Series C, due 2047 (incorporated by reference to FE’s Form 8-K filed June 21, 2017, Exhibit 4.1, File No. 333-21011).
4-3 Form of 3.90% Note, Series B, due 2027 (incorporated by reference to FE’s Form 8-K filed June 21, 2017, Exhibit 4.1, File No. 333-21011).
4-4 Form of 4.85% Note, Series C, due 2047 (incorporated by reference to FE’s Form 8-K filed June 21, 2017, Exhibit 4.1, File No. 333-21011).
4-5 Officer’s Certificate relating to FirstEnergy Corp.'s 2.050% Notes, Series A, due 2025, 2.650% Notes, Series B, due 2030 and 3.400% Notes, Series C, due 2050 (incorporated by reference to FE’s Form 8-K filed February 20, 2020, Exhibit 4.1, File No. 333-21011).
4-6 Form of 2.050% Note, Series A, due 2025 (incorporated by reference to FE’s Form 8-K filed February 20, 2020, Exhibit 4.2, File No. 333-21011).
4-7 Form of 2.650% Note, Series B, due 2030 (incorporated by reference to FE’s Form 8-K filed February 20, 2020, Exhibit 4.3, File No. 333-21011).
4-8 Form of 3.400% Note, Series C, due 2050 (incorporated by reference to FE’s Form 8-K filed February 20, 2020, Exhibit 4.4, File No. 333-21011).
4-9 Officer’s Certificate relating to FirstEnergy Corp.'s 1.600% Notes, Series A, due 2026, 2.250% Notes, Series B, due 2030 (incorporated by reference to FE’s Form 8-K filed June 8, 2020, Exhibit 4.1, File No. 333-21011).
4-10 Form of 1.600% Note, Series A, due 2026 (incorporated by reference to FE’s Form 8-K filed June 8, 2020, Exhibit 4.2, File No. 333-21011).
4-11 Form of 2.250% Note, Series B, due 2030 (incorporated by reference to FE’s Form 8-K filed June 8, 2020, Exhibit 4.3, File No. 333-21011).
4-12 Description of Securities Registered under Section 12(b) of the Securities Exchange Act of 1934 (incorporated by reference to FE's Form 10-K filed February 10, 2020, Exhibit 4-10, File No. 333-21011).
Exhibit
Number
10-1 Credit Agreement, dated as of October 18, 2021, by and among FirstEnergy Corp., FirstEnergy Transmission, LLC, the banks and other financial institutions party thereto, as lenders, and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to FE’s Form 8-K filed October 18, 2021, Exhibit 10.1, File No. 333-210111).
10-2 Credit Agreement, dated as of October 18, 2021, by and among The Cleveland Electric Illuminating Company, Ohio Edison Company, The Toledo Edison Company, the banks and other financial institutions party thereto, as lenders, and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to FirstEnergy’s Form 8-K filed October 18, 2021, Exhibit 10.2, File No. 333-21011).
10-3 Credit Agreement, dated as of October 18, 2021, by and among Metropolitan Edison Company, Pennsylvania Power Company, Pennsylvania Electric Company, West Penn Power Company, the banks and other financial institutions party thereto on the date hereof, as lenders, and Mizuho Bank, Ltd., as administrative agent (incorporated by reference to FirstEnergy’s Form 8-K filed October 18, 2021, Exhibit 10.3, File No. 333-21011).
10-4 Credit Agreement, dated as of October 18, 2021, by and among Jersey Central Power & Light Company, the banks and other financial institutions party thereto on the date hereof, as lenders, and Mizuho Bank, Ltd., as administrative agent (incorporated by reference to FirstEnergy’s Form 8-K filed October 18, 2021, Exhibit 10.4, File No. 333-21011).
10-5 Credit Agreement, dated as of October 18, 2021, by and among American Transmission Systems, Incorporated, Mid-Atlantic Interstate Transmission, LLC, and Trans-Allegheny Interstate Line Company, the banks and other financial institutions party thereto on the date hereof, as lenders, and PNC Bank, National Association, as administrative agent (incorporated by reference to FirstEnergy’s Form 8-K filed October 18, 2021, Exhibit 10.5, File No. 333-21011).
10-6 Credit Agreement, dated as of October 18, 2021, by and among Monongahela Power Company, The Potomac Edison Company, the banks and other financial institutions party thereto on the date hereof, as lenders, and Mizuho Bank, Ltd, as administrative agent (incorporated by reference to FirstEnergy’s Form 8-K filed October 18, 2021, Exhibit 10.6, File No. 333-21011).
10-7 Consent Decree dated March 18, 2005 (incorporated by reference to FE’s Form 8-K filed March 18, 2005, Exhibit 10-1, File No. 333-21011).
10-8 Settlement Agreement, dated as of August 26, 2018, by and among the Debtors, the FE Non-Debtor Parties, the Ad Hoc Noteholders Group, the Bruce Mansfield Certificateholders Group and the Committee (in each case, as defined therein) (incorporated by reference to FE’s Form 8-K filed August 27, 2018, Exhibit 10.1, File No. 333-21011).
10-9 Deferred Prosecution Agreement, dated as of July 21, 2021 (incorporated by reference to FE’s Form 8-K filed July 22, 2021, Exhibit 10.1, File No. 333-21011).
10-10 Purchase and Sale Agreement, dated as of November 6, 2021, among the FirstEnergy Corp. and North American Transmission Company II LLC, and Brookfield Super-Core Infrastructure Partners L.P., Brookfield Super-Core Infrastructure Partners (NUS) L.P. and Brookfield Super-Core Infrastructure Partners (ER) SCSp, as guarantors. (incorporated by reference to FE’s Form 10-K filed February 16, 2022, Exhibit 10-10, File No. 333-21011).
10-11 (B) Amended and Restated Limited Liability Company Operating Agreement of FirstEnergy Transmission, LLC (incorporated by reference to FE’s Form 8-K filed May 31, 2022, Exhibit 10.1, File No. 333-21011).
10-12 Common Stock Purchase Agreement, dated as of November 6, 2021, among the FirstEnergy Corp. and BIP Securities II-B L.P. (incorporated by reference to FE’s Form S-3 filed on December 13, 2021, Exhibit 4(d), File No. 333-210111).
10-13 Director Appointment and Nomination Agreement, dated March 16, 2021, by and among the Icahn Group and FirstEnergy (incorporated by reference to FE's Form 8-K filed March 16, 2021, Exhibit 10.1, File No. 333-21011).
10-14 (B) FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, amended and restated January 1, 2005, further amended December 31, 2010 (incorporated by reference to FE's Form 10-K filed February 27, 2014, Exhibit 10-6, File No. 333-21011).
10-15 (B) Amendment No. 1 to Deferred Compensation Plan for Outside Directors, effective as of January 1, 2012 (incorporated by reference to FE's Form 10-Q filed May 3, 2011, Exhibit 10.7, File No. 333-21011).
10-16 (B) Amendment No. 2 to FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, effective January 21, 2014, (incorporated by reference to FE's Form 10-K filed February 27, 2014, Exhibit 10-8, File No. 333-21011).
10-17 (B) Amendment No. 3 to FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, dated January 14, 2019 and effective as of April 1, 2018 (incorporated by reference to FE's Form 10-K filed February 19, 2019, Exhibit 10-7, File No.333-21011).
10-18 (B) FirstEnergy Corp. Supplemental Executive Retirement Plan, amended and restated January 1, 2005, further amended December 31, 2010 (incorporated by reference to FE's Form 10-K filed February 27, 2014, Exhibit 10-9, File No. 333-21011).
Exhibit
Number
10-19 (B) Amendment No. 1 to FirstEnergy Corp. Supplemental Executive Retirement Plan, effective January 1, 2012 (incorporated by reference to FE's Form 10-Q filed May 3, 2011, Exhibit 10.8, File No. 333-21011).
10-20 (B) Amendment No. 2 to FirstEnergy Corp. Supplemental Executive Retirement Plan, dated January 14, 2019 and effective as of April 1, 2018 (incorporated by reference to FE's Form 10-K filed February 19, 2019, Exhibit 10-10, File No. 333-21011).
10-21 (B) FirstEnergy Corp. Cash Balance Restoration Plan, effective January 1, 2014 (incorporated by reference to FE's Form 10-K filed February 27, 2014, Exhibit 10-11, File No. 333-21011).
10-22 (B) Retirement Plan for Outside Directors of GPU, Inc. as amended and restated as of August 8, 2000 (incorporated by reference to GPU, Inc. Form 10-K filed March 21, 2001, Exhibit 10-N, File No. 001-06047).
10-23 (B) Allegheny Energy, Inc. Non-Employee Director Stock Plan (incorporated by reference to FE's Form 8-K filed February 25, 2011, Exhibit 10.4, File No. 21011).
10-24 (B) Allegheny Energy, Inc. Amended and Restated Revised Plan for Deferral of Compensation of Directors (incorporated by reference to FE's Form 10-K filed February 27, 2014, Exhibit 10-29, File No. 333-21011).
10-25 (B) Amendment No. 1 to Allegheny Energy, Inc. Amended and Restated Revised Plan for Deferral of Compensation of Directors (incorporated by reference to FE's Form 10-K filed February 27, 2014, Exhibit 10-30, File No. 333-21011).
10-26 (B) Form of Director and Officer Indemnification Agreement (incorporated by reference to FE’s Form 8-K filed May 16, 2018, Exhibit 10.1, File No. 333-21011).
10-27 (B) Guarantee, dated as of September 16, 2013 by FirstEnergy Corp. in favor of participants under the FirstEnergy Corp. Executive Deferred Compensation Plan (incorporated by reference to FE’s Form 10-Q filed November 5, 2013, Exhibit 10.2, File No. 333-21011).
10-28 (B) Form of Restricted Stock Agreement (incorporated by reference to FE’s Form 10-K filed February 17, 2015, Exhibit 10-49, File No. 333-21011).
10-29 (B) FirstEnergy Corp. Amended and Restated Executive Deferred Compensation Plan, dated July 20, 2015, and effective as of November 1, 2015 (incorporated by reference to FE's Form 8-K filed July 24, 2015, Exhibit 10.1, File No. 333-21011).
10-30 (B) Amendment No. 1 to FirstEnergy Corp. Amended and Restated Executive Deferred Compensation Plan, dated January 14, 2019 and effective as of April 1, 2018 (incorporated by reference to FE's Form 10-K filed February 19, 2019, Exhibit 10-23, File No. 333-21011).
10-31 (B) FirstEnergy Corp. 2017 Change in Control Severance Plan, dated as of September 15, 2015, and effective as of January 1, 2017 (incorporated by reference to FE's Form 8-K filed September 18, 2015, Exhibit 10.1, File No. 333-21011).
10-32 (B) Waiver of Participation in the FirstEnergy Corp. Change in Control Severance Plan, entered into by Charles E. Jones dated as of September 15, 2015 (incorporated by reference to FE's Form 8-K filed September 18, 2015, Exhibit 10.2, File No. 333-21011).
10-33 (B) Non-Competition and Non-Disparagement Agreement, entered into by Charles E. Jones, dated as of September 15, 2015 (incorporated by reference to FE's Form 8-K filed September 18, 2015, Exhibit 10.3, File No. 333-21011).
10-34 (B) FirstEnergy Corp. 2015 Incentive Compensation Plan (incorporated by reference to FE's Definitive Proxy Statement filed April 1, 2015, Appendix A, File No. 333-21011).
10-35 (B) Amendment No. 1 to the FirstEnergy Corp. 2015 Incentive Compensation Plan, effective February 21, 2017 (incorporated by reference to FE's Form 10-K filed February 21, 2017, Exhibit 10-51, File No. 333-21011).
10-36 (B) Executive Severance Benefits Plan, as amended and restated as of December 20, 2016 (incorporated by reference to FE’s Form 8-K filed December 21, 2016, Exhibit 10.1, File No. 333-21011).
10-37 (B) Amendment No. 2 to FirstEnergy Corp. Amended and Restated Executive Deferred Compensation Plan, dated September 18, 2019 and effective as of November 1, 2015 (incorporated by reference to FE's Form 10-Q filed November 4, 2019, Exhibit 10.3, File No.333-21011).
10-38 (B) Guarantee, dated as of February 21, 2017, by FirstEnergy Corp. in favor of participants under the FirstEnergy Corp. Cash Balance Pension Restoration Plan (incorporated by reference to FE’s Form 10-Q filed July 27, 2017, Exhibit 10.1, File No. 333-21011).
10-39 (B) Form of 2018-2020 Cash-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated by reference to FE’s Form 10-K filed February 20, 2018, Exhibit 10-56, File No. 333-21011).
10-40 (B) Form of 2018-2020 Stock-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated by reference to FE’s Form 10-K filed February 20, 2018, Exhibit 10-57, File No. 333-21011).
Exhibit
Number
10-41 (B) Form of 2018-2019 Stock-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated by reference to FE’s Form 10-Q filed April 23, 2018, Exhibit 10.12, File No. 333-21011).
10-42 (B) FirstEnergy Solutions Corp. Voluntary Enhanced Retirement Option, effective as of January 2, 2019 (incorporated by reference to FE’s Form 8-K filed November 21, 2018, Exhibit 10.1, File No. 333-21011).
10-43 (B) Form of 2019-2021 Cash-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated by reference to FE's Form 10-Q filed April 23, 2019, Exhibit 10.2, File No.333-21011).
10-44 (B) Form of 2019-2021 Stock-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated by reference to FE's Form 10-Q filed April 23, 2019, Exhibit 10.3, File No.333-21011).
10-45 Consent and Waiver to the Settlement Agreement, dated April 18, 2019, by and among the Debtors and the FE Non-Debtor Parties (incorporated by reference to FE's Form 10-Q filed April 23, 2019, Exhibit 10.1, File No.333-21011).
10-46 First Amendment to Settlement Agreement dated November 21, 2019, by and among the Debtors, FE Non-Debtor Parties, Ad Hoc Noteholders Group, Bruce Mansfield Certificateholders Group, and the Committee (incorporated by reference to FE’s Form 8-K filed November 26, 2019, Exhibit 10.1, File No. 333-21011).
10-47 (B) Form of 2020-2022 Cash-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated by reference to FE's Form 10-Q filed April 23, 2020, Exhibit 10.1, File No.333-21011).
10-48 (B) Form of 2020-2022 Stock-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated by reference to FE's Form 10-Q filed April 23, 2020, Exhibit 10.2, File No.333-21011).
10-49 (B) Form of 2020 Restricted Stock Award Agreement (incorporated by reference to FE's Form 10-Q filed April 23, 2020, Exhibit 10.3, File No.333-21011).
10-50 (B) FirstEnergy Corp. 2020 Incentive Compensation Plan (incorporated by reference to FE's Form 8-K filed May 20, 2020, Exhibit 10.1, File No.333-21011).
10-51 (B) Form of 2021-2023 Cash-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated by reference to FE’s Form 10-Q filed July 22, 2021, Exhibit 10.1, File No. 333-21011).
10-52 (B) Form of 2021-2023 Stock-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated by reference to FE’s Form 10-Q filed July 22, 2021, Exhibit 10.2, File No. 333-21011).
10-53 (B) Form of Restricted Stock Award Agreement (incorporated by reference to FE’s Form 10-Q filed July 22, 2021, Exhibit 10.3, File No. 333-21011).
10-54 (B) Voluntary Retirement Agreement with Gary D. Benz (incorporated by reference to FE’s Form 10-Q filed July 22, 2021, Exhibit 10.4, File No. 333-21011).
10-55 (B) Restricted Stock Award Agreement to John W. Somerhalder II (incorporated by reference to FE’s Form 10-Q filed July 22, 2021, Exhibit 10.5, File No. 333-21011).
10-56 (B) Form of 2022-2024 Cash-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated by reference to FE’s Form 10-Q filed April 21, 2022, Exhibit 10.1, File No. 333-21011).
10-57 (B) Form of 2022-2024 Stock-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated by reference to FE’s Form 10-Q filed April 21, 2022, Exhibit 10.2, File No. 333-21011).
10-58 (B) Stock-Based Performance-Adjusted Restricted Stock Unit Award Agreement to John W. Somerhalder II (incorporated by reference to FE’s Form 10-Q filed July 26, 2022, Exhibit 10.2, File No. 333-21011).
10-59 (A)(B) 2022 Interim Chief Executive Officer Restricted Stock Units Award Agreement to John W. Somerhalder II.
10-60 (A)(B) 2023 Interim Chief Executive Officer Restricted Stock Units Award Agreement to John W. Somerhalder II.
14 Code of Business Conduct and Ethics (incorporated by reference to FE’s Form 10-Q filed July 22, 2021, Exhibit 14.1, File No. 333-21011).
21 (A) List of Subsidiaries of the Registrant at December 31, 2022.
23 (A) Consent of Independent Registered Public Accounting Firm.
Exhibit
Number
31-1 (A) Certification of interim chief executive officer, pursuant to Rule 13a-14(a).
31-2 (A) Certification of chief financial officer, pursuant to Rule 13a-14(a).
32 (A) Certification of interim chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.
101 The following materials from the Annual Report on Form 10-K for FirstEnergy Corp. for the period ended December 31, 2022, formatted in iXBRL (Inline Extensible Business Reporting Language): (i) Consolidated Statements of Income and Consolidated Statements of Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Stockholders' Equity, (iv) Consolidated Statements of Cash Flows, (v) related notes to these financial statements and (vi) document and entity information.
104 Cover Page Interactive Data File (the cover page XBRL tags are embedded within the Inline XBRL document)
(A) Provided herein in electronic format as an exhibit.
(B) Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, FirstEnergy has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but hereby agrees to furnish to the SEC on request any such documents.