Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-Q discusses the three months ended March 31, 2026 and year-over-year comparisons between the three months ended March 31, 2026 and 2025 and should be read in conjunction with the Registrants’ interim financial statements and notes included in this Form 10-Q, and the Registrants’ audited financial statements and notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7. in its Annual Report on Form 10-K for the year ended December 31, 2025, filed with the SEC on February 18, 2026.

EXECUTIVE SUMMARY AND RECENT DEVELOPMENTS

Company Overview

FirstEnergy is dedicated to integrity, safety, reliability and operational excellence and is principally involved in the transmission, distribution and generation of electricity through its reportable segments: Distribution, Integrated and Stand-Alone Transmission. Its electric distribution companies form one of the nation's largest investor-owned electric systems, serving over 6 million customers in Ohio, Pennsylvania, New Jersey, West Virginia, Maryland and New York. FirstEnergy’s transmission subsidiaries operate more than 24,000 miles of transmission lines that connect the Midwest and Mid-Atlantic regions and two regional transmission operation centers. As of March 31, 2026, AGC and MP control 3,610 MWs of net maximum generation capacity.

Segment Overview

See Note 10., “Segment Information,” of the Combined Notes to Financial Statements of the Registrants.

Investment Strategy

FirstEnergy invests in both its regulated operations to improve reliability and the customer experience, and its people to attract, retain and develop talented and engaged employees to carry out its strategy.

FirstEnergy’s customer-focused Energize365 investment plan for the 2026 to 2030 time period is $36 billion, approximately 25% higher than the previous 2025 to 2029 five-year plan, and aims to strengthen the grid, improve reliability and support growing customer demand. Through the Energize365 program, system-wide capital investments from 2026 to 2030 are expected to include the Distribution segment 28%, the Integrated segment 35%, and the Stand-Alone Transmission segment 35%, focused on the following:

Distribution and Transmission investments to enhance grid reliability and resiliency and support growing customer demand, including through:
Programs to drive system resiliency through automation technology and communication, including the Ohio Companies’ distribution grid modernization plans, Pennsylvania's LTIIP, New Jersey's EnergizeNJ, and implementing advanced metering infrastructure;
Operational flexibility projects that are expected to build capacity and support the evolving grid such as projects to support increased data center load;
Enhancing system performance by implementing new designs and technologies to reduce load at risk;
Upgrading system conditions that enhance reliability; and
Transmission projects awarded through the PJM Open Window to address regional expansion projects, including incremental opportunities in the 2026 Open Window, for which the planning period was recently opened.
Base distribution projects to address aging infrastructure.
Generation maintenance projects that maintain operations of fossil electric generation facilities and remain compliant with environmental regulations through the end of their useful life.

FirstEnergy believes there is a continued long-term pipeline of investment opportunities for its existing distribution and transmission infrastructure beyond those opportunities identified through 2030, which are expected to strengthen the grid and cyber security and make the transmission system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility.

Finance

FirstEnergy aims to execute its Energize365 investment plan through a strengthened financial position. Energize365 capital investments included in the current five-year plan are expected to be funded with a combination of organic cash flows and the issuance of debt, including hybrid securities. Additionally, FirstEnergy may issue its common equity to fund capital expenditures

in its 2026 through 2030 planning period averaging approximately 1% of its now current market capitalization in each year of the planning period, subject to market conditions and other factors. FirstEnergy believes it has optimized its financing plan to retain flexibility in an uncertain interest rate environment.

On March 30, 2026, Moody’s revised FE’s outlook to positive from stable. Moody’s also affirmed FE’s ratings, including its Baa3 Issuer and senior unsecured ratings.

Dividend Growth

FirstEnergy continues to return value to shareholders. In February 2026, the FE Board declared a $0.02 per share increase to the quarterly cash common stock dividend to $0.465 per share payable June 1, 2026, which represents a 4.5% increase compared to dividends declared in 2025. Modest dividend growth is expected to enable enhanced shareholder returns, while still allowing for continued substantial regulated investments. Dividend payments are subject to declaration by the FE Board, and future dividend decisions determined by the FE Board may be impacted by earnings, cash flows, credit metrics and general economic and other business conditions.

PJM RTEP Long-Term Proposal Window Projects

On February 21, 2025, FET, DominionHV and Transource entered into the Valley Link Operating Agreement, which established the general framework for Valley Link and the Valley Link Subsidiaries to accept, design, develop, construct, own, operate and finance those transmission projects awarded by PJM to Valley Link. This general framework includes parameters regarding the relationship among the three members, confers governance rights to its members so long as certain ownership percentages are maintained, as described below, and defines the list of projects that Valley Link will have the right to develop. Valley Link is the owner of the Valley Link Subsidiaries, which are organized in various states. On February 26, 2025, in response to the PJM 2024 RTEP Long-Term Proposal Window #1, PJM awarded two electric transmission projects to Valley Link estimated to be approximately $3 billion, with FET’s share estimated to be approximately $1 billion.

On February 13, 2026, FET and Transource entered into the Grid Growth Operating Agreement, which established the general framework for Grid Growth to accept, design, develop, construct, own, operate and finance certain transmission projects awarded by PJM to certain of the subsidiaries of Grid Growth. This general framework includes parameters regarding the relationship among the two members, confers governance rights to its members so long as certain ownership percentages are maintained and defines the list of projects that Grid Growth will have the right to develop. The relative ownership interests of the members under the Grid Growth Operating Agreement are 50% for each of FET and Transource. Grid Growth is the sole owner of Grid Growth Ohio and owns an 80% interest in Grid Growth EHV, with Transource owning the remaining interest. On February 12, 2026, in response to the PJM 2025 RTEP Long-Term Proposal Window #1, PJM awarded a project to Grid Growth estimated to be approximately $1 billion, with FET’s share estimated to be approximately $448 million.

Regulatory Matters - Ohio

On April 5, 2023, the Ohio Companies sought approval from the PUCO for their ESP V. The proposed plan would maintain an eight-year term beginning June 1, 2024, and continue riders recovering costs associated with distribution infrastructure investments and approved grid modernization investments. ESP V additionally proposed new riders that would support reliability, and included provisions supporting affordability and enhancing the customer experience. As more fully described in “Outlook - State Regulation - Ohio,” in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations," on October 29, 2024, the Ohio Companies filed a notice of their intent to withdraw ESP V and proposed the terms under which they would resume operating under ESP IV, which was approved by the PUCO on December 18, 2024. On January 22, 2025, the PUCO approved the Ohio Companies’ ESP IV compliance tariffs with an effective date of February 1, 2025, at which point the Ohio Companies resumed operating under ESP IV with certain modifications, as described in “Outlook - State Regulation - Ohio,” in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations". The Ohio Companies’ return to ESP IV was appealed by certain intervenors and the matter remains pending before the Supreme Court of Ohio.

On May 31, 2024, the Ohio Companies filed their application for an increase in base distribution rates based on a 2024 calendar year test period. On January 27, 2025, the Ohio Companies notified the PUCO of their intention to update their application for an increase in base distribution rates to remove ESP V related provisions from the base rate case. On November 19, 2025, the PUCO issued an order in the rate case. On November 26, 2025, the Ohio Companies filed proposed compliance tariffs. On December 19, 2025, the Ohio Companies and other parties filed applications for rehearing and on December 29, 2025, the Ohio Companies filed a memorandum against intervenors’ applications for rehearing. On January 7, 2026, the PUCO issued an entry granting rehearing in order to determine whether its November 19, 2025 base rate case opinion and order should be affirmed, abrogated, or modified on rehearing. On January 9, 2026, the Ohio Companies filed an expedited motion for ruling on the proposed compliance tariffs and on February 4, 2026, PUCO staff issued a letter recommending that most of the Ohio Companies’ proposed compliance tariffs be approved. The Ohio Companies cannot predict the outcome of the rehearing, but do not expect material changes to the November 2025 order. See “Outlook - State Regulation - Ohio,” in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations".

On April 22, 2026, the Ohio Companies submitted the required pre-filing notice to the PUCO of their intent to file a Three-Year Rate Plan with the PUCO in May 2026 that includes plans to invest on average $800 million annually to focus on improving reliability for customers. New rates are expected to become effective in mid-2027.

Regulatory Matters - West Virginia

On October 1, 2025, MP and PE filed their integrated resource plan with the WVPSC. To ensure that MP and PE can meet their PJM adequacy requirements, the plan proposes, among other things, near-term market capacity purchases and the addition of 70 MWs of solar generation by 2028 and 1,200 MWs of natural gas combined cycle generation by 2031. On November 26, 2025, the WVPSC issued a procedural order setting a hearing for May 2026.

MP and PE anticipate filing a base rate distribution case with the WVPSC in the second quarter of 2026, with new rates expected to become effective in the first quarter of 2027.

Regulatory Matters - Maryland

PE anticipates filing a base rate distribution case with the MDPSC in the second half of 2026, with new rates expected to become effective in the first quarter of 2027.

FIRSTENERGY’S CONSOLIDATED RESULTS OF OPERATIONS

First Three Months of 2026 Compared with First Three Months of 2025


(In millions)	For the Three Months Ended March 31,
	2026		2025		Increase

Revenues	$	4,202	$	3,765	$	437	12	%

Operating expenses	(3,374)		(3,011)		363		12	%

Other expenses, net	(224)		(214)		10		5	%

Income taxes	(138)		(126)		12		10	%

Income attributable to noncontrolling interest	(61)		(54)		7		13	%

Earnings attributable to FE	$	405	$	360	$	45	13	%

Earnings attributable to FE were $405 million or $0.70 per share (basic and diluted) in the first three months of 2026 compared to $360 million or $0.62 per share (basic and diluted) in the first three months of 2025, representing an increase of $45 million that was primarily due to the following:

Higher transmission revenues from regulated capital investments that increased rate base;
Higher customer usage and demand due to the colder weather temperatures;
The absence of customer credits associated with the PUCO-approved Ohio Stipulation in 2025;
The absence of severance and related costs associated with FirstEnergy’s organizational changes announced in the first quarter of 2025;
Lower other operating expenses, including vegetation management work that was accelerated in 2025; and
Higher net periodic pension and OPEB credits.

These factors were partially offset by the following:

Higher investigation and other related costs associated with the ongoing government investigations and litigation;
Higher non-deferred storm restoration costs; and
Higher interest expenses from long-term debt issuances since the first quarter of 2025.

Detailed segment reporting explanations are included below.

Distribution services by customer class are summarized in the following table:


	For the Three Months Ended March 31,
(In thousands)	Actual				Weather-Adjusted
Electric Distribution MWh Deliveries	2026	2025	Increase		2026	2025	Increase (Decrease)

Residential	15,596	15,491	0.7	%	15,364	15,384	(0.1)	%
Commercial(1)	10,118	9,844	2.8	%	9,997	9,858	1.4	%
Industrial	12,899	12,837	0.5	%	12,899	12,837	0.5	%

Total Electric Distribution MWh Deliveries	38,613	38,172	1.2	%	38,260	38,079	0.5	%

(1) Includes street lighting.

Actual distribution deliveries in the first quarter of 2026 for the residential and commercial customer classes were higher than the same period of 2025 due to the impact of colder weather temperatures. Heating degree days in the first three months of 2026 were 2% above the same period of 2025 and 3% above normal.

The financial results discussed below in Segment Results of Operations include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 10., “Segment Information,” of the Combined Notes to Financial Statements of the Registrants.

Summary of Results of Operations — First Three Months of 2026 Compared with First Three Months of 2025

Financial results for FirstEnergy’s business segments for the first three months of 2026 and 2025 were as follows:


First Three Months 2026 Financial Results (In millions)	Distribution		Integrated		Stand-Alone Transmission		Corporate/Other and Reconciling Adjustments		FirstEnergy Consolidated
Revenues:
Electric	$	1,950	$	1,542	$	509	$	10	$	4,011
Other	40		161		7		(17)		191
Total Revenues	1,990		1,703		516		(7)		4,202

Operating Expenses:
Fuel	—		161		—		—		161
Purchased power	762		663		—		4		1,429
Other operating expenses	716		672		79		(7)		1,460
Provision for depreciation	165		139		97		20		421
Amortization (deferral) of regulatory assets, net	(254)		(205)		2		—		(457)
General taxes	223		40		83		14		360
Total Operating Expenses	1,612		1,470		261		31		3,374



Other Income (Expense):


Miscellaneous income (expense), net	29		26		3		(10)		48

Interest expense	(107)		(78)		(85)		(56)		(326)
Capitalized financing costs	10		18		25		1		54
Total Other Expense	(68)		(34)		(57)		(65)		(224)


Income taxes (benefits)	64		46		46		(18)		138





Income attributable to noncontrolling interest	—		—		61		—		61



Earnings (Loss) Attributable to FE	$	246	$	153	$	91	$	(85)	$	405


First Three Months 2025 Financial Results (In millions)	Distribution		Integrated		Stand-Alone Transmission		Corporate/Other and Reconciling Adjustments		FirstEnergy Consolidated
Revenues:

Electric	$	1,896	$	1,333	$	486	$	4	$	3,719
Other	40		16		5		(15)		46

Total Revenues	1,936		1,349		491		(11)		3,765

Operating Expenses:
Fuel	—		149		—		—		149
Purchased power	610		472		—		6		1,088
Other operating expenses	627		337		98		(28)		1,034
Provision for depreciation	162		138		91		20		411
Amortization (deferral) of regulatory assets, net	(19)		8		1		—		(10)
General taxes	210		37		74		18		339
Total Operating Expenses	1,590		1,141		264		16		3,011



Other Income (Expense):


Miscellaneous income (expense), net	26		18		4		(12)		36

Interest expense	(99)		(65)		(73)		(51)		(288)
Capitalized financing costs	5		15		17		1		38
Total Other Expense	(68)		(32)		(52)		(62)		(214)


Income taxes (benefits)	60		40		40		(14)		126




Income attributable to noncontrolling interest	—		—		54		—		54

Earnings (Loss) Attributable to FE	$	218	$	136	$	81	$	(75)	$	360


Changes Between First Three Months 2026 and First Three Months 2025 Financial Results (In millions)	Distribution		Integrated		Stand-Alone Transmission		Corporate/Other and Reconciling Adjustments		FirstEnergy Consolidated
Revenues:

Electric	$	54	$	209	$	23	$	6	$	292
Other	—		145		2		(2)		145

Total Revenues	54		354		25		4		437

Operating Expenses:
Fuel	—		12		—		—		12
Purchased power	152		191		—		(2)		341
Other operating expenses	89		335		(19)		21		426
Provision for depreciation	3		1		6		—		10
Amortization (deferral) of regulatory assets, net	(235)		(213)		1		—		(447)
General taxes	13		3		9		(4)		21
Total Operating Expenses	22		329		(3)		15		363



Other Income (Expense):


Miscellaneous income (expense), net	3		8		(1)		2		12

Interest expense	(8)		(13)		(12)		(5)		(38)
Capitalized financing costs	5		3		8		—		16
Total Other Expense	—		(2)		(5)		(3)		(10)


Income taxes (benefits)	4		6		6		(4)		12





Income attributable to noncontrolling interest	—		—		7		—		7

Earnings (Loss) Attributable to FE	$	28	$	17	$	10	$	(10)	$	45

Distribution Segment — First Three Months of 2026 Compared with First Three Months of 2025

Distribution segment’s earnings attributable to FE increased $28 million in the first three months of 2026, as compared to the same period of 2025, primarily due to the absence of severance and related costs in the first quarter of 2025, lower other operating expenses and the absence of customer credits associated with the PUCO-approved Ohio Stipulation.

Revenues —

Distribution segment’s total revenues increased $54 million as a result of the following sources:


	For the Three Months Ended March 31,
Revenues by Type of Service	2026		2025		Increase (Decrease)
	(In millions)
Distribution services	$	1,091	$	1,179	$	(88)
Generation sales:
Retail	855		716		139
Wholesale	4		1		3
Total generation sales	859		717		142




Other	40		40		—
Total Revenues	$	1,990	$	1,936	$	54

Distribution services revenues decreased $88 million in the first three months of 2026, as compared to the same period of 2025, primarily due to customer restitution and refunds resulting from the Ohio Companies’ PUCO-approved settlement. These restitution and refunds were recognized in the fourth quarter of 2025 and are offset by the amortization of a regulatory liability resulting in no impact to earnings in the first quarter of 2026. The revenue decrease was partially offset by higher rider revenues associated with certain regulated investment programs and the absence of customer credits associated with the PUCO-approved Ohio Stipulation. Additionally, revenues increased due to the higher recovery of transmission expenses, which have no material impact to earnings.

Generation sales revenues increased $142 million in the first three months of 2026, as compared to the same period in 2025, primarily due to higher non-shopping generation auction rates, higher retail generation sales volumes as a result of weather temperatures, and lower shopping, which increased sales volumes. Total generation provided by alternative suppliers as a percentage of total MWh deliveries for the Ohio Companies and FE PA decreased to 87% from 88% in Ohio and to 59% from 60% in Pennsylvania in the first three months of 2026, as compared to the same period of 2025. Retail and wholesale generation sales revenue have no material impact to earnings.

Operating Expenses —

Total operating expenses increased $22 million, primarily due to:

Purchased power costs, which have no material impact to earnings, increased $152 million during the first three months of 2026, as compared to the same period of 2025, primarily due to higher unit costs and generation sales volumes as described above.
Other operating expenses increased $89 million in the first three months of 2026, as compared to the same period of 2025, primarily due to:
Higher network transmission expenses of $28 million, which are deferred for future recovery, resulting in no material impact to earnings;
Higher energy efficiency and other state mandated program costs of $22 million, which were deferred for future recovery, resulting in no material impact to earnings; and
Higher storm restoration expenses of $72 million, which were mostly deferred for future recovery.

The increase was partially offset by:

Lower planned vegetation management expenses of $13 million, primarily due to accelerated work in 2025 in Pennsylvania;
Lower uncollectible expenses of $2 million;
The absence of $13 million of severance and related costs associated with FirstEnergy’s organizational changes announced in the first quarter of 2025; and
Lower other operating expense of $5 million, primarily due to lower other employee benefit costs and increased construction support and lower maintenance work, partially offset by higher contractor expenses.
Depreciation expense increased $3 million in the first three months of 2026, as compared to the same period of 2025, primarily due to a higher asset base, partially offset by a change in depreciation rates effective March 1, 2026 as a result of the Ohio Base Rate Case.
Deferral of regulatory assets increased $235 million in the first three months of 2026, as compared to the same period of 2025, primarily due to higher deferred storm restoration expenses of $72 million, a $158 million increase in the amortization of a regulatory liability as a result of providing restitution and refunds to Ohio customers and a $28 million net increase in generation and transmission deferrals, partially offset by a $2 million increase in amortization associated with recovery of previously incurred storm costs in Ohio and a $21 million net decrease in other deferrals.
General taxes increased $13 million in the first three months of 2026, as compared to the same period of 2025, primarily due to higher property and gross receipts taxes.

Other Expense —

Other expense was flat in the first three months of 2026, as compared to the same period of 2025, primarily due to higher interest expense as a result of new debt issuances since the first quarter of 2025, partially offset by higher capitalized interest and higher pension and OPEB non-service credits.

Income Taxes —

Distribution segment’s effective tax rate was 20.6% and 21.6% for the three months ended March 31, 2026 and 2025, respectively.

Integrated Segment — First Three Months of 2026 Compared with First Three Months of 2025

Integrated segment’s earnings attributable to FE increased $17 million in the first three months of 2026, as compared to the same period of 2025, primarily due to the absence of severance and related costs in the first quarter of 2025, higher transmission revenues from regulated capital investments that increased rate base, higher revenues associated with certain investment programs, and increased customer usage and demand, partially offset by higher non-deferred storm restoration costs.

Revenues —

Integrated segment’s total revenues increased $354 million as a result of the following sources:


	For the Three Months Ended March 31,
Revenues by Type of Service	2026		2025		Increase
	(In millions)
Distribution services (1)	$	444	$	431	$	13
Generation sales:
Retail	867		755		112
Wholesale	112		47		65
Total generation sales	979		802		177
Transmission revenues:



JCP&L	71		61		10
MP & PE	48		39		9
Total transmission revenues	119		100		19
Other	161		16		145
Total Revenues	$	1,703	$	1,349	$	354

(1) Includes $13 million of ARP revenues in 2026, related to lost distribution revenues associated with energy efficiency in New Jersey.

Distribution services revenues increased $13 million in the first three months of 2026, as compared to the same period of 2025, primarily resulting from higher customer usage as a result of the colder weather temperatures and higher rider revenues associated with certain regulated investment programs. Additionally, revenues increased due to the higher recovery of transmission expenses, which have no material impact to earnings.

Generation sales revenues increased $177 million in the first three months of 2026, as compared to the same period of 2025.

Retail generation sales increased $112 million in the first three months of 2026, as compared to the same period in 2025, primarily due to higher non-shopping generation auction rates and higher volumes as a result of the colder weather temperatures. Retail generation sales, other than those in West Virginia, have no material impact to earnings.
Wholesale generation revenues increased $65 million in the first three months of 2026, as compared to the same period in 2025, primarily due to higher wholesale rates and capacity revenues, partially offset by lower sales volumes. The difference between current wholesale generation revenues and certain energy costs incurred is deferred for future recovery or refund, with no material impact to earnings.

Transmission revenues increased $19 million in the first three months of 2026, as compared to the same period of 2025, primarily due to higher recovery of transmission operating expenses and higher rate base from regulated investment programs.

Other revenues increased $145 million in the first three months of 2026, as compared to the same period of 2025, primarily due to higher FTR credits, which offset higher transmission congestion charges. Due to the ENEC, FTRs have no material impact to earnings.

Operating Expenses —

Total operating expenses increased $329 million, primarily due to:

Fuel costs increased $12 million during the first three months of 2026, as compared to the same period of 2025, primarily due to higher unit costs, partially offset by lower consumption volumes. Due to the ENEC, fuel expense has no material impact to earnings.
Purchased power costs, which have no material impact to earnings, increased $191 million during the first three months of 2026, as compared to the same period of 2025, primarily due to higher volumes, capacity expenses and prices, which were impacted by the Winter Storm Fern weather event.
Other operating expenses increased $335 million in the first three months of 2026, as compared to the same period of 2025, primarily due to:
Higher network transmission expenses of $25 million, which were deferred for future recovery, resulting in no material impact to earnings;
Higher transmission congestion charges of $221 million, primarily from the net impacts of the Winter Storm Fern weather event. Due to the ENEC, congestion charges, net of FTR revenue, have no material impact to earnings;
Higher storm restoration expenses of $77 million, of which $71 million were deferred for future recovery;
Higher formula rate transmission operating and maintenance expenses of $2 million, which have no material impact to earnings;
Higher vegetation management expenses of $5 million, which were mostly deferred for future recovery, resulting in no material impact to earnings; and
Higher energy efficiency and other state mandated program costs of $16 million, which were deferred for future recovery, resulting in no material impact to earnings.

The increase was partially offset by:

The absence of $10 million of severance and related costs associated with FirstEnergy’s organizational changes announced in the first quarter of 2025.
Deferral of regulatory assets increased $213 million in the first three months of 2026, as compared to the same period of 2025, primarily due to $71 million in higher deferral of storm related expenses and a $146 million net increase from higher generation and transmission related deferrals, partially offset by $4 million related to net decreases in other deferrals.
General taxes increased $3 million in the first three months of 2026, as compared to the same period of 2025, primarily due to higher property taxes.

Other Expense —

Other expense increased $2 million in the first three months of 2026, as compared to the same period of 2025, primarily due to higher interest expense as a result of new debt issuances since the first quarter 2025, partially offset by higher capitalized interest and higher pension and OPEB non-service credits.

Income Taxes —

Integrated segment’s effective tax rate was 23.1% and 22.7% for the three months ended March 31, 2026 and 2025, respectively.

Stand-Alone Transmission Segment — First Three Months of 2026 Compared with First Three Months of 2025

Stand-Alone Transmission segment’s earnings attributable to FE increased $10 million in the first three months of 2026, as compared to the same period of 2025, primarily due to higher revenues from regulated capital investments that increased rate base and higher capitalized financing costs, partially offset by higher interest expenses from new long-term debt issuances.

Revenues —

Stand-Alone Transmission’s total revenues increased $25 million, primarily due to a higher overall rate base, partially offset by lower recovery of transmission operating expenses.

The following table shows revenues by transmission asset owner:


	For the Three Months Ended March 31,
Revenues by Transmission Asset Owner	2026		2025		Increase (Decrease)
	(In millions)
ATSI	$	286	$	265	$	21
TrAIL	67		71		(4)
MAIT	139		132		7
KATCo	24		23		1

Total Revenues	$	516	$	491	$	25

Operating Expenses —

Total operating expenses decreased $3 million in the first three months of 2026, as compared to the same period of 2025, primarily due to lower operating and maintenance expenses, partially offset by higher depreciation and property tax expenses from a higher asset base. Nearly all operating expenses are recovered through formula rates.

Other Expense —

Total other expense increased $5 million in the first three months of 2026, as compared to the same period of 2025, primarily due to higher interest expenses from new long-term debt issuances, partially offset by higher capitalized financing costs.

Income Taxes —

Stand-Alone Transmission’s effective tax rate was 23.2% and 22.9% for the three months ended March 31, 2026 and 2025, respectively.

Corporate / Other — First Three Months of 2026 Compared with First Three Months of 2025

Financial results at Corporate/Other resulted in a $10 million increase in losses attributable to FE in the first three months of 2026, as compared to the same period of 2025, primarily due to:

$11 million (after-tax) of higher investigation and other related costs associated with the ongoing government investigations and ongoing litigation; and
$4 million (after-tax) of higher interest expense as a result of the issuance of the 2029 Convertible Notes and 2031 Convertible Notes, partially offset by the redemption of a portion of the 2026 Convertible Notes.

The increase in losses were partially offset by:

$4 million (after-tax) of higher income associated with a legacy purchase power contract.

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. The Registrants 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.

FirstEnergy has regulatory assets of $1,092 million and $829 million, and regulatory liabilities of $877 million and $1,185 million as of March 31, 2026 and December 31, 2025, respectively. The following table provides information about the composition of FirstEnergy’s net regulatory assets and liabilities as of March 31, 2026 and December 31, 2025, and the changes during the three months ended March 31, 2026:


Net Regulatory Assets (Liabilities) by Source - FirstEnergy	March 31, 2026		December 31, 2025		Change
	(In millions)
Customer payables for future income taxes	$	(2,006)	$	(2,041)	$	35
Spent nuclear fuel disposal costs	(72)		(76)		4
Asset removal costs	(606)		(675)		69
Deferred transmission costs	(65)		(43)		(22)
Deferred generation costs	558		405		153
Deferred distribution costs	479		466		13
Storm-related costs	1,271		1,122		149
Energy efficiency program costs	500		462		38
New Jersey societal benefit costs	66		80		(14)
Vegetation management costs	148		153		(5)
Ohio settlement charges	(102)		(250)		148
Other	44		41		3
Net Regulatory Assets (Liabilities) included on FirstEnergy’s Consolidated Balance Sheets	$	215	$	(356)	$	571

The following table provides information about the composition of JCP&L’s net regulatory assets and liabilities as of March 31, 2026 and December 31, 2025, and the changes during the three months ended March 31, 2026:


Net Regulatory Assets (Liabilities) by Source - JCP&L	March 31, 2026		December 31, 2025		Change
	(In millions)
Customer payables for future income taxes	$	(390)	$	(393)	$	3
Spent nuclear fuel disposal costs	(72)		(76)		4
Asset removal costs	(71)		(87)		16
Deferred transmission costs	(33)		(25)		(8)

Deferred distribution costs	309		318		(9)
Storm-related costs	437		367		70
Energy efficiency program costs	374		316		58
New Jersey societal benefit costs	66		80		(14)

Other	45		15		30
Net Regulatory Assets included on JCP&L’s Balance Sheets	$	665	$	515	$	150

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 TCJA 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 generation facilities, Oyster Creek and Three Mile Island Unit 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. Also included is the recovery of non-market based costs or fees charged to certain of the Electric Companies 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), the Warrior Run purchased power agreement termination fee at PE (amortized through 2029), and 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) and JCP&L’s AMI program costs.

Storm-related costs - Relates to the deferral of storm costs, which vary by jurisdiction. Approximately $659 million and $80 million for FirstEnergy and JCP&L, respectively, are currently being recovered through rates as of March 31, 2026. Approximately $335 million and $73 million for FirstEnergy and JCP&L, respectively, and were currently being recovered through rates as of December 31, 2025.

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, FE PA's 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, certain distribution and transmission vegetation management costs in West Virginia, and certain transmission vegetation management costs at ATSI (amortized through 2030) and KATCo (amortized through 2036).

Ohio settlement charges - Reflects restitution and refunds owed to customers associated with the Ohio Companies' PUCO-approved settlement order, which began to be provided to customers in February 2026. See Note 8., "Regulatory Matters," of the Combined Notes to Financial Statements of the Registrants for additional details.

The following table provides information about the composition of FirstEnergy’s net regulatory assets that do not earn a current return as of March 31, 2026 and December 31, 2025, of which approximately $943 million and $802 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral and the jurisdiction:


Regulatory Assets by Source Not Earning a Current Return - FirstEnergy	March 31, 2026		December 31, 2025		Change
	(In millions)

Deferred generation costs	$	423	$	280	$	143
Deferred distribution costs	181		199		(18)
Storm-related costs	952		844		108

Other	87		102		(15)
FirstEnergy Regulatory Assets Not Earning a Current Return	$	1,643	$	1,425	$	218

The following table provides information about the composition of JCP&L’s net regulatory assets that do not earn a current return as of March 31, 2026 and December 31, 2025, of which approximately $83 million and $76 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral:


Regulatory Assets by Source Not Earning a Current Return - JCP&L	March 31, 2026		December 31, 2025		Change
	(In millions)


Deferred distribution costs	$	130	$	147	$	(17)
Storm-related costs	437		367		70

Other	24		24		—
JCP&L Regulatory Assets Not Earning a Current Return	$	591	$	538	$	53

CAPITAL RESOURCES AND LIQUIDITY

The Registrants’ businesses are 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 the pension plan.

The Registrants 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 the remainder of 2026 and beyond, the Registrants 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 the Registrants, which may include hybrid securities by FE 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. Additionally, FE may issue its common equity to fund capital expenditures in its 2026 through 2030 planning period averaging approximately 1% of its now current market capitalization in each year of the planning period, subject to market conditions and other factors.

In alignment with FirstEnergy’s strategy to invest in its 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 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 subsidiaries to utilize short-term borrowing capacity, which could impact available liquidity. In addition, FE and its subsidiaries expect to continually evaluate any planned financings, which may result in changes from time to time.

FirstEnergy continues to monitor supply lead times in light of demand increases across the industry, including due to data center usage, and the imposition of tariffs and retaliatory tariffs that have been, and may be, imposed by the U.S. government in response. In addition, ongoing geopolitical conflicts have contributed to volatility in global energy markets and fuel and transportation costs, which may further impact supply availability or pricing. FirstEnergy continues to implement mitigation strategies to address volatility in interest rates, inflation and supply constraints and does not expect any corresponding service disruptions or any material impact on its capital investment plan. However, a prolonged continuation or further increase in demand, sustained or escalating geopolitical tensions, rising fuel costs or the continuation of uncertain or adverse macroeconomic conditions, including inflationary pressures and new or increased existing tariffs, could lead to an increase in supply chain disruptions that could, in turn, have an adverse effect on the Registrants’ results of operations, cash flow and financial condition.

As of March 31, 2026, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was approximately $2.8 billion, primarily due to current portion of long-term debt, accounts payable, short-term borrowings 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. See further discussion on cash from operations below.

As of March 31, 2026, JCP&L’s net deficit in working capital (current assets less current liabilities) was approximately $372 million, primarily due to accounts payable, short-term borrowings, accrued interest, and compensation and benefits. JCP&L believes its cash from operations and available liquidity will be sufficient to meet its current working capital needs. See further discussion on cash from operations below.

Short-Term Borrowings / Revolving Credit Facilities

On October 27, 2025, FE, the Electric Companies, Transmission Companies, and FET, each entered into an amended credit facility to, among other things: (i) remove the 10 basis point credit spread adjustment from the interest rate calculation; (ii) permit a one-week interest period for any Term Benchmark Advance (as defined under each of the Amended Credit Facilities) based upon daily simple SOFR; and (iii) extend the maturity date of each credit facility for an additional one-year period (a) from October 20, 2028 to October 20, 2029 for the KATCo credit facility, (b) from October 20, 2029 to October 20, 2030 for the FET credit facility and (c) from October 18, 2028 to October 18, 2029 for the remaining Amended Credit Facilities.

Borrowings under each of the Amended 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 Amended Credit Facilities contains 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 Amended Credit Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. FE is required under its 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.

Each of the Amended Credit Facilities bears interest at fluctuating interest rates, primarily based on SOFR, including term SOFR and daily simple SOFR. 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 SOFR and other variable interest rates. 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 $1,305 million and $325 million of outstanding short-term borrowings as of March 31, 2026, and December 31, 2025, respectively. FirstEnergy’s available liquidity from external sources as of April 27, 2026, was as follows**:**


Revolving Credit Facilities	Maturity	Commitment		Available Liquidity
		(In millions)
FE	October 2029	$	1,000	$	747
FET	October 2030	1,000		680
Ohio Companies	October 2029	800		423
FE PA	October 2029	950		699
JCP&L	October 2029	750		600
MP and PE	October 2029	400		214
ATSI, MAIT and TrAIL	October 2029	850		849
KATCo	October 2029	150		150
	Subtotal	$	5,900	$	4,362
Cash and cash equivalents		—		47
	Total	$	5,900	$	4,409

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 March 31, 2026:


Individual Borrower	Regulatory Debt Limitations			Credit Facility Commitment			Debt-to-Total-Capitalization Ratio
	(In millions)
FE		N/A			$	1,000		N/A(2)
ATSI(1)		$	500		350			39.7	%
CEI(1)		750			300			46.2	%
FET		N/A			1,000			65.5	%
FE PA(1)		1,250			950			48.9	%
JCP&L(1)		1,500			750			39.5	%
KATCo(1)		200			150			28.8	%
MAIT(1)		400			350			35.8	%
MP(1)		900			250			49.6	%
OE(1)		500			300			54.9	%
PE(1)		450			150			46.7	%
TE(1)		300			200			52.7	%
TrAIL(1)		400			150			39.2	%

(1) Regulatory debt limitations include amounts which may be borrowed under the regulated companies’ money pool.

(2) FE is not required to maintain a debt-to-total-capitalization ratio under its credit facility. However, FE is required 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. FE's consolidated interest coverage ratio as of March 31, 2026, was approximately 4.3 times.

Subject to each borrower’s sublimit, the amounts noted below are available for the issuance of LOCs (subject to borrowings drawn under the Amended 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 Amended Credit Facilities and against the applicable borrower’s borrowing sublimit. As of March 31, 2026, FirstEnergy had $238 million in outstanding LOCs, $103 million of which are issued under the Amended Credit Facilities.


Revolving Credit Facility	LOC Availability as of March 31, 2026		LOC Utilized as of March 31, 2026
	(In millions)
FE	$	100	$	3
FET	100		—
Ohio Companies	150		27
FE PA	200		1
JCP&L	100		—
MP and PE	100		71
ATSI, MAIT and TrAIL	200		1
KATCo	35		—

Each of the Amended 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 Amended Credit Facilities are related to the credit ratings of the company borrowing the funds. Additionally, borrowings under each of the 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 March 31, 2026, FE was in compliance with its applicable consolidated interest coverage ratio and the Electric Companies, the Transmission Companies, and FET were each in compliance with their debt-to-total-capitalization ratio covenants under each of their Amended Credit Facilities.

FirstEnergy Money Pools

FirstEnergy’s regulated 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.


Average Interest Rates	Regulated Companies’ Money Pool				Unregulated Companies’ Money Pool
	2026		2025		2026		2025
For the Three Months Ended March 31,	4.22	%	4.93	%	3.97	%	5.44	%

Long-Term Debt Capacity

FE 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 and its subsidiaries’ credit ratings as of April 27, 2026:


	Corporate Credit Rating			Senior Secured			Senior Unsecured			Outlook/Credit/Watch(1)
Issuer	S&P	Moody’s	Fitch	S&P	Moody’s	Fitch	S&P	Moody’s	Fitch	S&P	Moody’s	Fitch
FE	BBB+	Baa3	BBB	—	—	—	BBB	Baa3	BBB	S	P	S

Distribution:
CEI	BBB+	Baa3	BBB+	—	—	—	BBB+	Baa3	A-	S	S	P
OE	A-	A3	BBB+	A	A1	A	A-	A3	A-	S	S	P
TE	BBB+	Baa2	BBB+	A	A3	A	—	—	—	S	S	P
FE PA	A-	A3	A-	A	A1	—	A-	A3	A	S	S	S

Integrated:
JCP&L	BBB+	A3	A-	—	—	—	BBB+	A3	A	S	S	S
MP	BBB	Baa2	A-	A-	A3	A+	—	Baa2	—	P	S	S
AGC	BBB-	Baa2	A-	—	—	—	—	—	—	S	S	S
PE	BBB	Baa2	BBB+	A-	A3	A	—	—	—	P	S	S

Stand-Alone Transmission:
FET	A	Baa2	BBB+	—	—	—	A-	Baa2	BBB+	S	S	S
ATSI	A	A3	A	—	—	—	A	A3	A+	S	S	S
MAIT	A	A3	A	—	—	—	A	A3	A+	S	S	S
TrAIL	A	A3	A	—	—	—	A	A3	A+	S	S	S
KATCo	—	A3	A-	—	—	—	—	—	—	—	S	S

(1) S = Stable, P = Positive

On March 30, 2026, Moody’s revised FE’s outlook to positive from stable. Moody’s also affirmed FE’s ratings, including its Baa3 Issuer and senior unsecured ratings.

The applicable undrawn and drawn margin on the credit facilities are subject to ratings-based pricing grids. The applicable fee paid on the undrawn commitments and on actual borrowings under the credit facilities are based on FE’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 FE's credit facility. As of March 31, 2026, FirstEnergy could incur approximately $0.9 billion of incremental interest expense or incur a $2.3 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 requirements of FE's credit facility.

As of March 31, 2026, JCP&L could incur approximately $6.3 billion of additional debt or incur an approximate $3.4 billion reduction to equity, as defined under the debt to capital covenant, and JCP&L would remain within the limitations of the financial covenant requirements of JCP&L's credit facility.

Cash Requirements and Commitments

The Registrants have certain obligations and commitments to make future payments under contracts. For an in-depth discussion of the Registrants’ cash requirements and commitments, see “Capital Resources and Liquidity - Cash Requirements and Commitments" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" within the Registrants’ Form 10-K for the year ended December 31, 2025 (filed on February 18, 2026).

Changes in Cash Position

As of March 31, 2026, FirstEnergy had $52 million of cash and cash equivalents and $28 million of restricted cash as compared to $57 million of cash and cash equivalents and $42 million of restricted cash as of December 31, 2025, on the Consolidated Balance Sheets.

The following table summarizes the major classes of cash flow items:


	For the Three Months Ended March 31,
(In millions)	2026		2025		Change

Net cash provided from operating activities	$	148	$	637	$	(489)
Net cash used for investing activities	(1,372)		(1,093)		(279)
Net cash provided from financing activities	1,205		465		740
Net change in cash, cash equivalents, and restricted cash	(19)		9		(28)

Cash, cash equivalents, and restricted cash at beginning of period	99		154		(55)
Cash, cash equivalents, and restricted cash at end of period	$	80	$	163	$	(83)

Cash Flows From Operating Activities

FirstEnergy’s most significant sources of cash are derived from electric service provided by its operating subsidiaries. The most significant use of cash from operating activities is buying electricity to serve non-shopping customers, return of cash collateral associated with certain generation suppliers that serve 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 $148 million in the first three months of 2026, as compared to net cash provided from operating activities of $637 million in the first three months of 2025. The decrease in cash provided from operating activities in 2026, compared to the same period of 2025, is primarily due to:

Restitution and refunds returned to Ohio customers resulting from the PUCO-approved settlement, which began to be provided to customers in February 2026;
Higher storm restoration costs;
Higher transmission and purchased power costs, primarily from the net impacts of the Winter Storm Fern weather event in the first quarter of 2026;
Decreased working capital due to the timing of prepaid and accrued taxes and accrued interest, and higher employee benefit payments in the first quarter of 2026, as compared to the same period in 2025; and
Decreased cash collateral received from suppliers due to changes in power prices.

The decrease in cash provided from operating activities was partially offset by:

Increased customer usage and demand as a result of the colder weather temperatures;
Higher return on regulated capital investment programs; and
Temporary rate credits that were provided to JCP&L residential customers during the third quarter of 2025 that were recovered in the first quarter of 2026.

Cash Flows From Investing Activities

Net cash used for investing activities in the first three months of 2026 principally represented cash used for capital investments. The following table summarizes investing activities for the first three months of 2026 and 2025:


	For the Three Months Ended March 31,
Investing Activities	2026		2025		Change
	(In millions)
Capital investments:
Distribution Segment	$	364	$	265	$	99
Integrated Segment	476		395		81
Stand-Alone Transmission Segment	333		314		19
Corporate / Other	82		31		51

Asset removal costs	117		84		33
Other	—		4		(4)
	$	1,372	$	1,093	$	279

Net cash used for investing activities for the first three months of 2026 increased $279 million, compared to the same period of 2025, primarily due to capital investments.

Cash Flows From Financing Activities

In the first three months of 2026 and 2025, net cash provided from financing activities was $1,205 million and $465 million, respectively. The following table summarizes financing activities for the first three months of 2026 and 2025:


	For the Three Months Ended March 31,
Financing Activities	2026		2025		Change
	(In millions)

New Issues:

Senior unsecured notes	$	850	$	—	$	850



	$	850	$	—	$	850

Redemptions / Repayments:

Senior unsecured notes	$	(300)	$	(300)	$	—


Senior secured notes	(25)		(24)		(1)
	$	(325)	$	(324)	$	(1)


Short-term borrowings, net	$	980	$	1,085	$	(105)

Noncontrolling interest cash distributions	(25)		(24)		(1)


Common stock dividend payments	(257)		(245)		(12)
Debt issuance and redemption costs, and other	(18)		(27)		9
	$	1,205	$	465	$	740

FirstEnergy and JCP&L had the following issuances during the three months ended March 31, 2026:


Company	Type	Redemption / Issuance Date	Interest Rate	Maturity	Amount (In millions)	Description
Redemptions
FE PA	Senior Unsecured	March, 2026	5.15%	2026	$300	Redeemed unsecured notes that became due.










Issuances
FE PA	Senior Unsecured	March, 2026	4.15%	2028	$300	Proceeds are expected to be used to: (i) refinance existing indebtedness, including the repayment of FE PA's 5.15% senior notes due 2026, and short-term borrowings; (ii) to fund capital expenditures; (iii) to fund working capital; and (iv) to fund general corporate purposes.
FE PA	Senior Unsecured	March, 2026	4.55%	2031	$550	Proceeds are expected to be used to: (i) refinance existing indebtedness, including the repayment of FE PA's 5.15% senior notes due 2026, and short-term borrowings; (ii) to fund capital expenditures; (iii) to fund working capital; and (iv) to fund general corporate purposes.

On March 11, 2026, MAIT agreed to sell $250 million of new 5.02% Senior Unsecured Notes due May 1, 2036. The sale is expected to close on April 30, 2026. Proceeds are expected to be used to repay short-term borrowings, to finance capital expenditures, for working capital and for other general corporate purposes.

On April 21, 2026, ATSI issued $175 million of new 5.19% Senior Unsecured Notes due May 15, 2033. Proceeds are expected to be used to repay short-term borrowings, including short-term borrowings incurred to repay at maturity $75 million aggregate principal amount of ATSI’s 4.00% Senior Unsecured Notes due 2026, to finance capital expenditures, for working capital and for other general corporate purposes.

On April 28, 2026, FE entered into the FE Term Loan Facility with a maturity date of April 27, 2027, which was fully drawn upon execution. The FE Term Loan Facility contains covenants and other terms and conditions substantially similar to those applicable to FE under the Amended Credit Facilities, including the same requirement 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. Proceeds were used to repay short-term borrowings outstanding under the Amended Credit Facilities.

FE Convertible Notes Issuance

On May 4, 2023, FE issued $1.5 billion aggregate principal amount of 2026 Convertible Notes, at a rate of 4.00% per year, payable semiannually in arrears on May 1 and November 1 of each year, beginning on November 1, 2023. The 2026 Convertible Notes are unsecured and unsubordinated obligations of FE, and will mature on May 1, 2026, unless required to be converted or repurchased in accordance with their terms. Proceeds from the issuance were approximately $1.48 billion, net of issuance costs. FE may not elect to redeem the 2026 Convertible Notes prior to the maturity date.

In June 2025, FE repurchased approximately $1.2 billion aggregate principal amount of the 2026 Convertible Notes, using a portion of the proceeds from the offering of the 2029 Convertible Notes and 2031 Convertible Notes described below. The 2026 Convertible Notes are included within “Currently payable long-term debt” on the FirstEnergy Consolidated Balance Sheets.

Through the close of business on the second scheduled trading day immediately preceding the maturity date, holders of the 2026 Convertible Notes may convert all or any portion of their 2026 Convertible Notes at their option at any time at the conversion rate then in effect. FE will settle conversions of the 2026 Convertible Notes, if any, by paying cash for the aggregate principal amount of the 2026 Convertible Notes being converted and its conversion obligation in excess of such aggregate principal amount. Based on the FE common stock price and conversion price as of March 31, 2026, the cash settlement premium on the 2026 Convertible Notes would be approximately $27 million.

The amount of consideration that a holder will receive upon conversion will be determined by reference to the volume-weighted average price of FE’s common stock for each trading day in a 40 trading day observation period beginning on, and including, the 41st scheduled trading day immediately preceding the maturity date.

On June 12, 2025, FE issued $1.35 billion aggregate principal amount of its 2029 Convertible Notes, at a rate of 3.625% per year, and $1.15 billion aggregate principal amount of its 2031 Convertible Notes, at a rate of 3.875% per year, payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2026. The 2029 Convertible Notes and 2031 Convertible Notes are unsecured and unsubordinated obligations of FE and will mature on January 15, 2029 and January 15, 2031, respectively, unless earlier converted or repurchased in accordance with their terms.

The 2029 Convertible Notes and 2031 Convertible Notes are included within “Long-term debt and other long-term obligations” on the FirstEnergy Consolidated Balance Sheets. Proceeds from the issuance were approximately $2.47 billion, net of issuance costs.

For more information regarding the 2026 Convertible Notes, the 2029 Convertible Notes and 2031 Convertible Notes, including applicable conversion features, refer to Note 6., “Long Term Debt and Other Long-Term Liabilities – FE Convertible Notes Issuance.”

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.

JCP&L Senior Notes and Registration Rights

On September 4, 2025, JCP&L issued: (i) $350 million of senior unsecured notes due in 2029; (ii) $500 million of senior unsecured notes due in 2031; and (iii) $500 million of senior unsecured notes due in 2036, in a private offering that included registration rights agreements in which JCP&L agreed to conduct an exchange offer of these senior notes for the like principal amounts registered under the Securities Act. On April 9, 2026, JCP&L filed a registration statement on Form S-4 for the exchange offer with the SEC, which was declared effective on April 23, 2026.

FE PA Senior Notes and Registration Rights

On March 19, 2026, FE PA issued $300 million of 4.15% senior unsecured notes due in 2028 and $550 million of 4.55% senior unsecured notes due in 2031, in a private offering that included registration rights agreements in which FE PA agreed to conduct an exchange offer of these senior notes for the like principal amounts registered under the Securities Act within 366 days after the closing.

FIRSTENERGY - 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 March 31, 2026, outstanding guarantees and other assurances aggregated approximately $1.1 billion, consisting of parental guarantees on behalf of its consolidated subsidiaries ($618 million) and other assurances of ($491 million).

In 2025, FET, DominionHV and Transource issued an equity support agreement to enable Valley Link to enter into a credit facility with a third party. The equity support agreement expires once all Valley Link credit agreement obligations are satisfied or when FET has fulfilled its support obligations under the equity support agreement. As of March 31, 2026, the maximum exposure of FET’s support obligations relating to the Valley Link credit facility was $102 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 March 31, 2026, $238 million of collateral, in the form of LOCs, has been posted by FE or its subsidiaries. FE or its subsidiaries are holding $47 million of net cash collateral as of March 31, 2026, from certain generation suppliers, 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 March 31, 2026:


Potential Collateral Obligations	Electric Companies and Transmission Companies		FE		Total
	(In millions)
Contractual obligations for additional collateral

Upon downgrade	$	52	$	1	$	53

Surety bonds (collateralized amount)(1)	114		153		267
Total Exposure from Contractual Obligations	$	166	$	154	$	320

(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 $22 million of surety bond obligations for which the collateral obligation is capped at 60% of the face amount, and typical obligations require 30 days to cure.

JCP&L - GUARANTEES AND OTHER ASSURANCES

JCP&L has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include stand-by LOCs and surety bonds. JCP&L 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 JCP&L could be required to make under these guarantees as of March 31, 2026, was $48 million.

Collateral and Contingent-Related Features

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

JCP&L has posted $28 million of collateral in the form of LOCs as of March 31, 2026. JCP&L is holding $6 million of net cash collateral as of March 31, 2026, from certain generation suppliers, and such amount is included in "Other current liabilities" on JCP&L's Balance Sheets.

These credit-risk-related contingent features stipulate that if JCP&L 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 March 31, 2026:


Potential Collateral Obligations	JCP&L
	(In millions)
Contractual obligations for additional collateral

Upon downgrade	$	52

Surety bonds (collateralized amount)(1)	20
Total Exposure from Contractual Obligations	$	72

(1) Surety bonds are not tied to a credit rating, and their impact assumes maximum contractual obligations, which is 100% of the face amount of the surety bond, 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, including market risk.

Commodity Price Risk

FirstEnergy has limited exposure to financial risks resulting from fluctuating commodity prices, including prices for electricity, coal and energy transmission.

The valuation of derivative contracts is based on observable market information. As of March 31, 2026, FirstEnergy has a net asset of $3 million in non-hedge derivative contracts that are related to FTRs at certain of the Electric Companies. FTRs are subject to regulatory accounting and do not impact earnings.

Equity Price Risk

As of March 31, 2026, the FirstEnergy pension plan assets were allocated approximately as follows: 30% in equity securities, 19% in fixed income securities, 5% in alternatives, 9% in real estate, 24% in private debt/equity, 9% in derivatives and 4% in cash and short-term securities. FirstEnergy does not currently expect to have a required contribution to the pension plan until 2027, which, based on various assumptions, including an expected rate of return on assets of 8.0% for 2026, is expected to be approximately $250 million. However, FirstEnergy may elect to contribute to the pension plan voluntarily. JCP&L is not expected to make a contribution to the pension plan.

As of March 31, 2026, FirstEnergy’s OPEB plan assets were allocated approximately as follows: 57% in equity securities, 39% in fixed income securities and 4% in cash and short-term securities.

In the three months ended March 31, 2026, FirstEnergy’s pension plan assets have lost approximately 1.3% as compared to an annual expected return on plan assets of 8%. In the three months ended March 31, 2026, FirstEnergy’s qualified OPEB plan assets have lost approximately 0.2% as compared to an annual expected return on plan assets of 7%. FirstEnergy determines the annual expected return on plan asset assumption based on historical asset performance, target asset allocations and other economic indicators, including current market conditions and forward looking capital market expectations, among other factors. FirstEnergy periodically evaluates target asset allocations to support long-term funding and volatility mitigation objectives, which could impact future expected return on plan asset assumptions.

See Note 4., “Pension and Other Post-Employment Benefits,” of the Combined Notes to Financial Statements of the Registrants for additional details on FirstEnergy’s pension and OPEB plans.

Interest Rate Risk

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 (unless a remeasurement is triggered) and are recorded on a monthly basis. Changes in asset performance and discount rates will not impact these pension and OPEB costs for 2026, unless an additional remeasurement were to be triggered during the year, however, future years could be impacted by changes in the market.

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. As of March 31, 2026, the spot rate was 5.87% and 5.68% for pension and OPEB obligations, respectively, as compared to 5.59% and 5.37% as of December 31, 2025, respectively.

The final discount rate and return or loss on plan assets as of the year-end remeasurement date is difficult to predict based on the currently volatile equity markets and interest rate environment. As a result, FirstEnergy is unable to determine or meaningfully project the mark-to-market adjustment, or estimate a reasonable range of adjustment, that will be recorded as of December 31, 2026.

Economic Conditions

CREDIT RISK

Credit risk is the risk that the Registrants would incur a loss as a result of nonperformance by counterparties of their contractual obligations. The Registrants maintain 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. The Registrants have concentrations of suppliers and customers among electric utilities, financial institutions and energy marketing and trading companies. These concentrations may impact the Registrants’ 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, FE PA, JCP&L or PE defaults on its obligation, the affected company would be required to seek replacement power in the market. In general, subject to regulatory review or other processes, it is expected that appropriate incremental costs incurred by these entities would be recoverable from customers through applicable rate mechanisms, thereby mitigating the financial risk for these entities. The Registrants' credit policies to manage credit risk include the use of an established credit approval process and daily credit mitigation provisions, such as margin, prepayment or collateral requirements. FirstEnergy and its subsidiaries, including JCP&L, may request additional credit assurance, in certain circumstances, in the event that the counterparties' credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit.

OUTLOOK

INCOME TAXES

For federal income tax purposes, FirstEnergy files as a consolidated group, which includes JCP&L but excludes FET and its subsidiaries, and maintains an intercompany income tax allocation agreement for the allocation of consolidated tax liability, including corporate AMT. Subsequent to the closing of the FET Equity Interest Sale, FET and its subsidiaries file as their own consolidated group for federal income tax purposes and have their own intercompany income tax allocation agreement.

On February 18, 2026, the U.S. Treasury and IRS issued guidance that allows certain tax repair deductions in computing corporate AMT. As a result of this guidance, FirstEnergy reversed $18 million in corporate AMT credit carryforwards in the first quarter of 2026 related to corporate AMT incurred and paid in prior tax years by both the FirstEnergy consolidated tax group and the FET consolidated tax group, none of which had an impact to the effective tax rate. Both the FirstEnergy consolidated tax group and the FET consolidated tax group remain subject to the corporate AMT, but expect that this allowance for certain tax repair deductions will reduce future corporate AMT liability.

On July 4, 2025, President Trump signed into law the OBBBA, which makes permanent certain corporate tax incentives from the TCJA but are not expected to materially impact FirstEnergy. The OBBBA also accelerates the phase out of tax credits for wind and solar projects and, accordingly, FirstEnergy is evaluating potential impacts those tax credit provisions and related IRS guidance may have on the proposed construction of solar generation facilities in West Virginia, as discussed in Note 8., “Regulatory Matters,” of the Combined Notes to Financial Statements of the Registrants.

During 2025, FERC issued orders to a non-affiliate concluding that, based on certain previously issued IRS private letter rulings, certain NOL carryforward deferred tax assets, as computed on a separate return basis, should be included in rate base for ratemaking purposes. FirstEnergy determined in the third quarter of 2025 that these rulings and orders also would apply to certain of its subsidiaries, resulting in a benefit from a reduction in regulatory liabilities, reflected as the remeasurement of excess deferred income taxes and an increase in accumulated deferred income tax assets for ratemaking purposes. FirstEnergy made the appropriate updates in its annual formula rates for the impacted subsidiaries.

FirstEnergy will continue to monitor and evaluate future tax legislation, guidance from the U.S. Treasury and/or the IRS, including guidance related to the corporate AMT, and developments concerning the regulatory treatment of income taxes by FERC and/or applicable state regulatory authorities, that could negatively impact FirstEnergy’s and/or JCP&L’s cash flows, results of operations and financial condition.

STATE REGULATION

Each of the Electric Companies’ 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 and TrAIL in Virginia, ATSI in Ohio, the Transmission Companies in Pennsylvania, PE and MP in West Virginia, and PE in Maryland are subject to certain regulations of the VSCC, PUCO, PPUC, WVPSC, and MDPSC, 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.

MARYLAND

PE operates under MDPSC-approved distribution base rates that were effective as of October 19, 2023, and that were subsequently modified by an MDPSC order dated January 3, 2024, which became effective as of March 1, 2024. 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, following passage of the Climate Solutions Now Act of 2022, required annual incremental energy efficiency targets of 2% per year from 2022 through 2024, 2.25% per year in 2025 and 2026, and 2.5% per year in 2027 and thereafter. On August 1, 2023, PE filed its proposed plan for the 2024-2026 cycle as required by the MDPSC and later, at the direction of the MDPSC, PE submitted three scenarios with projected costs over a three-year cycle of $311 million, $354 million, and $510 million, respectively. On December 29, 2023, the MDPSC issued an order approving the $311 million scenario for most programs, with some modifications. On August 15, 2024, PE filed a revised plan for the remainder of the 2024-2026 cycle to comply with refined GHG reduction targets with a total budget of $314 million, which the MDPSC approved on December 27, 2024. PE recovers EmPOWER Maryland program costs with carrying costs on unamortized balances through an annually reconciled surcharge, with certain costs subject to recovery over a five-year amortization period. Lost distribution revenue attributable to energy efficiency or demand reduction is recovered only through base rates. Consistent with an MDPSC order dated December 29, 2022, phasing out the unamortized balances of EmPOWER Maryland investments, PE is required to expense 100% of its EmPOWER Maryland program costs in 2026 and beyond. All previously unamortized costs for prior cycles are to be collected by the end of 2030, consistent with the 2024-2026 order issued on December 29, 2023. Legislation which took effect on July 1, 2024 is expected to reduce the carrying costs on the EmPOWER Maryland unamortized balances for PE by a total of $25 to $30 million over the period of 2024-2030. On July 31, 2024, the MDPSC issued an order implementing revised EmPOWER Maryland surcharge rates for PE in accordance with the new law, denying PE’s request for a hearing that sought to challenge certain portions of the law. On August 30, 2024, PE filed a petition seeking judicial review of its challenge to the law in the Circuit Court for Washington County, Maryland. On August 6, 2025, the Circuit Court for Washington County, Maryland issued an order granting PE’s petition, finding that the legislature may not change terms to apply retroactively to monies already expended. MDPSC and the Maryland Office of People’s Counsel have each appealed the decision. On November 14, 2025, the Appellate Court of Maryland issued an order denying the unopposed motion of the Attorney General of Maryland to Intervene without prejudice to the ability to file an amicus curiae brief, which the Attorney General filed on December 30, 2025. PE's response brief was filed on January 21, 2026.

NEW JERSEY

JCP&L operates under NJBPU approved rates that took effect as of February 15, 2024, and became effective for customers as of June 1, 2024. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third-party EGSs that fail to provide the contracted service. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates.

On September 17, 2021, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US LLC 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 part, in an order issued by NJBPU. The proposal, as accepted, included approximately $723 million in investments for JCP&L 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. On April 17, 2023, JCP&L applied for the FERC “abandonment” transmission rates incentive, which would provide for recovery of 100% of the cancelled prudent project costs that are incurred after the incentive is approved, and 50% of the costs incurred prior to that date, in the event that some or all of the project is cancelled for reasons beyond JCP&L’s control. On August 21, 2023, FERC approved JCP&L’s application, effective August 22, 2023.

On October 31, 2023, offshore wind developer, Orsted, announced plans to cease development of two offshore wind projects in New Jersey—Ocean Wind 1 and 2—having a combined planned capacity of 2,248 MWs. On January 30, 2025, and February 25, 2025, Shell New Energies US LLC and EDF Renewables North America respectively announced that each was exiting its Atlantic Shores partnership to construct wind energy off the shore of New Jersey. On June 4, 2025, Atlantic Shores filed a petition with the NJBPU, requesting consent to terminate its 1.5 GW offshore wind project. These cancellations are not expected to directly affect JCP&L’s awarded projects.

On May 23, 2025, JCP&L filed with the NJBPU a motion seeking declaratory guidance in view of recent offshore wind developments, including a shift in federal energy policy toward more traditional energy resources. JCP&L requested that the NJBPU provide guidance either affirming the current project schedule or, alternatively, authorizing JCP&L to modify the schedule. On June 9, 2025, responses to JCP&L’s motion were filed with the NJBPU, including a cross-motion by the New Jersey Division of Rate Counsel to reopen the offshore wind transmission proceeding, which JCP&L opposed. JCP&L advised that it intended to

comply with its contractual obligations to construct the transmission project, and that its motion was limited to seeking guidance on the construction milestones. On July 28, 2025, the New Jersey Division of Rate Counsel asked the NJBPU to take judicial notice of a recent NYPSC order terminating its offshore wind transmission infrastructure process in the interest of protecting ratepayers. On August 13, 2025, the NJBPU issued an order requesting that JCP&L delay expenditures of certain of the transmission investment planned by JCP&L for a 2.5-year period, and directing that JCP&L work with NJBPU staff and PJM to ensure alignment as to the work that is to be continued on the original timeline and the work that is to be delayed consistent with the order. On April 22, 2026, the NJBPU issued an order authorizing termination of all but one of the transmission projects that were awarded to JCP&L per the NJBPU’s October 26, 2022 order. On April 23, 2026, the NJBPU and PJM filed the termination agreement at FERC. If FERC approves the termination agreement, JCP&L would expect to file a subsequent abandonment proceeding with FERC.

In February 2025, the NJBPU certified the results of its annual basic generation service auctions through which New Jersey’s four EDCs – including JCP&L – satisfy their generation supply requirements for BGS customers for the period beginning June 1, 2025 through May 31, 2026. The certified results resulted in significant rate increases for New Jersey EDC customers and, by order dated April 23, 2025, the NJBPU directed the four EDCs to submit proposals to mitigate the impact of the rate increases that affected residential customers beginning June 1, 2025. On May 7, 2025, JCP&L filed a petition in response to the April 2025 order, modeling four potential mitigation scenarios. On June 18, 2025, the NJBPU approved a stipulation that included JCP&L, NJBPU Staff and New Jersey Division of Rate Counsel, pursuant to which, among other things, JCP&L agreed to apply a temporary rate credit of $30.00 to each residential electric customer’s monthly bill in July and August 2025 that would be deferred in a regulatory asset and recovered with a charge of $10 applied to each residential bill from September 2025 through February 2026 to recover the amounts deferred, without carry charges, subject to a final reconciliation. As of March 31, 2026, JCP&L had substantially recovered the regulatory asset associated with the temporary rate credits.

On August 13, 2025, the NJBPU issued an Order to Show Cause reviewing JCP&L’s 2024 Annual System Performance Report, which includes information regarding JCP&L’s systems level of electric service reliability performance during the prior calendar year. Failure to attain NJBPU’s minimum reliability levels may subject JCP&L to a penalty. The NJBPU order alleges JCP&L has failed to achieve minimum reliability levels for calendar years 2022, 2023, and 2024, and directed JCP&L to file an answer demonstrating why the NJBPU should not impose certain penalties upon JCP&L for such failure, which JCP&L filed on October 10, 2025. On April 13, 2026, NJBPU Staff issued a letter to JCP&L stating its intention to recommend that the NJBPU impose a penalty against JCP&L in the amount of $44 million, while also requesting a meeting with JCP&L to discuss the potential penalty recommendation and a possible resolution. On April 16, 2026, JCP&L responded in writing to the NJBPU Staff welcoming the opportunity to discuss with NJBPU Staff and disputing the magnitude of the recommended penalty and questioning the approach taken by NJBPU Staff. JCP&L is unable to predict the outcome of this matter, including the amount of any penalty and/or other actions that may be imposed by the NJBPU.

On January 14, 2026, the NJBPU issued an order authorizing JCP&L to modify its Lost Revenue Adjustment Mechanism rate rider in its tariff. The modification allows JCP&L to recover the revenue impact of sales losses of approximately $16 million (pre-tax) primarily resulting from the implementation of JCP&L’s Energy Efficiency and Conservation Plan during the one-year period from July 1, 2023, through June 30, 2024. The modification was effective February 1, 2026.

OHIO

The Ohio Companies operated under ESP IV through May 31, 2024, which provided for the supply of power to non-shopping customers at a market-based price set through an auction process. From June 1, 2024, until January 31, 2025, the Ohio Companies operated under ESP V, as modified by the PUCO, and as further described below. On December 18, 2024, the PUCO approved the Ohio Companies’ notice to withdraw ESP V and approved the Ohio Companies’ proposal for returning to ESP IV, with modifications. ESP IV, as modified, continues the DCR rider, which supports continued investment related to the distribution system for the benefit of customers, with an annual revenue cap of $390 million. In addition, ESP IV, as modified, includes a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and contributions, totaling $6.39 million per year, to: (a) fund energy conservation, economic development and job retention programs in the Ohio Companies’ service territories; and (b) establish fuel-funds in each of the Ohio Companies’ service territories to assist low-income customers.

On April 5, 2023, the Ohio Companies filed an application with the PUCO for approval of ESP V, for an eight-year term beginning June 1, 2024, and continuing through May 31, 2032. On May 15, 2024, the PUCO issued an order approving ESP V with modifications, which became effective June 1, 2024, and would have continued through May 31, 2029. The Ohio Companies filed an application for rehearing challenging various aspects of the May 15, 2024, but due to the risks and uncertainty resulting from the Ohio Companies’ application for rehearing being denied by operation of law, on October 29, 2024, the Ohio Companies filed a notice of their intent to withdraw ESP V and proposed the terms under which they would resume operating under ESP IV. On December 18, 2024, the PUCO approved the Ohio Companies’ notice of withdrawal. Also on December 18, 2024, the PUCO approved the Ohio Companies’ proposal for returning to ESP IV, with modifications. Consistent with ESP IV, the PUCO authorized the Ohio Companies’ reinstatement of the DCR rider. Additionally, the PUCO ordered that storm costs deferred under ESP V since June 1, 2024, remain on the Ohio Companies’ books and subject to review in a future case. On January 22, 2025, the PUCO approved the Ohio Companies’ revised ESP IV tariffs, effective February 1, 2025, at which time the Ohio Companies resumed operating under ESP IV. On April 7, 2025, certain intervenors filed an appeal to the Supreme Court of Ohio challenging the Ohio Companies’ return to ESP IV. On May 22, 2025, the Ohio Supreme Court granted the Ohio Companies motion to

intervene in the appeal. On July 7, 2025, OCC and NOAC filed their Appellants’ brief. Appellees, including the PUCO and the Ohio Companies, filed their briefs on August 26, 2025, to which OCC and NOAC replied on September 15, 2025.

On January 31, 2025, the Ohio Companies filed an application with the PUCO for ESP VI. On May 15, 2025, the Ohio Governor signed HB 15, which repealed the statute authorizing ESPs in Ohio, effective August 14, 2025. On December 17, 2025, the PUCO dismissed the Ohio Companies’ application for ESP VI due to the repeal of the ESP statute.

On March 14, 2025, as directed by the PUCO in its December 18, 2024, order approving the Ohio Companies’ revised ESP IV tariffs, the Ohio Companies filed with the PUCO a request to commence their statutorily required quadrennial review of ESP IV and establish a proposed schedule. On July 10, 2025, the Ohio Companies withdrew the request for the PUCO to establish a procedural schedule following the May 15, 2025 signing by the Ohio Governor of HB 15 ending the statutory mandate to conduct the quadrennial review, effective August 14, 2025. The OCC filed its response to the Ohio Companies’ notice of withdrawal on July 25, 2025, to which the Ohio Companies replied on August 1, 2025. The matter remains pending before the PUCO.

On May 31, 2024, the Ohio Companies filed their application for an increase in base distribution rates based on a 2024 calendar year test period. On November 19, 2025, the PUCO issued an order in the rate case lifting the rate freeze and approving a net increase in base distribution revenues of the Ohio Companies of approximately $34 million, with a return on equity of 9.63% and a hypothetical capital structure of 48.8% debt and 51.2% equity for all three Ohio Companies, which reflects a roll-in of current riders such as DCR and AMI. The PUCO authorized continuance of Rider DCR with a cap increase commensurate with capital investments through January 31, 2025, and approved the Ohio Companies’ proposal to change pension and OPEB recovery to the delayed recognition method. Additionally, the order authorizes recovery of certain deferred costs for storm restoration, operations and maintenance, and energy efficiency programs. As a result of the order, the Ohio Companies recognized a $352 million pre-tax impairment charge related to future recovery disallowances of certain previously capitalized amounts. On November 26, 2025, the Ohio Companies filed proposed compliance tariffs. On December 19, 2025, the Ohio Companies and other parties filed applications for rehearing and on December 29, 2025, the Ohio Companies filed a memorandum against intervenors’ applications for rehearing. On January 7, 2026, the PUCO issued an entry granting rehearing in order to determine whether its November 19, 2025 base rate case opinion and order should be affirmed, abrogated, or modified on rehearing. On February 18, 2026, the PUCO issued an entry on rehearing, which extended the amortization period for recovery of deferred storm restoration costs from five years to twenty-five years, subject to prudency review, and clarified the amount of the authorized increase in Rider DCR revenue caps is $14 million, subject to the Ohio Companies meeting reliability standards. The entry further ordered the Ohio Companies to file revised final tariffs and approved the Ohio Companies’ compliance tariffs, effective March 1, 2026. On March 20, 2026, the Ohio Companies and certain other parties filed with the PUCO second applications for rehearing of the February 18, 2026 entry on rehearing. On April 14, 2026, the PUCO issued an entry on rehearing denying all applications for rehearing.

On May 16, 2022, May 15, 2023, and May 15, 2024, the Ohio Companies filed their SEET applications for determination of the existence of significantly excessive earnings under ESP IV for calendar years 2021, 2022, and 2023, respectively. On May 15, 2025, the Ohio Companies filed their SEET application for determination of the existence of significantly excessive earnings under ESPs IV and V for calendar year 2024. Each application demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. These matters remain pending before the PUCO.

On January 7, 2026, the PUCO issued an order, which directed the Ohio Companies to pay their customers, among other things, restitution and refunds totaling approximately $275 million ($213 million after-tax), which was recognized in the fourth quarter of 2025. The restitution and refunds are being provided to customers over three billing cycles, which began in February 2026. As of March 31, 2026, the Ohio Companies have issued approximately $163 million in restitution and refunds.

See below for additional details on the government investigations and ongoing litigation surrounding the investigation of HB 6.

PENNSYLVANIA

FE PA has five rate districts in Pennsylvania – four that correspond to the territories previously serviced by ME, PN, Penn, and WP and one rate district that corresponds to WP’s service provided to The Pennsylvania State University. The rate districts created by the PA Consolidation will not reach full rate unity until the earlier of 2033 or the conclusion of three base rate cases filed after January 1, 2025. FE PA operates under rates approved by the PPUC, effective as of January 1, 2025. FE PA operates under a DSP through the May 31, 2027 delivery period, which provides for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service.

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 2007-2008 peak demands, at 2.9% MW for ME, 3.3% MW for PN, 2.0% MW for Penn, and 2.5% MW for WP; and energy consumption reduction targets, as a percentage of the Pennsylvania Companies’ historic 2009 to 2010 reference load at 3.1% MWh for ME, 3.0% MWh for PN, 2.7% MWh for Penn, and 2.4% MWh for WP. The fourth phase of FE PA’s energy efficiency and peak demand reduction program, which runs for the five-year period beginning June 1, 2021 through May 31, 2026, was approved by the PPUC on June 18, 2020, providing cost recovery of approximately $390 million to be recovered through Energy Efficiency and Conservation Phase IV Riders for each FE PA rate district.

On November 26, 2025, FE PA submitted a petition for approval of its Phase V Energy Efficiency and Conservation Plan, which includes energy efficiency and peak demand reduction programs with demand reduction targets, relative to 2007-2008 peak demands, at 2.01% MW, and energy consumption reduction targets, as a percentage of FE PA’s historic 2009 to 2010 reference load, at 2.00% MWh. The proposed plan includes cost recovery of approximately $390 million to be recovered through its Phase V Energy Efficiency and Conservation Charge Rider and runs for a five-year period beginning June 1, 2026, through May 31, 2031. Hearings were held on January 29, 2026. The parties reached a full settlement in principle and filed with the PPUC a Joint Petition for Complete Settlement on February 19, 2026. On March 12, 2026, the PPUC issued an order approving the settlement with limited modifications requiring FE PA to file revisions to the plan, which were filed on April 15, 2026.

On February 3, 2026, FE PA filed a proposed DSP for provision of generation for the June 1, 2027 through May 31, 2031 delivery period, to be sourced through competitive procurements for customers who do not receive service from an alternative EGS. Under this DSP, supply would be provided through a mix of 12, 24, and in the case of residential customers, 60-month energy contracts, as well as spot market purchases for industrial customers. Hearings are scheduled to begin on June 15, 2026, and a final order is expected from the PPUC in the fourth quarter of 2026.

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 March 27, 2024 and, for applicable customers, a WVPSC-approved solar surcharge that was most recently adjusted effective January 15, 2026. 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 typically updated annually and MP and PE filed their ENEC filing on August 29, 2025, for rates effective January 1, 2026.

On April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, a tariff to offer solar power on a voluntary basis to West Virginia customers and requiring MP and PE to subscribe at least 85% of the planned 50 MWs of solar generation before seeking approval for surcharge cost recovery. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in excess of the approved solar power tariff. Two of the five solar generation sites went into service in 2024, with the third in April 2025.

On August 29, 2025, MP and PE filed with the WVPSC their biennial review of their vegetation management program and surcharge. MP and PE have proposed an approximate $3.2 million decrease in the surcharge rates due to an over-recovery balance as of June 30, 2025, and higher costs for fuel and reagents. The WVPSC held a hearing regarding rate matters on December 15, 2025. The WVPSC issued an order on March 26, 2026 approving the MP and PE vegetation management program and granting rate recovery for its costs.

On October 1, 2025, MP and PE filed their integrated resource plan with the WVPSC. To ensure that MP and PE can meet their PJM adequacy requirements, the plan proposes, among other things, near-term market capacity purchases, and the addition of 70 MWs of solar generation by 2028 and 1,200 MWs of natural gas combined cycle generation by 2031. On November 26, 2025, the WVPSC issued a procedural order setting a hearing in May 2026.

On February 13, 2026, MP and PE filed a CPCN to construct and operate a 1,200 MW combined cycle gas turbine plant and 70 MWs of solar generation capacity for an estimated capital investment totaling approximately $2.7 billion as of the date of the filing. The request also includes a surcharge designed to recover financing costs during development and construction of the projects, as well as to transition to recovery in base rates once the projects are placed in-service and approved through a base rate case. Hearings have been scheduled for July 16 and 17, 2026. A final order is expected from the WVPSC in the second half of 2026. See Note 9., “Commitments, Guarantees and Contingencies - Environmental Matters - Clean Water Act" of the Combined Notes to Financial Statements of the Registrants for additional details on the EPA's ELG.

FERC REGULATORY MATTERS

Under the Federal Power Act, 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 Electric Companies, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE 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.

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 Electric Companies and AE Supply each have the necessary authorization from FERC to sell their wholesale power, if any, in interstate commerce at market-based rates, although in the case of the Electric Companies major wholesale purchases remain subject to review and regulation by the relevant state commissions. The Electric Companies

and AE Supply are required to renew their respective authorizations every three years, and on December 16, 2025, the companies filed applications for the next renewal period.

Federally enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Electric Companies, 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.

Transmission ROE Incentive

On February 24, 2022, the OCC filed a complaint with FERC against ATSI, AEP’s Ohio affiliate and American Electric Power Service Corporation, and Duke Energy Ohio, Inc. 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. On December 15, 2022, FERC denied the complaint as to ATSI and Duke Energy Ohio, Inc., but granted it as to AEP’s Ohio affiliate. AEP’s Ohio affiliate and OCC appealed FERC’s orders to the Sixth Circuit. On January 17, 2025, the Sixth Circuit ruled that the 50 basis point adder is available only where RTO membership is voluntary, that Ohio law requires Ohio’s transmission utilities to be members of an RTO, and that it was unlawful for FERC to excise the adder from AEP’s Ohio affiliate rates, but not from the Duke Energy Ohio, Inc. and ATSI rates. During 2024, as a result of the ruling, ATSI recognized a $46 million pre-tax charge, with interest, of which $42 million is reported in “Transmission Revenues” and $4 million is reported in “Miscellaneous income, net” on the FirstEnergy Consolidated Statements of Income and Comprehensive Income at the Stand-Alone Transmission segment, to reflect the expected refund owed to transmission customers back to February 24, 2022. On June 20, 2025 and June 24, 2025, ATSI and AEP’s Ohio affiliate, respectively, applied for the Supreme Court of the U.S. to review the Sixth Circuit’s decision. On November 10, 2025, the Supreme Court of the U.S. denied ATSI’s petition for the court to review the case. On November 13, 2025, the Sixth Circuit issued a mandate sending the case back to FERC for further proceedings.

Transmission ROE Methodology

A proposed rulemaking proceeding concerning transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act was initiated in March of 2020 and remains pending before FERC. Among other things, the rulemaking explored whether utilities should collect an “RTO membership” ROE incentive adder for more than three years. FirstEnergy is a member of PJM, and its transmission subsidiaries could be affected by the proposed rulemaking. 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; provided however, due to the Sixth Circuit’s ruling in the Transmission ROE Incentive matter described above, ATSI is collecting the ROE incentive adder subject to refund.

Transmission Planning Supplemental Projects

On September 27, 2023, the OCC filed a complaint against ATSI, PJM and other transmission utilities in Ohio alleging that the PJM Tariff and operating agreement are unjust, unreasonable, and unduly discriminatory because they include no provisions to ensure PJM’s review and approval for the planning, need, prudence and cost-effectiveness of the PJM Tariff Attachment M-3 “Supplemental Projects.” Supplemental Projects are projects that are planned and constructed to address local needs on the transmission system. The OCC demands that FERC: (i) require PJM to review supplemental projects for need, prudence and cost-effectiveness; (ii) appoint an independent transmission monitor to assist PJM in such review; and (iii) require that Supplemental Projects go into rate base only through a “stated rate” procedure whereby prior FERC approval would be needed for projects with costs that exceed an established threshold. Subsequently, intervenors expanded the scope of this proceeding to all of the transmission utilities in PJM, including JCP&L. ATSI and the other transmission utilities in Ohio and PJM filed comments.

Local Transmission Planning Complaint

On December 19, 2024, the Industrial Energy Consumers of America, a group representing large industrial customers, and state consumer advocates filed a complaint at FERC that asserts that transmission owners are overbuilding “local transmission facilities” with corresponding unjustified increases in transmission rates. The complaint demands that FERC: (i) prohibit transmission owners from planning “local transmission facilities” that are rated at 100 kV or higher; (ii) appoint “independent transmission monitors” to conduct such planning; and (iii) condition construction of local transmission facilities on the facility having been planned by the “independent transmission monitor.” FirstEnergy is participating in this matter through a consortium of PJM transmission owners and through certain trade groups, including EEI. FirstEnergy, together with the PJM transmission owners, filed a motion to dismiss the complaint on March 20, 2025, which is pending before FERC. FirstEnergy is unable to predict the outcome or estimate the impact that this complaint may have on its Transmission Companies, however, whether this lawsuit moves forward could have a material impact on FirstEnergy and its transmission capital investment strategy.

Ghiorzi v. PJM

In December 2023, PJM assigned certain baseline RTEP projects to NextEra Energy Transmission, which subsequently informed PJM that it would not construct the projects. On April 3, 2025, following the reassignment by PJM of certain baseline RTEP projects in Maryland and Virginia to PE, two individuals filed a complaint at FERC challenging this outcome, which FERC denied on February 2, 2026. The complainants asserted that PJM erred in reassigning the work to PE because such reassignment projects: (i) did not reflect the cost estimates or cost caps included in NextEra Energy Transmission’s bid; and (ii) would be constructed with different routing than as originally proposed. On February 2, 2026, FERC denied the complaint and on April 3, 2026, FERC denied the rehearing request filed by the complainants on March 4, 2026. FirstEnergy and PE are unable to predict the outcome or estimate the impact that this complaint may have.

Abandonment Transmission Rate Incentive

On February 26, 2025, PJM completed its 2024 RTEP Open Window 1 process and, among other actions, designated each of ATSI and PE to construct certain transmission projects. On July 11, 2025, ATSI and PE filed a joint application for the abandonment incentive with FERC, which, was approved on September 9, 2025. Effective September 10, 2025, ATSI and PE each became eligible to recover 50% of the project costs incurred prior to September 10, 2025, and 100% of the project costs incurred thereafter for any projects subsequently cancelled for reasons beyond the control of utility management.

PJM Capacity Market Reforms

On January 16, 2026, the Trump administration and the governors of all thirteen PJM states released a Statement of Principles Regarding PJM. This Statement of Principles is designed to, among other things, increase capacity available in the PJM market. PJM is seeking input from its stakeholders on matters related to the Statement of Principles, including: (i) proposals for a backstop capacity auction, price (cap), term, and quantity; (ii) on whether to extend the existing capacity auction price collar; and (iii) accelerating large load interconnections bringing their own generation. FirstEnergy is participating in the stakeholder processes that are described in the Statement of Principles, including by filing comments on March 22, 2026 at FERC asking that FERC set the price collar at a level that is lower than the level proposed in PJM’s filing. On April 10, 2026, PJM announced a “backstop reliability procurement” of up to 14.8 gigawatts of new resources. PJM proposes to procure the resources in two phases. The first phase will run from September 2026 through March 2027, and will consist of PJM facilitating bilateral contracts between resource developers and load. The second phase will run from March 2027 through September 2027 and will consist of PJM procuring new resources on behalf of EDCs that have agreed for PJM to conduct the procurement. PJM plans to file the necessary tariff amendments in June 2026 and asserts that it is looking for FERC authorization by September 2026. FirstEnergy is participating in the PJM stakeholder processes and will participate in the FERC proceedings.

Large Load Interconnection Rulemaking

On October 23, 2025, the U.S. Secretary of Energy directed FERC to conduct a rulemaking procedure to develop regulations that would speed interconnection to the transmission system of large loads, including “Artificial Intelligence” data centers and “hybrid” data center/electric generation facilities. The U.S. Secretary of Energy advanced 14 principles to guide this outcome, including that such large loads should be responsible for paying the costs of any network transmission system upgrades required for interconnection of such large loads, and that these large loads should have the option for building such network transmission upgrades. The U.S. Secretary of Energy requested that FERC take final action by April 30, 2026. On October 27, 2025, FERC noticed the U.S. Secretary of Energy’s directive for comment, and subsequently established November 21, 2025 as the deadline for initial comments and December 5, 2025 as the deadline for reply comments. FET and its transmission affiliates, as well as over 150 other parties, filed comments on the established deadlines. FirstEnergy is unable to predict the outcome of this rulemaking procedure. On April 16, 2026, FERC issued notice of its intent to take action in June 2026. To the extent the new regulations do not permit transmission utilities to fully recover costs associated with transmission network upgrades required to serve new large loads, FirstEnergy’s strategy of investing in transmission could be adversely affected.

ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate the Registrants regarding air and water quality, hazardous and solid waste management and disposal, and other environmental matters. While the Registrants’ 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. The Registrants cannot predict changes in regulations, regulatory guidance, legal interpretations, policy positions and implementation actions that may evolve.

On March 12, 2025, the EPA announced its intent to reevaluate or reconsider numerous environmental regulations, many of which apply to the Registrants. The final outcome of this initiative remains unknown, but regular required rulemaking processes and procedures still apply, and litigation also anticipated has occurred. The disclosures herein do not attempt to discern potential impacts of these deregulatory actions until and unless formal rulemaking or other regulatory actions are announced and the potential impacts to operations can be discerned.

The disclosures below apply to FirstEnergy and the disclosures under “Regulation of Waste Disposal,” are also applicable to JCP&L.

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 electric generation facilities 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 electric generation facilities in 13 states, including West Virginia. This followed the 2014 Supreme Court of the U.S. 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 electric generation facilities 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 addressed, 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 upwind states, including West Virginia, with the stated purpose of allowing downwind states to attain or maintain compliance with the 2015 ozone National Ambient Air Quality Standards. On February 13, 2023, the EPA disapproved 21 SIPs, which was a prerequisite for the EPA to issue a final Good Neighbor Plan or FIP. On June 5, 2023, the EPA issued the final Good Neighbor Plan with an effective date 60 days thereafter. Certain states, including West Virginia, have appealed the disapprovals of their respective SIPs, and some of those states have obtained stays of those disapprovals precluding the Good Neighbor Plan from taking effect in those states. On August 10, 2023, the 4th Circuit granted West Virginia an interim stay of the disapproval of its SIP and on January 10, 2024, after a hearing held on October 27, 2023, granted a full stay which precludes the Good Neighbor Plan from going into effect in West Virginia. In addition to West Virginia, certain other states, and certain trade organizations, including the Midwest Ozone Group of which FE is a member, separately filed petitions for review and motions to stay the Good Neighbor Plan itself at the D.C. Circuit. On September 25, 2023, the D.C. Circuit denied the motions to stay the Good Neighbor Plan. On October 13, 2023, the aggrieved parties filed an Emergency Application for an Immediate Stay of the Good Neighbor Plan with the Supreme Court of the U.S. Oral argument was heard on February 21, 2024. On June 27, 2024, the Supreme Court of the U.S. granted a stay of the Good Neighbor Plan pending disposition of the petition for review in the D.C. Circuit. On February 6, 2025, the EPA filed a motion at the D.C. Circuit to hold the proceedings in abeyance for 60 days to allow the EPA time to familiarize itself with the Good Neighbor Plan and in particular, time to brief the new administration about these consolidated petitions and the underlying Rule to allow them to decide what action, if any, is necessary. On March 10, 2025, the EPA filed a motion for remand with the D.C. Circuit identifying issues with the Good Neighbor Plan that make reconsideration appropriate. The D.C. Circuit granted the motion for remand and cancelled oral argument. Consistent with its March 12, 2025 announcement, the EPA intends to undertake reconsideration of the rule and complete any new rulemaking by the fourth quarter of 2026. On January 27, 2026, the EPA proposed phase 1 of its reconsideration of the rule applicable to eight states outside of FirstEnergy’s service area. FirstEnergy will continue to monitor any further actions by the EPA for any potential impact to its business and results of operations.

Climate Change

In recent years, certain regulators in the U.S. have focused efforts on increasing disclosures by companies related to climate change and mitigation efforts. At the federal level, presidential administrations have held differing views on prioritizing actions to address GHG emissions and, by extension, climate change. Those differing views have led to policy changes, creating uncertainty about environmental requirements and associated impacts.

In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHGs under the Clean Air Act,” known as the 2009 Endangerment Finding, 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 generation facilities. The 2009 Endangerment Finding is the basis of the EPA’s authority to regulate GHG emissions under the CAA.

In January 2025, Executive Order 14514 was issued and, among other deregulatory actions, directed the EPA Administrator to make recommendations on the “legality and continuing applicability” of the EPA’s 2009 Endangerment Finding, which forms the basis for the EPA's GHG regulations. On March 12, 2025, the EPA announced a series of planned deregulatory actions that it would be taking related to such executive order, including reconsideration of the regulations to limit power plant GHG emissions. On July 29, 2025, the EPA announced a proposal to rescind its 2009 Endangerment Finding. On February 12, 2026, the EPA issued a final rule rescinding its 2009 Endangerment Finding, thereby eliminating the basis for much of the EPA’s regulation of GHG emissions. However, depending on the outcome of any appeals and any future EPA actions, compliance with the GHG emissions limits could require additional capital expenditures or changes in operation at the Fort Martin and Harrison power stations.

On May 23, 2023, the EPA published a proposed rule pursuant to CAA Section 111 (b) and (d) in line with the decision in West Virginia v. Environmental Protection Agency intended to reduce power sector GHG emissions (primarily CO2 emissions) from fossil fuel based EGUs. On April 25, 2024, the EPA issued a final rule, which we refer to as the GHG rule, that imposed stringent GHG emissions limitations on power plants based on fuel type and unit retirement date. In May 2024, a group of 25 states, including West Virginia, filed a challenge to the rule in the D.C. Circuit. Also in May 2024, other utility groups, including the Midwest Ozone Group and Electric Generators for a Sensible Transition, both of which MP is a member, filed petitions for review of the GHG rule as well as motions to stay the rule in the D.C. Circuit. The D.C. Circuit subsequently granted a motion from the EPA placing the litigation in abeyance until further order of the Court. On June 17, 2025, the EPA published a proposed rule to repeal the GHG rule. This proposal to repeal the GHG remains under active consideration by the EPA. If and when finalized, the EPA’s repeal of the GHG rule is expected to be challenged in federal court. Although FirstEnergy continues to evaluate the impact of federal GHG regulations on its operations, it cannot predict the outcome of any regulatory actions or the result of potential litigation challenging any of these actions.

At the state level, there are several initiatives to reduce GHG emissions. Certain northeastern states are participating in the Regional Greenhouse Gas Initiative and western states, including California, have implemented programs to control emissions of certain GHGs and enhance public disclosures relating to the same. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.

FirstEnergy has pledged to achieve carbon neutrality by 2050 with respect to GHGs within FirstEnergy’s direct operational control (known as Scope 1 emissions). FirstEnergy’s ability to achieve its GHG reduction goal is subject to its ability to make operational changes and is conditioned upon numerous risks, many of which are outside of its control. With respect to FirstEnergy’s coal-fired facilities in West Virginia, which serve as the primary source of its Scope 1 emissions, it has identified that the end of the useful life date is 2035 for Fort Martin and 2040 for Harrison. MP filed its 10-year integrated resource plan with the WVPSC on October 1, 2025, which highlighted, among other things, the need for new dispatchable generation 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 FirstEnergy is unable to recover these costs, it could have a material adverse effect on FirstEnergy’s financial condition, results of operations, and cash flow. 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.

FirstEnergy continues to monitor climate change policies at both the federal and state level. Based on the EPA’s final rule rescinding the 2009 Endangerment Filing and other anticipated rulemaking, we may experience a reduction in GHG reporting and other regulatory obligations at the federal level over the near term. Multiple lawsuits opposing the EPA’s rescission were filed after it was finalized and the legal conflict is expected to be extensive. In light of the pending legal challenges, FirstEnergy is unable to predict the impact on its business and operations.

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal Clean Water Act 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 were 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. On March 29, 2023, the EPA published proposed revised ELGs applicable to coal-fired electric generation facilities that include more stringent effluent limitations for wet scrubber systems and ash transport water, and new limits on landfill leachate. The rule was issued as final by the EPA on April 25, 2024. On May 30, 2024, the Utility Water Act Group, of which FirstEnergy is a member, filed a Petition for Review of the 2024 ELG Rule with the U.S. Court of Appeals for the Fifth and Eighth Circuit Courts, and on June 18, 2024, the Utility Water Group filed a motion to stay the rule pending disposition on the merits. A number of other parties have challenged the final rule in various petitions for review across several circuits. Those petitions and motions for stay have been consolidated in the U.S. Court of Appeals for the Eighth Circuit. On October 10, 2024, the U.S. Court of Appeals for the Eighth Circuit denied the motions for stay. Depending on the outcome of appeals and the EPA’s review, compliance with the 2024 ELG rule could require additional capital expenditures or changes in operation at closed and active landfills, and at the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to comply with the 2020 ELG rule. On February 19, 2025, the U.S. Department of Justice filed a motion on behalf of the EPA in the U.S. Court of Appeals for the Eighth Circuit, seeking to hold the litigation in abeyance for a period of 60 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed. On February 28, 2025, U.S. Court of Appeals for the Eighth Circuit granted the EPA’s motion. On March 12, 2025, the EPA announced a series of planned deregulatory actions, including reconsideration of the 2024 ELG rule. On December 31, 2025, the EPA published a final ELG Deadline Extensions Rule extending certain compliance deadlines included in the 2024 ELG Rule by five years.

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 generation facilities. 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 allowed for an extension of the closure deadline based on meeting identified site-specific criteria. AE Supply transferred the McElroy’s Run CCR impoundment facility and adjacent dry landfill and related remediation obligations on March 4, 2025, pursuant to the environmental liability transfer agreement dated February 3, 2025 with a subsidiary of IDA Power, LLC. Pursuant to the agreement, AE Supply established a $160 million escrow account that AE Supply will fund over five years and is secured by a surety bond, which is guaranteed by FE. As of March 31, 2026, AE Supply has made cumulative cash payments of $46 million to the escrow account since the transfer in 2025.

On May 8, 2024, the EPA issued the legacy CCR rule, which finalized changes to the CCR regulations addressing inactive surface impoundments at inactive electric utilities, known as legacy CCR surface impoundments. The rule extends 2015 CCR Rule requirements for groundwater monitoring and protection, operational and reporting procedures as well as closure requirements to impoundments and landfills that were not originally included for coverage by the 2015 CCR Rule. Furthermore, the EPA’s interpretations of the EPA CCR regulations continue to evolve through enforcement and other regulatory actions. FirstEnergy is currently assessing the potential impacts of the final rule, including a review of additional sites to which the new rule might be applicable. On February 13, 2025, the U.S. Department of Justice filed a motion on behalf of the EPA in the D.C. Circuit, seeking to hold the litigation, which was filed on August 8, 2024, by the Utility Solid Waste Act Group with FE as a member, in abeyance for a period of 120 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed, which the D.C. Circuit granted. On March 12, 2025, the EPA announced a series of planned deregulatory actions, including reconsideration of the final legacy CCR rule. FirstEnergy continues to monitor the EPA’s actions related to CCR regulations; however, the ultimate impact is unknown at this time and is subject to the outcome of the litigation and any future state regulatory actions. Depending on the outcome of appeals and the EPA’s rule, compliance with the final legacy CCR rule could require remedial actions, including removal of coal ash.

Certain of the FirstEnergy companies 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 FirstEnergy’s Consolidated Balance Sheets as of March 31, 2026, 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 $95 million have been accrued through March 31, 2026, of which approximately $70 million are for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable societal benefits charge. 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

U.S. 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. In March 2023, a jury found Mr. Householder and his co-defendant, Matthew Borges, guilty and in June 2023, the two were sentenced to prison for 20 and five years, respectively. Messrs. Householder and Borges have appealed their sentences; the Sixth Circuit recently rejected their appeal upholding their convictions. Also, on July 21, 2020, and in connection with the U.S. Attorney’s Office’s investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the Southern District of Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020. On January 17, 2025, the U.S. Attorney’s Office announced that a federal grand jury charged two former FirstEnergy senior officers with one count of participating in a Racketeer Influenced and Corrupt Organizations Act conspiracy. The allegations in the indictment are largely based on the conduct described in the DPA.

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 as to FE. 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 DPA required 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, consisting of (x) $115 million paid by FE to the U.S. 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 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 an expense in the second quarter of 2021 and paid in the third quarter of 2021. As of July 22, 2024, FirstEnergy had successfully completed the obligations required within the three-year term of the DPA. Under the DPA, FirstEnergy has an obligation to continue: (i) publishing quarterly a list of all payments to 501(c)(4) entities and all payments to entities known by FirstEnergy operating for the benefit of a public official, either directly or indirectly; (ii) not making any statements that contradict the DPA; (iii) notifying the U.S. Attorney’s Office of any changes in FirstEnergy’s corporate form; and (iv) cooperating with the U.S. Attorney’s Office until the conclusion of any related investigation, criminal prosecution, and civil proceeding brought by the U.S. Attorney’s Office, including the aforementioned federal indictment against two former FirstEnergy senior officers. Within 30 days of those matters concluding, and FirstEnergy’s successful completion of its remaining obligations, the U.S. Attorney’s Office will dismiss the criminal information. On February 26, 2025, the U.S. Attorney’s Office filed a status report confirming these commitments.

Legal Proceedings Relating to U.S. v. Larry Householder, et al.

Certain FE stockholders and FirstEnergy customers also 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).

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 alleged 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 as a result of alleged misrepresentations or omissions in connection with offerings of senior notes by FE in February and June 2020. On March 30, 2023, the court granted plaintiffs’ motion for class certification. On April 14, 2023, FE filed a petition in the Sixth Circuit seeking to appeal that order. On August 13, 2025, the Sixth Circuit vacated the S.D. Ohio’s order granting class certification. On November 6, 2025, the S.D. Ohio held oral argument to further consider class certification in light of the Sixth Circuit’s decision. 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 then-current and former officers of Energy Harbor Corp. 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.

The outcome of any of these lawsuits 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.

NEW ACCOUNTING PRONOUNCEMENTS

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

JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

JCP&L is a wholly owned subsidiary of FE. JCP&L conducts business in New Jersey by providing regulated electric transmission and distribution services in northern, western and east central New Jersey, representing $5.1 billion in rate base as of December 31, 2025. JCP&L is subject to regulation by the NJBPU and FERC.

JCP&L distributes electricity to approximately 1.2 million customers in New Jersey across its distribution footprint. JCP&L owns and operates transmission infrastructure that is used to transmit electricity, with revenues derived from forward-looking formula rates, pursuant to which the revenue requirement is updated annually based on a projected rate base and projected costs, which are subject to an annual true-up based on actual rate base and costs. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU. JCP&L’s results reflect the costs of securing and delivering electric generation to customers and net transmission expenses related to the delivery of electricity on JCP&L’s transmission facilities, including the deferral and amortization of certain costs.

As discussed, in Note 1.,"Organization and Basis of Presentation," of the Combined Notes to Financial Statements of the Registrants, during the fourth quarter of 2025, JCP&L identified an error in the recording of certain expenses for smart meter cost of removal associated with the deployment of its AMI program, resulting in an understatement of expense on the Statements of Income and Comprehensive Income and Regulatory assets/liabilities on the Balance Sheets since 2023. JCP&L evaluated the error, and the specific impact on each affected prior period was not material, however, as a result of the cumulative impact, JCP&L determined it should revise previously issued financial statements to correct the error and in doing so also corrected other immaterial errors. As such, JCP&L has revised the previously issued interim Results of Operations for the three months ended March 31, 2025.

As of January 1, 2026, JCP&L made changes in how management evaluates operating performance and allocates resources. As a result of these changes, JCP&L reassessed its operating segments and determined that its operations are now managed as a single integrated business. Historically, JCP&L reported two operating segments, Distribution and Transmission. Accordingly, JCP&L changed its external segment reporting to present its results, including comparative periods, as a single reportable segment for the first quarter of 2026, and reclassified prior periods for comparability. There are no changes to JCP&L’s significant expenses, measure of profit or loss, or other segment items.

For additional information with respect to JCP&L, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Executive Summary and Recent Developments, Regulatory Assets and Liabilities, Capital Resources and Liquidity, Guarantees and Other Assurances, Market Risk Information, Credit Risk, Outlook, Critical Accounting Policies and Estimates and New Accounting Pronouncements.

JCP&L Summary of Results of Operations — First Three Months of 2026 Compared with First Three Months of 2025

JCP&L financial results for the three months ended March 31, 2026 and 2025, were as follows:


	For the Three Months Ended March 31,
(In millions)	2026		2025 (1)		Change

Revenues	$	666	$	566	$	100

Operating Expenses:
Purchased power	378		298		80
Other operating expenses	224		145		79
Provision for depreciation	61		65		(4)
Deferral of regulatory assets, net	(106)		(20)		(86)
General taxes	7		6		1
Total operating expenses	564		494		70

Other Income (Expense):
Miscellaneous income, net	15		12		3

Interest expense - other	(39)		(29)		(10)
Interest expense - affiliates	(2)		(1)		(1)
Capitalized financing costs	12		9		3
Total other expense	(14)		(9)		(5)

Income taxes	22		16		6

Net Income	$	66	$	47	$	19

(1) Previously issued 2025 JCP&L amounts have been revised due to the correction of immaterial errors as discussed in Note 1., "Organization and Basis of Presentation," of the Combined Notes to Financial Statements of the Registrants.

Distribution services by customer class are summarized in the following table:


	For the Three Months Ended March 31,
(In thousands)	Actual				Weather-Adjusted
Electric Distribution MWh Deliveries	2026	2025	Increase		2026	2025	Increase

Residential	2,437	2,307	5.6	%	2,340	2,323	0.7	%
Commercial(1)	2,123	2,019	5.2	%	2,112	2,038	3.6	%
Industrial	435	434	0.2	%	435	434	0.2	%

Total Electric Distribution MWh Deliveries	4,995	4,760	4.9	%	4,887	4,795	1.9	%

(1) Includes street lighting.

Distribution deliveries for each customer class were impacted by higher customer usage and demand. Heating degree days in the first three months of 2026 were 7% above the same period of 2025 and 6% above normal.

JCP&L Results of Operations

Net income increased $19 million in the first three months of 2026, as compared to the same period of 2025, primarily due to the absence of severance and related costs in the first quarter of 2025, lower other operating expenses, higher transmission revenues from regulated capital investments that increased rate base, higher revenues associated with certain investment programs, and increased customer demand.

Revenues

The $100 million increase in total revenues resulted from the following sources:


	For the Three Months Ended March 31,
Revenues by Type of Service	2026		2025		Increase
	(In millions)
Distribution services	$	229	$	223	$	6

Generation sales:
Retail	360		277		83
Wholesale	2		1		1
Total generation sales	362		278		84

Transmission	71		61		10

Other	4		4		—
Total Revenues	$	666	$	566	$	100

Distribution services revenue increased $6 million during the first three months of 2026, as compared to the same period of 2025, primarily due to colder weather temperatures that increased customer usage and demand, and higher rider revenues associated with certain regulated investment programs.

Generation sales revenues increased $84 million during the first three months of 2026, as compared to the same period of 2025, primarily due to higher non-shopping generation auction rates and higher sales volumes.

Transmission revenues increased $10 million during the first three months of 2026, as compared to the same period of 2025, primarily due to higher recovery of transmission operating expenses and higher rate base from regulated investment programs.

Operating Expenses

Total operating expenses increased by $70 million primarily due to:

Purchased power costs, which have no material impact to earnings, increased by $80 million during the first three months of 2026, as compared to the same period of 2025, primarily due to higher sales volumes and unit costs.
Other operating expenses increased $79 million in the first three months of 2026, as compared to the same period of 2025, primarily due to:
Higher storm restoration expenses of $81 million, of which $74 were deferred for future recovery;
Higher energy efficiency and other state mandated program costs of $10 million, which were deferred for future recovery, resulting in no material impact to earnings; and
Higher formula rate transmission operating and maintenance expenses of $4 million, which have no material impact to earnings.

The increase was partially offset by:

The absence of $4 million of severance and related costs associated with FirstEnergy’s organizational changes announced in the first quarter of 2025; and
Lower other operating expenses of $11 million, primarily due to lower other employee benefits and increased construction support and lower maintenance work.
Depreciation expense decreased $4 million in the first three months of 2026, as compared to the same period of 2025, primarily due to the accelerated amortization of legacy smart meters in New Jersey, which concluded in December 2025, partially offset by a higher asset base.
Deferral of regulatory assets, net increased $86 million in the first three months of 2026, as compared to the same period of 2025, primarily due to a $74 million increase from higher deferral of storm restoration costs, and $12 million related to net increases in other deferrals.

Other Expenses

Total other expenses increased $5 million in the first three months of 2026, as compared to the same period of 2025, primarily due to higher interest expense as a result of new debt issued since the first quarter of 2025, partially offset by higher capitalized interest and higher pension & OPEB non-service credits.

Income Taxes

The effective tax rate for the three months ended March 31, 2026 and 2025, was 25.0% and 25.4%, respectively.

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