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PUBLIC SERVICE ENTERPRISE GROUP INC (PEG)

CIK: 0000788784. SIC: 4931 Electric & Other Services Combined. Latest 10-K as of: 2026-02-26.

SIC breadcrumb: Transportation, Communications, Electric, Gas, And Sanitary Services > Electric, Gas, And Sanitary Services > SIC 4931 Electric & Other Services Combined

SEC company page: https://www.sec.gov/edgar/browse/?CIK=788784. Latest filing source: 0001193125-26-077446.

Selected Fundamentals

MetricValueUnitFYFiled
Revenue12,168,000,000USD20252026-02-26
Net income2,111,000,000USD20252026-02-26
Assets57,576,000,000USD20252026-02-26

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-26. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000788784.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

Metric2016201720182019202020212022202320242025
Revenue8,966,000,0009,094,000,0009,696,000,00010,076,000,0009,603,000,0009,722,000,0009,800,000,00011,237,000,00010,290,000,00012,168,000,000
Net income887,000,0001,574,000,0001,438,000,0001,693,000,0001,905,000,000-648,000,0001,031,000,0002,563,000,0001,772,000,0002,111,000,000
Operating income1,598,000,0001,429,000,0002,298,000,0001,943,000,0002,270,000,000-856,000,0001,381,000,0003,685,000,0002,353,000,0002,980,000,000
Diluted EPS1.753.102.833.333.76-1.292.065.133.544.22
Assets40,070,000,00042,716,000,00045,326,000,00047,730,000,00050,050,000,00048,999,000,00048,718,000,00050,741,000,00054,640,000,00057,576,000,000
Stockholders' equity13,130,000,00013,847,000,00014,377,000,00015,089,000,00015,984,000,00014,438,000,00013,729,000,00015,477,000,00016,114,000,00016,982,000,000
Cash and cash equivalents423,000,000313,000,000177,000,000147,000,000543,000,000818,000,000465,000,00054,000,000125,000,000132,000,000
Net margin9.89%17.31%14.83%16.80%19.84%-6.67%10.52%22.81%17.22%17.35%
Operating margin17.82%15.71%23.70%19.28%23.64%-8.80%14.09%32.79%22.87%24.49%

Financial Charts

Macro Cross-References

Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-26. Report date: 2025-12-31.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)

This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG) and Public Service Electric and Gas Company (PSE&G). Information contained herein relating to any individual company is filed by such company on its own behalf.

PSEG’s business consists of two reportable segments, PSE&G and PSEG Power LLC (PSEG Power) & Other, primarily comprised of our principal direct wholly owned subsidiaries, which are:

•
PSE&G—which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU), the Federal Energy Regulatory Commission (FERC), and other federal and New Jersey state regulators. PSE&G also invests in regulated solar generation projects and regulated energy efficiency (EE) and related programs in New Jersey, which are regulated by the BPU, and

•
PSEG Power—which is an energy supply company that consists of the operations of merchant nuclear generating assets and fuel supply functions engaged in competitive energy sales via its principal direct wholly owned subsidiaries. PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC) and other federal regulators and state regulators in the states in which they operate.

The PSEG Power & Other reportable segment also includes amounts related to the parent company as well as PSEG’s other direct wholly owned subsidiaries, which are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) transmission and distribution (T&D) system under an Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily holds legacy lease investments and competitively bid, FERC regulated transmission; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Our business discussion in Item 1. Business provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Item 1A. Risk Factors provides information about factors that could have a material adverse impact on our businesses. The following discussion provides an overview of the significant events and business developments that have occurred during 2025 and key factors that we expect may drive our future performance. This discussion refers to the Consolidated Financial Statements (Statements) and the related Notes to the Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements and Notes.

EXECUTIVE OVERVIEW OF 2025 AND FUTURE OUTLOOK

We are a public utility holding company that, acting through our wholly owned subsidiaries, is a predominantly regulated electric and gas utility and a nuclear generation business. Our business plan focuses on achieving growth by allocating capital primarily toward regulated investments in an effort to continue to improve the sustainability and predictability of our business and realizing the value of the consistent and reliable carbon-free generation from our nuclear units. We are focused on investing to meet growing energy demand, modernize our energy infrastructure, improve reliability and resilience, increase EE to meet customer expectations and be well aligned with public policy objectives. With these investments and higher working capital recovery approved in the distribution rate case, our regulated rate base increased from approximately $34 billion as of December 31, 2024 to approximately $36 billion as of December 31, 2025. In addition, our nuclear facilities retain the downside price protection of a production tax credit (PTC) from 2024 through 2032.

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For the years 2026-2030, our regulated capital investment program is estimated to be in a range of $22.5 billion to $25.5 billion. We expect these capital investments to result in a compound annual growth rate in our regulated rate base in a range of 6.0% to 7.5% from year-end 2025 to year-end 2030. The regulated capital investments represent the majority of PSEG’s total capital investment program of $24 billion to $28 billion. The low end of the range includes an extension of our Gas System Modernization Program (GSMP) and Clean Energy Future (CEF)-EE program, as these programs are expected to continue beyond their currently approved timeframes. The upper end of our capital investment range includes potential incremental investments to address continued demand growth and other investments to meet infrastructure needs and support New Jersey's clean energy goals.

PSE&G

At PSE&G, our focus is on investing capital in T&D infrastructure and clean energy programs to meet growing demand, enhance the reliability and resiliency of our T&D system, meet customer expectations and support public policy objectives.

In October 2024, the BPU approved our CEF-EE II filing authorizing approximately $2.9 billion for energy efficiency projects committed between January 1, 2025 through June 30, 2027, and completed over an expected six-year period. The Order approved a program investment budget of approximately $1.9 billion, net of administrative expenses, and approximately $1 billion to continue our customer on-bill repayment program. This EE filing is a significant increase from our prior filings, driven by an increase in the savings targets required under the BPU Energy Efficiency Framework and higher costs to achieve those targeted savings.

Our GSMP II program extension provided for main replacement through December 2025 plus trailing services replacement and paving costs into 2026 totaling approximately $900 million of investment. Of the $900 million, $750 million is recovered through three periodic rate adjustments with the balance recovered through a future base rate case. In November 2025, the BPU issued an Order approving PSE&G’s GSMP III program, authorizing $1.05 billion of capital investment to replace 525 miles of high pressure cast iron gas mains and unprotected steel mains, with cost recovery through three periodic rate adjustments as portions of the investment are put into service. In that Order, the BPU also authorized $360 million of investment to replace an additional 75 miles of gas main, with cost recovery to be requested in a future base rate case. Investment under the GSMP III program will begin in 2026 and continue through December 2028 plus trailing services replacement and paving costs into 2029.

In October 2024, the BPU issued an Order approving the settlement of PSE&G's distribution rate case with new rates effective October 15, 2024. The Order provided for a $17.8 billion rate base, a 9.6% return on equity for PSE&G’s distribution business and a 55% equity component of its capitalization structure. In addition, the Order approved mechanisms beginning January 1, 2025 associated with the recovery of future storm costs as well as the recovery of annual pension and OPEB expenses.

PSEG Power

At PSEG Power, we seek to produce low-cost electricity by efficiently operating our nuclear generation assets, mitigate earnings volatility through hedging and the PTC mechanism, and support public policies that preserve these existing carbon-free base load nuclear generating plants. During 2025, our nuclear units generated approximately 30.9 terawatt hours and operated at a capacity factor of 91.2%. Effective April 2025, PSEG Power revised the estimated useful lives for the Salem 1, Salem 2 and Hope Creek nuclear plants due to our expectation that a 20-year license extension will be approved for these facilities. In October 2025, we completed work to extend the refueling cycle at our Hope Creek facility from 18 months to 24 months. In addition, we are planning power uprates at Salem Units 1 and 2 that will increase generation capacity and reliability and support long-term operation of these units, including through a potential subsequent license renewal.

Our hedging strategy continues to incorporate an estimated range of risk reduction impacts from the PTCs on our nuclear generation portfolio while retaining the ability to benefit when market pricing exceeds the level at which we would receive PTCs. As of December 31, 2025, we expect that our current portfolio position for 2026 will result in the realized value of our nuclear generation output being above the level at which we would receive PTCs. Our strategy will continue to evolve taking into account energy market conditions, PTC guidance uncertainty, and potential incremental changes upon receiving U.S.

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Treasury guidance. In addition, we continue to explore opportunities for the potential sale of power, capacity and/or emission credits from our nuclear facilities pursuant to long-term agreements.

Climate Strategy and Sustainability Efforts

We remain guided by our vision to power a future where people use energy more efficiently, and it’s safer and delivered more reliably than ever. Our investments remain focused on infrastructure modernization, energy efficiency, and supporting growing customer demand, as well as New Jersey's long-term energy goals. We have adjusted our net zero greenhouse gas (GHG) emissions goal that includes direct GHG emissions (Scope 1) and indirect GHG emissions from operations (Scope 2) across our business operations, which supports New Jersey's clean energy and climate goals, from 2030 to 2050. Transition risks, including federal and/or state policy and regulation, technology availability and affordability, market demands, and customer needs likely will impact the pace of our net zero progress and our ability to achieve the 2050 goal.

PSE&G has undertaken a number of initiatives that support the reduction of GHG emissions, including our implementation of New Jersey's EE and related programs that are intended to support New Jersey’s Energy Master Plan (EMP) and Gubernatorial Executive Orders through programs designed to help customers use energy more efficiently, reduce GHG emissions, support the expansion of the EV infrastructure in New Jersey, install energy storage capacity to supplement solar generation and enhance grid resiliency, install smart meters and supporting infrastructure to allow for the integration of other clean energy technologies and to more efficiently respond to weather and other outage events.

We continue to assess physical risks of climate change and adapt our capital investment program to improve the reliability and resiliency of our system in an environment of increasing frequency and severity of weather events. PSE&G is committed to the safe and reliable delivery of natural gas to approximately 1.9 million customers throughout New Jersey and we are equally committed to reducing GHG emissions associated with such operations. The GSMP is designed to improve safety and reliability and significantly reduce natural gas leaks in our distribution system, which would reduce the release of methane, a potent GHG, into the air. From 2018 through 2025 we reduced reported methane emissions by over 30% system wide.

We also continue to focus on working to preserve the economic viability of our nuclear units, which provide over 80% of the carbon-free energy in New Jersey. These efforts include reducing market risk by advocating for state and federal policies, such as the PTC established by the IRA, and capacity market reform and related generator interconnection policies at PJM Interconnection, L.L.C. (PJM) that recognize the value of our nuclear fleet’s carbon-free generation and its contribution to grid reliability and resource adequacy, and potential long-term contracts that recognize the value of its consistent and reliable carbon-free energy.

Competitively Bid, FERC Regulated Transmission

PSEG continues to evaluate additional investment opportunities in regulated transmission. In December 2023, PJM awarded us an approximately $424 million project to address increasing load and reliability issues in Maryland and northern Virginia as part of its 2022 Window 3 competitive solicitation. PJM has directed that the project be placed in service in 2027. However, based on the procedural timeline established by order of the Maryland Public Service Commission, we do not currently believe a 2027 in-service date for the project is reasonably achievable. We are continuing to take all available steps to obtain approvals for timely project execution. We cannot predict the outcome.

PSEG will continue to evaluate opportunities to participate in transmission solicitation processes and may decide to submit bids for these opportunities, some of which could be material investments.

PSEG LI

PSEG LI has been operating LIPA’s electric T&D system in Long Island, New York since 2014 under a 12-year OSA with LIPA that expired on December 31, 2025. In 2025, a five year extension of the contract was approved. A competitor in the contract bidding process filed litigation against LIPA challenging the process. LIPA filed a motion to dismiss the competitor’s claim as untimely, which was granted by the New York Supreme Court in December 2025. The competitor filed an appeal in January 2026.

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Financial Results

The financial results for PSEG, PSE&G and PSEG Power & Other for the years ended December 31, 2025 and 2024 are presented as follows:

Years Ended December 31,

2025

2024

Millions, except per share data

PSE&G

$

1,745

$

1,547

PSEG Power & Other

366

225

PSEG Net Income

$

2,111

$

1,772

PSEG Net Income Per Share (Diluted)

$

4.22

$

3.54

For a detailed discussion of our financial results, see Results of Operations.

Regulatory, Legislative and Other Developments

We closely monitor and engage with stakeholders on significant regulatory and legislative developments.

Transmission Rate Proceedings and Return on Equity (ROE)

Under current FERC rules, PSE&G continues to earn a 50 basis point adder to its base ROE for its membership in PJM as a transmission owner. However, certain regulatory or legislative actions could potentially lead to the loss of this adder which, if eliminated, would prospectively reduce PSE&G’s annual Net Income and annual cash inflows by approximately $40 million.

New Jersey Clean Energy Stakeholder Proceedings

In February 2023, the previous governor of New Jersey issued executive orders (EOs) that establish or accelerate previously established 2050 targets for clean-sourced energy, building decarbonization, and EV adoption goals, with new target dates of 2030 or 2035, as applicable. In November 2025 the BPU released the updated Energy Master Plan (EMP) that presents potential pathways toward meeting New Jersey’s clean energy and decarbonization goals. Given the new administration took office in January 2026, it is not clear how the EMP might influence New Jersey’s energy policy and we cannot predict the impact on our business that might result.

Environmental Regulation

We are subject to liability under environmental laws for the costs and penalties of remediating contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. In particular, the historic operations of PSEG companies and the operations of numerous other companies within the Newark Bay Complex are alleged by federal and state agencies to have discharged substantial contamination into the Newark Bay Complex in violation of various statutes. The Newark Bay Complex is a tidal estuary in northern New Jersey that includes Newark Bay, as well as portions of the Passaic River, the Hackensack River and other surrounding waterways. The U.S. Environmental Protection Agency (EPA) has designated various portions of the Newark Bay Complex as federal Superfund sites that must be investigated and remediated under the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA).

In addition, PSEG Power has retained ownership of certain liabilities excluded from the sale of its fossil generation portfolio, primarily related to obligations under New Jersey and Connecticut state laws to investigate and remediate the sites. We are also currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, and the costs and penalties of any such remediation efforts could be material.

For further information regarding the matters described above, as well as other matters that may impact our financial condition and results of operations, see Item 8. Note 12. Commitments and Contingent Liabilities.

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Nuclear

In May 2025, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants zero emission certificate (ZEC) sales concluded. Pursuant to a process established by the BPU, ZECs were purchased from these nuclear plants by the electric distribution companies (EDCs) in New Jersey. As previously noted, the Federal government established a PTC for electricity generated using existing nuclear energy, which began January 2024 and continues through 2032 and impacted PSEG Power's decision not to apply for the next ZEC three-year eligibility period starting June 2025. The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts. The PTC rate and the gross receipts threshold are subject to annual inflation adjustments. ZEC revenue recorded has been reduced by the estimated PTCs generated from these nuclear plants. The PTC amounts recorded to date are subject to change based on several factors, including but not limited to, adjustments to estimated market prices and generation and the issuance of authoritative guidance by Treasury/the Internal Revenue Service, including clarification of the definition of “gross receipts” used to determine the phase out. Any adjustments to amounts previously recorded could be material. We continue to analyze the impact of the PTC, including any future guidance from the U.S. Treasury to assess any impact of PTCs on expected ZEC payments and/or any future ZEC application periods.

Demand, Supply and Energy Costs

An increasing demand for power and a lack of sufficient new generation resources in PJM and in New Jersey, has raised resource adequacy concerns and has resulted in higher electricity costs for our customers in 2025. Prices from the July 2024 PJM annual capacity market auction, which were approximately 10 times higher than prices from the 2023 auction and which impacted customer bills, provoked concern from state regulators and legislators and have created regulatory uncertainty. Prices from the July 2025 capacity market auction were higher than those produced by the July 2024 auction and PJM indicated that the prices would have been even higher if not for the existence of a FERC-approved ceiling, which remained in effect for the December 2025 auction and which PJM has recently indicated it will seek to extend for two more auction cycles. In January 2026, the White House’s National Energy Dominance Council signed an agreement with the governors of all 13 states in the PJM region that memorializes a “statement of principles” intended to prompt PJM to make major changes to its capacity market, including running a “reliability backstop auction” to procure new generation capacity to provide 15-year “price certainty”. PJM has committed to run this backstop auction and is targeting a September 2026 date following FERC approval of all needed rule changes. There are outstanding questions associated with this auction, including whether the procurement costs will be disproportionately allocated to zones where demand exceeds supply. In addition, in 2025, FERC both issued an order that will encourage optionality for “large load” customers like data centers by facilitating co-location with generation, and initiated a rulemaking to establish definitive rules for future large customer connections intended to ensure reliability and address resource adequacy concerns. See Item 1. Business—Regulatory Issues—Federal Regulation.

As a result of the capacity market price increases, the costs of which are flowed through to customers, and per direction to EDCs from the BPU, PSE&G filed a petition in May 2025 that provided proposals to mitigate bill impacts to customers. In June 2025, the BPU approved a settlement under which PSE&G applied a credit to each residential electric customer’s monthly bill for July 2025 and August 2025, with the offset being charged on monthly bills for September 2025 through February 2026. PSE&G agreed to waive carrying costs on the outstanding credit amount. In addition, PSE&G agreed to: extend protections precluding the shut-off of eligible residential customers, normally available during the winter months, to the period from July 1, 2025 through September 30, 2025; offer residential customers deferred payment arrangements with terms of up to twenty-four months for the payment of overdue billed amounts; and waive all reconnection fees for residential customers during the period from July 1, 2025 through September 30, 2025. In September 2025, the New Jersey Legislature enacted a law prohibiting disconnection for non-payment during the period June 15 through August 31, beginning in 2026, and for such period annually thereafter, for certain qualified electric and gas customers. This new requirement for a summer shutoff moratorium and the extended deferred payment arrangements have increased our Accounts Receivable and bad debt expense in 2025 with potential additional increases in the future.

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Federal and State Executive Orders and State Legislative and Other Activity

There have been a number of federal executive orders during the past year, including but not limited to orders requiring retiring generating units to stay on-line beyond their retirement date to mitigate system reliability risk and orders imposing widespread and substantial tariffs on imports.

There has been increased New Jersey state legislative activity and executive orders regarding energy affordability, resource adequacy and regulatory topics.

We are continuing to monitor the federal and state legislative activity and executive orders, certain of which may require regulatory actions to implement, and their impacts on our supply chain, business, cash flow, results of operations and financial condition.

Interest Rate Matters

PSEG’s long-term financing plan is designed to replace maturities and support funding its capital program. Given our financing needs, the prevailing interest rate environment will be a key factor in determining interest expense on variable-rate debt and long-term rates on future financing plans. In order to increase the predictability of interest expense, we may use interest rate hedges to help limit our exposure to fluctuating interest rates and fix a portion of our interest rate exposure for anticipated long-term financing plans at PSEG and PSEG Power. PSE&G’s interest rate risk is moderated due to annual transmission rate filings and distribution recoveries through periodic rate filings.

Tax Legislation

The enactment, amendment or repeal of federal or state tax legislation and/or the clarification of previously enacted tax laws could have a material impact on our effective tax rate and cash tax position.

In August 2022, the IRA enacted a 15% corporate alternative minimum tax (CAMT), which is based on adjusted financial statement income, and established a PTC for existing qualified nuclear facilities. In February 2026, the U.S. Treasury issued Notice 2026-07 (CAMT Notice) which clarifies AFSI computation by allowing an adjustment to deduct certain repair and maintenance costs that are capitalized in the applicable financial statement. This CAMT Notice will result in a reduction to PSEG’s and PSE&G’s AFSI for CAMT purposes. However, aspects of the IRA provisions for CAMT and PTCs remain unclear; therefore, the issuance of future authoritative guidance could materially impact PSEG’s and PSE&G’s results of operations, financial condition and cash flows.

In April 2023, the U.S. Treasury issued Revenue Procedure 2023-15 that provides a Natural Gas Safe Harbor (NGSH) method of accounting to determine the annual repair tax deduction for gas T&D property. As a result of the CAMT Notice, PSE&G intends to adopt the NGSH method for its gas distribution assets in its 2025 Federal tax return, including a historical cumulative IRC Section 481(a) adjustment. While PSEG is still evaluating this guidance, it expects that the additional repair deductions will reduce our taxable income and AFSI, and will result in lower cash taxes.

In July 2025, “An Act to Provide for Reconciliation Pursuant to Title II of H. Con. Res. 14” (the Act) was signed into law. The Act made no material changes to the PTC for existing qualified nuclear generation facilities. The Act permanently extends 100% bonus depreciation to qualified business property retroactive to January 19, 2025. The impact of the Act on PSEG’s and PSE&G’s financial statements is subject to continued evaluation.

Future Outlook

Our future success will be influenced by our ability to continue to maintain strong operational and financial performance, address regulatory and legislative developments that impact our business and respond to the issues and challenges described below. In order to do this, we will seek to:

•
obtain approval of and execute on our utility capital investment program to meet increasing customer demand, modernize our infrastructure, improve the reliability and resilience of the service we provide to our customers, and align our sustainability and climate goals with New Jersey’s energy policy;

•
obtain a fair return for our T&D investments through our transmission formula rate, existing rate incentives, distribution infrastructure and clean energy investment programs and periodic distribution base rate case proceedings;

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•
focus on controlling costs while maintaining safety, reliability and customer satisfaction and complying with applicable standards and requirements;

•
manage the risks and opportunities in federal and state policies related to energy;

•
advocate for appropriate regulatory guidance on the PTC to ensure long-term support for New Jersey’s largest carbon-free generation resource, and adapt our hedging program accordingly, and realize the value of our consistent and reliable, carbon-free nuclear output;

•
engage constructively with our multiple stakeholders, including regulators, government officials, customers, employees, investors, suppliers and the communities in which we do business or are seeking to do business; and

•
deliver on our human capital management strategy to attract, develop and retain a high-performing diverse workforce.

In addition to the risks described elsewhere in this Form 10-K for 2025 and beyond, the key issues and challenges we expect our business to confront include:

•
regulatory and political uncertainty with regard to Federal and State energy and related policies, including transmission planning and rates policy, the role of distribution utilities and decarbonization impacts, design of energy and capacity markets, resource adequacy and affordability, tax regulation and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceedings;

•
performance of the financial markets, including the impact on our pension funding requirements and interest rates on our future financing plans;

•
continuing to manage costs and maintain affordable customer rates, which could impact customer collections, investment programs and have other impacts;

•
the increasing frequency, sophistication and magnitude of cybersecurity attacks against us and our respective vendors and business partners who may have our sensitive information and/or access to our environment, and the increasing frequency and magnitude of physical attacks on electric and gas infrastructure;

•
future changes in federal and state tax laws or any other associated tax guidance; and

•
the impact of changes in energy demand, natural gas and electricity prices and PJM’s challenge to ensure resource adequacy to meet demand growth amidst efforts to decarbonize several sectors of the economy.

We continually assess a broad range of strategic options to maximize long-term shareholder value and address the interests of our multiple stakeholders. We consider a wide variety of factors when determining how and when to efficiently deploy capital, including the performance and prospects of our businesses; returns and the sustainability and predictability of future earnings streams; the views of investors, regulators, public policy initiatives, rating agencies, customers and employees; our existing indebtedness and restrictions it imposes; and tax considerations, among other things. Strategic options available to us include:

•
investments in PSE&G, including T&D facilities to enhance reliability, resiliency and modernize the system to meet the growing needs and increasingly higher expectations of customers, and clean energy investments, particularly our EE programs;

•
continued operation of our nuclear generation facilities that are expected to be supported by the PTC through 2032, nuclear capacity uprates, such as our planned Salem power uprate supported by a clean energy PTC, as well as obtaining license extensions and energy and/or emission credit sales with potential customers seeking consistent and reliable carbon-free power, as well as opportunities that may arise from our enabling of new nuclear projects, including providing services for these projects;

•
investments in competitive, regulated transmission and the potential enabling of investments in generation through PJM processes and BPU solicitations that provide revenue predictability and reasonable risk-adjusted returns; and

•
acquisitions, dispositions, development and other transactions involving our common stock, assets or businesses that could provide value to customers and shareholders.

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There can be no assurance, however, that we will successfully develop and execute any of the strategic options noted above, or any additional options we may consider in the future. The execution of any such strategic plan may not have the expected benefits or may have unexpected adverse consequences.

RESULTS OF OPERATIONS

Years Ended December 31,

2025

2024

2023

Earnings

Millions, except per share data

PSE&G

$

1,745

$

1,547

$

1,515

PSEG Power & Other (A)(B)

366

225

1,048

PSEG Net Income

$

2,111

$

1,772

$

2,563

PSEG Net Income Per Share (Diluted)

$

4.22

$

3.54

$

5.13

(A)
PSEG Power & Other results in 2023 include a $239 million after-tax pension charge due to the settlement of a portion of the qualified pension plans.

(B)
Other includes after-tax activities at the parent company, PSEG LI and Energy Holdings as well as intercompany eliminations.

PSEG Power’s results above include the Nuclear Decommissioning Trust (NDT) Fund activity and the impacts of non-trading commodity mark-to-market (MTM) activity, which consist of the financial impact from positions with future delivery dates.

The variances in our Net Income attributable to changes related to the NDT Fund and MTM are shown in the following table:

Years Ended December 31,

2025

2024

2023

Millions, after tax

NDT Fund and Related Activity (A) (B)

$

136

$

81

$

109

Non-Trading MTM Gains (Losses) (C)

$

(54

)

$

(151

)

$

959

(A)
NDT Fund activity includes gains and losses on NDT securities which are recorded in Net Gains (Losses) on Trust Investments. See Item 8. Note 9. Trust Investments for additional information. NDT Fund activity also includes interest and dividend income and other costs related to the NDT Fund recorded in Net Other Income (Deductions), interest accretion expense on PSEG Power’s nuclear Asset Retirement Obligation (ARO) recorded in Operation & Maintenance (O&M) Expense and the depreciation related to the ARO asset recorded in Depreciation and Amortization (D&A) Expense.

(B)
Net of tax (expense) benefit of $(87) million, $(56) million, and $(74) million for the years ended December 31, 2025, 2024 and 2023, respectively.

(C)
Net of tax (expense) benefit of $21 million, $59 million, and $(376) million for the years ended December 31, 2025, 2024 and 2023, respectively.

Our increase in Net Income for 2025 as compared to 2024 was driven primarily by

•
higher earnings as a result of the 2024 distribution base rate case settlement and continued investments in T&D clause programs at PSE&G and higher energy and capacity prices at PSEG Power, and

•
changes in the NDT Fund and MTM gains (losses) as shown in the table above.

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Our results of operations are primarily comprised of the results of operations of our principal operating segments, PSE&G and PSEG Power, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 8. Note 23. Related-Party Transactions.

PSEG

Increase /

Increase /

Years Ended December 31,

(Decrease)

(Decrease)

2025

2024

2023

2025 vs. 2024

2024 vs. 2023

Millions

Millions

%

Millions

%

Operating Revenues

$

12,168

$

10,290

$

11,237

$

1,878

18

$

(947

)

(8

)

Energy Costs

4,159

3,393

3,260

766

23

133

4

Operation and Maintenance (A)

3,772

3,362

3,157

410

12

205

6

Depreciation and Amortization

1,257

1,182

1,135

75

6

47

4

Net Gains (Losses) on Trust Investments

189

127

189

62

49

(62

)

(33

)

Net Other Income (Deductions)

145

154

173

(9

)

(6

)

(19

)

(11

)

Net Non-Operating Pension and OPEB (Costs) Credits

65

73

(218

)

(8

)

(11

)

291

N/A

Interest Expense

1,005

882

748

123

14

134

18

Income Tax Expense

263

53

518

210

N/A

(465

)

(90

)

(A)
Includes amortization of EE programs regulatory investment expenditures of $169 million, $125 million and $82 million for the years ended December 31, 2025, 2024 and 2023, respectively.

The 2025, 2024 and 2023 amounts in the preceding table for Operating Revenues and O&M costs each include $644 million, $592 million and $533 million, respectively, for PSEG LI’s subsidiary, Long Island Electric Utility Servco, LLC (Servco). These amounts represent the O&M pass-through costs for the Long Island operations, the full reimbursement of which is reflected in Operating Revenues. See Item 8. Note 3. Variable Interest Entity for additional information. The following discussions for PSE&G and PSEG Power provide a detailed explanation of their respective variances.

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PSE&G

Years Ended December 31,

Increase /

(Decrease)

Increase /

(Decrease)

2025

2024

2023

2025 vs. 2024

2024 vs. 2023

Millions

Millions

%

Millions

%

Operating Revenues

$

9,558

$

8,449

$

7,807

$

1,109

13

$

642

8

Energy Costs

3,782

3,189

3,010

593

19

179

6

Operation and Maintenance (A)

2,253

1,949

1,843

304

16

106

6

Depreciation and Amortization

1,116

1,025

980

91

9

45

5

Net Other Income (Deductions)

64

64

80

—

—

(16

)

(20

)

Net Non-Operating Pension and OPEB Credits

70

77

114

(7

)

(9

)

(37

)

(32

)

Interest Expense

644

582

493

62

11

89

18

Income Tax Expense

152

298

160

(146

)

(49

)

138

86

(A) Includes amortization of EE programs regulatory investment expenditures of $169 million, $125 million and $82 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Year Ended December 31, 2025 as compared to 2024

Operating Revenues increased $1,109 million due to changes in delivery, clause, commodity and other operating revenues.

Delivery Revenues are primarily derived from revenues recovered on our regulated investments in rate base and costs through periodic filings of distribution rate cases, approved distribution investment recovery programs and the annual filing of transmission formula rates. Due to PSE&G’s electric and gas distribution CIP decoupling mechanism, there is minimal impact from sales volumes on most distribution delivery revenues. Also included in delivery revenues are revenue credits to customers to flowback tax benefits realized by PSE&G. These revenue credits are offset in Income Tax Expense.

Delivery revenues increased $584 million due primarily to $577 million from increased electric and gas revenues primarily as a result of the 2024 distribution base rate case, $87 million from higher GPRC revenues and a $44 million increase in transmission revenues due primarily to higher rate base investments, offset primarily by a $146 million increase in revenue credits flowed back to customers as part of our TAC mechanism.

Clause Revenues are revenues from various pass through regulatory programs for which PSE&G earns no margin. These revenues are entirely offset by the amortization of related costs in O&M, D&A and Interest and Income Tax Expense, which were originally recognized as regulatory assets.

Clause Revenues decreased $94 million due primarily to a $186 million decrease in Tax Adjustment Credits (TAC) and Green Program Recovery Charge (GPRC) deferrals, offset by $91 million in higher Societal Benefits Clause (SBC) collections.

Commodity Revenues are revenues from customers choosing default electric (basic generation service or BGS) and gas supply (basic gas supply service or BGSS) from PSE&G. PSE&G procures the BGS and BGSS on behalf of these retail customers and earns no margin on this service as all costs are passed back to the BGS and BGSS customers. The changes in Commodity Revenues for both electric and gas are entirely offset by changes in Energy Costs.

Commodity Revenues increased $706 million due to higher electric BGS revenues of $575 million primarily from higher prices, and higher gas BGSS revenues of $131 million primarily from higher sales volumes.

Other Operating Revenues are primarily comprised of revenues derived from various GPRC programs including Transition Renewable Energy Certificates (TREC) revenues, Community Solar collections and the Successor Solar Incentive Program (SuSI) and ZECs. The revenues from these programs offset costs included in Energy Costs. In addition, other operating revenues include revenues from our Appliance Service Business (ASB) which offers various appliance protection and repair plans to customers.

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Other Operating revenues decreased $87 million due primarily to a decrease in ZECs as a result of the ZEC collection ending effective May 31, 2025.

Operating Expenses

Energy Costs increased $593 million. This is offset by changes in Commodity Revenues and Other Operating Revenues.

Operation and Maintenance increased $304 million due primarily to $178 million in higher clause and renewable expenditures, $72 million in higher distribution and transmission operational expenditures and $49 million in higher other operating and service company expenses.

Depreciation and Amortization increased $91 million due primarily to an increase in depreciation due to higher plant placed in service and increases in the amortization of software and Regulatory Assets and Liabilities.

Net Non-Operating Pension and OPEB Credits decreased $7 million due primarily to a decrease in the expected return on plan assets.

Interest Expense increased $62 million due primarily to incremental debt and the replacement of maturing debt at higher rates.

Income Tax Expense decreased $146 million primarily due to an increase in the flowback of excess deferred income tax benefits to customers, partially offset by higher pre-tax income.

Year Ended December 31, 2024 as compared to 2023

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2024 as filed with the SEC on February 25, 2025 for information related to the year ended December 31, 2024 as compared to 2023, which information is incorporated herein by reference.

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PSEG Power & Other

Years Ended December 31,

Increase /

(Decrease)

Increase /

(Decrease)

2025

2024

2023

2025 vs. 2024

2024 vs. 2023

Millions

Millions

%

Millions

%

Operating Revenues

$

3,722

$

2,807

$

4,533

$

915

33

$

(1,726

)

(38

)

Energy Costs

1,489

1,170

1,353

319

27

(183

)

(14

)

Operation and Maintenance

1,519

1,413

1,314

106

8

99

8

Depreciation and Amortization

141

157

155

(16

)

(10

)

2

1

Net Gains (Losses) on Trust Investments

189

127

189

62

49

(62

)

(33

)

Net Other Income (Deductions)

84

95

97

(11

)

(12

)

(2

)

(2

)

Net Non-Operating Pension and OPEB Costs

5

4

332

1

25

(328

)

(99

)

Interest Expense

364

305

259

59

19

46

18

Income Tax Expense (Benefit)

111

(245

)

358

356

N/A

(603

)

N/A

Year Ended December 31, 2025 as compared to 2024

Operating Revenues increased $915 million due primarily to changes in generation and gas supply and other operating revenues.

Generation Revenues increased $493 million due primarily to

•
a net increase of $192 million due primarily to higher average realized energy prices and volumes sold in 2025,

•
a net increase of $153 million in capacity revenue due primarily to higher capacity prices, and

•
a net increase of $120 million due to lower MTM losses in 2025 as compared to 2024. Of this amount, there was a $101 million increase due to positions reclassified to realized upon settlement, coupled with a $19 million increase due to changes in forward prices in 2025 as compared to 2024.

Gas Supply Revenues increased $362 million due primarily to

•
a net increase of $246 million in sales under the BGSS contract due primarily to $126 million from higher sales prices, and $120 million from higher sales volumes,

•
a net increase of $97 million related to sales to third parties due primarily to $112 million from higher sales prices, partially offset by $15 million from lower sales volumes, and

•
a net increase of $19 million due primarily to MTM gains in 2025 as compared to MTM losses in 2024, primarily from positions reclassified to realized upon settlement.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet PSEG Power’s obligation under its BGSS contract with PSE&G. Energy Costs increased $319 million due to

Gas costs increased $313 million due primarily to

•
a net increase of $231 million related to sales under the BGSS contract, of which $133 million was due to higher average prices, and $98 million was due to higher send out volumes, and

•
a net increase of $78 million related to sales to third parties due primarily to $81 million from higher average prices.

Generation costs increased $6 million due primarily to increased fuel costs at nuclear.

Operation and Maintenance increased $106 million due primarily to higher Servco operating costs, and increased planned refueling outage costs in 2025.

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Depreciation and Amortization decreased $16 million due primarily to revised estimated useful lives in April 2025 for the Salem and Hope Creek nuclear plants based on the expectation that a 20-year license extension will be approved for these facilities.

Net Gains (Losses) on Trust Investments increased $62 million due primarily to NDT investments with a $59 million increase in net unrealized gains in 2025 on equity securities, and a $4 million increase in net realized gains in 2025.

Net Other Income (Deductions) decreased $11 million due primarily to an increase in donations, partially offset by higher NDT dividend income.

Interest Expense increased $59 million due primarily to incremental debt and the replacement of maturing long-term debt at higher rates.

Income Tax Expense (Benefit) variance of $356 million due primarily to the absence of the benefit from nuclear PTCs in 2025 and higher pre-tax income.

Year Ended December 31, 2024 as compared to 2023

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2024 as filed with the SEC on February 25, 2025 for information related to the year ended December 31, 2024 as compared to 2023, which information is incorporated herein by reference.

LIQUIDITY AND CAPITAL RESOURCES

The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our two direct major operating subsidiaries.

Financing Methodology

We expect our capital requirements to be met through internally generated cash flows and external financings, consisting of short-term debt for working capital needs and long-term debt for capital investments.

PSE&G’s sources of external liquidity include a $1 billion multi-year revolving credit facility. PSE&G uses internally generated cash flow and its commercial paper program to meet seasonal, intra-month and temporary working capital needs. PSE&G does not engage in any intercompany borrowing or lending arrangements. PSE&G maintains a back-up credit facility in an amount sufficient to cover the commercial paper and letters of credit outstanding. PSE&G’s dividend payments to/capital contributions from PSEG are consistent with its capital structure objectives which have been established to maintain investment grade credit ratings. PSE&G’s long-term financing plan is designed to replace maturities, fund a portion of its capital program and manage short-term debt balances. Generally, PSE&G uses either secured medium-term notes or first mortgage bonds to raise long-term capital.

PSEG, PSEG Power, Energy Holdings, PSEG LI and Services participate in a corporate money pool, an aggregation of daily cash balances designed to efficiently manage their respective short-term liquidity needs, which are accounted for as intercompany loans. Servco does not participate in the corporate money pool. Servco’s short-term liquidity needs are met through an account funded and owned by LIPA.

PSEG and PSEG Power have access through sub-limits to a revolving Master Credit Facility, which provides for $2.75 billion of multi-year credit capacity. The current PSEG sub-limit is $1.5 billion and current PSEG Power sub-limit is $1.25 billion. Sub-limits can be adjusted subject to the terms of the Master Credit Facility.

PSEG’s available sources of external liquidity may include the issuance of long-term debt securities and the incurrence of additional indebtedness through our commercial paper program back-stopped by our credit facility. Our current sources of external liquidity include the Master Credit Facility. This facility is available to back-stop PSEG’s commercial paper program, issue letters of credit and for general corporate purposes. PSEG’s Master Credit Facility and the commercial paper program are available to support PSEG’s working capital needs and are also available to make equity contributions or provide liquidity support to its subsidiaries. Additionally, from time to time, PSEG enters into short-term loan agreements designed to enhance its liquidity position.

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PSEG Power’s sources of external liquidity include the Master Credit Facility and PSEG Power’s letter of credit facilities and may include the issuance of long-term debt securities and entering into short-term loan agreements. Credit capacity is primarily used to provide collateral in support of PSEG Power’s sales and purchases of electricity and natural gas as the market prices for energy and fuel fluctuate, and to meet potential collateral postings in the event that PSEG Power is downgraded to below investment grade by Standard & Poor’s (S&P) or Moody’s. PSEG Power’s dividend payments to PSEG are also designed to be consistent with its capital structure objectives which have been established to maintain investment grade credit ratings and provide sufficient financial flexibility.

Operating Cash Flows

We continue to expect our operating cash flows combined with cash on hand and financing activities to be sufficient to fund planned capital expenditures and shareholder dividends.

For the year ended December 31, 2025, our operating cash flow increased $1,165 million, as compared to 2024. The net increase was primarily due to a net change at PSE&G, as discussed below, combined with an inflow of $22 million in net cash collateral postings in 2025 as compared to a $131 million outflow in 2024 at PSEG Power, and an $89 million decrease in payments to counterparties at PSEG Power.

PSE&G

PSE&G’s operating cash flow increased $643 million from $1,725 million to $2,368 million for the year ended December 31, 2025, as compared to 2024. The increase was due primarily to a decrease in net regulatory deferrals, a decrease in materials and supplies inventory, lower tax payments, and the timing of vendor payments, partially offset by an increase in accounts receivable.

Short-Term Liquidity

PSEG meets its short-term liquidity requirements, as well as those of PSEG Power, primarily through the issuance of commercial paper and, from time to time, short-term loans. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facility.

Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs.

In March 2025, PSEG, PSEG Power and PSE&G executed a one year extension to their existing $3.75 billion revolving credit facilities, extending the maturity through March 2029 and PSEG Power amended certain provisions in the Master Credit Facility including removal of subsidiary guarantees of PSEG Power. The PSEG Power letter of credit facilities and term loans were also amended to be consistent with the Master Credit Facility, and the $150 million uncommitted credit facility at a subsidiary of PSEG Power was terminated.

In December 2025, PSEG Power amended its existing $400 million 364-day variable rate term loan, which increased the balance to $500 million and extended the maturity to December 2026.

In February 2026, PSEG entered into a 364-day variable rate term loan agreement for $500 million.

PSEG Power has uncommitted credit facilities totaling $425 million, which can be utilized for letters of credit. As of December 31, 2025, PSEG Power had $243 million in letters of credit outstanding under these uncommitted credit facilities.

PSE&G has an uncommitted credit facility totaling $30 million, which can be utilized for letters of credit. As of December 31, 2025, PSE&G's letters of credit outstanding were immaterial under this uncommitted credit facility.

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Our total committed credit facilities and available liquidity as of December 31, 2025 were as follows:

As of December 31, 2025

Company/Facility

Total

Facility

Usage

Available

Liquidity

Millions

PSEG

$

1,500

$

719

$

781

PSE&G

1,000

351

649

PSEG Power

1,325

82

1,243

Total

$

3,825

$

1,152

$

2,673

For additional information, see Item 8. Note 13. Debt and Credit Facilities.

We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements, including to satisfy any additional collateral requirements. As of December 31, 2025, our liquidity position, including our credit facilities and access to external financing, was expected to be sufficient to meet our projected stressed requirements over our 12-month planning horizon. PSEG analyzes its liquidity requirements using stress scenarios that consider different events, including changes in commodity prices and the potential impact of PSEG Power losing its investment grade credit rating from S&P or Moody’s, which would represent a two-level downgrade from its current Moody’s and S&P ratings. In the event of a deterioration of PSEG Power’s credit rating, certain of PSEG Power’s agreements allow the counterparty to demand further performance assurance. The potential additional collateral that we would be required to post under these agreements if PSEG Power were to lose its investment grade credit rating was approximately $703 million and $618 million as of December 31, 2025 and 2024, respectively. See Item 8. Note 12. Commitments and Contingent Liabilities for additional discussion of PSEG Power’s agreements.

Long-Term Debt Financing

During the next twelve months,

•
PSE&G has $450 million of 0.95% Secured Medium-Term Notes Series N, due March 2026, and

•
PSE&G has $425 million of 2.25% Secured Medium-Term Notes Series L, due September 2026.

For additional information, see Item 8. Note 13. Debt and Credit Facilities.

Debt Covenants

Our credit agreements contain maximum debt to equity ratios and other restrictive covenants and conditions to borrowing. We are currently in compliance with all of our debt covenants. Continued compliance with applicable financial covenants will depend upon our future financial position, level of earnings and cash flows, as to which no assurances can be given.

In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As of December 31, 2025, PSE&G’s Mortgage coverage ratio was 3.9 to 1 and the Mortgage would permit up to approximately $10.2 billion aggregate principal amount of new Mortgage Bonds to be issued against additions and improvements to its property.

Default Provisions

Our bank credit agreements and indentures contain various, customary default provisions that could result in the potential acceleration of indebtedness under the defaulting company’s agreement.

In particular, PSEG’s bank credit agreement contains provisions under which certain events, including an acceleration of material indebtedness under PSE&G’s and PSEG Power’s respective financing agreements, a failure by PSEG, PSE&G or PSEG Power to satisfy certain final judgments and certain bankruptcy events by PSEG, PSE&G or PSEG Power, would constitute an event of default under the PSEG bank credit agreements. Under the PSEG bank credit agreements, it would also be an event of default if, in certain circumstances, either PSE&G or PSEG Power ceases to be wholly owned by PSEG. The PSE&G and PSEG Power bank credit agreements include certain similar default provisions; however, such provisions only

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Table of Contents

relate to the respective borrower under such agreement and its subsidiaries and do not contain cross default provisions to each other. The PSE&G and PSEG Power bank credit agreements do not include cross default provisions relating to PSEG. Each of PSEG's, PSE&G’s and PSEG Power’s bank credit agreements also contain limitations on the incurrence of liens by it and certain of its subsidiaries and PSEG Power’s bank credit agreements contain restrictions on the incurrence of certain subsidiary debt.

PSEG’s senior notes include a cross acceleration provision that may be triggered upon the acceleration of more than $75 million of indebtedness incurred by PSEG. Such provision does not extend to an acceleration of indebtedness by any of PSEG’s subsidiaries. PSEG Power’s senior notes contain a similar provision with respect to the acceleration of more than $75 million of indebtedness incurred by PSEG Power but such provision does not extend to an acceleration of indebtedness by any of PSEG Power’s subsidiaries. Under PSE&G’s medium-term note indenture, an event of default under PSE&G’s mortgage indenture and acceleration of the mortgage bonds would constitute an event of default.

Ratings Triggers

Our debt indentures and credit agreements do not contain any material “ratings triggers” that would cause an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a downgrade, any one or more of the affected companies may be subject to increased interest costs on certain bank debt and certain collateral requirements. In the event that we are not able to affirm representations and warranties on credit agreements, lenders would not be required to make loans.

In accordance with BPU requirements under the BGS contracts, PSE&G is required to maintain an investment grade credit rating. If PSE&G were to lose its investment grade rating, it would be required to file a plan to assure continued payment for the BGS requirements of its customers.

Fluctuations in commodity prices or a deterioration of PSEG Power’s credit rating to below investment grade could increase PSEG Power’s required margin postings under various agreements entered into in the normal course of business. PSEG Power believes it has sufficient liquidity to meet the required posting of collateral which would result from a credit rating downgrade to below investment grade by S&P or Moody’s at today’s market prices.

Common Stock Dividends

Years Ended December 31,

Dividend Payments on Common Stock

2025

2024

2023

Per Share

$

2.52

$

2.40

$

2.28

in Millions

$

1,258

$

1,196

$

1,137

On February 24, 2026, our Board of Directors approved a $0.67 per share common stock dividend for the first quarter of 2026. This reflects an indicative annual dividend rate of $2.68 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. For additional information related to cash dividends on our common stock, see Item 8. Note 21. Earnings Per Share (EPS) and Dividends.

Credit Ratings

If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Credit ratings shown are for securities that we typically issue. Outlooks are shown for the credit ratings at each entity and can be Stable, Negative, or Positive. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.

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Moody’s (A)

S&P (B)

PSEG

Outlook

Stable

Stable

Senior Notes

Baa2

BBB

Commercial Paper

P2

A2

PSE&G

Outlook

Stable

Stable

Mortgage Bonds

A1

A

Commercial Paper

P2

A2

PSEG Power

Outlook

Stable

Stable

Senior Notes

Baa2

BBB

(A)
Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.

(B)
S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.

Other Comprehensive Income

For the year ended December 31, 2025, we had Other Comprehensive Income of $42 million on a consolidated basis. The Other Comprehensive Income was due primarily to $34 million of net unrealized gains related to available-for-sale debt securities, $20 million related to pension and other postretirement benefits, partially offset by $12 million of unrealized losses on derivative contracts accounted for as hedges. See Item 8. Note 20. Accumulated Other Comprehensive Income (Loss), Net of Tax for additional information.

CAPITAL REQUIREMENTS

We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. Projected capital construction and investment expenditures, excluding nuclear fuel purchases, for the next three years are presented in the following table. These projections include Allowance for Funds Used During Construction for PSE&G and Interest Capitalized During Construction for PSEG’s other subsidiaries. These amounts are subject to change, based on various factors. Amounts shown below for PSE&G include currently approved programs. We intend to continue to invest in infrastructure modernization and will seek to extend these and related programs as appropriate.

2026

2027

2028

Millions

PSE&G:

Transmission

$

835

$

950

$

975

Electric Distribution

1,410

1,440

1,520

Gas Distribution

1,130

1,115

1,165

Clean Energy

810

885

700

Total PSE&G

$

4,185

$

4,390

$

4,360

Competitively Bid, FERC Regulated Transmission

20

115

195

PSEG Power & Other

435

330

275

Total PSEG

$

4,640

$

4,835

$

4,830

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PSE&G

PSE&G’s projections for future capital expenditures include material additions and replacements to its T&D systems to meet expected growth and to manage reliability. As project scope and cost estimates develop, PSE&G will modify its current projections to include these required investments. PSE&G’s projected expenditures for the various items reported above are primarily comprised of the following:

•
Transmission—investments focused on growing demand, reliability improvements and replacement of aging infrastructure.

•
Electric and Gas Distribution—investments for new business and demand, reliability improvements and modernization and replacement of equipment that has reached the end of its useful life.

•
Clean Energy—investments associated with customer EE programs, infrastructure supporting EVs and grid-connected solar.

In 2025, PSE&G made $2,731 million of capital expenditures, primarily for T&D system reliability. In addition, PSE&G had $145 million associated with CEF-EE II on-bill repayments included in investing cash flows, as well as cost of removal, net of salvage, of $156 million associated with capital replacements, and expenditures for EE programs of approximately $552 million, which are included in operating cash flows.

Competitively Bid, FERC Regulated Transmission

In December 2023, PJM awarded us an approximately $424 million project to address increasing load and reliability issues in Maryland and northern Virginia as part of its 2022 Window 3 competitive solicitation.

PSEG Power & Other

PSEG’s other projected expenditures are primarily comprised of investments to maintain and enhance current nuclear operations and opportunities to increase nuclear generation at PSEG Power and to purchase hardware, software and office equipment at Services.

In 2025, PSEG Power & Other made capital expenditures of $236 million, excluding $336 million for nuclear fuel, primarily related to various nuclear projects at PSEG Power and various IT projects at Services.

Other Material Cash Requirements

The following table reflects our other material cash requirements which include debt maturities and interest payments, operating lease payments and energy related purchase commitments in the respective periods in which they are due. For additional information, see Item 8. Note 13. Debt and Credit Facilities and Note 6. Leases.

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The table below does not reflect any anticipated cash payments for pension and OPEB or AROs due to uncertain timing of payments. See Item 8. Note 11. Pension, Other Postretirement Benefits (OPEB) and Savings Plans and Note 10. Asset Retirement Obligations (AROs) for additional information.

Total

Amount

Committed

Less

Than

1 Year

2 - 3

Years

4 - 5

Years

Over

5 Years

Millions

Long-Term Recourse Debt Maturities

PSEG

$

5,346

$

—

$

1,300

$

1,900

$

2,146

PSE&G

16,115

875

1,125

675

13,440

PSEG Power

1,250

—

—

750

500

Interest on Recourse Debt

PSEG

1,385

253

466

296

370

PSE&G

10,318

653

1,256

1,183

7,226

PSEG Power (A)

449

68

136

116

129

Operating Leases

PSE&G

103

18

26

20

39

PSEG Power & Other

76

16

32

28

—

Energy-Related Purchase Commitments

PSEG Power (B)

3,049

861

997

489

702

Total

$

38,091

$

2,744

$

5,338

$

5,457

$

24,552

(A)
Based on a blended rate including effects of floating to fixed rate hedging transacted at the Parent level.

(B)
Represents the nuclear fuel and natural gas commitments for the facilities we operate.

CRITICAL ACCOUNTING ESTIMATES

Under accounting guidance generally accepted in the United States (GAAP), many accounting standards require the use of estimates, variable inputs and assumptions (collectively referred to as estimates) that are subjective in nature. Because of this, differences between the actual measure realized versus the estimate can have a material impact on results of operations, financial position and cash flows. We have determined that the following estimates are considered critical to the application of rules that relate to the respective businesses.

Accounting for Pensions and Other Postretirement Benefits (OPEB)

The market-related value of plan assets held for PSEG’s qualified pension and OPEB plans is equal to the fair value of these assets as of year-end. The plan assets are comprised of investments in both debt and equity securities which are valued using quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Plan assets also include investments in unlisted real estate which is valued via third-party appraisals. We calculate pension and OPEB costs using various economic and demographic assumptions.

Assumptions and Approach Used: Economic assumptions include the discount rate and the expected rate of return on plan assets. Demographic pension and OPEB assumptions include projections of future mortality rates, pay increases and retirement patterns, as well as projected health care costs for OPEB.

Assumption

2025

2024

2023

Qualified Pension

Discount Rate

5.50

%

5.68

%

5.02

%

Expected Rate of Return on Plan Assets

8.10

%

8.10

%

8.10

%

OPEB

Discount Rate

5.31

%

5.59

%

4.96

%

Expected Rate of Return on Plan Assets

8.10

%

8.10

%

8.10

%

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The discount rate used to calculate PSEG’s pension and OPEB obligations is determined as of December 31 each year, our measurement date. The discount rate is determined by developing a spot rate curve based on the yield to maturity of a universe of high quality corporate bonds with similar maturities to the plan obligations. The spot rates are used to discount the estimated plan distributions. The discount rate is the single equivalent rate that produces the same result as the full spot rate curve.

Our expected rate of return on plan assets reflects current asset allocations, historical long-term investment performance and an estimate of future long-term returns by asset class, long-term inflation assumptions and a premium for active management.

We utilize a corridor approach that reduces the volatility of reported costs/credits. The corridor requires differences between actuarial assumptions and plan results be deferred and amortized as part of the costs/credits. Amortization occurs only when the accumulated differences exceed 10% of the greater of the benefit obligation or the fair value of plan assets as of each year-end. For PSEG’s qualified pension plan, the excess would be amortized over the average remaining service period of active employees, which is approximately fifteen years.

Effect if Different Assumptions Used: As part of the business planning process, we have modeled future costs assuming an 8.00% expected rate of return and a 5.50% discount rate for 2026 pension costs/credits and a 5.31% discount rate for 2026 OPEB costs/credits. Based upon these assumptions, we have estimated a net periodic pension expense in 2026 of approximately $27 million, or pension income of $10 million, net of amounts capitalized, and net periodic OPEB income in 2026 of approximately $8 million, or $8 million, net of amounts capitalized. Beginning in 2023, our net periodic pension amounts include the impact of the accounting order approved by the BPU authorizing PSE&G to modify its pension accounting for ratemaking purposes. Actual future pension costs/credits and funding levels will depend on future investment performance, changes in discount rates, market conditions, funding levels relative to our projected benefit obligation and accumulated benefit obligation and various other factors related to the populations participating in the pension plans. Actual future OPEB costs/credits will depend on future investment performance, changes in discount rates, market conditions, and various other factors.

The following chart reflects the sensitivities associated with a change in certain assumptions.

% Change

Impact on Benefit Obligation as of December 31, 2025

Increase to

Costs

in 2026

Increase to

Costs, net

of Amounts

Capitalized

in 2026

Assumption

Millions

Qualified Pension

Discount Rate

(1

)%

$

458

$

19

$

13

Expected Rate of Return on Plan Assets

(1

)%

N/A

$

41

$

41

OPEB

Discount Rate

(1

)%

$

58

$

(1

)

$

(1

)

Expected Rate of Return on Plan Assets

(1

)%

N/A

$

4

$

4

See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information.

Derivative Instruments

The operations of PSEG, PSEG Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through executing derivative transactions. Derivative instruments are used to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.

Current accounting guidance requires us to recognize all derivatives on the balance sheet at their fair value, except for derivatives that qualify for and are designated as normal purchases and normal sales contracts.

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Assumptions and Approach Used: In general, the fair value of our derivative instruments is determined primarily by end of day clearing market prices from an exchange, such as the Intercontinental Exchange and Nodal Exchange, among others, or auction prices.

For our wholesale energy business, many of the forward sale, forward purchase, option and other contracts are derivative instruments that hedge commodity price risk, but do not meet the requirements for, or are not designated as, either cash flow or fair value hedge accounting. The changes in value of such derivative contracts are marked to market through earnings as the related commodity prices fluctuate. As a result, our earnings may experience significant fluctuations depending on the volatility of commodity prices.

Effect if Different Assumptions Used: Any significant changes to the fair market values of our derivatives instruments could result in a material change in the value of the assets or liabilities recorded on our Consolidated Balance Sheets and could result in a material change to the unrealized gains or losses recorded in our Consolidated Statements of Operations.

For additional information regarding Derivative Financial Instruments, see Item 8. Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies, Note 15. Financial Risk Management Activities and Note 16. Fair Value Measurements.

Long-Lived Assets

Management evaluates long-lived assets for impairment and reassesses the reasonableness of their related estimated useful lives whenever events or changes in circumstances warrant assessment. Such events or changes in circumstances may be as a result of significant adverse changes in regulation, business climate, counterparty credit worthiness, market conditions, or a determination that it is more-likely-than-not that an asset or asset group will be sold or retired before the end of its estimated useful life.

Assumptions and Approach Used: In the event certain triggers exist indicating an asset/asset group may not be recoverable, an undiscounted cash flow test is performed to determine if an impairment exists. When the carrying value of a long-lived asset/asset group exceeds the undiscounted estimate of future cash flows associated with the asset/asset group, an impairment may exist to the extent that the fair value of the asset/asset group is less than its carrying amount.

For PSEG Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the nuclear generation units are evaluated at the portfolio level. These tests require significant estimates and judgment when developing expected future cash flows. Significant inputs may include, but are not limited to, forward power prices, the impact of PTCs, fuel costs, other operating and capital expenditures, the cost of borrowing and asset sale prices and probabilities associated with any potential sale prior to the end of the estimated useful life or the early retirement of assets. The assumptions used by management incorporate inherent uncertainties that are at times difficult to predict and could result in impairment charges or accelerated depreciation in future periods if actual results materially differ from the estimated assumptions utilized in our forecasts.

In addition, long-lived assets are depreciated under the straight-line method based on estimated useful lives. An asset’s operating useful life is generally based upon operational experience with similar asset types and other non-operational factors. In the ordinary course, management, together with an asset’s co-owners in the case of certain of our jointly-owned assets, make a number of decisions that impact the operation of our generation assets beyond the current year. These decisions may have a direct impact on the estimated remaining useful lives of our assets and will be influenced by the financial outlook of the assets, including future market conditions such as forward energy, capacity prices, and long-term agreements to supply large power users, such as data centers, operating and capital investment costs and any state or federal legislation and regulations, among other items.

Effect if Different Assumptions Used: The above cash flow tests, and fair value estimates and estimated remaining useful lives may be impacted by a change in the assumptions noted above and could significantly impact the outcome, triggering additional impairment tests, write-offs or accelerated depreciation.

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Asset Retirement Obligations (ARO)

PSE&G, PSEG Power and Services recognize liabilities for the expected cost of retiring long-lived assets for which a legal obligation exists. These AROs are recorded at fair value in the period in which they are incurred and are capitalized as part of the carrying amount of the related long-lived assets. PSE&G, as a rate-regulated entity, recognizes Regulatory Assets or Liabilities as a result of timing differences between the recording of costs and costs recovered through the rate-making process. We accrete the ARO liability to reflect the passage of time with the corresponding expense recorded in O&M Expense.

Assumptions and Approach Used: Because quoted market prices are not available for AROs, we estimate the initial fair value of an ARO by calculating discounted cash flows that are dependent upon various assumptions, including:

•
estimation of dates for retirement, which can be dependent on environmental and other legislation,

•
amounts and timing of future cash expenditures associated with retirement, settlement or remediation activities,

•
discount rates,

•
cost escalation rates,

•
market risk premium,

•
inflation rates, and

•
if applicable, past experience with government regulators regarding similar obligations.

We obtain updated nuclear decommissioning cost studies triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2024. When we revise any assumptions used to calculate fair values of existing AROs, we adjust the ARO balance and corresponding long-lived asset which generally impacts the amount of accretion and depreciation expense recognized in future periods.

Nuclear Decommissioning AROs

AROs related to the future decommissioning of PSEG Power’s nuclear facilities comprised nearly 100% or $916 million of PSEG Power’s total AROs as of December 31, 2025. PSEG Power determines its AROs for its nuclear units by assigning probability weighting to various discounted cash flow outcomes for each of its nuclear units that incorporate the assumptions above as well as:

•
potential retirement dates including the probability of license renewals,

•
SAFSTOR alternative, which assumes the nuclear facility can be safely stored and subsequently decommissioned in a period within 60 years after operations,

•
DECON alternative, which assumes decommissioning activities begin after operations, and

•
recovery from the federal government of assumed specific costs incurred for spent nuclear fuel.

Effect if Different Assumptions Used: Changes in the assumptions could result in a material change in the ARO balance sheet obligation and the period over which we accrete to the ultimate liability. Had the following assumptions been applied, our estimates of the approximate impacts on the Nuclear ARO as of December 31, 2025 are as follows:

•
A decrease of 1% in the discount rate would result in a $61 million increase in the Nuclear ARO.

•
An increase of 1% in the inflation rate would result in a $360 million increase in the Nuclear ARO.

•
If we were not reimbursed by the federal government for the spent costs, as prescribed under the Nuclear Waste Policy Act, the Nuclear ARO would increase by $94 million.

Accounting for Regulated Businesses

PSE&G prepares its financial statements to comply with GAAP for rate-regulated enterprises, which differs in some respects from accounting for non-regulated businesses. In general, accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (Regulatory Asset)

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or recognize obligations (Regulatory Liability) if the rates established are designed to recover the costs and if the competitive environment makes it probable that such rates can be charged or collected. This accounting results in the recognition of revenues and expenses in different time periods than that of enterprises that are not regulated.

Assumptions and Approach Used: PSE&G recognizes Regulatory Assets where it is probable that such costs will be recoverable in future rates from customers and Regulatory Liabilities where it is probable that refunds will be made to customers in future billings. The highest degree of probability is an order from the BPU either approving recovery of the deferred costs over a future period or requiring the refund of a liability over a future period.

Virtually all of PSE&G’s Regulatory Assets and Regulatory Liabilities are supported by BPU orders. In the absence of an order, PSE&G will consider the following when determining whether to record a Regulatory Asset or Liability:

•
past experience regarding similar items with the BPU,

•
treatment of a similar item in an order by the BPU for another utility,

•
passage of new legislation, and

•
recent discussions with the BPU.

All deferred costs are subject to prudence reviews by the BPU. When the recovery of a Regulatory Asset or payment of a Regulatory Liability is no longer probable, PSE&G charges or credits earnings, as appropriate.

Effect if Different Assumptions Used: A change in the above assumptions may result in a material impact on our results of operations or our cash flows. See Item 8. Note 5. Regulatory Assets and Liabilities for a description of the amounts and nature of regulatory balance sheet amounts.

Uncertain Tax Positions - Nuclear Production Tax Credits (PTCs)

We are required to make judgments in developing our provision for income tax expense (benefit), including those related to the uncertainty of tax positions taken, or expected to be taken, on a tax return. Our most significant uncertain tax position relates to the estimated benefit associated with PTCs.

Assumptions and Approach Used: We account for uncertain income tax positions using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold.

Management uses judgments in determining the amount of income tax benefit to recognize due to the uncertainties associated with the technical merits of each position and with consideration to the amount of benefit to be sustained upon examination by a taxing authority. The estimated PTC benefits are subject to change based on the issuance of authoritative guidance by the U.S. Treasury. Specifically, clarification of the definition of “gross receipts”, which is used to determine the reduction amount of the PTC, by the U.S. Treasury could affect the amount to be recognized.

Effect if Different Assumptions Used: There were no PTCs recorded for the year ended December 31, 2025. While we believe the amount of PTCs recognized for the year ended December 31, 2024, is more-than-likely to be sustained upon examination, the ultimate outcome could result in material favorable or unfavorable adjustments to our consolidated financial statements. Guidance issued by the U.S. Treasury supporting or not supporting our tax position could result in an additional income tax benefit (expense) between approximately $89 million and $(89) million, respectively. Further, ZEC revenue was reduced by the estimated PTCs generated from PSEG Power’s Salem 1, Salem 2, and Hope Creek nuclear plants for the year ended December 31, 2024. ZEC revenue will be adjusted based upon the actual value of the PTCs generated which is dependent on the U.S. Treasury issuing additional guidance. This would result in an additional adjustment to Net Income between $(29) million and $44 million if our tax position discussed above is, or is not supported, respectively. See Item 8. Note 19. Income Taxes and Note 2. Revenues for more information.

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