PEG 10-K & 10-Q changes, risk factors and insider trading

Macroeconomic considerations, including inflationary levels, gas and electric supply prices that are passed through to customers and other pressures could factor into our regulators’ assessment in approving the size, duration and timing of cost recovery of certain of these programs. Further, certain negative public and political views by certain stakeholders on natural gas and other types of energy infrastructure could result in diminishing support for those investments.

Climate change may increasingly drive change to existing or additional legislation and regulation that may impact our business and shape our customers’ energy preference and sustainability goals.goals, Whileincluding theimpacts CIPof protects PSE&G’s margin variances againstpotential changes in customer usageuse of natural gas and electricity,electricity customerdue demandto electrification over the long-term and the impact on need for naturaladditional gasgeneration couldto decreasemeet asthose aelectric resultneeds. of changing customer preferences favoring electrification and advanced technologies that offer energy efficient options. Electric demand could also be impacted by electrification, including greater adoption of EVs, installation of distributed energy resources, such as behind the meter solar, installation of more energy efficient equipment, flexible load and/or energy storage, and other advances in technology. Further, climate change may adversely impact the economy and reduced economic and consumer activity in our service areas could lower demand for electricity and gas we deliver. Any one or all of theseThese factors could impact the need to invest in our electric and gas T&D systems and, therefore, our company growth rate.

These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining generation facilities and T&D systems, resulting in increased maintenance and capital costs (and potentialpotentially increased financing needs), increased regulatory oversight, and lower customer satisfaction. Where recovery of costs to restore service and repair damaged equipment and facilities is available, any determination by the regulator not to permit timely and full recovery of the costs incurred could have a material adverse effect on our businesses, financial condition, results of operations and prospects.

Further, our business is subject to policy, regulatory, technology and economic uncertainties and contingencies, including regulatory approvals required for our various investments, many of which are beyond our control and may affect planned investments and our ability to meet our targets of net zero GHG emissions by 2030 for Scopes 1 and 2 emissions, or other GHG emissions reduction or climate-related goals that we may set from time to time, in a cost-effective manner or at all.

We may be adversely affected by asset and equipment failures, gas explosions, accidents, critical operating technology or business system failures, natural disasters, severe weather events, acts of war or terrorism or other acts of violence, sabotage, physical attacks or security breaches, cyberattacks, or other incidents, including pandemics, that impact our ability to provide safe and reliable service to our customers and remain competitive and could result in substantial financial losses.

The success of our businesses is dependent on our ability to continue providing safe and reliable service to our customers while minimizing service disruptions. We are exposed to the risk of asset and equipment failures, gas explosions,explosions or leaks, accidents, pandemics, natural disasters, severe weather events, acts of war or terrorism or other acts of violence, including active shooter situations, sabotage, physical attacks or security breaches, cyberattacks or other incidents, which could result in damage to or destruction of our substations or other facilities or infrastructure, or damage to persons or propertyproperty, andfire, toloss of life, outages, mechanical problems, environmental pollution, electric and gas supply interruptions.interruptions or other adverse impacts to our business. Further, a major failure of availability or performance of a critical operating technology or business system, and inadequate preparation or execution of business continuity or disaster recovery plans for the loss of one or several critical systems, could result in extended disruption to operations or business processes, damage to systems and/or loss of data. We have historically benefited from access to mutual aid, a voluntary and reciprocal arrangement with other utilities that provides access to a trained and flexible labor force which has helped to reduce outage restoration times during extreme weather events. There is no guarantee that we will have continued access to mutual aid as the frequency of severe weather events rises.

The supply chain of goods and services could be impacted by several factors, including sanctions, tariffs, manufacturing labor shortages, domestic and international shipping constraints, increases in demand, physical alterations in technologies that create cyber risks, and shortages of raw materials and specialty components. This could cause price increases in some areas and delivery delays of certain goods, which could increase our costs and impact our operations.

our current level of indebtedness and compliance with covenants in our debt instruments and credit agreements;

Cybersecurity threats to the energy market infrastructure are increasing in sophistication, magnitude and frequency, particularly with the regularity of virtual operations.frequency. Because of the inherent vulnerability of infrastructure and technology and operational systems to disability or failure due to hacking, viruses, malicious or destructive code, phishing and other social engineering attacks, denial of service attacks, ransomware, acts of war or terrorism, or other cybersecurity incidents, we face increased risk of cyberattack. We rely on information and operational technology systems and network infrastructure to operate our generation and T&D systems.systems and to conduct power marketing and hedging activities. We also store sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, infrastructure, employees, shareholders, customers and vendors on our IT systems and conduct power marketing and hedging activities.systems. In addition, the operation of our business is dependent upon the IT systems of Nth parties (i.e., our third parties and other business relationships, including fourth parties, etc.), including our vendors, regulators, RTOs and ISOs, among others. Our and Nth-party operational and IT systems and products may be vulnerable to cybersecurity attacks involving fraud, malice or oversight on the part of our employees, other insiders or Nth parties, whether domestic or foreign sources. Further, new types of cyberattacks, whether directed at our own infrastructure and technology and operational systems or that of third parties, may be generated or enhanced through the use of Artificial Intelligence (AI) and/or cloud-based infrastructure. A successful cybersecurity attack may result in unauthorized use of our systems to cause disruptions at an Nth party. Cybersecurity risks to our operations include:

disruption of the operation of our assets, the fuel supply chain, the power grid and gas T&D, theft of confidential company, employee, shareholder, vendor or customer information, and critical energy infrastructure information, which may cause us to be in breach of certain covenants and contractual, legal or regulatory obligations and pose risk to our system and our customers, general business system and process interruption or compromise, including preventing us from servicing our customers, working remotely, collecting revenues or therecording, ability to record, processprocessing and/or reportreporting financial information correctly, and breaches of vendors’ infrastructures where our confidential information is stored.

We and our Nth-party vendors have been and will continue to be subject to cybersecurity attacks, including but not limited to ransomware, denial of service, business email compromises, and malware attacks. To date, there has been no material impact or reasonably likely material impact on our business strategy, results of operations or financial condition from these attacks or other cybersecurity incidents, including as a result of prior cybersecurity incidents. However, we may be unable to prevent all such attacks in the future from having such a material impact as such attacks continue to increase in sophistication and frequency. If a significant cybersecurity event or breach occurs within our company or with one of our material vendors, we could be exposed to significant loss of revenue, material repair costs to intellectual and physical property, significant fines and penalties if determined that we were in non-compliance with existing laws and regulations, significant litigation costs, increased costs to finance our businesses, negative publicity, damage to our reputation and loss of confidence from our customers, regulators, investors, vendors and employees. The misappropriation, corruption or loss of personally identifiable information and other confidential data from us or one of our vendors could lead to significant breach notification expenses, mitigation expenses such as credit monitoring, and legal and regulatory fines and penalties. Moreover, new or updated security laws or regulations, including laws and regulations that respond to evolving application of AI, or unforeseen threat sources could require changes in current measures taken by us and our business operations, which could result in increased costs and adversely affect our financial statements.costs. Similarly, a significant cybersecurity event or breach experienced by a competitor, regulatory authority, RTO, ISO, or vendor could also materially impact our business and results of operations via enhanced legal and regulatory requirements. The amount and scope of insurance we maintain against losses that result from cybersecurity incidents may not be sufficient to cover losses or adequately compensate for resulting business disruptions. To address the risks to our information and operational technology systems, we maintain a cybersecurity program that includes policies and controls, cybersecurity insurance, cybersecurity governance and compliance, awareness and training, table-top exercises, logging and monitoring, and testing. These preventative actions minimizereduce the likelihood and potential impact of cybersecurity breaches. For a discussion of state and federal cybersecurity regulatory requirements and information regarding our cybersecurity program, see Item 1C. Cybersecurity. Further, we are subject to changing data protection laws in the U.S. and abroad. Legal requirements and regulatory scrutiny for the collection, storage, handling, use, disclosure, transfer, and security of personal data continue to evolve and expand, which may present material obligations and risks to our business, including expanded compliance burdens, restrictions on transfer of personal data, costs, and enforcement risks.

Certain events such as an aging workforce looking to retire without an opportunity to transfer knowledge to a successor, inadequate workforce plans and replacements, lack of skill set to meet current and evolving business needs, a culture that does not foster inclusion leading to turnover, a failure to successfully negotiate new collective bargaining agreements with our labor unions on mutually acceptable terms or at all, acts of violence in the workplace, inadequate training and a workforce that is not engaged may lead to operating challenges, safety concerns and increased costs. The challenges include loss of knowledge and a lengthy time period associated with skill development, increased turnover, costs for contractors to replace employees, poor productivity, and a lack of innovation. Specialized knowledge and experience are required of employees across PSEG and its affiliates. There is competition for these skilled employees. Failure to hire and adequately train and retain employees, including the transfer of significant historical knowledge and expertise to new employees, may adversely affect our results of operations, financial position and cash flows.

Higher costs from suppliers of equipment and materials, fuel and services and labor and health care costs to attract and retain our workforce, as well as policy matters such as tax rates, tariffs and other policies impacting costs, could lead to increased costs, which could reduce our earnings.costs. Also, seeking recovery of higher costs in future distribution base rate cases could pressure customer rates, resulting in a potentially adverse outcome of such proceedings, or in other proceedings, including the proposal of certain investment programs or other proceedings that impact customer rates.

PSEG’s andPSEG’s, PSE&G’s and PSEG Power’s debt instruments contain events of default customary for financings of their type, including cross accelerations to other debt of that entity. PSEG’s, PSE&G’s and PSEG Power’s bank credit agreements contain events of default customary for financings of their type, including cross defaults and accelerations and, in the case of PSEG’s and PSEG Power’s bank credit agreements, certain change of control events. PSEG’s, PSE&G’s and PSEG Power’s bank credit agreements, and PSEG Power’s debt instruments contain certain limitations on the incurrence of liens and PSEG Power’s bank credit agreements and debt instruments also contain limitations on the incurrence of certain subsidiary debt. PSEG Power’s bank credit agreements contain limitations on sales of assets and PSEG Power’s debt instruments contain limitations on certain sale and leaseback transactions. PSEG Power's term loan agreements contain a change-of-control clause, which includes under certain circumstances, PSEG Power ceasing to be a wholly owned subsidiary of PSEG. Our ability to comply with these and future covenants may be affected by events beyond our control. If we fail to comply with the covenants and are unable to obtain a waiver or amendment, or a default exists and is continuing under such debt, the lenders or the holders or trustee of such debt, as applicable, could give notice and declare outstanding borrowings and other obligations under such debt immediately due and payable. We may not be able to obtain waivers, amendments or alternative financing, or if obtainable, it could be on terms that are not acceptable to us. Any of these events could adversely impact our financial condition, results of operations and cash flows.

The performance of the financial markets will affect the value of the assets that are held in trust to satisfy our future obligations under our defined benefit plansplan and to decommission our nuclear generating plants. A decline in the market value of the defined benefit plan trust funds could increase our pension plan funding requirements and result in increased pension costs in future years. The market value of our defined benefit plan trusts could be negatively impacted by adverse financial market conditions that reduce the return on trust assets, decreased interest rates used to measure the required minimum funding levels, and future government regulation. Additional funding requirements for our defined benefit plansplan could be caused by changes in required or voluntary contributions, an increase in the number of employees becoming eligible to retire and changes in life expectancy assumptions. A decline in the market value of our NDT Fund could increase PSEG Power’s funding requirements to decommission its nuclear plants. An increase in projected costs could also lead to additional funding requirements for our decommissioning trust. Failure to adequately manage adequately our investments in our defined benefit plan trusts and NDT Fund could result in the need for us to make significant cash contributions in the future to maintain our funding at sufficient levels, which would negatively impact our results of operations, cash flows and financial position.

PSEG Power sells wholesale natural gas, primarily through a full-requirements BGSS contract with PSE&G to meet the needs of PSE&G’s default gas supply service customers. In 2022, the BPU approved an extension of the long-term BGSS contract to March 31, 2027, and thereafter the contract remains in effect unless terminated by either party with a two-year notice. PSEG LI has an OSA with LIPA to operate LIPA’s electric T&D system in Long Island.Island Thewhich OSAwas continuesrecently extended through 20252030. andAny LIPA is currently conducting a process for provisiondiscontinuation of these services after 2025. It is uncertain whether these contracts will be extended or renewed, which may negatively affect our financial condition and operating results.

Changes in prevailing market prices below the PTC threshold could have a material adverse effect on our financial condition and results of operations. Factors that may cause market price fluctuations include:

increases and decreases in generation capacity, including the addition of new supplies of power as a result of the development of new power plants, expansion of existing power plants, continuing retirement of existing generation units, inability ofof, or delay in, new generating units to bebeing placed online, the retention of power plants that were expected to be retired or recently retired units being returned to service, the extent to which those generating units are firm or intermittent, or additional transmission capacity;

Our generation business currently involves the establishment of forward sale positions in the wholesale energy markets on long-term and short-term bases. If the realized value of our generation falls outside of the PTClevel thresholds,at which we would receive PTCs, to the extent that we have contracted obligations in excess of energy we have produced, an increase in market prices could reduce profitability. If the strategy we utilize to hedge our exposure to these various risks or if our internal policies and procedures designed to monitor the exposure to these various risks are not effective, we could incur material losses. Our market positions can also be adversely affected by the level of volatility in the energy markets that, in turn, depends on various factors, including weather in various geographical areas, short-term supply and demand imbalances, and pricing differentials at various geographic locations. These risks cannot be predicted with certainty.

Advances in distributed generation technologies, such as fuel cells, micro turbines, micro grids, windmills and net-metered solar installations, coupled with subsidies, may reduce the cost of alternative methods of delivering electricity to customers to a level that is competitive with that of most central station electric production. Large customers, such as universities and hospitals, continue to explore potential micro grid installation. Certain states are also considering mandating the use of power storage resources to replace uneconomic or retiring generation facilities. Such developments could (i) affect the price of energy, (ii) reduce energy deliveries as customer-owned generation becomes more cost-effective, (iii) require further improvements to our distribution systems to address changing load demands, and (iv) make portions of our transmission and/or distribution facilities obsolete prior to the end of their useful lives. These technologies could also result in further declines in commodity prices or demand for delivered energy. Further, a material shift away from natural gas due to customer preference or regulatory developments and initiatives could reduce the number of gas customers.

In the spot markets, we are exposed to the risks of the default sharing mechanisms that exist in those markets, some of which attempt to spread the risk across all participants. Therefore, a default by a third party could increase our costs, which could negatively impact our results of operations and cash flows. We sellhedge generation output through the execution of bilateral contracts. These contracts are subject to credit risk, which relates to the ability of our counterparties to meet their contractual obligations to us. Any failure of these counterparties to perform could have a material adverse impact on our results of operations, cash flows and financial position. In the spot markets, we are exposed to the risks of the default sharing mechanisms that exist in those markets, some of which attempt to spread the risk across all participants. Therefore, a default by a third party could increase our costs, which could negatively impact our results of operations and cash flows.

Because the obligations under most of these forward sale agreements are not contingent on a unit being available to generate power, PSEG Power’s results of operations and cash flows are at risk even in the event of a plant outage, or a reduction in the available capacity of the unit. To the extent that PSEG Power does not meet its expected nuclear generation output, PSEG Power would be required to pay the difference between the market price and the contract price on its financial contracts without receiving the physical spot energy revenue or be required to purchase energy at higher prices to cover its shortfall. In addition, as capacity performance resources in PJM, PSEG’s nuclear units have been and will in the future be required to pay penalties if a forced outage at a plant occurs during a declared emergency event within PJM as defined by PJM's rules and that plant’s expected performance exceeds its actual performance during such event. The amount of such payments could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows.

In addition, changing market design rules, including capacity performance rules and the design and timing of capacity market auctions, and/or failure to follow existing rules – by PJM or market participantsparticipants, –as well as any future supply/demand imbalance in PJM, creates regulatory uncertainty and reliability risk.

PSE&G is a regulated public utility that operates and invests in an electric T&D system and a gas distribution system as well as certain regulated clean energy investments, including solar and EE within New Jersey. PSE&G invests in capital projects to maintain and improve its existing T&D system and to address various public policy goals and meet customer expectations. Transmission projects are subject to the rules governing PJM's FERC-approved transmission expansion planning process which may be challenged in the future as well as other FERC rules, while distribution and clean energy projects are subject to approval by the BPU. The costs of PSE&G’s transmission projects are subject to prudency challenge at FERC and PSE&G’s rates themselves may also be challenged at FERC. FERC has also proposed elimination of certain transmission rate incentives, including the incentive that PSE&G receives for being a transmission owner member of PJM and accepting the related risk of RTO membership.

We are subject to regulation by federal authorities. Such regulation affects almost every aspect of our businesses, including management and operations; the terms and rates of transmission services; the rules governing the payments we receive from PJM markets; investment strategies; the financing of our operations and the payment of dividends. Failure to comply with these regulations could have a material adverse impact on our ability to operate our business and could result in fines, penalties or sanctions.

A significant input into PJM’s transmission planning process is its regional load forecast, which is adjusted on an annual basis. InPJM’s regional load forecast has increased significantly over the past few years, reflecting increased expectations of large customer growth and in January 2025,2026, PJM adjustedprovided an annual update of its load forecast in the PSEG zone and across PJM to reflect increasedcontinued expectations of large customer growth. Developing an accurate load forecast that reflects customer demand of the state – and other states in PJM – is critical to ensure that transmission is planned and built where it is needed to maintain reliability and that sufficient generation is procured in the capacity market.

The markets, PTC and/or ZEC programPTC may not provide sufficient financial support for our New Jersey nuclear plants which could result in the retirement of all of these nuclear plants.

As further described in Item 7. MD&A—Executive Overview of 20242025 and Future Outlook, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants have beenwere awarded ZECs by the BPU through May 2025.

If the markets,markets or PTC and/or the ZEC program do not provide sufficient financial support, or, in the case of the Salem nuclear plants, decisions by the EPA and state environmental regulators regarding the implementation of Section 316(b) of the CWA and related state regulations, or other factors, PSEG Power may take all necessary steps to cease to operate all of these plants and will incur associated costs and accounting charges in the event that the financial condition of the plants is materially adversely impacted in the future. Ceasing operations of these plants would result in a material adverse impact on PSEG’s results of operations.

The energy industry continues to be regulated and the rules to which our businesses are subject are always at risk of being changed. Our business has been impacted by established rules that create locational capacity markets in PJM. Under these rules, generators located in constrained areas are paid more for their capacity so there is an incentive to locate in those areas where generation capacity is most needed. PJM’s capacity market design rules continue to evolve and change, including in response to projections of higher demand, efforts to integrate public policy initiatives into the wholesale markets, lack of sufficient generation capacity and extreme weather events. These changes have led to capacity market auction delays.delays and rules changes that have created regulatory and business uncertainty. For a discussion of recent changes in energy regulatory policies that may affect our business and results of operations, see Item 1. Business—Regulatory Issues—Federal Regulation.

We are subject to numerous federal, state and local environmental laws and regulations that may significantly limit or affect our businesses, result in significant litigation, adversely impact our business plans and/or expose us to significant environmental finesfines, costs and other liabilities.

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.

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 freecarbon-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 and deliver clean energy 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 $30 billion as of December 31, 2023 to approximately $34 billion as of December 31, 2024.2024 to approximately $36 billion as of December 31, 2025. In addition, theour passagenuclear offacilities retain the Inflationdownside Reductionprice Actprotection of 2022 (IRA) established a production tax credit (PTC) for existing nuclear facilities from 2024 through 2032. The PTC is designed to provide downside price protection for our nuclear generation fleet as the tax credit value is directly linked to a nuclear facility’s gross receipts.

For the years 2025-2029,2026-2030, our regulated capital investment program is estimated to be in a range of $21$22.5 billion to $24$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%6.0% to 7.5% from year-end 20242025 to year-end 2029.2030. The regulated capital investments represent the majority of PSEG’s total capital investment program of $22.5$24 billion to $26$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 at their current average annual investment levels plus inflation,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.

Pursuant to our GSMP II and Energy Strong II programs, PSE&G filed a distribution base rate case as required by the BPU. In October 2024, the BPU issued an Order approving the settlement of thatPSE&G's distribution rate case with new rates effective October 15, 2024. The Order providesprovided 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. ForIn additionaladdition, information,the seeOrder Itemapproved 8.mechanisms Notebeginning 6.January Regulatory1, Assets2025 associated with the recovery of future storm costs as well as the recovery of annual pension and Liabilities.OPEB expenses.

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 hedging,mechanism, and support public policies that preserve these existing carbon-free base load nuclear generating plants. During 2024,2025, our nuclear units generated approximately 3130.9 terawatt hours and operated at a capacity factor of approximately91.2%. 90%.Effective BeginningApril in2025, 2024,PSEG Power revised the estimated useful lives for the Salem 1, Salem 2 and Hope Creek nuclear plants due to our hedgingexpectation strategythat incorporateda an20-year estimatedlicense rangeextension ofwill riskbe reductionapproved impactsfor these facilities. In October 2025, we completed work to extend the refueling cycle at our Hope Creek facility from the18 PTCs on our nuclear generation portfolio while retaining the abilitymonths to benefit24 when market pricing exceeds the phase out threshold. As of December 31, 2024, we expect that our hedged position for 2025 in conjunction with the PTC and market price variability will result in the realized value of our nuclear generation output being at, or above, the PTC phase out. Our strategy will continue to evolve given PTC guidance uncertainty, and potential incremental changes upon final U.S. Treasury guidance.months. In addition, we are exploringplanning opportunitiespower foruprates theat Salem Units 1 and 2 that will increase generation capacity and reliability and support long-term operation of these units, including through a potential salesubsequent oflicense power and/or emission credits from our nuclear facilities pursuant to long-term agreements.renewal.

ForWe moreremain thanguided a century, our purpose has been to provide safe access to an around-the-clock supply of reliable, affordable energy. Today,by our vision is to power a future where people use lessenergy energy,more efficiently, and it is cleaner,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 establishedadjusted aour net zero greenhouse gas (GHG) emissions by 2030 goal that includes direct GHG emissions (Scope 1) and indirect GHG emissions from operations (Scope 2) across our business operations, assuming advances in technology, public policy and customer behavior, which goal supports New Jersey's clean energy and climate goals.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 program. PSE&G’s approved CEF-EE and EE II, CEF-Energy Cloud and CEF-EVrelated programs and the proposed CEF-ES programthat 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. Through GSMP II, fromFrom 2018 through 20242025 we reduced reported methane emissions by over 30% system wide.

We also continue to focus on providing cleaner energy for our customers by working to preserve the economic viability of our nuclear units, which provide over 85%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,reliability and resource adequacy, and potential long-term contracts that recognize the value of its consistent and reliable carbon-free energy.

PSEG continues to evaluate additional investment opportunities in regulated transmission beyond PSE&G.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.

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. InHowever, Aprilcertain 2021,regulatory FERCor proposedlegislative eliminatingactions could potentially lead to the loss of this ROE adder forwhich, Regional Transmission Owner participation. FERC has not acted on the proposal. If the adder wasif eliminated, itwould wouldprospectively reduce PSE&G’s annual Net Income and annual cash inflows by approximately $40 million.

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. TheIn EOsNovember direct2025 the BPU and other state agencies to collaborate with stakeholders to develop plans to reachreleased the targetsupdated Energy Master Plan (EMP) that presents potential pathways toward meeting New Jersey’s clean energy and thedecarbonization BPUgoals. has convened a stakeholder proceeding to develop a plan for gas distribution utilities to reachGiven the targetnew ofadministration 50%took naturaloffice gasin emissionsJanuary reductions2026, overit 2006is levelsnot byclear 2030. The BPU commenced proceedings to updatehow the State’s EMP viamight publicinfluence inputNew hearingsJersey’s inenergy Maypolicy and Junewe 2024. We are unable tocannot predict the outcomes of this proceeding, but it could have a material impact on our business,business resultsthat ofmight operations and cash flows.result.

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 alongwithin the PassaicNewark andBay Hackensack RiversComplex are alleged by federal and state agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes. InThe addition,Newark PSEGBay PowerComplex hasis retaineda ownershiptidal ofestuary certainin liabilities excluded from the sale of its fossil generation portfolio, primarily related to obligations undernorthern New Jersey andthat Connecticutincludes stateNewark lawsBay, toas investigatewell as portions of the Passaic River, the Hackensack River and remediateother surrounding waterways. The U.S. Environmental Protection Agency (EPA) has designated various portions of the sites.Newark WeBay areComplex alsoas currentlyfederal involvedSuperfund insites athat numbermust be investigated and remediated under the Comprehensive Environmental Response, Compensation and Liability Act of proceedings1980 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.(CERCLA).

In AprilMay 2021,2025, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded zero emission certificatescertificate (ZECsZEC) forsales the three-year eligibility period starting June 2022 at the same approximate $10 per megawatt hour (MWh) received during the prior ZEC period through May 2025.concluded. Pursuant to a process established by the BPU, ZECs arewere purchased from selectedthese nuclear plants andby recoveredthe through a non-bypassableelectric distribution chargecompanies (EDCs) in theNew amount of $0.004 per kilowatt-hour used (which is equivalent to approximately $10 per MWh generated in payments to selected nuclear plants (ZEC payment)).Jersey. As previously noted, in August 2022, the IRAFederal was signed into law expanding incentives promoting carbon-free generation. The enacted legislationgovernment established a PTC for electricity generated using existing nuclear energy, which began January 1, 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 ishas been reduced by the estimated PTCs generated from PSEG Power’s Salem 1, Salem 2, and Hope Creekthese 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 IRAPTC, on our nuclear units, and will analyzeincluding 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.

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.rates As of December 31, 2024, PSEG had entered into floating-to-fixed interest rate hedges totaling $1.25 billion through March 2025 in order to reduce the volatility in interest expense related to PSEG Power’s variable rate term loan due June 2025. PSEG Power also entered into a 364-day variable rate term loan for $400 million in December 2024. In addition, from time to time, we may enter into interest rate hedges toand 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 baseperiodic rate filings and clause-based investment programs.filings.

TheIn August 2022, the IRA enacted a new 15% corporate alternative minimum tax (CAMT), which is based on adjusted financial statement income, and established a PTC for existing qualified nuclear generationfacilities. facilities,In discussedFebruary above,2026, the U.S. Treasury issued Notice 2026-07 (CAMT Notice) which clarifies AFSI computation by allowing an adjustment to deduct certain repair and allowsmaintenance energycosts taxthat creditsare capitalized in the applicable financial statement. This CAMT Notice will result in a reduction to bePSEG’s transferable.and ManyPSE&G’s AFSI for CAMT purposes. However, aspects of the IRA,IRA includingprovisions thefor CAMT and PTC,PTCs remain unclear and are in need of further guidance; therefore, we continue to analyze the issuance of future authoritative guidance could materially impact the IRA will have on PSEG’s and PSE&G’s results of operations, financial condition and cash flows, which could be material.flows.

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 continueseek to:

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

Net of tax (expense) benefit of $59$(87) million, $(37656) millionmillion, and $178$(74) million for the years ended December 31, 2024,2025, 20232024 and 2022,2023, respectively.

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, and 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.

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 the first threesix months of 2026, our nuclear units generated approximately 815.8 terawatt hours and operated at a capacity factor of 95.5%.93.7%. 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 2025, we also 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 DecemberJune 31,30, 2025,2026, 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. 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.

The results for PSEG, PSE&G and PSEG Power & Other for the three and six months ended MarchJune 31,30, 2026 and 2025 are presented as follows:

Net of tax benefit (expense) of $11$(59) million and $53$(43) million for the three months and $(60) million and $(49) million for the six months ended MarchJune 31,30, 2026 and 2025, respectively.

OurThe increasedecreases in Net Income for the three and six months ended MarchJune 31,30, 2026 versus the comparable periodperiods in 2025 was driven primarily by MTM losses in 2026 compared to gains in the prior year, as shown in the table above. These impacts were partially offset by increases from continued investment in T&D clause programs at PSE&G and higher capacity revenues and gas sales and capacity revenues at PSEG Power, combined with MTM and NDT activity, as shown in the table above.Power.

Under current FERC rules, PSE&G continues to earn a 50 basis point adder to its base ROE for its voluntary membership in PJM as a transmission owner. However,In certainJune regulatory2026, orlegislation legislativewas actionspassed in New Jersey that requires transmission owners that own and operate transmission facilities in New Jersey to be members of a Regional Transmission Organization (RTO) approved by FERC. The legislation will require that, effective January 1, 2027, transmission owners be members in an RTO. While we are continuing to assess the potential impact of this legislation, this mandatory RTO membership requirement could potentiallyresult lead toin the future loss of thisPSE&G’s 50 basis-point ROE adder which,for ifparticipating eliminated,in an RTO. This would prospectively reduce PSE&G’s annual Net Income and annual cash inflows by approximately $40 million. We cannot predict the outcome of this matter.

New Jersey Clean Energy Stakeholder ProceedingsMatters

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 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. In February 2026, PJM filed with FERC a proposal to extend the price cap for another two delivery years (2028/29 and 2029/30) and, in April 2026, FERC issued an order accepting PJM’s proposal. 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 up to 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. ThereIn areJuly outstanding2026, questionsPJM associatedsubmitted proposed tariff revisions with this auction, including around the role to be played by electric utilities in both setting the procurement target and purchasing the capacity from PJM during the auction, which could create collection risk for both PSE&G and its customers. In addition, in 2025, FERC both issued an order that will encourage optionality for “large load” customers by facilitating co-location with generation, and initiated a rulemaking to establish definitivea rulesone-time forcapacity futureprocurement large customer connections intendedmechanism to ensure reliability and address resource adequacy concerns.challenges in the PJM region. Under the “Reliability Backstop Procurement” framework, PJM intends to secure 15-year commitments from new eligible generation resources to match the reliability shortfall observed in the base residual auction for the 2028/2029 delivery year. To commence the procurement window on September 30, 2026, PJM asked FERC to approve the filing with an effective date of September 29, 2026. We cannot predict the outcome of thesethis proceedings and their impact on our business.proceeding.

In January 2026, the New Jersey Governor issued executive orders directing the BPU within its legal authority to mitigate electric rate increases through state funding during 2026 as well as other actions, and to advance resource adequacy solutions, in New Jersey. Executive Order No. 1 directed the BPU to complete and issue a study regarding modernization of the traditional electric distribution utility business model and the BPU retained a consultant to prepare the study. In July 2026, the BPU issued its consultant’s study, which discusses potential options for electric distribution utility ratemaking, including a review of other jurisdictions. The consultant will now undertake a quantitative analysis of the modernization options presented in its report. We cannot predict the outcome of this initiative or its potential impact on our business. It is not clear how these orders might influence New Jersey’s energy policy.

investments in generation and battery storage through BPUBPU, RTO or other similar solicitations or bilateral agreements;

Includes amortization of Energy Efficiency (EE) programs regulatory expenditures of $50$53 million, $41 million, $103 million and $38$79 million for the three months and six months ended MarchJune 31,30, 2026 and 2025, respectively.

Includes amortization of EE programs regulatory expenditures of $50$53 million, $41 million, $103 million and $38$79 million for the three months and six months ended MarchJune 31,30, 2026 and 2025, respectively.

Three Months Ended MarchJune 31,30, 2026 as Compared to Three Months Ended MarchJune 31,30, 2025

Delivery revenues increased $93$40 million due primarily to a $53$17 million increase in delivery volumes, $29$13 million from increased GPRC revenues and ana $18$10 million increase in transmission revenues due primarily to higher rate base investments. These delivery revenue increases were offset by a $7 million decrease due to an increase in credits flowed back to customers as part of our TAC mechanism.

Commodity Revenues increased $308$64 million primarily due to higher electric BGS revenues of $202$66 millionmillion, andprimarily from higher prices, partially offset by lower gas BGSS revenues of $106$2 million, primarily from higherlower prices.volume.

Other Operating revenues decreased $42$48 million due primarily to a decrease in Zero Emission Certificates (ZECs) as a result of the ZEC collection ending effective May 31, 2025.

Operation and Maintenance increased $61$41 million due primarily to $52$28 million in higher clause and renewable expenditures, $4 million in higher distribution and transmission operational expenditures and $5$13 million in higher other operating and Services expenses.

Depreciation and Amortization increased $15$11 million due primarily to an increase in depreciation due to higher plant placed in service and increased amortization of software and Regulatory Assets.

ThreeSix Months Ended MarchJune 31,30, 2026 as Compared to ThreeSix Months Ended MarchJune 31,30, 2025

Operating Revenues increased $324$527 million due primarily to changes in generationdelivery, andcommodity, gas supplyclause and other operating revenues.

OperationClause andRevenues Maintenanceincreased decreased $43$114 million due primarily to aan net$82 decreasemillion increase in various operational expensesTAC and anGPRC adjustmentdeferrals toand indirecta taxes$36 million increase in 2026.SBC collections.

InterestOther ExpenseOperating increasedrevenues $12decreased $88 million due primarily to incrementala debtdecrease andin ZECs as a result of the replacementZEC ofcollection maturingending long-termeffective debtMay at31, higher rates.2025.

Income TaxInterest Expense (Benefit)increased variance of $44$31 million due primarily to incremental debt and the replacement of maturing debt at higher pre-tax income.rates.