PUBLIC SERVICE ENTERPRISE GROUP INC

In the ordinary course of our business, we are subject to regulation by, and are party to various claims and regulatory proceedings with FERC, the BPU, the Commodity Futures Trading Commission (CFTC) and various state and federal environmental regulators, among others. For information regarding material matters, other than those discussed below, see Item 8. Note 13. Commitments and Contingent Liabilities. In addition, information regarding PSE&G’s specific filings pending before the BPU is discussed in Item 8. Note 6. Regulatory Assets and Liabilities.

Federal Regulation

FERC is an independent federal agency that regulates the transmission of electric energy and natural gas in interstate commerce and the sale of electric energy and natural gas at wholesale pursuant to the FPA and the Natural Gas Act. PSE&G and certain operating subsidiaries of PSEG Power are public utilities as defined by the FPA. FERC has extensive oversight over such public utilities. FERC approval is usually required when a public utility seeks to: sell or acquire an asset that is regulated by FERC (such as a transmission line or a generating station); collect costs from customers associated with a new transmission facility; charge a rate for wholesale sales under a contract or tariff; or engage in certain mergers and internal corporate reorganizations.

FERC also regulates RTOs/ISOs, such as PJM, and their regional transmission planning processes as well as their energy and capacity markets.

Transmission Regulation

FERC has exclusive jurisdiction to establish the rates and terms and conditions of service for interstate transmission. We currently have FERC-approved formula rates in effect to recover the costs of our transmission facilities. Under this formula, rates are put into effect in January of each year based upon our internal forecast of annual expenses and capital expenditures. Rates are subsequently trued up to reflect actual annual expenses and capital expenditures.

Transmission Rate Proceedings and ROE—From time to time, various matters are pending before FERC relating to, among other things, transmission planning and transmission rates and returns, including incentives. Depending on their outcome, any of these matters could materially impact our results of operations and financial condition.

In a rulemaking proceeding issued in 2021, FERC proposed to eliminate the existing 50 basis point adder for RTO membership, which is currently available to PSE&G and other transmission owners in RTOs. Elimination of the RTO adder for RTO membership would reduce PSE&G’s annual Net Income and annual cash inflows by approximately $40 million.

Transmission Planning Proceedings—Through rulemaking proceedings, FERC continues to determine whether changes are needed to current transmission and interconnection planning rules to facilitate the integration of renewable resources onto the grid. FERC is also examining whether there is sufficient oversight over transmission costs to protect customers. Among other issues, FERC is considering whether transmission competitive solicitations are working as intended, whether interconnection queue rules for new generation should dramatically change and whether some type of transmission monitor construct to oversee costs should be imposed.

On the interconnection front, in July 2023, FERC issued a Final Rule, which parties have challenged on rehearing, that will require RTOs to implement rules to speed up the processing of interconnection queue requests. This rule may also result in penalties being imposed on generators, RTOs and transmission owners that fail to meet certain process deadlines. In December 2024, PJM submitted proposed revisions to the PJM Tariff to provide for a reliability based expansion of the interconnection queue window so that a limited number of additional generating resources (50 projects) needed to address PJM’s reliability challenges can be added to this interconnection cycle. FERC accepted this proposal in February 2025, which will allow PJM to accelerate the interconnection of new, "shovel-ready" generation capacity resources and may facilitate PSEG's plan to implement power uprates for both Salem Unit 1 and Unit 2.

In May 2024, FERC issued a Final Rule on transmission planning and cost allocation. As a result of this rule, RTOs like PJM will be required to engage in 20-year transmission planning, applying certain scenarios to the planning process. FERC also reinstated the Right of First Refusal for a discrete category of transmission projects. On rehearing, FERC expanded the states' role in the process for determining how transmission costs will be allocated to various sets of customers. PJM is currently in the process of developing a plan to implement the rule.

In December 2024, a coalition of industrial customers and state ratepayer advocates filed a complaint at FERC against various named public utilities and RTOs/ISOs, including PJM. The complaint alleges that local planning has produced inefficient planning and projects that are not cost-effective, and therefore requests that FERC require the application of regional planning requirements, including relevant competitive solicitation processes, to all transmission facilities over 100kV. The complaint also requests that FERC require RTOs/ISOs to appoint an “Independent System Planner” to oversee transmission planning. While PSEG is not a named party in the complaint, our local planning authority and rights may be impacted by the resolution of this proceeding. We cannot predict the outcome of this proceeding.

Regulation of Wholesale Sales—Generation/Market Issues/Market Power

Under FERC regulations, public utilities that wish to sell power at market rates must receive FERC authorization (market-based rate (MBR) authority) to sell power in interstate commerce before making power sales. They can sell power at cost-based rates or apply to FERC for authority to make MBR sales. For a requesting company to receive MBR authority, FERC must first determine that the requesting company lacks market power in the relevant markets and/or that market power in the relevant markets is sufficiently mitigated. Certain PSEG companies are public utilities and currently have MBR authority. These companies, which include PSEG Energy Resources & Trading LLC, PSEG Nuclear LLC and PSE&G must file at FERC every three years to update their market power analyses. At the end of 2022, PSEG filed such a market power update at FERC, which remains pending.

In October 2024, FERC issued a Final Rule that eliminates compensation for reactive power in circumstances when the generator is operating within the normal power factor range specified in its interconnection agreement. PSEG Power currently receives reactive power compensation, and we have sought rehearing of this Final Rule. In January 2025, PJM made a compliance filing at FERC seeking approval to delay implementation of the rule, and the resulting prospective loss of reactive power compensation for generators like PSEG Power within the PJM footprint, until June 1, 2026. The loss of reactive power compensation is not expected to have a material impact on PSEG's results of operations.

In addition, there are several ongoing proceedings at FERC that may impact future co-located customer arrangements, such as data centers, involving the supply of power from nuclear units, including whether certain data center customers, depending on their configuration, will pay transmission service charges. FERC is also broadly examining issues concerning whether and to what extent there are potential reliability, cost and customer impacts raised by the location of large customers at generating facilities. In February 2025, FERC issued a show cause order directing PJM and PJM transmission owners to explain within 30 days why the PJM tariff is just and reasonable or, alternatively, what revisions might be necessary, to address perceived gaps in the PJM tariff with respect to co-located load arrangements. We cannot predict the outcome of these proceedings.

Energy Clearing Prices

Energy clearing prices in the markets in which we operate are generally based on bids submitted by generating units. Under FERC-approved market rules, bids are subject to price caps and mitigation rules applicable to certain generation units. FERC rules also govern the overall design of these markets. At present, all units, including those owned by PSEG, within a delivery zone receive a clearing price based on the bid of the marginal unit (i.e., the last unit that must be dispatched to serve the needs of load) which can vary by location.

Capacity Market Issues

PJM operates a capacity market called the Reliability Pricing Model (RPM), the rules for which are approved by FERC. RPM incorporates a forward auction for installed capacity. Under the RPM, generators located in constrained areas within PJM are paid more for their capacity as an incentive to ensure adequate supply where generation capacity is most needed. The mechanics of the RPM in PJM continue to evolve and be refined in stakeholder proceedings and FERC proceedings in which we are active.

Over the past several months, there have been significant activities related to PJM’s capacity market. PJM has delayed capacity auctions for the next three delivery years (2027/28, 2028/29 and 2029/30). Three complaints were filed against PJM alleging that PJM’s capacity market rules have resulted in unjust and unreasonable capacity prices, and seeking to produce short-term increases in supply in the market and a short-term decrease in clearing prices. PJM has also made filings to change its rules to address concerns raised in the complaints, including tariff revisions filed in February 2025 with FERC proposing a collar of $175 per MW-day floor and $325 per MW-day ceiling on capacity prices for the next two delivery years. These ongoing proceedings, as well as potential future proceedings, may affect the future design of the capacity market. We cannot predict the outcome of these proceedings or their impact on our business, results of operations and cash flows.

Compliance

Reliability Standards—PSEG is required to comply with the North American Electric Reliability Corporation (NERC) Reliability Standards, promulgated by NERC and approved by FERC, which are designed to ensure the security and reliability of the United States electric transmission and generation system (the “electric grid”). As a result, PSEG is subject to requirements governing the planning and operation of the electric grid, and requirements governing the physical and cyber security of PSEG assets that are used to protect and operate the electric grid. Due to the increasing sophistication of physical and cyber security threats to the security and reliability of the electric grid, it is anticipated that FERC and NERC will continue to promulgate new Reliability Standards, and modify existing Reliability Standards, to meet these challenges.

CFTC

In accordance with the Dodd-Frank Wall Street Reform and Consumer Protection Act, the SEC and the CFTC continue to implement a regulatory framework for swaps and security-based swaps. The rules are intended to reduce risk, increase transparency and promote market integrity within the financial system by providing for the registration and comprehensive regulation of swap dealers and by imposing recordkeeping, data reporting, margin and clearing requirements with respect to swaps. We are currently subject to recordkeeping and data reporting requirements applicable to commercial end users. The CFTC finalized new rules establishing federal position limits for trading in certain commodities, such as natural gas. Entities such as PSEG began complying with the rules on January 1, 2022.

Nuclear

Nuclear Regulatory Commission (NRC)

Our operation of nuclear generating facilities is subject to comprehensive regulation by the NRC, a federal agency established to regulate nuclear activities to ensure the protection of public health and safety, as well as the environment. Such regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety, security, cybersecurity, and environmental requirements. Continuous demonstration to the NRC that plant operations meet requirements is necessary.

The NRC has the ultimate authority to determine whether any U.S. nuclear generating unit may operate. The NRC conducts ongoing reviews of nuclear industry operations experience and may issue or revise regulatory requirements. We are unable to predict the final outcome of these reviews or the cost of any actions we would need to take to comply with any new regulations, including possible modifications to the Salem, Hope Creek and Peach Bottom facilities, but such costs could be material.

The current operating licenses of our nuclear facilities expire in the years shown in the following table:

(A)

Depreciation Expense and the Asset Retirement Obligation assume these units will operate through 2053 and 2054, respectively, given our expectation that previously approved operating license expiration dates will be restored by the NRC. See Item 8. Note 11. Asset Retirement Obligations (AROs) for additional information.

In 2024, PSEG submitted a letter to the NRC regarding a potential timeline to seek a second license renewal for our Salem and Hope Creek units. This second license renewal would extend the operating licenses through 2056 and 2060 for Salem Units 1 and 2, respectively, and 2066 for Hope Creek.

State Regulation

Our principal state regulator is the BPU, which oversees electric and natural gas distribution companies in New Jersey. We are also subject to various other states’ regulations due to our operations in those states.

Our New Jersey utility operations are subject to comprehensive regulation by the BPU including, among other matters, regulation of retail electric and gas distribution rates and service, the issuance and sale of certain types of securities and compliance matters.

In addition to base rates, we recover certain costs or earn on certain investments pursuant to mechanisms known as adjustment clauses. These clauses permit the flow-through of costs to, or the recovery of investments from, customers related to specific programs, outside the context of base rate proceedings. Recovery of these costs or investments is subject to BPU approval for which we make periodic filings. Delays in the pass-through of costs or recovery of investments under these mechanisms could result in significant changes in PSE&G’s cash flow. PSE&G’s participation in solar, EV and EE programs is also regulated by the BPU, as the terms and conditions of these programs are approved by the BPU. BPU regulation can also have a direct or indirect impact on our power generation business as it relates to energy supply agreements and energy policy in New Jersey.

New Jersey Energy Master Plan (EMP) and Future of Gas Stakeholder Proceeding—In January 2020, the State of New Jersey released its EMP. While the EMP does not have the force of law and does not impose any obligations on utilities, it outlines current expectations regarding New Jersey’s role in the use, management, and development of energy. The EMP recognizes the goals of New Jersey’s Clean Energy Act of 2018 (the Clean Energy Act) to achieve, by 2026, annual reductions of electric and gas consumption of at least 2% and 0.75%, respectively, of the average of the prior three years of retail sales. The annual reductions were subsequently adjusted to 2.15% for electric and 1.10% for gas by 2027 in the BPU’s EE framework approved in June 2020. The EMP outlines several strategies, including statewide EE programs; expansion of renewable generation (solar and offshore wind), energy storage and other carbon-free technologies; preservation of existing nuclear generation; electrification of the transportation sector; and reduced reliance on natural gas. The BPU began proceedings to update the State’s EMP via public input hearings in May and June 2024.

In February 2023, the governor of New Jersey issued three Executive Orders (EOs), one of which directed the BPU to convene a stakeholder process on the future of gas to develop a plan to meet the State’s current EMP goal to reduce emissions by 50% versus 2006 levels by 2030. In March 2023, the BPU opened a stakeholder proceeding to implement such EO that commenced in August 2023 with a two-day technical conference. We cannot predict the impact on our business or results of operations from these stakeholder proceedings, or any laws, rules, or regulations promulgated as a result thereof.

Stakeholder Proceeding on Gas Competition, BGSS—In February 2023, the BPU announced that it would open a new docket to conduct a stakeholder proceeding regarding gas supply issues previously raised by competitive gas suppliers, including third-party suppliers’ participation in New Jersey gas distribution companies’ annual BGSS filings, and other aspects of the existing BGSS construct. There has been no public activity in this matter since May 2023.

Gas Capacity Review—In September 2019, the BPU formally opened a stakeholder proceeding to explore gas capacity procurement service to all New Jersey natural gas customers and in June 2022 accepted a consultant’s finding that, through 2030, New Jersey’s firm gas capacity can meet firm demand under normal design day conditions. The BPU noted that its consultant’s analysis supported the argument against the need for additional interstate pipeline capacity and also supports the BPU’s aggressive policy approach to reduce New Jersey’s overall reliance on fossil fuels and achieve the New Jersey governor’s goal of 100% clean energy by 2050.

Regional Energy Access (REA) Expansion Project— In September 2024, the United States Circuit Court for the District of Columbia Circuit vacated FERC approval of the REA Expansion Project, which involves a natural gas pipeline running through New Jersey and several other states, and in which PSEG Energy Resources & Trade, LLC, the provider of gas supplies to satisfy PSE&G’s BGSS customers, is a customer. The court found that FERC failed to properly consider the environmental consequences of the project, and the alleged lack of market demand for additional natural gas capacity in New Jersey. In January 2025, FERC responded to the Circuit Court’s concerns and reinstated its approval of the project. PSEG is continuing to monitor this proceeding.

Energy Efficiency, Triennial Review—In May 2024, the BPU approved an approximate $300 million extension of our CEF-EE program covering a commitment period from July 2024 through December 2024. In October 2024, the BPU approved our CEF-EE II filing authorizing a total spend of 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. The filing also includes demand response programs and building decarbonization programs.

BGS Process—In June 2024, New Jersey’s EDCs, including PSE&G, filed their annual joint proposal for the conduct of the February 2025 BGS auction covering energy years 2026 through 2028. PSE&G’s company-specific addendum to the joint filing includes a proposal for an optional, two-year pilot program for time-of-use rates for residential customers.

EV Activity—Consistent with the policy set forth in New Jersey’s EMP, the BPU has supported electrification of the transportation sector. EDCs in New Jersey, including PSE&G, are making investments, approved by the BPU for recovery in rates, initially focused on light duty vehicles, such as preparatory work to deliver infrastructure to the EV charging point. In October 2024, the BPU released an Order that provided program guidance and minimum filing requirements for electric utility operated medium- and heavy-duty charging incentive programs. The Order caps PSE&G’s program investment at $30 million and requires electric utilities to submit program filings by February 27, 2025.

Grid Modernization—In June 2022, following a stakeholder proceeding, the BPU Staff issued a report containing findings and recommendations to update the BPU’s interconnection regulations and processes. In furtherance of the recommendations, in June 2024 the BPU amended its interconnection rules to speed up the interconnection of renewable resources to the distribution grid. Separately, in July 2024, BPU Staff convened a working group to develop recommendations for integrated distribution planning for distributed energy resources. We cannot predict the impact on our business or results of operations from this Grid Modernization plan or any laws, rules or regulations promulgated as a result thereof, particularly as they may relate to PSE&G’s electric distribution assets.

Cybersecurity Regulation

Federal—NERC Critical Infrastructure Protection standards establish cybersecurity and physical security protections for critical systems and facilities. These standards are also designed to promote coordination, threat sharing and interaction between utilities and various government agencies regarding potential cyber and physical threats against the nation’s electric grid. The Critical Infrastructure Protection standards are designed to protect Bulk Electric System (BES) Cyber Systems that would impact the reliable operation of the BES. PSE&G is obligated to comply with the NERC Critical Infrastructure Protection standards.

NERC Critical Infrastructure Protection standards do not apply to nuclear facilities which are instead governed by the NRC for purposes of physical and cyber security. NRC has a number of risk-informed, performance-based security programs in place to effectively protect U.S. commercial nuclear facilities. NRC has existing requirements, effective processes, and the expertise to regulate and inspect cybersecurity to ensure the federal requirements are met. NERC continues to examine revising criteria for low-impact cyber systems, which could result in expanding the Critical Infrastructure Protection standards to a larger set of applicable cyber assets.

NRC requires operating nuclear power plant licensee and license applicants to ensure that digital computer and communication systems associated with a nuclear power plant’s safety, security, and emergency preparedness functions are protected from cyberattacks. As a result, computer systems at operating power plants that monitor and control safety systems and help the reactor operate are isolated from external communications. Security systems that provide safeguards of the facility are also isolated from external communications, including the Internet.

NRC’s Office of Nuclear Security and Incident Response established the Cyber Security Branch (CSB) to strengthen internal governance of the agency’s regulatory activities. The CSB plans, coordinates, and manages agency activities related to cybersecurity for NRC applicants and licensees, such as security programs’ development and policy enhancements to prevent malevolent cyber acts against NRC-licensed facilities. The CSB’s cybersecurity-related responsibilities include developing rules and guidance, reviewing licensing actions, developing policy enhancements, and overseeing NRC-licensed facilities.

NRC regularly monitors the threats associated with cybersecurity, including potential threats against NRC-licensed facilities. Within the CSB there is a cyber assessment team that assesses real-world cyber events at NRC-licensed facilities. The team evaluates whether an identified threat could impact licensed facilities and makes recommendations for NRC actions and communications to the licensees. Furthermore, the NRC has established liaison relationships with the intelligence and law enforcement communities to include the National Counterterrorism Center, the U.S. Department of Homeland Security’s (DHS) Computer Emergency Response Team, and the Federal Bureau of Investigation.

The Transportation Security Administration, an agency of the U.S.DHS, has issued multiple security directives since May 2021 designed to mitigate cybersecurity threats to natural gas pipelines.

State—The BPU requires utilities, including PSE&G, to, among other things, implement a cybersecurity program that defines and implements organizational accountabilities and responsibilities for cyber risk management activities, and establishes policies, plans, processes and procedures for identifying and mitigating cyber risk to critical systems. Additional requirements of this order include, but are not limited to (i) annually inventorying critical utility systems; (ii) annually assessing risks to critical utility systems; (iii) implementing controls to mitigate cyber risks to critical utility systems; (iv) monitoring log files of critical utility systems; (v) reporting cyber incidents to the BPU; and (vi) establishing a cybersecurity incident response plan and conducting biennial exercises to test the plan. In addition, New York’s Stop Hacks and Improve Electronic Data Security (SHIELD) Act, which became effective in March 2020, requires businesses that own or license computerized data that includes New York State residents’ private information to implement reasonable safeguards to protect that information.