10-K

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

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The aggregate market value of the Common Stock of Public Service Enterprise Group Incorporated held by non-affiliates as of June 30, 2024 was $36,632,552,572 based upon the New York Stock Exchange Composite Transaction closing price.

The number of shares outstanding of Public Service Enterprise Group Incorporated’s sole class of Common Stock as of February 21, 2025 was 498,561,467.

As of February 21, 2025, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were held, beneficially and of record, by Public Service Enterprise Group Incorporated.

Public Service Electric and Gas Company is a wholly owned subsidiary of Public Service Enterprise Group Incorporated and meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K. Public Service Electric and Gas Company is filing its Annual Report on Form 10-K with the reduced disclosure format authorized by General Instruction I.

Certain of the matters discussed in this report about our and our subsidiaries’ future performance, including, without limitation, future revenues, earnings, strategies, prospects, consequences and all other statements that are not purely historical constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “should,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities, and other filings we make with the United States Securities and Exchange Commission (SEC), including our subsequent reports on Form 10-Q and Form 8-K. These factors include, but are not limited to:

All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized or even if realized, will have the expected consequences to, or effects on, us or our business, prospects, financial condition, results of operations or cash flows. Readers are cautioned not to place undue reliance on these forward-looking statements in making any investment decision. Forward-looking statements made in this report apply only as of the date of this report. While we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even in light of new information or future events, unless otherwise required by applicable securities laws.

The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.

From time to time, PSEG and PSE&G release important information via postings on their corporate Investor Relations website at https://investor.pseg.com. Investors and other interested parties are encouraged to visit the Investor Relations website to review new postings. You can sign up for automatic email alerts regarding new postings at the bottom of the webpage at https://investor.pseg.com or by navigating to the Email Alerts webpage at https://investor.pseg.com/resources/email-alerts/default.aspx. The information on https://investor.pseg.com and https://investor.pseg.com/resources/email-alerts/default.aspx is not incorporated herein and is not part of this Form 10-K.

This combined Annual Report on Form 10-K is separately filed by Public Service Enterprise Group Incorporated (PSEG) and Public Service Electric and Gas Company (PSE&G). Information relating to any individual company is filed by such company on its own behalf. PSE&G is only responsible for information about itself and its subsidiaries.

Discussions throughout the document refer to PSEG and its direct operating subsidiaries. Depending on the context of each section, references to “we,” “us,” and “our” relate to PSEG or to the specific company or companies being discussed.

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may obtain our filed documents from commercial document retrieval services, the SEC’s internet website at www.sec.gov or our website at https://investor.pseg.com. Information on our website should not be deemed incorporated into or as a part of this report. Our Common Stock is listed on the New York Stock Exchange under the trading symbol PEG. You can obtain information about us at the offices of the New York Stock Exchange, Inc., 11 Wall Street, New York, New York 10005.

We were incorporated under the laws of the State of New Jersey in 1985 and our principal executive offices are located at 80 Park Plaza, Newark, New Jersey 07102. 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.

As a holding company, our profitability depends on our subsidiaries’ operating results. We principally conduct our business through two direct wholly owned subsidiaries, PSE&G and PSEG Power LLC (PSEG Power), described below, each of which also has its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. Over the past several years, we have simplified our business mix and focused our capital allocation towards PSE&G, resulting in the majority of earnings being contributed by PSE&G and providing us more predictability of earnings.

In February 2022, we completed the sale of our 6,750 megawatt (MW) fossil generation portfolio which represented an important milestone in our strategy.

Our other direct wholly owned subsidiaries are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under a contractual agreement; PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily holds our legacy lease investments and competitively bid, FERC regulated transmission; and PSEG Services Corporation (Services), which provides us and our operating subsidiaries with certain management, administrative and general services at cost.

Our regulated T&D public utility, PSE&G, distributes electric energy and natural gas to customers within a designated service territory running diagonally across New Jersey where approximately 6.8 million people, or about 74% of New Jersey’s population resides.

The commodity portion of our utility business’ electric and gas sales is managed by basic generation service (BGS) and basic gas supply service (BGSS) suppliers. Pricing for those services is set by the BPU as a pass-through, resulting in no margin for our utility operations.

In addition, we continue to invest in and pursue opportunities in regulated clean energy programs, including EE, electric vehicle (EV) make-ready charging infrastructure and other potential investments.

We also earn margins through competitive services, such as appliance repair, in our service territory.

We are a transmission owner in PJM Interconnection, L.L.C. (PJM) which is an Independent System Operator (ISO) and Regional Transmission Organization (RTO) that operates the electric transmission system in the Mid-Atlantic Region,

including New Jersey and the surrounding states. We provide distribution service to 2.4 million electric customers and 1.9 million gas customers in a service area that covers approximately 2,600 square miles running diagonally across New Jersey. We serve the most densely populated, commercialized and industrialized territory in New Jersey, including its six largest cities and approximately 300 suburban and rural communities.

We use formula rates for our transmission cost of service and investments. Formula rates provide a method of rate recovery where the transmission owner annually determines its revenue requirements through a fixed formula that provides for a recovery of our operating costs and a return of and on our capital investments in the system, net of accumulated depreciation and deferred tax liabilities (also known as rate base) using an approved return on equity (ROE) in developing the weighted average cost of capital. 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. Our transmission revenues are not impacted by sales volumes. Our current approved transmission rates provide for a base ROE of 9.90% and a 50 basis point adder for our membership in PJM as an RTO. See Item 7. MD&A—Executive Overview of 2024 and Future Outlook for additional information.

PSE&G distributes electricity and natural gas to end users in our respective franchised service territories. Our distribution rates are subject to periodic rate cases approved by the BPU. In October 2024, the BPU issued an Order approving the settlement of PSE&G’s electric and gas distribution base rate case with new rates effective October 15, 2024. The Order provides 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. For additional information, see Item 8. Note 6. Regulatory Assets and Liabilities.

The BPU has also approved a series of PSE&G infrastructure, EE, EV and renewable energy investment programs with cost recovery through various clause mechanisms. For a discussion of proposed and approved programs, see Investment Clause Programs as follows and Item 7. MD&A—Executive Overview of 2024 and Future Outlook.

Our load requirements are split among commercial, residential and industrial customers, as shown in the following table for 2024:

Our customer base has modestly increased since 2020, with electric and gas loads changing as illustrated in the following table:

As part of the BPU's approval of the Clean Energy Future-Energy Efficiency (CEF-EE) filing in 2021, we implemented the Conservation Incentive Program (CIP) that trues up PSE&G’s distribution margin to a rate case-approved baseline per customer for the majority of our customers. As a result, electric gas sales volumes and demands are no longer a driver of our margin and over 90% of our Electric and Gas Distribution margin will only vary based upon the number of customers. While load has modestly decreased in the past due to a decline in larger industrial customers, greater EE and other factors, a significant increase in load is anticipated due to the increasing adoption of EVs, the expansion of data centers and other large users in our area, ongoing growth in the number of customers, other sources of electrification and other factors, which will collectively drive the need for increased system investment.

The following table lists our major approved investment clause programs that are in progress:

Our CEF-Energy Storage (ES) program, which was filed with the BPU in October 2018, is being held in abeyance.

GSMP II Extension—designed to replace at least 400 miles of cast iron and unprotected steel mains and services in our gas system.

Energy Strong II Program—structured to harden, modernize and improve the resiliency of our electric and gas distribution systems.

IAP—designed to improve the reliability of the “last mile” of our electric distribution system and address aging substations and gas metering and regulation stations.

See Item 7. MD&A—Executive Overview of 2024 and Future Outlook for additional information.

We have also undertaken solar initiatives at PSE&G, which primarily invest in utility-owned solar photovoltaic (PV) grid-connected solar systems installed on PSE&G property and third-party sites with our economics driven by our net investment in solar, with a contemporaneous return on that rate base.

We make no margin on the default supply of electricity and gas since the actual costs are passed through to our customers.

All electric and gas customers in New Jersey have the ability to choose their electric energy and/or gas supplier. Pursuant to BPU requirements, we serve as the supplier of last resort for two types of electric and gas customers within our service territory that are not served by another supplier. The first type provides default supply service for smaller C&I customers and residential customers at seasonally-adjusted fixed prices for a three-year term (BGS-Residential Small Commercial Pricing (RSCP)). These rates change annually on June 1 and are based on the average price obtained at auctions in the current year and two prior years. The second type provides default supply for larger customers, with energy priced at hourly PJM real-time market prices for a contract term of 12 months (BGS-Commercial Industrial Energy Pricing).

We procure the supply to meet our BGS obligations through auctions authorized by the BPU for New Jersey’s total BGS requirement. These auctions take place annually in February. Once approved by the BPU, electricity prices for BGS service are set. Approximately one-third of PSE&G’s total BGS-RSCP eligible load is auctioned each year for a three-year term. For information on current prices, see Item 8. Note 13. Commitments and Contingent Liabilities.

PSE&G procures the supply requirements of its default service BGSS gas customers through a full-requirements contract with PSEG Power. The BPU has approved a mechanism designed to recover all gas commodity costs related to BGSS for residential customers. BGSS filings are made annually by June 1 of each year, with a targeted effective date of provisional rates by October 1. PSE&G’s revenues are matched with its costs using deferral accounting, with the goal of achieving a zero cumulative balance by September 30 of each year. In addition, we have the ability to put in place two self-implementing BGSS increases on December 1 and February 1 of up to 5% and also may reduce the BGSS rate at any time and/or provide bill credits. Any difference between rates charged under the BGSS contract and rates charged to our residential customers is deferred and collected or refunded through adjustments in future rates. C&I customers that do not select third-party suppliers are also supplied under the BGSS arrangement. These customers are charged a market-based price largely determined by prices for commodity futures contracts.

PSEG Power & Other is predominantly comprised of its nuclear generation assets, its natural gas supply operations, the Operating Services Agreement (OSA) of PSEG LI with LIPA, and other legacy investments. PSEG Power is a public utility within the meaning of the Federal Power Act (FPA) and the payments it receives and how it operates are subject to FERC regulation.

As a nuclear generation owner and operator, our revenue has been derived primarily from energy, capacity and ancillary services sold to PJM in the spot markets. These products and services may also be transacted through exchange markets or bilaterally.

In August 2022, the Inflation Reduction Act (IRA) was signed into law expanding incentives that promote carbon-free generation. The enacted legislation established the production tax credit (PTC) for electricity generation using nuclear energy, which began January 1, 2024 and is available through 2032. PSEG Power’s nuclear plants are expected to benefit from the PTC. The expected PTC rate is up to $15 per megawatt hour (MWh) subject to adjustment based upon a facility’s gross receipts and meeting prevailing wage rules. The PTC rate and the gross receipts threshold are subject to annual inflation adjustments. Until additional guidance is issued by the U.S. Treasury, the final realized value of the PTC is subject to adjustment, which may be material.

PSEG Power also sells wholesale natural gas, primarily through a full-requirements BGSS contract with PSE&G to meet the needs of PSE&G’s default 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 Power supplies PSE&G’s peak daily gas requirements through its balanced portfolio of firm gas transportation capacity, storage contracts, contract peaking supply, and liquefied natural gas and propane. Based upon the availability of natural gas beyond PSE&G’s actual daily needs, PSEG Power sells gas to other customers and shares these proceeds with PSE&G’s customers.

As of December 31, 2024, PSEG Power had 3,758 MW of nuclear generation capacity. All of our nuclear generation capacity is located in New Jersey and Pennsylvania.

Our nuclear generation is considered to be base load. Base load units run the most and typically are called to operate whenever they are available. Variable operating costs are low due to the combination of highly efficient operations and the use of relatively lower-cost fuels. Performance is generally measured by the unit’s “capacity factor,” or the ratio of the actual output to the theoretical maximum output.

In PJM, owners of power plants specify prices at which they are prepared to generate and sell energy based on the marginal cost of generating energy from each individual unit. Typically, the bid price of the last unit dispatched by PJM establishes the energy market-clearing price.

This method of determining supply and pricing creates a situation where natural gas prices often have a major influence on the price that generators will receive for their output, especially in periods of relatively strong or weak demand. Therefore, changes in the price of natural gas will often translate into changes in the wholesale price of electricity and will continue to have a strong influence on the price of electricity in the markets in which we operate.

Market wholesale prices may vary by location resulting from congestion or other factors and do not necessarily reflect our contract prices. Forward prices are volatile and there can be no assurance that current forward prices will remain in effect or that we will be able to contract output at these forward prices. The PTC is expected to mitigate our downside exposure to this volatility and provide support for the nuclear units.

We expect to be able to meet the nuclear fuel supply demands of our operations. However, there are limited suppliers for certain aspects of this supply chain and the ability to maintain an adequate fuel supply could be affected by several factors not within our control, including changes in prices and demand, tariffs, curtailments by suppliers, severe weather, environmental regulations, war and hostilities, and other factors. For additional information and a discussion of risks, see Item 1A. Risk Factors, Item 7. MD&A—Executive Overview of 2024 and Future Outlook and Item 8. Note 13. Commitments and Contingent Liabilities.

Our nuclear generating units’ performance, market prices and the PTC, have a considerable effect on our profitability. The PTC is designed to increase with inflation, and therefore, future inflation levels will impact the financial support of the nuclear units. In addition, market revenues in excess of the PTC threshold would provide incremental benefit.

PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants have also been awarded zero emission certificates (ZECs) by the BPU through May 2025. These nuclear plants are expected to receive ZEC revenue from the electric distribution companies (EDCs) in New Jersey, which is equivalent to approximately $10/MWh. ZEC revenue recorded is reduced by the

estimated production tax credits (PTCs) generated from PSEG Power’s Salem 1, Salem 2, and Hope Creek nuclear plants. ZEC revenue will be adjusted based upon the actual amount of the PTCs when guidance is issued on how to calculate gross receipts and that adjustment could be material.

In addition to energy sales, we earn revenue from capacity payments for our generating assets. These payments are compensation for committing our generating units to PJM for dispatch at its discretion. Capacity payments reflect the value to PJM of assurance that there will be sufficient generating capacity available at all times to meet system reliability and energy requirements.

In PJM the market design for capacity payments provides for a forward-looking, capacity pricing mechanism through the Reliability Pricing Model (RPM). For additional information regarding auction delays, complaints against PJM regarding RPM, PJM and FERC actions related to the capacity market construct and resulting market uncertainty, see Regulatory Issues—Federal Regulation.

The prices to be received by generating units in PJM for capacity have been set through RPM base residual and incremental auctions and depend upon the zone in which the generating unit is located. The average capacity prices that PSEG expects to receive from the base residual and incremental auctions which have been completed are disclosed in Item 8. Note 2. Revenues.

In addition, the PJM capacity market imposes performance obligations and non-performance penalties on resources during times of system stress. These rules provide an opportunity for bonus payments or require the payment of penalties depending on whether a unit is available during a performance interval.

The PTC is intended to provide sufficient and stable support for nuclear units and was effective January 2024. To mitigate volatility in our results, we seek to contract in advance to hedge the price exposure for a significant portion of our anticipated electric output, capacity and fuel needs. The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts. While the PTC eligibility period began in January 2024, the U.S. Treasury has yet to issue guidance regarding the definition of gross receipts. We continue to analyze the impact of the IRA on our nuclear units, including potential future guidance from the U.S. Treasury, potential impacts on hedging strategies and overall financial support.

We historically have sold a portion of our anticipated generation over a multi-year forward horizon, normally over a period of two to three years. Beginning in 2024, our hedging strategy has incorporated 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 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.

Generally, we seek to hedge the financial risks of our generation through sales at PJM West or other nodes corresponding to our generation portfolio. Our hedge transactions in PJM generally reflect energy sales at the liquid PJM Western Hub or other basis locations when available and other transactions that seek to secure price certainty for our energy output. Our hedging practices help to manage some of the volatility of the nuclear generation business when forward prices are greater than the PTC threshold. While this limits our exposure to decreasing prices, our ability to realize benefits from rising market prices is also limited.

Our fuel strategy is to maintain certain levels of uranium in inventory and to make periodic purchases to support such levels. Our nuclear fuel commitments cover approximately 100% of our estimated uranium, enrichment and fabrication requirements through 2027 and a significant portion through 2028.

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 expires on December 31, 2025. Under the OSA, PSEG LI acts as LIPA’s agent in performing many of its obligations and in return (a) is prefunded for pass-through operating expenditures, (b) receives a fixed management fee and (c) is eligible to receive an incentive fee contingent on meeting established performance metrics. PSEG is participating in a process to continue as operations service provider for LIPA’s electrical transmission and distribution system, with resolution expected in the first half of 2025. It is uncertain whether the OSA will be renewed.

PSEG continues to evaluate investment opportunities in regulated transmission beyond PSE&G. In December 2023, PJM awarded us an approximately $424 million project to construct a 500 kV transmission line to address increasing load and reliability issues in Maryland and northern Virginia as part of its 2022 Window 3 competitive solicitation. PJM directed that the project be placed in service in 2027.

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. For additional information, see Item 7. MD&A— Executive Overview of 2024 and Future Outlook.

Energy Holdings maintains our portfolio of legacy lease investments. See Item 8. Note 8. Long-Term Investments and Note 9. Financing Receivables for additional information.

Energy Holdings also owns 50% of Garden State Offshore Energy LLC (GSOE) which holds rights to an offshore wind lease area just south of New Jersey. We are evaluating our options for the potential sale of our interest in GSOE.

Our T&D business is not affected when customers choose alternate electric or gas suppliers since we earn our return on our net investment in rate base to provide T&D service, not by supplying the commodity. Based on our transmission formula rate and the CIP program for electric and gas distribution, we are also minimally impacted by changes in customers’ usage. Our growth is driven by (i) our investment program to deliver energy more reliably by investing to meet anticipated demand growth and modernizing our electric transmission and electric and gas distribution system and (ii) investing in programs that meet State targets to help deliver cleaner energy, including our EE programs to help customers use less energy and investment programs to build EV infrastructure and solar generation. There may also be opportunities to expand into related clean energy areas, such as renewable natural gas, hydrogen, energy storage, additional solar and renewables, and broader EE investments, though utility participation in these areas is subject to regulatory approval and market design, which continues to evolve. That growth can be affected by customer cost pressures which could result from higher commodity costs, higher supply costs to support subsidized renewable generation, higher operating costs, higher tax rates, macro-economic conditions including inflation, and other factors. Further rate regulated recovery methods, such as net metered generation and/or changes in customer usage behavior could lead to a reduction in billed customer usage to recover our costs, resulting in higher rates overall. Conversely, an increase in EV adoption and other factors could lead to an increase in system usage, require incremental investments to meet higher peak demands and result in a larger customer usage base. There could also be a shift toward greater electrification and less gas usage in the coming decades. While current costs and relative emission savings would limit any substantial change in the near term, technological advances for heat pumps, actions by certain jurisdictions in our service territory and other factors could drive these potential changes, which could result in a slowing in the growth of our gas distribution and an increase in the growth of our electric T&D business. Our CIP reduces the impact on our distribution revenues from changes in sales volumes and demand for most customers. The CIP, which is calculated annually, provides for a true-up of our current period revenue as compared to revenue thresholds established in our most recent

distribution base rate proceeding. Recovery under the CIP is subject to certain limitations, including an actual versus allowed ROE test and ceilings on customer rate increases.

Changes previously ordered by FERC and implemented by PJM and other ISOs to eliminate contractual provisions that previously provided us a “right of first refusal” to construct new transmission projects in our service territory could result in third-party construction of transmission lines in our area in the future and also allow us to seek opportunities to build in other service territories. While there has been minimal impact so far, these rules continue to evolve so both the extent of the risk within our service territory and the opportunities for our transmission business elsewhere remain difficult to assess.

Various market participants compete with us and one another in transacting in the wholesale energy markets and entering into bilateral contracts. Our competitors include but are not limited to merchant generators, utility generators, energy marketers, retailers, private equity firms, and other financial entities.

Anticipated demand growth and the pace of that relative to retirements of existing firm generation and new additions of intermittent and firm generation capacity, as well as subsidized generation capacity, or technological advances could impact forward market prices in the future.

PJM has a capacity market that has been approved by FERC. FERC regulates this market and must approve market design rule changes proposed by PJM. For information regarding recent actions by FERC relating to capacity market design, see the discussion in Regulatory Issues—Federal Regulation.

Environmental issues could also impact our competitiveness, including requirements regarding capital investments at our nuclear stations, such as cooling towers, and could lead to a material adverse effect, while other actions to further regulate carbon dioxide emissions could better position our nuclear plants.

Our human capital management strategy is integrated with our overall business strategy. Our Values and strong culture of inclusion support our goal to attract, develop and retain a high performing diverse workforce - one with the skill sets to succeed in a rapidly evolving environment.

We believe in treating people with dignity and respect, protecting each of our fundamental human rights, and striving to maintain the high standards of ethical conduct on which our business and reputation have been built.

The Organization and Compensation Committee of the PSEG Board of Directors is responsible for the oversight of PSEG’s human capital management strategy and risks. It is updated regularly on matters related to culture, executive compensation, and leadership succession and development. Safety metrics, such as Occupational Safety and Health Administration (OSHA) recordable incidence rate, OSHA days away from work rate, and serious injury incidence rate, are regularly monitored and reported to our Board.

Sixty percent of our workforce is represented by six unions under various collective bargaining agreements that cover wages, benefits and other terms and conditions of employment. Our current agreements with all six unions remain in place until 2027 and support strategic objectives and business goals.

The following chart presents our total employee population indicating percentages of employees that are represented by a labor organization:

As of December 31, 2024, women constituted approximately 27% of our non-represented employees and 19% of our total workforce. People who are racially/ethnically diverse constituted approximately 34% of our non-represented employees and 30% of our total workforce.

The safety and security of our employees and the public are integrated into our culture and business operations. We demonstrate this by providing support to employees so that everyone is empowered and encouraged to question, stop and correct any unsafe act or condition and provide feedback on safety and security matters. We take measures to provide employees with proper knowledge, training and protective equipment to maintain their personal health and safety and to mitigate workplace risks.

We provide our dedicated workforce the tools, the resources and an inclusive workplace culture to deliver safe and reliable energy to our customers. Under our Inclusion for All program, we embrace a broad definition of diversity as reflected in our Values where we look to embrace each other’s differences. Our efforts are supported by our Employee Business Resource Groups and Local Inclusion Teams within our business units and field locations. We seek to offer opportunities that are relevant and accessible to all employees, including community outreach, volunteerism, mentorship, recognition and professional development.

To determine if we are being responsive to the needs of our employees, we routinely assess the impact of our work by soliciting employee feedback through focus groups, listening sessions, pulse surveys and a biennial employee engagement survey.

Our recruitment strategy is focused on hiring a workforce to meet our business objectives, including critical skilled trade roles. We have a comprehensive workforce planning strategy to support our hiring needs. It includes hiring ahead of attrition for skilled trade roles, community outreach, workforce development and strategic sourcing with key external partners like trade schools, colleges, county workforce development boards, and other non-profit partners.

We value the growth and development of all our employees and offer a variety of opportunities to enhance their skills and abilities. We hold talent reviews and succession discussions regularly for leadership and critical positions to support workforce planning. We use tailored development opportunities and other tools to build a strong internal pipeline that is ready to take the next step in their careers. We continue to focus on upskilling our skilled trade roles to adapt to evolving technologies and digital advancements.

We support the well-being of our employees through a comprehensive total rewards program. We provide competitive compensation to our workforce and a benefit program that is designed to support emotional and physical health as well as financial wellness and wellbeing.

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.

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.

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.

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 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.

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.

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.

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.

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:

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.

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.

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.

We are subject to federal, state and local laws and regulations with regard to environmental matters. Our associated obligations change as legislatures and regulators pass new laws and regulations and amend existing ones. Therefore, it is difficult to project future costs of compliance and their impact on competition. Capital costs of complying with known pollution control requirements are included in our estimate of construction expenditures in Item 7. MD&A—Capital Requirements. The costs of compliance associated with any new requirements that may be imposed by future regulations are not known but may be material.

For additional information related to environmental matters, including proceedings not discussed below, as well as anticipated expenditures for installation of compliance technology, hazardous substance liabilities and fuel and waste disposal costs, see Item 1A. Risk Factors and Item 8. Note 13. Commitments and Contingent Liabilities.

Our facilities are subject to federal, state and local regulation that requires controls of emissions from sources of air pollution and imposes recordkeeping, reporting and permit requirements.

The Federal Water Pollution Control Act prohibits the discharge of pollutants from point sources to water, except pursuant to a duly issued permit. These permits must generally be renewed every five years. Applicable regulations also impose obligations on facility operators like PSEG Power to install certain technology to treat their discharges to ensure discharges meet certain water quality requirements.

The Environmental Protection Agency’s (EPA) Clean Water Act (CWA) Section 316(b) rule establishes requirements for the regulation of cooling water intakes at existing power plants, such as Salem.

PSEG’s operations involve substances and byproducts classified by environmental regulations as hazardous. These regulations impose handling, storage and disposal requirements for hazardous materials. They also impose liability for damages to the environment, including cash penalties.

Site Remediation—Federal and state environmental laws and regulations require the cleanup of discharged hazardous substances. They authorize the EPA, the New Jersey Department of Environmental Protection (NJDEP) and private parties to commence lawsuits to compel clean-ups or seek reimbursement for such remediation. The clean-ups can be more complicated and costly when the hazardous substances are in or under a body of water. Clean-up obligations may be imposed regardless of the absence of fault, contractual agreements between parties, or the legality of activities at the time of discharge.

In May 2024, the EPA finalized revisions to the coal combustion residuals rule (CCR Rule) which established new requirements for the investigation and, if necessary, the cleanup of certain types of coal ash placed at certain fossil generation station sites, including certain sites owned or formerly owned by PSEG Power. We are in the process of investigating each of the sites that we currently own that are subject to the CCR Rule, as well as sites that we formerly owned that are subject to the CCR Rule where we retained certain environmental obligations to investigate and, if necessary, remediate. PSEG is currently unable to estimate the impact of the CCR Rule, but it could have a material impact on our business, results of operations and cash flows.

Pursuant to the 2022 “Dirty Dirt” legislation, the NJDEP is proposing new requirements for the transportation, handling and disposal of soil and other waste materials generated by utility companies, including PSE&G. NJDEP has not yet finalized the requirements and, therefore, PSE&G is unable to quantify the increased costs of complying with these potential new requirements.

Natural Resource Damages—Federal and state environmental laws and regulations authorize damage assessments against persons who have caused an injury to natural resources through the discharge of a hazardous substance. The NJDEP requires persons conducting remediation to address such injuries through restoration or damage assessments.

Federal and state environmental laws and regulations govern activities that may harm certain wildlife or habitats. These laws and regulations impose permit requirements, prohibit certain activities, and impose penalties for violations.

In December 2024, the U.S. Fish and Wildlife Service proposed to designate the monarch butterfly as a “threatened” species under the federal Endangered Species Act. PSEG is unable to determine the impact of this development.

Nuclear Fuel Disposal—The federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of spent nuclear fuel. Under the Nuclear Waste Policy Act of 1982 (NWPA), nuclear plant owners are required to contribute to a Nuclear Waste Fund to pay for this service. Since May 2014, the nuclear waste fee rate has been zero. No assurances can be given that this fee will not be increased in the future. The NWPA allows spent nuclear fuel generated in any reactor to be stored in reactor facility storage pools or in Independent Spent Fuel Storage Installations located at reactors or away from reactor sites.

We have on-site storage facilities that are expected to satisfy the storage needs of Salem 1, Salem 2, Hope Creek, Peach Bottom 2 and Peach Bottom 3 through the end of their operating licenses.

Low-Level Radioactive Waste—As a by-product of their operations, nuclear generation units produce low-level radioactive waste. Such waste includes paper, plastics, protective clothing, water purification materials and other materials. These waste materials are accumulated on site and disposed of at licensed permanent disposal facilities. New Jersey, Connecticut and South Carolina have reached an agreement that gives New Jersey nuclear generators continued access to a waste disposal facility which is owned by South Carolina. We believe that this agreement will provide for adequate low-level radioactive waste disposal for Salem and Hope Creek through the end of their current licenses including full decommissioning, although no assurances can be given. Additionally, there are on-site storage facilities for Salem, Hope Creek and Peach Bottom, which we believe have the capacity for at least five years of temporary storage for each facility.

The following factors should be considered when reviewing our business. These factors could have a material adverse impact on our business, prospects, financial position, results of operations or cash flows and could cause results to differ materially from those expressed elsewhere in this report.

Inability to successfully develop, obtain regulatory approval for, or construct T&D, and our nuclear generation projects could adversely impact our businesses.

Our business plan calls for extensive investment in capital improvements and additions, including the construction of T&D facilities, modernizing and expanding existing infrastructure pursuant to investment programs that provide for current recovery in rates, addressing needs of new customers and increasing demand on the system, and our CEF programs, particularly our energy efficiency program which provides incentives for customers to install high-efficiency equipment at their premises and transmission capital investments outside of our utility service territory, as well as uprates and other potential investments at our nuclear facilities. Currently, we have several significant capital investments underway or being contemplated.

The successful construction and development of these projects will depend, in part, on our ability to:

Failure to obtain regulatory or other approvals, delays, cost escalations or otherwise unsuccessful construction and development could materially affect our financial position, results of operations and cash flows.

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.

In addition, the successful operation of new facilities or transmission or distribution projects is subject to risks relating to supply interruptions; labor availability, work stoppages and labor disputes; weather interferences; unforeseen engineering and environmental problems, including those related to climate change; opposition from local communities, and the other risks described herein.

Any of these risks could cause the amounts of our investments and/or our return on these investments to be lower than expected, which could adversely impact our financial condition and results of operations through lower investment opportunities and/or lower returns.

We are subject to physical, financial and transition risks related to climate change, including potentially increased legislative and regulatory burdens and changing customer preferences, and we may be subject to lawsuits, all of which could impact our businesses and results of operations.

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. While the CIP protects PSE&G’s margin variances against changes in customer usage of gas and electricity, customer demand for natural gas could decrease as a result 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 these factors could impact the need to invest in our electric and gas T&D systems and, therefore, our company growth rate.

Severe weather or acts of nature, including hurricanes, winter storms, earthquakes, floods, wildfires and other natural disasters can stress systems, disrupt operation of our facilities and cause service outages, and property damage that require incurring additional expenses. In addition, the effects of climate change will have increased the physical risks to our facilities and operations resulting from such climate hazards as more severe weather events (extreme wind, rainfall and flooding), such as experienced from Superstorm Sandy and Tropical Storms Isaias and Ida, sea level rise, and extreme heat and drought.

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 potential 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.

To the extent financial markets view climate change and greenhouse gas (GHG) emissions as a financial risk, our ability to access capital markets could be negatively affected or cause us to receive less than favorable terms and conditions.

Climate change-related political action and state and federal policy goals, including but not limited to those related to energy efficient targets, solar targets, energy storage targets, encouragement of electrification through EV adoption, policies to restrict the use of natural gas in new or existing homes and businesses, or encourage electrification of end use equipment currently fueled by natural gas, and the associated legislative and regulatory responses, may create financial risk as our operations may be subject to additional regulation at either the state or federal level in the future. Increased regulation of GHG emissions could impose significant additional costs on our electric and natural gas operations, our suppliers and ultimately, our customers. Developing and implementing plans for compliance with GHG emissions reduction, clean/renewable energy requirements, or for achieving voluntary climate commitments can lead to additional capital and Operation and Maintenance (O&M) expenditures and could significantly affect the economic position of existing operations and proposed projects. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with increasingly rigorous regulatory mandates, it could have a material adverse effect on our results of operations, financial condition or cash flows. On the other hand, in the event that the political, policy, regulatory or legislative support for clean energy projects declines, the benefits or feasibility of certain investments we could potentially make may be reduced.

We may be subject to climate change lawsuits that may seek injunctive relief, monetary compensation, penalties, and punitive damages, including but not limited to, for liabilities for damages related to mitigate harm caused by climate change. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.

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, 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, accidents, 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 property and to electric and gas supply interruptions. 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.

We are also exposed to the risk of pandemics, which could result in service disruptions and delays or otherwise impair our ability to timely provide service to our customers, complete our investment projects or obtain timely recovery of our costs.

These events could result in increased political, economic, financial and insurance market instability, a lack of available insurance or the availability of insurance on commercially reasonable terms, and volatility in power and fuel markets, which could materially adversely affect our business and results of operations, including our ability to access capital on terms and conditions acceptable to us.

Any of the issues described above, if experienced at our facilities or otherwise in our business, or by others in our industry, could adversely impact our revenues; increase costs to repair and maintain our systems; subject us to potential litigation and/or damage claims, fines or penalties; and increase the level of oversight of our utility and generation operations and infrastructure through investigations or through the imposition of additional regulatory or legislative requirements. Such actions could adversely affect our costs, competitiveness, future investments and customer rates, which could be material to our financial position, results of operations and cash flow. For our T&D business, the cost of storm restoration efforts may not be fully recoverable through the regulatory process. In addition, the inability to restore power to our customers on a timely basis could result in negative publicity and materially damage our reputation.

Any inability to recover the carrying amount of our long-lived assets could result in future impairment charges which could have a material adverse impact on our financial condition and results of operations.

Long-lived assets represent approximately 73% and 80% of the total assets of PSEG and PSE&G, respectively, as of December 31, 2024. Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, including a disallowance of certain costs, a potential sale or disposition of an asset significantly before the end of its useful life, business climate or market conditions, including prolonged periods of adverse commodity and capacity prices, could potentially indicate an asset’s or group of assets’ carrying amount may not be recoverable. Significant reductions in our expected revenues or cash flows for an extended period of time resulting from such events could result in future asset impairment charges, which could have a material adverse impact on our financial condition and results of operations.

Disruptions or cost increases in our supply chain, including labor shortages, could materially impact our business.

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, 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.

Inability to maintain sufficient liquidity in the amounts and at the times needed or access sufficient capital at reasonable rates or on commercially reasonable terms could adversely impact our business.

Funding for our investments in capital improvement and additions, scheduled payments of principal and interest on our existing indebtedness and the extension and refinancing of such indebtedness has been provided primarily by internally-generated cash flow and external debt financings. We have significant capital requirements and depend on our ability to generate cash in the future from our operations and continued access to capital and bank markets to efficiently fund our cash flow needs. Our ability to generate cash flow is dependent upon, among other things, industry conditions and general economic, financial, competitive, legislative, regulatory and other factors. The ability to arrange financing and to refinance existing debt and the costs of such financing or refinancing depend on numerous factors including, among other things:

Market disruptions, such as economic downturns experienced in the U.S. and abroad, the bankruptcy of an unrelated energy company or a systemically important financial institution, changes in market prices for electricity and gas, and actual or threatened acts of war or terrorist attacks, may increase our cost of borrowing or adversely affect our ability to access capital. As a result, no assurance can be given that we will be successful in obtaining financing for projects and investments, extending or refinancing maturing debt or meeting our other cash flow needs on acceptable terms or at all, which could materially adversely impact our financial position, results of operations and future growth.

During periods of rising energy prices, hedged positions could be out-of-the-money, increasing PSEG Power’s collateral requirements. In addition, if PSEG Power were to lose its investment grade credit rating from S&P or Moody’s, it would be required under certain agreements to provide a significant amount of additional collateral in the form of letters of credit or cash, which would have a material adverse effect on our liquidity and cash flows.

Cybersecurity attacks, data breaches, or intrusions or other disruptions to our IT, operational or other systems could adversely impact our businesses.

Cybersecurity threats to the energy market infrastructure are increasing in sophistication, magnitude and frequency, particularly with the regularity of virtual operations. 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. 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. 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:

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. 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 training, table-top exercises, logging and monitoring, and testing. These preventative actions minimize 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.

An increasing demand for power and load growth, potentially compounded by a shift away from natural gas toward increased electrification could cause reliability issues and higher costs for customers, which could lead to potential pressure on fair and timely recovery of our investments and proposed programs.

Substantial investments in generation, transmission and distribution will be required to meet current projections of increasing customer demand. Higher projected demand is driven by a number of factors, including data centers, reshoring manufacturing, port electrification, EV adoption, other electrification and a shift away from natural gas. Sustained distribution grid modernization will also be required to accommodate increased EE, EV infrastructure, increased penetration of distributed energy resources on the electric system, such as on-site solar generation and also potential deployment of

energy storage, fuel cells, and DR technologies. Higher electric demand could significantly increase the prices of energy and capacity, as well as raise resource adequacy and reliability concerns within PJM, particularly if that increased demand outpaces the addition of firm generation capacity and in transmission constrained zones. This resource adequacy challenge presents reliability concerns, as well as potential for increasing energy and capacity prices that could place pressure on customer bills, could attract political and regulatory scrutiny and increase regulatory uncertainty for utility investment initiatives and programs.

Failure to attract and retain a qualified workforce could have an adverse effect on our business.

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, 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.

Inflation, including increases in the costs of equipment and materials, fuel, services and labor could adversely affect our operating results.

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. 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.

Covenants in our debt instruments and credit agreements may adversely affect our business.

PSEG’s and PSE&G’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, contain certain limitations on the incurrence of liens and PSEG Power’s bank credit agreements also contain limitations on the incurrence of certain subsidiary debt. 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.

Financial market performance directly affects the asset values of our defined benefit plan trust funds and Nuclear Decommissioning Trust (NDT) Fund. Market performance and other factors could decrease the value of trust assets and could result in the need for significant additional funding.

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 plans 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 plans 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 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.

If we are unable to enter into or extend certain significant contracts, this may negatively affect our financial condition and operating results

We are party to, and are also exploring opportunities to enter into, several contracts from which we currently or may in the future derive significant revenues.

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. The OSA continues through 2025 and LIPA is currently conducting a process for provision 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.

In addition, we are exploring opportunities for the potential sale of power from our nuclear facilities pursuant to long-term agreements with large power users, such as data centers. It is uncertain whether we will be successful in entering into any of such contracts, including without limitation in connection with various ongoing regulatory proceedings.

Artificial Intelligence is an emerging area of technology that has the potential to impact various aspects of our business operations and customer interactions.

AI, including Generative AI and Post-Quantum Cryptography, has the potential to change the way we operate by creating efficiencies and improving processes and customer experiences. The development, adoption, and use for generative AI technologies are still in their early stages and ineffective or inadequate AI development or deployment practices by PSEG or Nth-party vendors could result in unintended consequences. We contract third-party vendors that use AI in products and/or services they provide and we may not have full control or visibility over the quality, performance, security or compliance of the products and services that incorporate AI-related technology. AI algorithms that we or our Nth-party vendors use may be flawed or may be based on data sets that are biased or insufficient. These limitations or failures could result in reputational damage, unauthorized disclosure of data, and legal liabilities. Developing, testing, and deploying resource-intensive AI systems may require additional investment and increase our costs. In addition, the evolving nature of AI may cause new laws and regulations to be enacted which may require significant resources to modify and maintain business practices to comply with the new laws and regulations, the nature of which cannot be determined at this time. Further, inaccurate results generated as a result of our employees’, contractors’ or vendors’ use of generative AI technologies could lead to operational interruptions or reputational harm.

Fluctuations in the wholesale power and natural gas markets could negatively affect our financial condition, results of operations and cash flows.

In the competitive markets where we operate, participants are not guaranteed any specific rate of return on their capital investments and natural gas prices have a major impact on the price that generators receive for their output. The natural gas market and energy markets have been, and may continue to be, volatile due to higher domestic demand, increased natural gas exports and impacts from the global liquefied natural gas market, weather and other factors. Lower natural gas prices often result in lower electricity prices, which could reduce our margins where our nuclear generation costs may not have declined similarly.

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:

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 PTC thresholds, 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.

In addition, the volatility and potential for higher natural gas or energy prices may have a material impact on collateral requirements related to the forward value of our open futures contracts. Higher collateral requirements reduce available short-term liquidity and increase working capital costs and may affect our ability to hedge generation output and fuel.

We obtain substantially all of our nuclear fuel supply from third parties pursuant to arrangements that vary in term, pricing structure, firmness and delivery flexibility. Our fuel supply arrangements must be coordinated with storage services and other contracts to ensure that the nuclear fuel is delivered to our power plants at the times, in the quantities and otherwise in a manner that meets the needs of our generation portfolio and our customers. We must also comply with laws and regulations governing the transportation of such fuels.

We are exposed to increases in the price of nuclear fuel, and significant changes in the price of nuclear fuel could affect our cash flow, future results and impact our liquidity needs. In addition, we face risks with regard to the delivery to, and the use of nuclear fuel by, our power plants including the following:

The nuclear units we operate have a diversified portfolio of contracts and inventory that provide a substantial portion of our fuel raw material needs over the next several years. However, each of the nuclear units we operate has contracted with a single fuel fabrication services provider, and transitioning to an alternative provider could take an extended period of time. This could have a material adverse impact on our business, the financial results of specific plants and on our results of operations.

Although our fuel contract portfolio provides a degree of hedging against these market risks, such hedging may not be effective and future increases in our fuel costs could materially and adversely affect our financial condition and results of operations.

The introduction or expansion of technologies related to energy generation, distribution and consumption and changes in customer usage patterns could adversely impact us.

Federal and state incentives for the development and operation of renewable sources of power have facilitated the penetration of competing technologies, such as wind, solar, and commercial-sized power storage. Additionally, the development of demand side management (DSM) and EE programs can impact demand requirements for electricity and natural gas markets. The development of competing on-site power generation could also result in a reduction in anticipated growth which could negatively impact our financial condition, results of operations and cash flows.

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.

Some or all of these factors could result in a lack of growth or decline in customer demand for electricity or natural gas or of customers, and may cause us to fail to fully realize anticipated benefits from significant capital investments and expenditures, which could have a material adverse effect on our financial position, results of operations and cash flows. These factors could also materially affect our results of operations, cash flows or financial positions through, among other things, reduced operating revenues, increased O&M expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.

We are subject to third-party credit risk relating to our sale of nuclear generation output.

We sell 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.

There may be periods when PSEG Power generation may not operate and/or may not be able to meet its commitments under forward sale obligations and PJM rules at a reasonable cost or at all.

A portion of PSEG Power’s nuclear generation output has been sold forward under fixed price financial power sales contracts. Forward financial sales offset physical sales in the PJM RTO spot market. Our forward sales of energy and capacity assume sustained, acceptable levels of operating performance. Operations at any of our plants could degrade to the point where the plant has to shut down or operate at less than full capacity. Some issues that could impact the operation of our facilities are:

Identifying and correcting any of these issues may require significant time and expense. Depending on the materiality of the issue, we may choose to close a plant rather than incur the expense of restarting it or returning it to full capacity.

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 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 timing of capacity market auctions, and/or failure to follow existing rules – by PJM or market participants – creates regulatory uncertainty and reliability risk.

PSE&G’s revenues, earnings and results of operations are dependent upon state laws and regulations that affect distribution and related activities.

PSE&G is subject to regulation by the BPU. Such regulation affects almost every aspect of its businesses, including its retail rates. Failure to comply with these regulations could have a material adverse impact on PSE&G’s ability to operate its business and could result in fines, penalties or sanctions. The retail rates for electric and gas distribution services are established in a distribution base rate proceeding and remain in effect until a new distribution base rate proceeding is filed and concluded. PSE&G's base rates were most recently approved in October 2024. In addition, our utility has received approval for several clause recovery mechanisms, some of which provide for recovery of costs and earn returns on authorized investments. These clause mechanisms require periodic financial reviews to update rates charged to customers which are independent of base rate proceedings and are subject to prudency reviews by the BPU. Inability to obtain fair or timely recovery of all our costs pursuant to the distribution base rate case and/or these clause recovery mechanisms, including a return of, or on, our investments in rates, could have a material adverse impact on our results of operations and cash flows. In addition, if legislative and regulatory structures were to evolve in such a way that PSE&G’s exclusive rights to serve its regulated customers were eroded, its future earnings could be negatively impacted.

PSE&G also is pursuing a number of opportunities to expand its products and services to customers. BPU approval is required for any new endeavor, and is not guaranteed. Rejection or delay of such filings could have an adverse impact on our future growth, or our standing stakeholders.

The BPU also conducts periodic combined management/competitive service audits of New Jersey utilities related to affiliate standard requirements, competitive services, cross-subsidization, cost allocation and other issues. A finding by the BPU of non-compliance with these requirements could potentially impact our business, results of operations and cash flows. For information regarding PSE&G’s most recent affiliate and management audit, see Item 8. Note 13. Commitments and Contingent Liabilities.

In addition, PSE&G procures the supply requirements of its default service BGSS gas customers through a full-requirements contract with PSEG Power. Government officials, legislators and advocacy groups are aware of the affiliation between PSE&G and PSEG Power. In periods of rising utility rates, those officials and advocacy groups may question or challenge costs and transactions incurred by PSE&G with PSEG Power, irrespective of any previous regulatory processes or approvals underlying those transactions. The occurrence of such challenges may subject PSEG Power to a level of scrutiny not faced by other unaffiliated competitors in those markets and could even adversely affect retail rates received by PSE&G.

PSE&G’s proposed investment projects or programs may not be fully approved by regulators and actual capital investment by PSE&G may be lower than planned, which would cause lower than anticipated rate base.

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 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 cannot be certain that any proposed project or program will be approved as requested or at all. If the projects or programs that PSE&G may file from time to time are only approved in part, or not at all, or if the approval fails to allow for the timely recovery of all of PSE&G’s costs, including a return of, or on, its investment, PSE&G will have a lower than anticipated rate base, thus causing its future earnings to be lower than anticipated. Further, the BPU could take positions to exclude or limit utility participation in certain areas, such as renewable generation, EE, EV infrastructure, or energy storage programs, renewable natural gas or hydrogen projects, which would limit our relationship with customers and narrow our future growth prospects. In addition, PSE&G’s Clean Energy Future – Energy Efficiency II Program provides nearly $1 billion of funding to continue the on-bill repayment program, which allows customers to repay their cost of equipment upgrades over time directly through their PSE&G bill. While the deployment of this capital in the form of on-bill repayment is subject to customers meeting acceptable credit standard and bad debt expense is a recoverable cost in this program, any such recovery is subject to prudency review and approval by the BPU.

We are subject to comprehensive federal regulation that affects, or may affect, our businesses.

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; 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.

Recovery of wholesale transmission rates—PSE&G’s wholesale transmission rates are regulated by FERC and our project costs are recovered through a FERC-approved formula rate. The revenue requirements are reset each year through this formula. Our formula rate and its components can be challenged at FERC in the future.

In April 2021, FERC issued a supplemental notice of proposed rulemaking to eliminate the incentive for RTO membership for transmitting utilities that have already received the incentive for three or more years. PSE&G began receiving a 50 basis

point adder for RTO membership in 2008. Elimination of the adder for RTO membership would reduce PSE&G’s annual Net Income and annual cash inflows by approximately $40 million.

Transmission Planning—FERC Order 1000 generally opened transmission development to competition from independent developers, allowing such developers to compete with incumbent utilities for the construction and operation of transmission facilities in its service territory. While Order 1000 retains limited carve-outs for certain projects that will continue to default to incumbents for construction responsibility, increased competition for transmission projects could decrease the value of new investments that would be subject to recovery by PSE&G under its rate base, which could have a material adverse impact on our financial condition and results of operations. FERC has considered, and may in the future consider, whether to modify - either limit or expand - Order 1000’s competition rules. FERC is also examining whether additional oversight is needed to control transmission costs.

A significant input into PJM’s transmission planning process is its regional load forecast, which is adjusted on an annual basis. In January 2025, PJM adjusted its load forecast in the PSEG zone and across PJM to reflect increased 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.

NERC Compliance—NERC, at the direction of FERC, has implemented mandatory NERC Operations and Planning and Critical Infrastructure Protection standards to ensure the reliability of the North American Bulk Electric System, which includes electric transmission and generation systems, and to prevent major system blackouts. NERC Critical Infrastructure Protection standards establish cybersecurity and physical security protections for critical systems and facilities. We have been, and will continue to be, periodically audited by NERC for compliance with both Operations and Planning and Critical Infrastructure Protection standards and are subject to penalties for non-compliance with applicable NERC standards. Failure to comply with applicable NERC standards could result in penalties or increased costs to bring such facilities into compliance. Such penalties and costs could materially adversely impact our business, results of operations and cash flows. Adverse audit findings and/or penalties for non-compliance could also pose reputational risk to us.

MBR Authority and Other Regulatory Approvals—Under FERC regulations, public utilities that sell power at market rates must receive MBR authority before making power sales, and the majority of our businesses operate with such authority. Failure to maintain MBR authorization, or the effects of any severe mitigation measures that would be required if market power was evaluated differently in the future, could have a material adverse effect on our business, financial condition and results of operations. In December 2022, all of PSEG’s operating companies with MBR authority filed at FERC for acceptance of the companies’ updated triennial market power analysis. This filing remains pending at FERC.

Oversight by the CFTC relating to derivative transactions—The CFTC has regulatory oversight of the swap and futures markets and options, including energy trading, and licensed futures professionals such as brokers, clearing members and large traders. Changes to regulations or adoption of additional regulations by the CFTC, including any regulations relating to futures and other derivatives or margin for derivatives and increased investigations by the CFTC, could negatively impact PSEG Power’s ability to hedge its portfolio in an efficient, cost-effective manner by, among other things, potentially decreasing liquidity in the forward commodity and derivatives markets or limiting PSEG Power’s ability to utilize non-cash collateral for derivatives transactions.

We may also be required to obtain various other regulatory approvals to, among other things, buy or sell assets, engage in transactions between our public utility and our other subsidiaries, and, in some cases, enter into financing arrangements, issue securities and allow our subsidiaries to pay dividends. Failure to obtain these approvals on a timely basis could materially adversely affect our results of operations and cash flows.

The markets, PTC and/or ZEC program 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 2024 and Future Outlook, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants have been awarded ZECs by the BPU through May 2025.

In August 2022, the IRA was signed into law expanding incentives promoting carbon-free generation. The enacted legislation established a PTC for electricity generation using nuclear energy which begins January 1, 2024 and continues through 2032. 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. The U.S. Treasury has not yet defined gross receipts. The ZEC payment will be adjusted by the BPU to offset environmental or fuel diversity payments that a selected nuclear plant may receive from another source. We continue to estimate the PTC while we await additional guidance from the U.S. Treasury. The U.S. Treasury may issue guidance related to the PTC and/or the Federal government could amend the IRA, either of which could have an adverse impact on our financial condition, results of operations and cash flows.

If the markets, 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.

We may be adversely affected by changes in energy regulatory policies, including energy and capacity market design rules and developments affecting transmission.

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. 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.

Further, some of the market-based mechanisms in which we participate are at times the subject of review or discussion by some of the participants in the New Jersey and federal arenas. We can provide no assurance that these mechanisms will continue to exist in their current form, nor otherwise be modified.

Our ownership and operation of nuclear power plants involve regulatory risks as well as financial, environmental and health and safety risks.

We are exposed to risks related to the continued successful operation of our nuclear facilities and issues that may adversely affect the nuclear generation industry. In addition to the risk of retirement discussed below, risks associated with the operation of nuclear facilities include:

Storage and Disposal of Spent Nuclear Fuel—Federal law requires the United States Department of Energy (DOE) to provide for the permanent storage of spent nuclear fuel. The DOE has not yet begun accepting spent nuclear fuel. Until a federal site is available, we use on-site storage for spent nuclear fuel, which is reimbursed by the DOE. However, future capital expenditures may be required to increase spent fuel storage capacity at our nuclear facilities. Once a federal site is available, the DOE may impose fees to support a permanent repository. Further, the on-site storage for spent nuclear fuel may significantly increase our nuclear unit decommissioning costs.

Regulatory and Legal Risk—We may be required to substantially increase capital expenditures or operating or decommissioning costs at our nuclear facilities if there is a change in the Atomic Energy Act or the applicable regulations, trade controls or the environmental rules and regulations applicable to nuclear facilities; a modification, suspension or revocation of licenses issued by the NRC; the imposition of civil penalties for failure to comply with the Atomic Energy Act, related regulations, trade controls or the terms and conditions of the licenses for nuclear generating facilities; or the shutdown of one of our nuclear facilities. Any such event could have a material adverse effect on our financial condition or results of operations.

Operational Risk—Operations and equipment reliability at any of our nuclear facilities, whether operated by us or our co-owner, could degrade to the point where an affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes could require significant time and expense and a significant outage could result in reduced earnings as we would have less electric output to sell and would be required to deliver on our forward sale commitments.

In addition, if a unit cannot be operated through the end of its current estimated useful life, our results of operations could be adversely affected by increased depreciation rates, impairment charges and accelerated future decommissioning costs.

Nuclear Incident or Accident Risk—Accidents and other unforeseen problems have occurred at nuclear stations, both in the U.S. and elsewhere. The consequences of an accident can be severe and may include loss of life, significant property damage and/or a change in the regulatory climate. We have nuclear units at two sites. It is possible that an accident or other incident at a nuclear generating unit could adversely affect our ability to continue to operate unaffected units located at the same site, which would further affect our financial condition, results of operations and cash flows. An accident or incident at a nuclear unit not owned by us could lead to increased regulation, which could affect our ability to continue to economically operate our units. Any resulting financial impact from a nuclear accident may exceed our resources, including insurance coverages. Further, as a licensed nuclear operator subject to the Price-Anderson Act and a member of a nuclear industry mutual insurance company, PSEG Power is subject to potential retroactive assessments as a result of an industry nuclear incident or retrospective premiums due to adverse industry loss experience and such assessments may be material.

In the event of non-compliance with applicable legislation, regulation and licenses, the NRC may increase oversight, impose fines, and/or shut down a unit, depending on its assessment of the severity of the non-compliance. If a serious nuclear incident were to occur, our business, reputation, financial condition and results of operations could be materially adversely affected. In each case, the amount and types of insurance available to cover losses that might arise in connection with the operation of our nuclear fleet are limited and may be insufficient to cover any costs we may incur.

Decommissioning—NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available to decommission a nuclear facility at the end of its useful life. PSEG Nuclear has established an NDT Fund to satisfy these obligations. However, forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. If we determine that it is necessary to retire one of our nuclear generating stations before the end of its useful life, there is a higher risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT investments could appreciate in value. A shortfall could require PSEG to post parental guarantees or make additional cash contributions to ensure that the NDT Fund continues to satisfy the NRC minimum funding requirements. As a result, our financial position or cash flows could be significantly adversely affected.

Third-Party Operation of Peach Bottom Plants—While we have a 50% ownership interest in the Peach Bottom nuclear generation plants, these plants are operated by a third party and, therefore, we have limited control over the operational and other risks associated with these plants.

We are subject to numerous federal, state and local environmental laws and regulations that may significantly limit or affect our businesses, adversely impact our business plans or expose us to significant environmental fines and liabilities.

We are subject to extensive federal, state and local environmental laws and regulations regarding air quality, water quality, site remediation, land use, waste disposal, climate change impact, natural resource damages and other matters. These laws and regulations affect how we conduct our operations and make capital expenditures. Over the past several years, there have been various changes to make existing environmental laws and regulations stricter and this trend may continue. Changes in these laws, or violations of laws, could result in significant increases in our compliance costs, capital expenditures to bring facilities into compliance, operating costs for remediation and clean-up actions, civil penalties or damages from actions brought by third parties for alleged health or property damages. Any such increase in our costs could have a material impact on our financial condition, results of operations and cash flows and could require further economic review to determine whether to continue operations or decommission an affected facility. We may also be unable to successfully recover certain

of these cost increases through our existing regulatory rate structures, in the case of PSE&G, or our contracts with our customers, in the case of PSEG Power.

Actions by state and federal government agencies could also result in reduced reliance on natural gas and could potentially result in stranding natural gas assets owned and operated by PSE&G, which could materially adversely affect our business, financial condition and results of operations.

PSE&G recovers certain remediation and legal costs associated with its manufactured gas plant sites through Remediation Adjustment Charge (RAC) filings with the BPU. Continued future recoveries through the RAC are not guaranteed. Any failure to make future recoveries could materially impact our financial condition.

In addition, PSEG Power retained ownership of certain liabilities excluded from the sale of its fossil generation portfolio. These primarily relate to obligations under environmental regulations, including remediation obligations under the New Jersey Industrial Site Recovery Act and the Connecticut Transfer Act. It will require multiple years and comprehensive environmental sampling to understand the extent of and to carry out the required remediation. At this stage of the remediation process, the full remediation costs are not estimable, but given the number and operating history of the facilities in the portfolio, the full remediation costs will likely be material in the aggregate. The costs could potentially include costs for, among other things, excavating soil, implementation of institutional controls, and the construction, operation and maintenance of engineering controls.

Environmental laws and regulations have generally become more stringent over time, and this trend is likely to continue. For further discussion of environmental laws and regulations impacting our business, results of operations and financial condition, including the impact of federal and state laws and regulations relating to remediation of environmental contamination, see Item 8. Note 13. Commitments and Contingent Liabilities.

We may not receive necessary licenses, permits and siting approvals in a timely manner or at all, which could adversely impact our business and results of operations.

We must periodically apply for licenses and permits from various regulatory authorities, including environmental regulatory authorities, and siting/permitting approvals for our transmission investments, and abide by their respective orders. Delay in obtaining, or failure to obtain and maintain, any permits or approvals, including environmental permits or approvals, or delay in or failure to satisfy any applicable regulatory requirements, could:

each of which could materially affect our business, financial condition, results of operations and cash flows. In addition, the process of obtaining licenses and permits from regulatory authorities may be delayed or defeated by concerted community opposition and such delay or defeat could have a material effect on our business.

Changes in tax laws and regulations may adversely affect our financial condition, results of operations and cash flows.

The enactment, amendment or repeal of federal or state tax legislation and/or the clarification of previously enacted tax laws, including U.S. Treasury guidance relating to the 15% CAMT, the nuclear PTC and other energy tax credit provisions, could have a material impact on our effective tax rate and cash tax position.

ITEM 1C. CYBERSECURITY

To reduce the likelihood and severity of cybersecurity incidents, we established a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of our technology systems and business operations more broadly. For a discussion of the risks associated with cybersecurity threats, see Item 1A. Risk Factors.

Risk Management and Strategy

Our processes for assessing, identifying, and managing material risks from cybersecurity threats include:

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Ongoing Assessment—The Cybersecurity department, led by the VP, Chief Information Security Officer (CISO), and reporting to the SVP, Chief Information and Digital Officer (CIDO) is staffed with cyber professionals tasked with the day-to-day responsibility of assessing material risks from cybersecurity threats. In addition, the Cybersecurity Council, comprised of senior management, is kept apprised of the state of PSEG’s cybersecurity program, including any emerging risks, and provides guidance on the strategic directions of the program.

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Engagement of Nth Parties—We engage Nth parties (third parties and other business relationships, including fourth parties, etc.), such as cybersecurity service providers, risk management firms, and external legal counsel, to assess material risks from cybersecurity threats and assess our internal incident response preparedness and cyber posture, support incident response, conduct tabletop exercises, and comply with applicable laws and regulations. We also carry cybersecurity insurance that provides certain protection against losses from a cybersecurity incident. Regulatory agencies, including but not limited to the NRC and Transportation Security Administration (TSA), as well as NERC, inspect applicable components of our cybersecurity program.

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Nth-Party Service Provider Management—We maintain processes to oversee and identify risks from cybersecurity threats associated with our use of Nth-party service providers. This includes a risk-based vendor management program, which incorporates robust cybersecurity contractual provisions, vendor security assessments and, if appropriate, periodic audits.

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Technical Safeguards—We manage controls to protect our network perimeter, internal IT and Operational Technology (OT) environments, such as internal and external firewalls, network intrusion detection and prevention, penetration testing, vulnerability assessments, threat intelligence, endpoint security and access controls.

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Training and Awareness—We provide mandatory annual cybersecurity training for all personnel with network access, and additional education for personnel with access to industrial control systems and/or customer information systems; and conduct phishing exercises with progressive consequences for failures. Employees also receive periodic cybersecurity awareness messages and each year, in recognition of Cybersecurity Awareness Month, are invited to presentations throughout October from internal and external cyber experts covering diverse cyber topics. These efforts better enable all employees to identify potential cybersecurity risks and escalate them appropriately.

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Incident Response Plans—We maintain and periodically update a cyber incident response plan that addresses the life cycle of a cybersecurity incident from a technical perspective (i.e., detection, response, and recovery), and a data breach response plan (with a focus on external communication/disclosure and legal compliance); and conduct regular tabletop exercises to test plan effectiveness (both internally and through external exercises).

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Mobile Security—We maintain controls to prevent loss of data through mobile device channels.

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Physical Security—We also maintain physical security measures to protect our OT systems, consistent with a defense in-depth and risk-tiered approach. Physical security measures may include access control systems, video surveillance, around-the-clock command center monitoring, and physical barriers (such as fencing, walls, and bollards). Additional features of PSEG’s physical security program include threat intelligence, insider threat mitigation, background checks, a threat level advisory system, a business interruption management model, and active coordination with federal, state, and local law enforcement officials. See Item 1. Business. Regulatory Issues—Federal Regulation for a discussion of Critical Infrastructure Protection standards that the NERC promulgated that mitigate risk associated with both cybersecurity and physical security of PSEG’s critical facilities.

These processes are integral to our overall risk management system/processes and inform the identification and assessment of risks and mitigations through our Enterprise Risk Management (ERM) program. The ERM team, led by the SVP, Audit, Enterprise, Risk and Compliance (AERC) considers cybersecurity risks alongside other PSEG risks, and facilitates discussion

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Management’s Role in Assessing and Managing Material Cybersecurity Risks:

The assessment and management of material risks from cyber threats is managed by the CIDO, CISO and Cybersecurity Council, as further described below.

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CIDO—The CIDO has had the overall responsibility for PSEG’s cybersecurity since September 2022, including the assessment and management of material risks to PSEG from cybersecurity threats. The CIDO has served in that position since August 2020 and is a direct report to the CEO. The CIDO has over 25 years of energy experience inclusive of leading technology compliance with cybersecurity regulations for nuclear, transmission, gas and corporate assets. Our CIDO’s experience includes leading the secure technology design, development, and deployment strategy for grid modernization efforts, including digital customer engagement platforms, advanced metering, enterprise asset management and distribution automation functionality.

As noted above, the CIDO provides cybersecurity updates to the Board or its Committees, regularly attends and provides updates with the CISO to the IOC, and has met with the IOC, without other members of management present, during the IOC executive sessions.

The CIDO remains informed about the monitoring, prevention, detection, mitigation, and remediation of cybersecurity incidents through the CISO and other members of the cybersecurity team, as appropriate, who are tasked with these responsibilities on a day-to-day basis.

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CISO—The CISO has day-to-day responsibility for PSEG’s cybersecurity, including the assessment and management of material risks to PSEG from cybersecurity threats, and leads the cybersecurity team. The CISO served in this role since July 2024. Our CISO has over 20 years of experience in cybersecurity and served as a VP, CISO in the manufacturing/chemicals sector prior to joining PSEG. Our CISO also started her career at the Department of Defense and led cyber teams in the financial and retail sectors. Our CISO holds an MBA in strategy, an MSE in Computer Science, a BS in Computer Science, and multiple cybersecurity certifications, including Certified Information Systems Security Professional.

As noted above, the CISO provides cybersecurity updates during the four regularly scheduled IOC meetings and regularly meets with the IOC, without other members of management present, during executive sessions. The CISO remains informed about the monitoring, prevention, detection, mitigation, and remediation of cybersecurity incidents through the members of the CISO’s cybersecurity team, who are tasked with these responsibilities on a day-to-day basis.

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Cybersecurity Council—The Cybersecurity Council, chaired by the CISO, ensures that senior management, and ultimately, the Board, are given the information required to exercise proper oversight over cybersecurity risks and that escalation procedures are followed. The Cybersecurity Council meets at least six times annually to receive reports on the state of PSEG’s cybersecurity program, provide guidance on the strategic direction of the program, discuss emerging cybersecurity issues, and review the cybersecurity scorecard to measure performance of key risk indicators. The Cybersecurity Council receives presentations from the CISO, members of the Cybersecurity team, other IT domain experts, cybersecurity managing counsel and external cybersecurity experts, and participates in tabletop exercises led by external consultants. In addition to the CISO, the Cybersecurity Council members include the: (i) CIDO; (ii) EVP and General Counsel; (iii) EVP and CFO; (iv) President and COO of PSE&G; (v) President of PSEG Nuclear and Chief Nuclear Officer; (vi) SVP – Corporate Citizenship; (vii) SVP – Chief Human Resources and Diversity Officer; (viii) VP of Corporate Security and Properties; (ix) SVP – AERC; (x) Project Executive Advisor; and (xi) Vice President and Controller. PSEG’s Corporate Secretary and Managing Counsel – Cybersecurity serves as counsel to the Cybersecurity Council. In providing oversight of risks from cybersecurity threats, Senior Management is informed of cybersecurity risks through updates shared during Cybersecurity Council meetings and through notifications or updates by the CISO, pursuant to PSEG’s Cybersecurity Event Escalation and Incident Response Practice.

For a discussion of regulatory requirements relating to cybersecurity matters, see Item 1. Business—Regulatory Issues.

All of our owned physical property is held by our subsidiaries. We believe that we and our subsidiaries maintain adequate insurance coverage against loss or damage to plants and properties, subject to certain exceptions and deductibles, to the extent such property is usually insured and insurance is available at a reasonable cost. For a discussion of nuclear insurance, see Item 8. Note 13. Commitments and Contingent Liabilities.

Primarily all of PSE&G’s property is located in New Jersey and PSE&G’s First and Refunding Mortgage, which secures the bonds issued thereunder, constitutes a direct first mortgage lien on substantially all of PSE&G’s property. PSE&G’s electric lines and gas mains are located over or under public highways, streets, alleys or lands, except where they are located over or under property owned by PSE&G or occupied by it under easements or other rights. PSE&G deems these easements and other rights to be adequate for the purposes for which they are being used.

As of December 31, 2024, PSE&G’s electric T&D system included approximately 25,000 circuit miles and 869,000 poles, of which 64% are jointly-owned. In addition, PSE&G owns and operates 57 switching stations with an aggregate installed capacity of approximately 40,000 megavolt-amperes (MVA) and 234 substations with an aggregate installed capacity of approximately 10,750 MVA. In addition, PSE&G owns four electric distribution headquarters and five electric sub-headquarters.

As of December 31, 2024, PSE&G’s gas system included approximately 18,000 miles of gas mains, 12 gas distribution headquarters, two sub-headquarters, and two meter shops serving all of its gas territory in New Jersey. In addition, PSE&G operates 54 natural gas metering and regulating stations, of which 25 are located on land owned by customers or natural gas pipeline suppliers and are operated under lease, easement or other similar arrangement. In some instances, the pipeline companies own portions of the metering and regulating facilities. PSE&G also owns one liquefied natural gas and three liquid petroleum air gas peaking facilities. The daily gas capacity of these peaking facilities (the maximum daily gas delivery available during the three peak winter months) is approximately 2.9 million therms in the aggregate.

As of December 31, 2024, PSE&G owned 158 MW dc of installed PV solar capacity throughout New Jersey.

As of December 31, 2024, PSEG Power’s share of installed nuclear generating capacity is shown in the following table:

We are party to various lawsuits and environmental and regulatory matters, including in the ordinary course of business. For information regarding material legal proceedings, see Item 1. Business—Regulatory Issues and Environmental Matters and Item 8. Note 13. Commitments and Contingent Liabilities.

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed on the New York Stock Exchange, Inc. under the trading symbol “PEG.” As of February 21, 2025, there were 45,779 registered holders.

The following graph shows a comparison of the five-year cumulative return assuming $100 invested on December 31, 2019 in our common stock and the subsequent reinvestment of quarterly dividends, the S&P Composite Stock Price Index, the Dow Jones Utilities Index and the S&P Electric Utilities Index.

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.

The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2024:

The number of shares available for future issuance includes amounts remaining under our 2021 Long-Term Incentive Plan (2021 LTIP) and 2021 Equity Compensation Plan for Outside Directors and the Employee Stock Purchase Plan and reflect a reduction for non-vested restricted stock units and performance share units (PSUs) (assumed at target payout). The number of shares available for future issuance may be increased or decreased depending on actual payouts for the PSUs based on achievement of targets and is increased by the number of shares that are forfeited, canceled or otherwise terminated without the issuance of shares. For additional discussion of specific plans concerning equity-based compensation, see Item 8. Note 18. Stock Based Compensation.

We own all of the common stock of PSE&G. For additional information regarding PSE&G’s ability to continue to pay dividends, see Item 7. MD&A—Liquidity and Capital Resources.

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:

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 2024 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.

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 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. In addition, the passage of the Inflation Reduction Act 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, our regulated capital investment program is estimated to be in a range of $21 billion to $24 billion. We expect these capital investments to result in a compound annual growth rate in our regulated rate base in a range of 6% to 7.5% from year-end 2024 to year-end 2029. The regulated capital investments represent the majority of PSEG’s total capital investment program of $22.5 billion to $26 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, 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.

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.

A remaining component of our CEF-Electric Vehicle (EV) program related to medium- and heavy-duty charging infrastructure has been the subject of a stakeholder process that the BPU began in 2021. 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 provides for PSE&G’s program investment up to $30 million and requires electric utilities to submit program filings by February 2025. In November 2024, the BPU released an updated draft Storage Incentive Program proposal. Our proposed CEF-Energy Storage (ES) program for a $109 million investment is being held in abeyance until the BPU concludes its proceedings.

In 2023, the BPU also approved a two-year extension of our current GSMP program to replace at least 400 miles of cast iron and unprotected steel mains and services in our gas system. The GSMP program extension provides for main replacement through December 2025 plus trailing services replacement and paving costs into 2026 and totals approximately $900 million of investment. Of the $900 million, $750 million is recovered through three periodic rate updates with the balance recovered through a future distribution base rate case. Pursuant to that settlement, we commenced extension discussions for our GSMP program in January 2025 with the intent of beginning a new program in January 2026.

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 that case with new rates effective October 15, 2024. The Order provides 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. For additional information, see Item 8. Note 6. Regulatory Assets and Liabilities.

At PSEG Power, we seek to produce low-cost electricity by efficiently operating our nuclear generation assets, mitigate earnings volatility through the PTC mechanism and hedging, and support public policies that preserve these existing carbon-free base load nuclear generating plants. During 2024, our nuclear units generated approximately 31 terawatt hours and operated at a capacity factor of approximately 90%. Beginning in 2024, our hedging strategy incorporated 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 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. In addition, we are exploring opportunities for the potential sale of power and/or emission credits from our nuclear facilities pursuant to long-term agreements.

For more than a century, our purpose has been to provide safe access to an around-the-clock supply of reliable, affordable energy. Today, our vision is to power a future where people use less energy, and it is cleaner, safer and delivered more reliably than ever. We have established a 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.

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-EV programs and the proposed CEF-ES program 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, from 2018 through 2024 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% 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 potential long-term contracts that recognize the value of its consistent and reliable carbon-free energy.

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

In April 2024, PSE&G submitted bids to the BPU for what the BPU has termed the Pre-Build Infrastructure (PBI) project, which is a combination of onshore and near-shore underwater infrastructure. It is unclear when the BPU may take action on this initiative, or parallel processes it has considered for transmission projects to support New Jersey’s offshore wind goal.

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.

In 2024, LIPA issued requests for two proposals - one for a service provider to operate its electrical transmission and distribution system and one for power supply and fuel management services, both of which are currently performed under contracts with PSEG that run through December 31, 2025. PSEG is negotiating its proposal with LIPA to continue as operations service provider for LIPA’s electrical transmission and distribution system, though the outcome of this process is uncertain. LIPA has selected another party for the power supply and fuel management services contract which will not have a material impact on PSEG's results of operations.

The financial results for PSEG, PSE&G and PSEG Power & Other for the years ended December 31, 2024 and 2023 are presented as follows:

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

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. In April 2021, FERC proposed eliminating this ROE adder for Regional Transmission Owner participation. FERC has not acted on the proposal. If the adder was eliminated, it would reduce PSE&G’s annual Net Income and annual cash inflows by approximately $40 million.

In February 2023, the 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. The EOs direct the BPU and other state agencies to collaborate with stakeholders to develop plans to reach the targets and the BPU has convened a stakeholder proceeding to develop a plan for gas distribution utilities to reach the target of 50% natural gas emissions reductions over 2006 levels by 2030. The BPU commenced proceedings to update the State’s EMP via public input hearings in May and June 2024. We are unable to predict the outcomes of this proceeding, but it could have a material impact on our business, results of operations and cash flows.

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 along the Passaic and Hackensack Rivers are alleged by federal and state agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes. 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 13. Commitments and Contingent Liabilities.

In April 2021, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded zero emission certificates (ZECs) for 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. Pursuant to a process established by the BPU, ZECs are purchased

from selected nuclear plants and recovered through a non-bypassable distribution charge in the 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)). As previously noted, in August 2022, the IRA was signed into law expanding incentives promoting carbon-free generation. The enacted legislation 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 is reduced by the estimated PTCs generated from PSEG Power’s Salem 1, Salem 2, and Hope Creek 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 IRA on our nuclear units, and will analyze 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. 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 to 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 base rate filings and clause-based investment programs.

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 April 2023, the U.S. Treasury issued Revenue Procedure 2023-15 that provides a safe harbor method of accounting to determine the annual repair tax deduction for gas T&D property. The impact, if any, that this may have on PSEG and PSE&G’s financial statements has not yet been determined.

The IRA enacted a new 15% corporate alternative minimum tax (CAMT), which is based on adjusted financial statement income, a PTC for existing nuclear generation facilities, discussed above, and allows energy tax credits to be transferable. Many aspects of the IRA, including the CAMT and PTC, remain unclear and are in need of further guidance; therefore, we continue to analyze the impact the IRA will have on PSEG’s and PSE&G’s results of operations, financial condition and cash flows, which could be material.

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 continue to:

In addition to the risks described elsewhere in this Form 10-K for 2024 and beyond, the key issues and challenges we expect our business to confront include:

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:

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.

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 (Loss) attributable to changes related to the NDT Fund and MTM are shown in the following table:

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 24. Related-Party Transactions.

The 2024, 2023 and 2022 amounts in the preceding table for Operating Revenues and O&M costs each include $592 million, $533 million and $516 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 4. Variable Interest Entity for additional information. The following discussions for PSE&G and PSEG Power provide a detailed explanation of their respective variances.

(A) Includes amortization of EE programs regulatory investment expenditures of $125 million, $82 million and $48 million for the years ended December 31, 2024, 2023 and 2022, respectively.

Operating Revenues increased $642 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 $321 million due primarily to $170 million from increased electric and gas revenues primarily as a result of the recently settled distribution base rate case, $99 million increase in transmission revenues due primarily to higher rate base investments, $26 million in increased revenues from Energy Strong II and IAP distribution rate roll ins, $42 million from increased GPRC revenues, $9 million from a reduction in revenue credits flowed back to customers as part of our TAC mechanism, offset by a decrease of $25 million in CIP decoupling revenues.

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 increased $141 million due primarily to a $132 million net increase in Tax Adjustment Credits (TAC) and Green Program Recovery Charge (GPRC) deferrals and $10 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 of 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 $143 million due to higher electric BGS revenues of $276 million from higher prices and sales volumes, offset by lower gas BGSS revenues of $133 million primarily from lower prices.

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). The revenues from these programs offset costs included in Energy Costs. In addition, other operating revenues include revenues from our appliance service business which offers various appliance protection and repair plans to customers.

Other Operating revenues increased $37 million due primarily to net increases in GPRC related other operating revenues of $35 million.

Energy Costs increased $179 million. This is offset by changes in Commodity Revenues and Other Operating Revenues.

Operation and Maintenance increased $106 million due primarily to higher T&D expenditures and net increases in various other operational expenses.

Depreciation and Amortization increased $45 million due primarily to an increase in depreciation due to higher plant placed in service, partially offset by a net decrease in the amortization of Regulatory Assets and Liabilities.

Net Other Income (Deductions) decreased $16 million due primarily to lower Allowance for Funds Used During Construction.

Net Non-Operating Pension and OPEB Credits decreased $37 million due primarily to a $43 million decrease in the amortization of prior service credits and a $6 million increase in amortization of the net actuarial loss, partially offset by a $7 million decrease in interest cost, $3 million in settlement charges in 2023 and a $2 million increase in the expected return on plan assets.

Interest Expense increased $89 million due primarily to long-term debt net issuances at higher rates in 2024 and 2023.

Income Tax Expense increased $138 million due primarily to higher pre-tax income and a decrease in the flowback of excess deferred income tax benefits.

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, 2023 as filed with the SEC on February 26, 2024 for information related to the year ended December 31, 2023 as compared to 2022, which information is incorporated herein by reference.

Operating Revenues decreased $1,726 million due primarily to changes in generation and gas supply and other operating revenues.

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 decreased $183 million due to

Generation costs decreased $10 million due primarily to lower renewable energy credit requirements caused by decreases in load volumes served.

Operation and Maintenance increased $100 million due primarily to a refueling outage in 2024 at our 100%-owned Hope Creek nuclear plant as compared to an outage at our 57%-owned Salem 2 nuclear plant in 2023, and higher Servco operating costs, partially offset by higher Services billings to PSE&G. See Item 8. Note 4. Variable Interest Entity for additional information on Servco and LIPA.

Net Gains (Losses) on Trust Investments decreased $62 million due primarily to NDT investments with $99 million of lower unrealized gains on equity securities as compared to the prior year, partially offset by $35 million of higher net realized gains in 2024.

Net Non-Operating Pension and OPEB Costs decreased $328 million primarily due to the pension lift-out settlement charge in August 2023.

Interest Expense increased $46 million due primarily to incremental debt and the replacement of maturing long-term debt at higher rates, partially offset by a reduction in term loans.

Income Tax Expense decreased $603 million due primarily to lower pre-tax income in 2024 and the benefit from PTCs.

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.

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.

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.

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, 2024, our operating cash flow decreased $1,673 million, as compared to 2023. The net decrease was primarily due to an outflow of $131 million in net cash collateral postings in 2024 as compared to a $1,408 million inflow in 2023 at PSEG Power, partially offset by a net change at PSE&G, as discussed below.

PSE&G’s operating cash flow increased $185 million from $1,540 million to $1,725 million for the year ended December 31, 2024, as compared to 2023. The increase was due primarily to higher earnings, the absence of returning cash collateral postings in 2024, which had been returned to BGS suppliers in 2023, and decreases in materials and supplies to support our electric AMI and other infrastructure programs. This was partially offset by a net increase in regulatory deferrals and accounts receivable, as well as lower unbilled revenues due primarily to higher volumes and lower prices.

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.

PSEG Power has uncommitted credit facilities totaling $200 million, which can be utilized for letters of credit. As of December 31, 2024, PSEG Power had $75 million in letters of credit outstanding under these uncommitted credit facilities. In addition, a subsidiary of PSEG Power has an uncommitted credit facility for $150 million, which can be utilized for cash collateral postings.

Our total committed credit facilities and available liquidity as of December 31, 2024 were as follows:

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, 2024, 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 $618 million and $751 million as of December 31, 2024 and 2023, respectively. See Item 8. Note 13. Commitments and Contingent Liabilities for additional discussion of PSEG Power’s agreements.

The NRC requires a biennial filing of the NDT fund balances against the decommissioning liability estimate. Any funding shortfalls are required to be cured prior to the next NDT reporting period. We do not currently expect to be required to provide supplemental funding of the NDT Fund.

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, 2024, PSE&G’s Mortgage coverage ratio was 3.3 to 1 and the Mortgage would permit up to approximately $11 billion aggregate principal amount of new Mortgage Bonds to be issued against additions and improvements to its property.

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 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 existing 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. 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.

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.

On February 11, 2025, our Board of Directors approved a $0.63 per share common stock dividend for the first quarter of 2025. This reflects an indicative annual dividend rate of $2.52 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 22. Earnings Per Share (EPS) and Dividends.

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.

For the year ended December 31, 2024, we had Other Comprehensive Income of $46 million on a consolidated basis. The Other Comprehensive Income was due primarily to $33 million of unrealized gains on derivative contracts accounted for as hedges, $26 million related to pension and other postretirement benefits, offset by $13 million of net unrealized losses related to available-for-sale debt securities. See Item 8. Note 21. Accumulated Other Comprehensive Income (Loss), Net of Tax for additional information.

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.

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:

In 2024, PSE&G made $2,921 million of capital expenditures, primarily for T&D system reliability. In addition, PSE&G had cost of removal, net of salvage, of $170 million associated with capital replacements, and expenditures for EE programs of approximately $544 million, which are included in operating cash flows.

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.

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 2024, PSEG Power & Other made capital expenditures of $251 million, excluding $208 million for nuclear fuel, primarily related to various nuclear projects at PSEG Power and various IT projects at Services.

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 14. Debt and Credit Facilities, Note 7. Leases and Note 13. Commitments and Contingent Liabilities.

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 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans and Note 11. Asset Retirement Obligations (AROs) for additional information.

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.

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.

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. This 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 one of PSEG’s qualified pension plans, the excess would be amortized over the average remaining expected life of inactive participants, which is approximately eighteen years. For PSEG’s other 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 8.10% expected rate of return and a 5.68% discount rate for 2025 pension costs/credits and a 5.59% discount rate for 2025 OPEB costs/credits. Based upon these assumptions, we have estimated a net periodic pension expense in 2025 of approximately $37 million, or $0 million, net of amounts capitalized, and a net periodic OPEB expense in 2025 of approximately $3 million, or $2 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.

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

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.

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 16. Financial Risk Management Activities and Note 17. Fair Value Measurements.

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, ZEC payments for the New Jersey nuclear assets, 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.

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:

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.

AROs related to the future decommissioning of PSEG Power’s nuclear facilities comprised approximately 100% or $1,035 million of PSEG’s total AROs as of December 31, 2024. 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:

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, 2024 are as follows:

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)

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:

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 6. Regulatory Assets and Liabilities for a description of the amounts and nature of regulatory balance sheet amounts.

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 for the year ended December 31, 2024, 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: 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 has been 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 20. Income Taxes and Note 2. Revenues for more information.

The risk inherent in our market-risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices and interest rates as discussed in the Notes to Consolidated Financial Statements. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management Committee comprised of executive officers who utilize a risk oversight function to ensure compliance with our corporate policies and risk management practices.

Additionally, we are exposed to counterparty credit losses in the event of non-performance or non-payment. We have a credit management process, which is used to assess, monitor and mitigate counterparty exposure. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our financial condition, results of operations or net cash flows.

The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, we enter into supply contracts and derivative contracts, including forwards, futures, swaps, and options with approved counterparties. These contracts, in conjunction with physical sales and other services, help reduce risk and optimize the value of owned electric generation capacity.

VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses.

MTM VaR consists of MTM derivatives that are economic hedges. The calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some load-serving activities.

The VaR models used are variance/covariance models adjusted for the change of positions with 95% and 99.5% confidence levels and a one-day holding period for the MTM activities. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio.

See Item 8. Note 16. Financial Risk Management Activities for a discussion of credit risk.

PSEG, PSE&G and PSEG Power are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or

interest rate environment. PSEG, PSE&G and PSEG Power may also use a mix of fixed and floating rate debt and interest rate hedges.

As of December 31, 2024, a hypothetical 10% increase in market interest rates would result in an additional $4 million in pre-tax annual interest costs related to either the current or the long-term portion of long-term debt, and term loan agreements.

As of December 31, 2024, we had $4.4 billion of net assets in trust for our pension and OPEB plans. Although fluctuations in market prices of securities within this portfolio do not directly affect our earnings in the current period, changes in the value of these investments could affect

The NDT Fund is comprised primarily of fixed income and equity securities. As of December 31, 2024, the portfolio included $1.4 billion of equity securities inclusive of $0.3 billion of investments in listed real assets, and $1.3 billion in fixed income securities. The fair market value of the assets in the NDT Fund will fluctuate primarily depending upon the performance of equity markets. As of December 31, 2024, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $138 million.

We use duration to measure the interest rate sensitivity of the fixed income portfolio. Duration is a summary statistic of the effective average maturity of the fixed income portfolio. The benchmark for the fixed income component of the NDT Fund currently has a duration of 6.08 years and a yield of 4.91%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2024, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $77 million.

This combined Form 10-K is separately filed by PSEG and PSE&G. Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G makes representations only as to itself and makes no representations as to any other company.

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Accounting for the Effects of Regulation – Refer to Notes 1 and 6 to the financial statements

PSEG’s subsidiary, Public Service Electric and Gas Company (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. Management believes that PSE&G’s transmission and distribution businesses continue to meet the accounting requirements for rate-regulated entities, and PSE&G’s financial statements reflect the economic effects of regulation. PSE&G has deferred certain costs based on rate orders issued by the New Jersey Board of Public Utilities (“BPU”) or Federal Energy Regulatory Commission (“FERC”) or based on PSE&G’s experience with prior rate proceedings.

PSE&G defers the recognition of costs as a regulatory asset or records the recognition of obligations as a regulatory liability if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. This accounting results in the recognition of revenues and expenses in different time periods than that of enterprises that are not regulated. Regulatory assets and other investments and costs incurred under various infrastructure filings and clause mechanisms are subject to prudence reviews and can be disallowed in the future by regulatory authorities. To the extent that collection of any infrastructure or clause mechanism revenue, regulatory assets or payments of regulatory liabilities is no longer probable, the amounts would be charged or credited to income.

We identified the accounting for the effects of rate regulation as a critical audit matter due to the significant judgments made by management in assessing the probable recovery of regulatory assets and incurred costs or the likelihood of refunds of regulatory liabilities. Auditing these judgments required specialized knowledge of accounting for rate regulation and the ratemaking process due to its inherent complexities.

Our audit procedures to evaluate the accounting for the effects of cost-based rate regulation, including the probable recovery or refund of regulatory assets and liabilities, included the following, among others:

We have audited the accompanying consolidated balance sheets of Public Service Electric and Gas Company and subsidiaries (the “Company” or "PSE&G") as of December 31, 2024 and 2023, the related consolidated statements of operations, comprehensive income, common stockholder’s equity, and cash flows, for each of the three years in the period ended December 31, 2024, and the related notes and the consolidated financial statement schedule listed in the Index at Item 15(B)(b) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Accounting for the Effects of Regulation – Refer to Notes 1 and 6 to the financial statements

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. Management believes that PSE&G’s transmission and distribution businesses continue to meet the accounting requirements for rate-regulated entities, and PSE&G’s financial statements reflect the economic effects of regulation. PSE&G has deferred certain costs based on rate orders issued by the New Jersey Board of Public Utilities (“BPU”) or Federal Energy Regulatory Commission (“FERC”) or based on PSE&G’s experience with prior rate proceedings.

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.

Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies

Organization

Public Service Enterprise Group Incorporated (PSEG) is a public utility holding company that, acting through its wholly owned subsidiaries, is a predominantly regulated electric and gas utility and a nuclear generation business. PSEG’s principal operating subsidiaries are:

•

Public Service Electric and Gas Company (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 energy efficiency (EE) and related programs in New Jersey, which are regulated by the BPU.

•

PSEG Power LLC (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.

PSEG’s other direct wholly owned subsidiaries are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric 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.

Basis of Presentation

The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Annual Reports on Form 10-K and in accordance with accounting guidance generally accepted in the United States (GAAP). Certain line item reclassifications have been made to prior year financial statements to conform with current year presentation. These reclassifications had no impact on PSEG’s or PSE&G’s results of operations, financial condition or cash flows.

Significant Accounting Policies

Principles of Consolidation

Each company consolidates those entities in which it has a controlling interest or is the primary beneficiary. See Note 4. Variable Interest Entity. Entities over which the companies exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary, are accounted for under the equity method of accounting. Equity investments that do not qualify for consolidation or equity method accounting are recorded at fair value or, if fair value is not readily determinable, are initially recognized at cost and subsequently remeasured if there is an orderly transaction in an identical or similar investment of the same issuer or if the investment is impaired. All significant intercompany accounts and transactions are eliminated in consolidation.

PSE&G and PSEG Power also have undivided interests in certain jointly-owned facilities, with each responsible for paying its respective ownership share of construction costs, fuel purchases and operating expenses. PSE&G and PSEG Power consolidate their portion of any revenues and expenses related to their respective jointly-owned facilities in the appropriate revenue and expense categories.

Accounting for the Effects of Regulation

In accordance with accounting guidance for rate-regulated entities, PSE&G’s financial statements reflect the economic effects of regulation. PSE&G defers the recognition of costs (a Regulatory Asset) or records the recognition of obligations (a Regulatory

Liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that collection of any such costs or payment of liabilities becomes no longer probable as a result of changes in regulation, the associated Regulatory Asset or Liability is charged or credited to income. Management believes that PSE&G’s T&D businesses continue to meet the accounting requirements for rate-regulated entities. For additional information, see Note 6. Regulatory Assets and Liabilities.

Cash, Cash Equivalents and Restricted Cash

The following provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same such amounts in the Consolidated Statements of Cash Flows for the years ended December 31, 2024 and 2023. Restricted cash consists primarily of deposits received related to a construction project at PSE&G.



	PSE&G		PSEG Power & Other (A)		Consolidated
	Millions
As of December 31, 2024
Cash and Cash Equivalents	$	79	$	46	$	125
Restricted Cash in Other Current Assets		8		—		8
Restricted Cash in Other Noncurrent Assets		21		—		21
Cash, Cash Equivalents and Restricted Cash	$	108	$	46	$	154
As of December 31, 2023
Cash and Cash Equivalents	$	30	$	24	$	54
Restricted Cash in Other Current Assets		23		—		23
Restricted Cash in Other Noncurrent Assets		22		—		22
Cash, Cash Equivalents and Restricted Cash	$	75	$	24	$	99

(A)

Includes amounts applicable to PSEG Power, Energy Holdings, Services and PSEG (parent company).

Derivative Instruments

Each company uses derivative instruments to manage risk pursuant to its business plans and prudent practices.

Within PSEG and its affiliate companies, PSEG Power has the most exposure to commodity price risk. PSEG Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, natural gas and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. PSEG Power uses a variety of derivative and non-derivative instruments, such as financial options, futures and swaps to manage the exposure to fluctuations in commodity prices and optimize the value of PSEG Power’s expected generation. Changes in the fair market value of the derivative contracts are recorded in earnings. Cash flows related to derivative instruments are included as a component of operating, investing or financing cash flows in PSEG’s Consolidated Statements of Cash Flows, depending on the nature of hedges.

Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing the contract’s market liquidity. PSEG has determined that contracts to purchase and sell certain products do not meet the definition of a derivative under the current authoritative guidance since they do not provide for net settlement, or the markets are not sufficiently liquid to conclude that physical forward contracts are readily convertible to cash.

Under current authoritative guidance, all derivatives are recognized on the balance sheet at their fair value, except for derivatives that may be designated as normal purchases and normal sales (NPNS). Further, derivatives that qualify for hedge accounting can be designated as fair value or cash flow hedges.

Certain offsetting derivative assets and liabilities are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, these positions are offset on the Consolidated Balance Sheets of PSEG.

For cash flow hedges, the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge is deferred in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction.

For derivative contracts that do not qualify or are not designated as cash flow or fair value hedges or as NPNS, changes in fair value are recorded in current period earnings. PSEG does not currently elect hedge accounting on its commodity derivative positions.

For additional information regarding derivative financial instruments, see Note 16. Financial Risk Management Activities.

Revenue Recognition

PSE&G’s regulated electric and gas revenues are recorded primarily based on services rendered to customers. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read and billed to the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms.

Regulated revenues from the transmission of electricity are recognized as services are provided based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of estimated revenue requirement with rates effective January 1 of each year. After completion of the annual period ending December 31, PSE&G files a true-up whereby it compares its actual revenue requirement to the original estimate to determine any over or under collection of revenue. PSE&G records the estimated financial statement impact of the difference between the actual and the filed revenue requirement as a refund or deferral for future recovery when such amounts are probable and can be reasonably estimated in accordance with accounting guidance for rate-regulated entities.

PSEG Power currently owns generation within PJM Interconnection, L.L.C. (PJM), which facilitates the dispatch of energy and energy-related products. PSEG generally reports electricity sales and purchases conducted with the PJM Independent System Operator (ISO) at PSEG Power on a net hourly basis in either Revenues or Energy Costs in its Consolidated Statement of Operations, the classification of which depends on the net hourly activity. Capacity revenue and expense are also reported net based on PSEG Power’s monthly net sale or purchase position in PJM. PSEG Power also has revenues that relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. PSEG Power’s revenue also includes changes in the value of energy derivative contracts. See Note 16. Financial Risk Management Activities for further discussion.

PSEG LI is the primary beneficiary of Long Island Electric Utility Servco, LLC (Servco). For transactions in which Servco acts as principal, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operation and Maintenance (O&M) Expense, respectively. See Note 4. Variable Interest Entity for further information.

For additional information regarding Revenues, see Note 2. Revenues.

Depreciation and Amortization

PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU or FERC. The average depreciation rate stated as a percentage of original cost of depreciable property was as follows:



	Average Rate
	2024			2023			2022
Electric Transmission		2.09	%		2.09	%		2.18	%
Electric Distribution		2.51	%		2.54	%		2.56	%
Gas Distribution		1.84	%		1.84	%		1.93	%

PSEG calculates depreciation on its nuclear generation-related assets under the straight-line method based on the assets’ estimated useful lives of approximately 60 years to 80 years.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC)

AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. IDC represents the cost of debt used to finance construction at PSEG’s other subsidiaries. The amount of AFUDC or IDC capitalized as Property, Plant and Equipment is included as a reduction of interest charges or other income for the equity portion. The amounts and average rates used to calculate AFUDC or IDC for the years ended December 31, 2024, 2023 and 2022 were as follows:



	AFUDC/IDC Capitalized
	2024					2023					2022
	Millions		Avg Rate			Millions		Avg Rate			Millions		Avg Rate
PSE&G	$	62		6.43	%	$	83		7.13	%	$	84		7.39	%
Other	$	9		6.08	%	$	9		5.66	%	$	4		2.24	%

Income Taxes

PSEG and its subsidiaries file a consolidated federal income tax return and PSEG and PSE&G file state income tax returns, some of which are combined or unitary. Income taxes are allocated to PSEG’s subsidiaries in accordance with a tax allocation agreement whereby each PSEG subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Each subsidiary is allocated an amount of tax similar to that which would be paid if it filed a separate income tax return, except for certain tax attributes and state apportionment results. Allocations between PSEG and its subsidiaries are recorded through intercompany accounts. Investment tax credits (ITC) deferred in prior years are being amortized over the useful lives of the related property.

Uncertain income tax positions are accounted for 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.

In 2024, PSEG recorded the benefit of the estimated PTCs generated by PSEG’s qualified nuclear generation facilities within Income Tax Expense in its Consolidated Statements of Operations in accordance with Accounting Standards Codification Topic 740, Income Taxes. See Note 20. Income Taxes for further discussion.

Impairment of Long-Lived Assets

Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate, counterparty credit worthiness or market conditions, including prolonged periods of adverse commodity and capacity prices or a current expectation that a long-lived asset will be sold or disposed of significantly before the end of its previously estimated useful life, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis is performed to determine if an impairment exists. When a long-lived asset’s or asset group’s carrying amount exceeds the associated undiscounted estimated future cash flows, the asset/asset group is considered impaired to the extent that its fair value is less than its carrying amount. An impairment would result in a reduction of the value of the long-lived asset/asset group through a non-cash charge to earnings.

For PSEG, 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. See Note 3. Asset Dispositions and Impairments for more information on impairment assessments performed on PSEG’s long-lived assets.

Accounts Receivable—Allowance for Credit Losses

PSE&G’s accounts receivable, including unbilled revenues, are primarily comprised of utility customer receivables for the provision of electric and gas service and appliance services, and are reported in the balance sheet as gross outstanding amounts adjusted for an allowance for credit losses. The allowance for credit losses reflects PSE&G’s best estimate of losses on the account balances. The allowance is based on PSE&G’s projection of accounts receivable aging, historical experience, economic factors and other currently available evidence, including the estimated impact of the coronavirus pandemic on the outstanding balances as of

December 31, 2024. PSE&G’s electric bad debt expense is recovered through the Societal Benefits Clause (SBC) mechanism and incremental gas bad debt has been deferred for future recovery through the coronavirus (COVID-19) Regulatory Asset. See Note 2. Revenues and Note 6. Regulatory Assets and Liabilities.

Accounts receivable are charged off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable are recorded when it is known they will be received.

Materials and Supplies and Fuel

PSEG and PSE&G’s materials and supplies are carried at average cost and charged to inventory when purchased and expensed or capitalized to Property, Plant and Equipment, as appropriate, when installed or used. Fuel inventory at PSEG is valued at the lower of average cost or market and primarily includes stored natural gas used to satisfy obligations under PSEG Power’s gas supply contracts with PSE&G. The costs of fuel, including initial transportation costs, are included in inventory when purchased and charged to Energy Costs when used or sold. The cost of nuclear fuel is capitalized within Property, Plant and Equipment and amortized to fuel expense using the units-of-production method.

Property, Plant and Equipment

PSE&G’s additions to and replacements of existing property, plant and equipment are capitalized at cost. The cost of maintenance, repair and replacement of minor items of property is charged to expense as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation.

PSEG capitalizes costs related to its generating assets, including those related to its jointly-owned facilities that increase the capacity, improve or extend the life of an existing asset; represent a newly acquired or constructed asset; or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred. PSEG also capitalizes spare parts for its generating assets that meet specific criteria. Capitalized spare parts are depreciated over the remaining lives of their associated assets.

Leases

PSEG and its subsidiaries, when acting as lessee or lessor, determine if an arrangement is a lease at inception. PSEG assesses contracts to determine if the arrangement conveys (i) the right to control the use of the identified property, (ii) the right to obtain substantially all of the economic benefits from the use of the property, and (iii) the right to direct the use of the property.

Lessee—Operating Lease Right-of-Use Assets represent the right to use an underlying asset for the lease term and Operating Lease Liabilities represent the obligation to make lease payments arising from the lease. Operating Lease Right-of-Use Assets and Operating Lease Liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term.

The current portion of Operating Lease Liabilities is included in Other Current Liabilities. Operating Lease Right-of-Use Assets and noncurrent Operating Lease Liabilities are included as separate captions in Noncurrent Assets and Noncurrent Liabilities, respectively, on the Consolidated Balance Sheets of PSEG and PSE&G. PSEG and its subsidiaries do not recognize Operating Lease Right-of-Use Assets and Operating Lease Liabilities for leases where the term is twelve months or less.

PSEG and its subsidiaries recognize the lease payments on a straight-line basis over the term of the leases and variable lease payments in the period in which the obligations for those payments are incurred.

As lessee, most of the operating leases of PSEG and its subsidiaries do not provide an implicit rate; therefore, incremental borrowing rates are used based on the information available at commencement date in determining the present value of lease payments. The implicit rate is used when readily determinable. PSE&G’s incremental borrowing rates are based on secured borrowing rates. PSEG’s incremental borrowing rates are generally unsecured rates. Having calculated simulated secured rates for each of PSEG and PSEG Power, it was determined that the difference between the unsecured borrowing rates and the simulated secured rates had an immaterial effect on their recorded Operating Lease Right-of-Use Assets and Operating Lease Liabilities. Services, PSEG LI and other subsidiaries of PSEG that do not borrow funds or issue debt may enter into leases. Since these

companies do not have credit ratings and related incremental borrowing rates, PSEG has determined that it is appropriate for these companies to use the incremental borrowing rate of PSEG, the parent company.

Lease terms may include options to extend or terminate the lease when it is reasonably certain that such options will be exercised.

PSEG and its subsidiaries have lease agreements with lease and non-lease components. For real estate, equipment and vehicle leases, the lease and non-lease components are accounted for as a single lease component.

Lessor—Property subject to operating leases, where PSEG or one of its subsidiaries is the lessor, is included in Property, Plant and Equipment and rental income from these leases is included in Operating Revenues.

PSEG and its subsidiaries have lease agreements with lease and non-lease components, which are primarily related to domestic energy generation and real estate assets. PSEG and subsidiaries account for the lease and non-lease components as a single lease component. See Note 7. Leases for detailed information on leases.

Energy Holdings is the lessor in leveraged leases. Leveraged lease accounting guidance is grandfathered for existing leveraged leases. Energy Holdings’ leveraged leases are accounted for in Operating Revenues and in Noncurrent Long-Term Investments. If modified after January 1, 2019, those leveraged leases will be accounted for as operating or financing leases. See Note 8. Long-Term Investments and Note 9. Financing Receivables.

Trust Investments

These securities comprise the Nuclear Decommissioning Trust (NDT) Fund, a master independent external trust account maintained to provide for the costs of decommissioning upon termination of operations of PSEG’s nuclear facilities and amounts that are deposited to fund a Rabbi Trust which was established to meet the obligations related to non-qualified pension plans and deferred compensation plans.

Unrealized gains and losses on equity security investments are recorded in Net Income. The debt securities are classified as available-for-sale with the unrealized gains and losses recorded as a component of Accumulated Other Comprehensive Income (Loss). Realized gains and losses on both equity and available-for-sale debt security investments are recorded in earnings and are included with the unrealized gains and losses on equity securities in Net Gains (Losses) on Trust Investments. Other-than-temporary impairments on NDT and Rabbi Trust debt securities are also included in Net Gains (Losses) on Trust Investments. See Note 10. Trust Investments for further discussion.

Pension and Other Postretirement Benefits (OPEB) Plans

The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of those assets as of year-end. Fair value is determined using quoted market prices and independent pricing services based upon the security type as reported by the trustee at the measurement date (December 31) as well as investments in unlisted real estate which are valued via third-party appraisals.

PSEG recognizes a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and OPEB liabilities. This receivable is presented separately on the Consolidated Balance Sheet of PSEG as a noncurrent asset. Pursuant to the OSA, Servco records expense for contributions to its pension plan trusts and for OPEB payments made to retirees.

See Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans for further discussion.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Revenues Unrelated to Contracts with Customers

Other PSE&G revenues unrelated to contracts with customers are derived from alternative revenue mechanisms recorded pursuant to regulatory accounting guidance. These revenues, which include the Conservation Incentive Program (CIP), green energy program true-ups and transmission formula rate true-ups, are not a material source of PSE&G revenues.

PSEG Power & Other

Revenues from Contracts with Customers

Electricity and Related Products—PSEG Power owns generation solely within PJM Interconnection, L.L.C. (PJM), which facilitates the dispatch of energy and energy-related products. PSEG Power primarily sells to the PJM Independent System Operator (ISO) energy and ancillary services which are separately transacted in the day-ahead or real-time energy markets. The energy and ancillary services performance obligations are typically satisfied over time as delivered and revenue is recognized accordingly. Also, revenue for wholesale load contracts is recognized over time as the bundled service is provided to the customer. PSEG generally reports electricity sales and purchases conducted with PJM net on an hourly basis in either Operating Revenues or Energy Costs in its Consolidated Statements of Operations. The classification depends on the net hourly activity.

PSEG Power enters into capacity sales and capacity purchases through PJM. The transactions are reported on a net basis dependent on PSEG Power’s monthly net sale or purchase position through PJM. The performance obligations with PJM are satisfied over time upon delivery of the capacity and revenue is recognized accordingly. In addition to capacity sold through PJM, PSEG Power sells capacity through bilateral contracts and the related revenue is reported on a gross basis and recognized over time upon delivery of the capacity.

PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants have been awarded zero emission certificates (ZECs) by the BPU through May 2025. These nuclear plants are expected to receive ZEC revenue from the electric distribution companies (EDCs) in New Jersey. PSEG Power recognizes revenue when the units generate electricity, which is when the performance obligation is satisfied. These revenues are considered variable consideration within the scope of revenue from contracts with customers and are included in PJM Sales in the following tables. ZEC revenue recorded has been reduced by the estimated production tax credits (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 by these nuclear plants and that adjustment could be material. See Note 20. Income Taxes for further discussion on the factors that could result in an adjustment to the value of the PTCs.

Gas Contracts—PSEG Power sells wholesale natural gas, primarily through an index based full-requirements Basic Gas Supply Service (BGSS) contract with PSE&G to meet the gas supply requirements of PSE&G’s customers. The BGSS contract remains in effect unless terminated by either party with a two-year notice. Based upon the availability of natural gas, storage and pipeline capacity beyond PSE&G’s daily needs, PSEG Power also sells gas and pipeline capacity to other counterparties under bilateral contracts. The performance obligation is primarily the delivery of gas which is satisfied over time. Revenue is recognized as gas is delivered or pipeline capacity is released.

PSEG LI Contract—PSEG LI has a contract with LIPA which generates revenues. PSEG LI’s subsidiary, Long Island Electric Utility Servco, LLC (Servco) records costs which are recovered from LIPA and records the recovery of those costs as revenues when Servco is a principal in the transaction.

Other Revenues from Contracts with Customers

PSEG Power has entered into long-term contracts with LIPA for energy management and fuel procurement services. Revenue is recognized over time as services are rendered. This agreement expires in December 2025.

Revenues Unrelated to Contracts with Customers

PSEG Power’s revenues unrelated to contracts with customers include electric, gas and certain energy-related transactions accounted for in accordance with Derivatives and Hedging accounting guidance. See Note 16. Financial Risk Management Activities for further discussion.

Energy Holdings generates lease revenues which are recorded pursuant to lease accounting guidance.

Disaggregation of Revenues



	PSE&G		PSEG Power & Other (A)		Eliminations			Consolidated
	Millions
Year Ended December 31, 2024
Revenues from Contracts with Customers
Electric Distribution	$	3,977	$	—	$	—		$	3,977
Gas Distribution		2,059		—		—			2,059
Transmission		1,754							1,754
Electricity and Related Product Sales
PJM
Third-Party Sales		—		819		—			819
Sales to Affiliates		—		114		(114	)		—
ISO-NE		—		5		—			5
Gas Sales
Third-Party Sales		—		206		—			206
Sales to Affiliates		—		846		(846	)		—
Other Revenues from Contracts with Customers (B)		368		692		(6	)		1,054
Total Revenues from Contracts with Customers		8,158		2,682		(966	)		9,874
Revenues Unrelated to Contracts with Customers (C)		291		125		—			416
Total Operating Revenues	$	8,449	$	2,807	$	(966	)	$	10,290

          
         PSE&G

         PSEG
Power &
Other (A)

         Eliminations

         Consolidated

          
         Millions

          
          Year Ended December 31, 2023


Title of Each Class	Trading Symbol(s)	Name of Each Exchange On Which Registered
Public Service Enterprise Group Incorporated
Common Stock without par value	PEG	New York Stock Exchange
Public Service Electric and Gas Company
8.00% First and Refunding Mortgage Bonds, due 2037	PEG37D	New York Stock Exchange
5.00% First and Refunding Mortgage Bonds, due 2037	PEG37J	New York Stock Exchange


Part of Form 10-K of Public Service Enterprise Group Incorporated		Documents Incorporated by Reference
III		Portions of the definitive Proxy Statement for the 2025 Annual Meeting of Stockholders of Public Service Enterprise Group Incorporated, which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 13, 2025, as specified herein.


	Note 23. Financial Information by Business Segment	155
	Note 24. Related-Party Transactions	158
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	159
Item 9A.	Controls and Procedures	159
Item 9B.	Other Information	159
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	159
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	163
Item 11.	Executive Compensation	164
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	164
Item 13.	Certain Relationships and Related Transactions, and Director Independence	164
Item 14.	Principal Accountant Fees and Services	165
PART IV
Item 15.	Exhibits, Financial Statement Schedules	165
	Schedule II - Valuation and Qualifying Accounts	171
	Signatures	172



Electric and Gas Distribution Statistics
	Number of Customers as of December 31, 2024	Historical Annual Customer Growth 2020-2024	Electric Sales and Firm Gas Sales for the Year Ended December 31, 2024 (A)	Historical Annual Load Decline 2020-2024
Electric	2.4 Million	0.9%	40,651 Gigawatt hours	—
Gas	1.9 Million	0.7%	2,371 Million Therms	(1.7)%



	Unit		Year
	Salem Unit 1		2036
	Salem Unit 2		2040
	Hope Creek		2046
	Peach Bottom Unit 2 (A)		2033
	Peach Bottom Unit 3 (A)		2034


Commission File Number	Name of Registrant, Address, and Telephone Number			State or other jurisdiction of Incorporation	I.R.S. Employer Identification Number
001-09120	Public Service Enterprise Group Incorporated			New Jersey	22-2625848
	80 Park Plaza
	Newark,	New Jersey	07102
	973	430-7000

001-00973	Public Service Electric and Gas Company			New Jersey	22-1212800
	80 Park Plaza
	Newark,	New Jersey	07102
	973	430-7000


Public Service Enterprise Group Incorporated	Large Accelerated Filer	☒	Accelerated Filer	☐	Non-accelerated Filer	☐	Smaller reporting company	☐	Emerging growth company	☐

Public Service Electric and Gas Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	☒	Smaller reporting company	☐	Emerging growth company	☐


		Page
FORWARD-LOOKING STATEMENTS		iii
FILING FORMAT		1
WHERE TO FIND MORE INFORMATION		1
PART I
Item 1.	Business	1
	Operations and Strategy	2
	Competitive Environment	8
	Human Capital Management	9
	Regulatory Issues	10
	Environmental Matters	16
	Information About Our Executive Officers (PSEG)	18
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	33
Item 1C.	Cybersecurity	34
Item 2.	Properties	37
Item 3.	Legal Proceedings	38
Item 4.	Mine Safety Disclosures	38
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	38
Item 6.	[Reserved]	39
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
	Executive Overview of 2024 and Future Outlook	40
	Results of Operations	46
	Liquidity and Capital Resources	51
	Capital Requirements	55
	Critical Accounting Estimates	57
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	62
Item 8.	Financial Statements and Supplementary Data	63
	Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)	64
	Consolidated Financial Statements	68
	Notes to Consolidated Financial Statements
	Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies	80
	Note 2. Revenues	86
	Note 3. Asset Dispositions and Impairments	91
	Note 4. Variable Interest Entity (VIE)	91
	Note 5. Property, Plant and Equipment and Jointly-Owned Facilities	92
	Note 6. Regulatory Assets and Liabilities	93
	Note 7. Leases	98
	Note 8. Long-Term Investments	102
	Note 9. Financing Receivables	103
	Note 10. Trust Investments	104
	Note 11. Asset Retirement Obligations (AROs)	111
	Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans	112
	Note 13. Commitments and Contingent Liabilities	122
	Note 14. Debt and Credit Facilities	129
	Note 15. Schedule of Consolidated Capital Stock	133
	Note 16. Financial Risk Management Activities	134
	Note 17. Fair Value Measurements	138
	Note 18. Stock Based Compensation	141
	Note 19. Net Other Income (Deductions)	145
	Note 20. Income Taxes	146
	Note 21. Accumulated Other Comprehensive Income (Loss), Net of Tax	152
	Note 22. Earnings Per Share (EPS) and Dividends	154



	% of 2024 Sales
Customer Type	Electric			Gas
Commercial		57	%		38	%
Residential		34	%		58	%
Industrial		9	%		4	%
Total		100	%		100	%



Program	Investment	Approval Date	Term of Investment		Year Started
CEF-EE	$1 billion	2020	5 years	(A)	2020
CEF-EE Extension	$280 million	2023	9 months		2023
CEF-EE Extension II	$300 million	2024	6 months		2024
CEF-EE II	$2.9 billion	2024	6 years		2025
CEF-EV	$166 million	2021	~6 years		2021
Energy Strong II Program	$842 million	2019	4 years	(B)	2019
Gas System Modernization Program II (GSMP II) Extension	$902 million	2023	2 years	(C)	2024
Infrastructure Advancement Program (IAP)	$511 million	2022	4 years		2022



Name	Age as of December 31, 2024	Office	Effective Date First Elected to Present Position

Ralph A. LaRossa	61	Chair of the Board (COB), President and Chief Executive Officer (CEO) - PSEG	January 2023 to present
		President and CEO -PSEG	September 2022 to present
		Chief Operating Officer (COO) - PSEG	January 2020 to August 2022
		COB and CEO - PSE&G	September 2022 to present
		COB, President and CEO - PSEG Power	May 2023 to present
		COB and CEO - PSEG Power	September 2022 to May 2023
		COB and CEO - Energy Holdings	September 2022 to present
		COB, CEO and President - Services	September 2022 to present
		President and COO - PSEG Power	October 2017 to August 2022
		President and COO - PSE&G	October 2006 to October 2017
		COB - PSEG Long Island LLC	December 2020 to August 2022


Daniel J. Cregg	61	Executive Vice President (EVP) and Chief Financial Officer (CFO) - PSEG	October 2015 to present
		EVP and CFO - PSE&G	October 2015 to present
		EVP and CFO - PSEG Power	October 2015 to present


Kim C. Hanemann	61	President and COO - PSE&G	June 2021 to present
		Senior Vice President (SVP) and COO - PSE&G	January 2020 to June 2021
		SVP - Electric Transmission and Distribution - PSE&G	September 2018 to January 2020


Tamara L. Linde	60	EVP and Chief Legal Officer - PSEG	September 2024 to present
		EVP and General Counsel - PSEG	July 2014 to September 2024
		EVP and General Counsel - PSE&G	July 2014 to September 2024
		EVP and General Counsel - PSEG Power	July 2014 to September 2024


Charles V. McFeaters	65	President and Chief Nuclear Officer - PSEG Nuclear LLC	May 2023 to present
		SVP - Nuclear Operations - PSEG Nuclear LLC	November 2020 to May 2023
		Vice President (VP) - Salem Generating Station - PSEG Nuclear LLC	October 2016 to November 2020


Grace Park	49	EVP and General Counsel - PSEG	September 2024 to present
		EVP and General Counsel - PSE&G	September 2024 to present
		EVP and General Counsel - PSEG Power	September 2024 to present
		VP - Deputy General Counsel and Chief Litigation Counsel - Services	July 2020 to September 2024

Sheila J. Rostiac	54	SVP - Human Resources, Chief Human Resources and Chief Diversity Officer - Services	January 2020 to present
		SVP - Human Resources and Chief Human Resources Officer - Services	September 2019 to January 2020


Richard T. Thigpen	64	SVP - Corporate Citizenship - Services	July 2018 to present


Rose M. Chernick	61	VP and Controller - PSEG	March 2019 to present
		VP and Controller - PSE&G	March 2019 to present
		VP and Controller - PSEG Power	March 2019 to present



Name	Location	Total Capacity (MW)		% Owned			Owned Capacity (MW)
Nuclear:
Hope Creek	NJ		1,172		100	%		1,172
Salem 1 & 2	NJ		2,285		57	%		1,311
Peach Bottom 2 & 3 (A)	PA		2,549		50	%		1,275
Total Nuclear			6,006					3,758



Plan Category	Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights (a)		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)		Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans (excluding securities reflected in column (a)) (c)
Equity Compensation Plans Approved by Security Holders		—	$	—		7,082,420
Equity Compensation Plans Not Approved by Security Holders		—		—		—
Total		—	$	—		7,082,420



	Years Ended December 31,
	2024		2023
	Millions, except per share data
PSE&G	$	1,547	$	1,515
PSEG Power & Other		225		1,048
PSEG Net Income	$	1,772	$	2,563

PSEG Net Income Per Share (Diluted)	$	3.54	$	5.13



									Increase /						Increase /
	Years Ended December 31,								(Decrease)						(Decrease)
	2024		2023			2022			2024 vs. 2023						2023 vs. 2022
	Millions								Millions			%			Millions			%
Operating Revenues	$	10,290	$	11,237		$	9,800		$	(947	)		(8	)	$	1,437			15
Energy Costs		3,393		3,260			4,018			133			4			(758	)		(19	)
Operation and Maintenance (A)		3,356		3,150			3,178			206			7			(28	)		(1	)
Depreciation and Amortization		1,182		1,135			1,100			47			4			35			3
Losses on Asset Dispositions and Impairments		6		7			123			(1	)		(14	)		(116	)		(94	)
Income from Equity Method Investments		1		1			14			—			—			(13	)		(93	)
Net Gains (Losses) on Trust Investments		127		189			(265	)		(62	)		(33	)		454		N/A
Net Other Income (Deductions)		153		172			124			(19	)		(11	)		48			39
Net Non-Operating Pension and OPEB (Costs) Credits		73		(218	)		376			291		N/A				(594	)	N/A
Interest Expense		882		748			628			134			18			120			19
Income Tax Expense (Benefit)		53		518			(29	)		(465	)		(90	)		547		N/A



	2019		2020		2021		2022		2023		2024
PSEG	$	100.00	$	102.37	$	121.14	$	114.98	$	119.14	$	169.91
S&P 500	$	100.00	$	118.39	$	152.34	$	124.73	$	157.48	$	196.85
DJ Utilities	$	100.00	$	101.68	$	119.44	$	121.88	$	115.43	$	133.53
S&P Utilities	$	100.00	$	100.52	$	118.29	$	120.14	$	111.63	$	137.79



	As of December 31, 2024
Company/Facility	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	1,500	$	764	$	736
PSE&G		1,000		468		532
PSEG Power		1,325		82		1,243
Total	$	3,825	$	1,314	$	2,511



	2025		2026		2027
			Millions
PSE&G:
Transmission	$	735	$	890	$	920
Electric Distribution		1,190		1,235		1,325
Gas Distribution		1,050		1,025		1,050
Clean Energy		745		840		935
Total PSE&G	$	3,720	$	3,990	$	4,230
Competitively Bid, FERC Regulated Transmission		30		265		115
PSEG Power & Other		280		305		290
Total PSEG	$	4,030	$	4,560	$	4,635



	Total Amount Committed		Less Than 1 Year		2 - 3 Years		4 - 5 Years		Over 5 Years
	Millions
Long-Term Recourse Debt Maturities
PSEG	$	4,896	$	550	$	700	$	1,350	$	2,296
PSE&G		15,115		350		1,300		1,075		12,390
PSEG Power		1,250		1,250		—		—		—
Interest on Recourse Debt
PSEG		1,158		207		405		268		278
PSE&G		9,683		590		1,147		1,078		6,868
PSEG Power (A)		32		32		—		—		—
Operating Leases
PSE&G		116		19		29		21		47
PSEG Power & Other		94		16		33		32		13
Energy-Related Purchase Commitments
PSEG Power		2,853		904		996		532		421
Total	$	35,197	$	3,918	$	4,610	$	4,356	$	22,313



	Years Ended December 31,							Increase / (Decrease)						Increase / (Decrease)
	2024		2023		2022			2024 vs. 2023						2023 vs. 2022
	Millions							Millions			%			Millions			%
Operating Revenues	$	8,449	$	7,807	$	7,935		$	642			8		$	(128	)		(2	)
Energy Costs		3,189		3,010		3,270			179			6			(260	)		(8	)
Operation and Maintenance (A)		1,949		1,843		1,838			106			6			5			—
Depreciation and Amortization		1,025		980		935			45			5			45			5
Net Gains (Losses) on Trust Investments		—		—		(2	)		—			—			2		N/A
Net Other Income (Deductions)		64		80		88			(16	)		(20	)		(8	)		(9	)
Net Non-Operating Pension and OPEB Credits		77		114		281			(37	)		(32	)		(167	)		(59	)
Interest Expense		582		493		427			89			18			66			15
Income Tax Expense		298		160		267			138			86			(107	)		(40	)



	Years Ended December 31,
Dividend Payments on Common Stock	2024		2023		2022
Per Share	$	2.40	$	2.28	$	2.16
in Millions	$	1,196	$	1,137	$	1,079



	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
Issuer Rating	Baa2	BBB



Assumption	2024			2023			2022
Pension
Discount Rate		5.68	%		5.02	%		5.20	%
Expected Rate of Return on Plan Assets		8.10	%		8.10	%		7.20	%
OPEB
Discount Rate		5.59	%		4.96	%		5.16	%
Expected Rate of Return on Plan Assets		8.10	%		8.10	%		7.20	%



	% Change			Impact on Benefit Obligation as of December 31, 2024		Increase to Costs in 2025		Increase to Costs, net of Amounts Capitalized in 2025
Assumption				Millions
Pension
Discount Rate		(1	)%	$	467	$	20	$	14
Expected Rate of Return on Plan Assets		(1	)%	N/A		$	38	$	38
OPEB
Discount Rate		(1	)%	$	61	$	—	$	—
Expected Rate of Return on Plan Assets		(1	)%	N/A		$	4	$	4



	MTM VaR
	Years Ended December 31,
	2024		2023
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	36	$	48
Average for the Period	$	44	$	56
High	$	152	$	127
Low	$	25	$	24

99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	57	$	75
Average for the Period	$	69	$	87
High	$	238	$	198
Low	$	39	$	38



	December 31,
	2024			2023
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	125		$	54
Accounts Receivable, net of allowance of $210 in 2024 and $279 in 2023		1,597			1,482
Tax Receivable		394			10
Unbilled Revenues, net of allowance of $5 in 2024 and $4 in 2023		313			244
Fuel		232			264
Materials and Supplies, net		892			759
Prepayments		117			144
Derivative Contracts		33			112
Regulatory Assets		516			273
Other		16			31
Total Current Assets		4,235			3,373
PROPERTY, PLANT AND EQUIPMENT		51,207			48,603
Less: Accumulated Depreciation and Amortization		(11,143	)		(10,572	)
Net Property, Plant and Equipment		40,064			38,031
NONCURRENT ASSETS
Regulatory Assets		6,125			5,157
Operating Lease Right-of-Use Assets		162			179
Long-Term Investments		263			295
Nuclear Decommissioning Trust (NDT) Fund		2,670			2,524
Long-Term Receivable of Variable Interest Entity		558			632
Rabbi Trust Fund		165			179
Derivative Contracts		51			29
Other		347			342
Total Noncurrent Assets		10,341			9,337
TOTAL ASSETS	$	54,640		$	50,741



	Years Ended December 31,
CASH FLOWS FROM OPERATING ACTIVITIES	2024			2023			2022
Net Income	$	1,772		$	2,563		$	1,031
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		1,182			1,135			1,100
Amortization of Nuclear Fuel		191			189			183
Losses on Asset Dispositions and Impairments		6			7			123
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual		—			3			55
Provision for Deferred Income Taxes and ITC		263			355			(261	)
Non-Cash Employee Benefit Plan (Credits) Costs		75			366			(239	)
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives		210			(1,333	)		639
Cost of Removal		(170	)		(166	)		(129	)
Energy Efficiency Programs Regulatory Investment Expenditures		(544	)		(466	)		(286	)
Amortization of Energy Efficiency Programs Regulatory Investment Expenditures		125			82			48
Net Change in Other Regulatory Assets and Liabilities		(273	)		2			(78	)
Net (Gains) Losses and (Income) Expense from NDT Fund		(194	)		(248	)		202
Net Change in Certain Current Assets and Liabilities:
Tax Receivable		(384	)	75			1
Cash Collateral		(131	)		1,408			(677	)
Obligation to Return Cash Collateral		4			(201	)		111
Accrued Taxes		2			(10	)		(94	)
Other Current Assets and Liabilities		(95	)		35			(188	)
Employee Benefit Plan Funding and Related Payments		(53	)		(40	)		(35	)
Other		147			50			(3	)
Net Cash Provided By (Used In) Operating Activities		2,133			3,806			1,503
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(3,380	)		(3,325	)		(2,888	)
Proceeds from Sales of Trust Investments		1,537			1,714			1,586
Purchases of Trust Investments		(1,563	)		(1,751	)		(1,611	)
Proceeds from Sales of Long-Lived Assets and Lease Investments		—			37			1,918
Proceeds from Sales of Equity Method Investments		—			291			—
Contributions to Equity Method Investments		—			—			(124	)
Other		100			76			18
Net Cash Provided By (Used In) Investing Activities		(3,306	)		(2,958	)		(1,101	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper		744			250			(819	)
Proceeds from Short-Term Loans		400			750			2,000
Repayment of Short-Term Loans		(500	)		(2,250	)		(2,500	)
Issuance of Long-Term Debt		3,350			2,800			2,850
Redemption of Long-Term Debt		(1,500	)		(1,575	)		(700	)
Payments for Share Repurchase Program		—			—			(500	)
Cash Dividends Paid on Common Stock		(1,196	)		(1,137	)		(1,079	)
Other		(70	)		(98	)		(6	)
Net Cash Provided By (Used In) Financing Activities		1,228			(1,260	)		(754	)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash		55			(412	)		(352	)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period		99			511			863
Cash, Cash Equivalents and Restricted Cash at End of Period	$	154		$	99		$	511
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	68		$	144		$	353
Interest Paid, Net of Amounts Capitalized	$	799		$	683		$	602
Accrued Property, Plant and Equipment Expenditures	$	326		$	443		$	366



	Common Stock					Treasury Stock									Accumulated Other
	Shares		Amount			Shares			Amount			Retained Earnings			Comprehensive Income (Loss)			Total
Balance as of December 31, 2021		534	$	5,045			(30	)	$	(896	)	$	10,639		$	(350	)	$	14,438
Net Income		—		—			—			—			1,031			—			1,031
Other Comprehensive Income (Loss), net of tax (expense) benefit of $111		—		—			—			—			—			(200	)		(200	)
Comprehensive Income																			831
Cash Dividends at $2.16 per share on Common Stock		—		—			—			—			(1,079	)		—			(1,079	)
Payments for Share Repurchase Program		—		—			(7	)		(500	)		—			—			(500	)
Other		—		20			—			19			—			—			39
Balance as of December 31, 2022		534	$	5,065			(37	)	$	(1,377	)	$	10,591		$	(550	)	$	13,729
Net Income		—		—			—			—			2,563			—			2,563
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(156)		—		—			—			—			—			371			371
Comprehensive Income																			2,934
Cash Dividends at $2.28 per share on Common Stock		—		—			—			—			(1,137	)		—			(1,137	)
Other		—		(47	)		1			(2	)		—			—			(49	)
Balance as of December 31, 2023		534	$	5,018			(36	)	$	(1,379	)	$	12,017		$	(179	)	$	15,477
Net Income		—		—			—			—			1,772			—			1,772
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(14)		—		—			—			—			—			46			46
Comprehensive Income																			1,818
Cash Dividends at $2.40 per share on Common Stock		—		—			—			—			(1,196	)		—			(1,196	)
Other		—		39			—			(24	)		—			—			15
Balance as of December 31, 2024		534	$	5,057			(36	)	$	(1,403	)	$	12,593		$	(133	)	$	16,114



	Common Stock		Contributed Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance as of December 31, 2021	$	892	$	2,156	$	11,524		$	1		$	14,573
Net Income		—		—		1,565			—			1,565
Other Comprehensive Income (Loss), net of tax (expense) benefit of $2		—		—		—			(6	)		(6	)
Comprehensive Income												1,559
Cash Dividend Paid		—		—		(450	)		—			(450	)
Balance as of December 31, 2022	$	892	$	2,156	$	12,639		$	(5	)	$	15,682
Net Income		—		—		1,515			—			1,515
Other Comprehensive Income (Loss), net of tax (expense) benefit of $0		—		—		—			1			1
Comprehensive Income												1,516
Cash Dividend Paid		—		—		(150	)		—			(150	)
Balance as of December 31, 2023	$	892	$	2,156	$	14,004		$	(4	)	$	17,048
Net Income		—		—		1,547			—			1,547
Other Comprehensive Income (Loss), net of tax (expense) benefit of $0		—		—		—			—			—
Comprehensive Income												1,547
Cash Dividends Paid		—		—		(150	)		—			(150	)
Balance as of December 31, 2024	$	892	$	2,156	$	15,401		$	(4	)	$	18,445