Item 1. BUSINESS

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 principally conduct our business through two direct wholly owned subsidiaries, PSE&G and PSEG Power LLC (PSEG Power), each of which also has its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102.

We are a public utility holding company consisting primarily of a regulated electric and gas utility and a nuclear generation business. Over the past several years, our investments resulted in a higher percentage of earnings contribution by PSE&G. The sale of the fossil generating portfolio in 2022 further simplified our business mix, resulting in an even higher percentage of earnings contribution by PSE&G going forward and provides more financial flexibility.

Our business approach focuses on operational excellence, financial strength and disciplined investment. As a holding company, our profitability depends on our subsidiaries’ operating results. Below are descriptions of our two principal direct operating subsidiaries.

• PSE&G**—A New Jersey corporation, incorporated in 1924, which is a franchised public utility in New Jersey. It is also the provider of last resort for gas and electric commodity service for end users in its service territory. PSE&G earns revenues from its regulated rate tariffs under which it provides electric transmission and electric and natural gas distribution to residential, commercial and industrial (C&I) customers in its service territory. It also offers appliance services and repairs to customers throughout its service territory and invests in regulated solar generation projects and regulated energy efficiency (EE) and related programs in New Jersey.

• PSEG Power**—A Delaware limited liability company formed in 1999 as a result of the deregulation and restructuring of the electric power industry in New Jersey. PSEG Power earns revenues from its nuclear generation and marketing of power and natural gas to hedge business risks and the value of its portfolio of nuclear power plants, other contractual arrangements and gas storage facilities.

In February 2022, we completed the sale of our 6,750 megawatt (MW) fossil generation portfolio which represented an important milestone in our strategy. See Item 8. Note 3. Asset Dispositions and Impairments for additional information.

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.

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OPERATIONS AND STRATEGY

PSE&G

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.

Products and Services

Our utility operations primarily earn margins through:

• Transmission**—the movement of electricity at high voltage from generating plants to substations and transformers, where it is then reduced to a lower voltage for distribution to homes, businesses and industrial customers. Our revenues for these services are based upon tariffs approved by the Federal Energy Regulatory Commission (FERC).

• Distribution**—the delivery of electricity and gas to the retail customer’s home, business or industrial facility. Our revenues for these services are based upon tariffs approved by the New Jersey Board of Public Utilities (BPU).

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, including EE, electric vehicle (EV) make-ready charging infrastructure, solar, energy storage and other potential investments.

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

How PSE&G Operates

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

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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.

Transmission

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 2023 and Future Outlook.

Distribution

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. 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. Our current approved

distribution base rates provide for an ROE of 9.6%. In December 2023, we filed a distribution base rate case as required by the BPU. For a discussion of our recent distribution base rate case filing, see Item 7. MD&A—Executive Overview of 2023 and Future Outlook. For a discussion of proposed and approved programs, see Investment Clause Programs as follows and Item 7. MD&A—Executive Overview of 2023 and Future Outlook. Our load requirements are split among residential, C&I customers, as described in the following table for 2023:

									% of 2023 Sales
			Customer Type						Electric						Gas
			Commercial						58%						38%
			Residential						33%						58%
			Industrial						9%						4%
			Total						100%						100%

Our customer base has modestly increased since 2019, with electric and gas loads changing as illustrated in the following table:

			Electric and Gas Distribution Statistics
						Number of Customers as of December 31, 2023									Historical Annual Customer Growth 2019-2023						Electric Sales and Firm Gas Sales as of December 31, 2023 (A)									Historical Annual Load Decline 2019-2023
			Electric			2.4			Million						0.9		%				39,085			Gigawatt hours						(1.4)%
			Gas			1.9			Million						0.6		%				2,282			Million Therms						(2.8)%

(A)Excludes sales from Gas rate classes that do not impact margin, specifically Contract, Non-Firm Transportation, Cogeneration Interruptible and Interruptible Services.

Effective June 1 and October 1, 2021 for electric and gas, respectively, as part of the BPU’s approval of the Clean Energy Future-Energy Efficiency (CEF-EE) filing, we implemented the Conservation Incentive Program (CIP) that trues up PSE&G’s margin to a baseline per customer from our 2018 distribution base rate case 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 there has been a recent decrease in load due to a decline in larger industrial customers, greater EE and other factors, PJM’s most recent forecast indicates an increase in load over the next several years 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 in the future.

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Investment Clause Programs

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

			Program						Investment						Approval Date						Term of Investment									Year Started
			Gas System Modernization Program II (GSMP II) Extension						$902 million						2023						2 years			(A)						2024
			Energy Strong II Program						$842 million						2019						4 years			(B)						2019
			CEF-EE						$1 billion						2020						5 years			(C)						2020
			CEF-EE Extension						$280 million						2023						9 months									2023
			CEF-Energy Cloud (EC)						$707 million						2021						4 years									2021
			CEF-EV						$166 million						2021						~6 years									2021
			Infrastructure Advancement Program (IAP)						$511 million						2022						4 years									2022

(A)The program has a small amount of trailing costs expected to be spent in year 3.

(B)The program has a small amount of trailing costs expected to be spent in year 5.

(C)Rolling three-year program with over 80% of spending within 5 years, with limited spending thereafter.

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.

To date, we launched three of the four components of our CEF:

• EE**—designed to achieve EE targets required under New Jersey’s Clean Energy Act through a suite of ten programs for residential, C&I programs, including low-income, multi-family, small business and local government.

• EC—driven by the implementation of “smart meters,” and new software and product solutions to improve our processes and better manage the electric grid.

• EV**—primarily relating to preparatory work to deliver infrastructure to the charging point for three programs: residential smart charging; Level-2 mixed use charging; and direct current (dc) fast charging.

Our CEF-Energy Storage (ES) program, which was filed with the BPU in October 2018, is being held in abeyance. Our proposed ES program is for a $109 million investment that encompasses solar smoothing, whereby a battery energy solar system is used to neutralize fluctuations in solar output to facilitate its entry into the grid, distribution investment deferral, outage management, microgrids and peak reduction for municipal facilities.

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 2023 and Future Outlook for additional information.

Solar Generation

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.

Supply

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).

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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 validated 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

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.

PSEG Power

Products and Services

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 begins January 1, 2024 and is available through 2032. PSEG Power’s Salem 1, Salem 2, Hope Creek, Peach Bottom 2 and Peach Bottom 3 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, we are unable to fully determine the impacts of the PTC.

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.

How PSEG Power’s Nuclear Generation Operates

As of December 31, 2023, PSEG Power had 3,761 MW of nuclear generation capacity. All of our nuclear generation capacity is located in New Jersey and Pennsylvania.

Generation Dispatch

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.

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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 exposure to this volatility and provide support for the nuclear units.

Nuclear Fuel Supply

We have long-term contracts for nuclear fuel. These contracts provide for:

• purchase of uranium (concentrates and uranium hexafluoride),

• conversion of uranium concentrates to uranium hexafluoride,

• enrichment of uranium hexafluoride, and

• fabrication of nuclear fuel assemblies.

We expect to be able to meet the nuclear fuel supply demands of our operations. However, the ability to maintain an adequate fuel supply could be affected by several factors not within our control, including changes in prices and demand, 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 2023 and Future Outlook and Item 8. Note 13. Commitments and Contingent Liabilities.

Markets and Market Pricing

All of PSEG Power’s nuclear generation assets are located within the PJM RTO.

Our nuclear generating units’ performance, together with 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. The number of ZECs purchased by each EDC from a selected nuclear power plant for an energy year is expected to be reduced by the number of ZECs equal in value to the dollar amount of PTCs received by the same plants.

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 structured, forward-looking, capacity pricing mechanism through the Reliability Pricing Model (RPM). For additional information regarding FERC actions related to the capacity market construct, 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 rigorous 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.

Hedging Strategy

The PTC is intended to provide sufficient and stable support for nuclear units and is effective January 1, 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. 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. As of the end of 2023, we have hedged approximately 90% to 95% of its expected generation output for 2024. Beginning in 2024, our hedging strategy will incorporate an estimated range of risk reduction impacts from the PTCs on our nuclear generation portfolio. This is expected to result in changes to our current approach given PTC guidance uncertainty, and potential incremental changes upon final U.S. Treasury guidance.

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Generally, we seek to hedge our output through sales at PJM West or other nodes corresponding to our generation portfolio. Sales in PJM generally reflect block 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. Although we enter into these hedges to provide price certainty for a large portion of our anticipated generation, there is variability in both our actual output as well as in the effectiveness of our hedges. Our hedging practices help to manage some of the volatility of the nuclear generation business. While this limits our exposure to decreasing prices, our ability to realize benefits from rising market prices is also limited.

The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts. The U.S. Treasury is expected to clarify the definition of gross receipts as the eligibility period begins January 1, 2024. We are continuing to analyze the impact of the IRA on our nuclear units, including additional future guidance from the U.S. Treasury, potential impacts on hedging strategies and overall financial support.

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 2026 and a significant portion through 2027.

LIPA Operations Services Agreement

In accordance with a 12-year OSA entered into by PSEG LI and LIPA, PSEG LI commenced operating LIPA’s electric T&D system in Long Island, New York on January 1, 2014. The OSA contract term continues through 2025, but can be extended subject to a mutual agreement of the parties. 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. Further, since January 2015, PSEG Power provides fuel procurement and power management services to LIPA under separate agreements that expire at the end of 2025. It is uncertain whether the OSA and the separate agreements will be renewed on terms acceptable to us or at all.

Energy Holdings

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.

In December 2023, PJM awarded a subsidiary of Energy Holdings an approximately $424 million project to construct a 500 kV transmission line in Maryland. PSEG’s project was part of a larger set of projects designed to address reliability issues driven by load growth and retirement of fossil generation. Our project is expected to be placed in service in 2027.

COMPETITIVE ENVIRONMENT

PSE&G

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 modernizing our electric transmission and electric and gas distribution system and (ii) investing in programs that 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. While there is not a substantial amount of net metered generation in our territory, a growing amount, and/or other changes in customer usage behavior could lead to a smaller base of 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 is also an expected 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 accelerate 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

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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.

PSEG Power

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.

New additions of lower-cost or more efficient 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 continues to examine whether this market design is working optimally. 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, could lead to a material adverse effect, while other actions to further regulate carbon dioxide emissions could better position our nuclear plants.

HUMAN CAPITAL MANAGEMENT

Our Core Commitments – safety, integrity, continuous improvement, customer service and diversity, equity and inclusion (DEI) – are at the center of our workplace culture. They guide us in important aspects of our Human Capital Management strategy, including recruitment, employee development, retention, performance, safety, and collaboration. We rely on our inclusive culture to support our many stakeholders including employees, customers, and the many diverse communities we serve. We believe in treating people with dignity and respect, protecting each of our fundamental human rights, and we strive to maintain the high standards of ethical conduct on which our business and reputation have been built.

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

Over 60% of our workforce is represented by six unions under various collective bargaining agreements that cover wages, benefits and other terms and conditions of employment. In 2023, we negotiated new agreements with all six of our unions in advance of contract expiration. These agreements contain four-year terms, expiring in 2027 and support strategic objectives and business goals.

The Organization and Compensation Committee of the PSEG Board of Directors is responsible for oversight of PSEG’s human capital management practices and is updated regularly on matters related to executive leadership succession and development, culture, and DEI. 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.

The following charts present our total employee population indicating percentages of employees that are represented by a collective bargaining unit, are women, or are racially and/or ethnically diverse:

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Health, Safety and Well-Being

We value the health, safety, security and well-being of our employees, contractors and the communities that we serve. 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. We take measures to provide employees and contractors with proper knowledge, training and protective equipment to maintain their personal health and safety and to mitigate workplace risks.

Culture, Diversity, Equity and Inclusion

We incorporate DEI throughout the employee life cycle and build on our Inclusion for All strategy. Since everyone is responsible for DEI and work-place culture, employees have many opportunities to influence the work environment, let their voices be heard and to step up and lead. Our efforts are led by the PSEG Office of DEI. It is supported by our Employee Business Resource Groups and the Local Inclusion Teams within our business units and field locations. The Office of DEI works to make sure our programs such as community outreach and volunteerism, mentorship, recognition and professional development, are relevant and accessible to all employees.

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 initiatives to advance DEI include doing business with certified minority, women, veteran and service-disabled veteran-owned businesses as well as LGBTQ+-owned businesses and continuously improving our supplier diversity process which is integrated into our company culture.

Talent, Attraction and Workforce Development

Our talent acquisition strategy is focused on hiring a diverse, high-performing workforce to meet our business objectives, including the critical skilled trade roles needed to provide energy that is safer and delivered more reliably than ever. As part of these efforts, we work to attract employees who reflect broad dimensions of diversity, including race, gender, disability, generation, education, and other traits and characteristics that make each person who they are.

Our employees grow through a variety of training and development opportunities offered to individual contributors, front line supervisors, managers and leaders. Talent reviews and succession planning for senior and critical positions are key components of our workforce planning strategy. We continue to identify and develop internal talent to step into key roles, minimizing any potential disruptions to our operations. We invest in technical and operational training for our craft and field workers to support safe and reliable operations. We continue to focus on hiring ahead of attrition and upskilling our skilled trade roles to adapt to evolving technologies and digital advancements.

Total Rewards

We support the well-being of our employees through a comprehensive total rewards program. We provide compensation to our workforce and a benefit program that is designed to support mental and physical health and emotional and financial wellness. In 2023, we performed a total rewards study, which included a comprehensive evaluation of our performance management process, compensation structure and design as well as pay fairness review.

REGULATORY ISSUES

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

Federal Regulation

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

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

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Transmission Regulation

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

Transmission Rate Proceedings and ROE—From time to time, various matters are pending before FERC relating to, among other things, transmission planning, reliability standards 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.

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

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

Energy Clearing Prices

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

Capacity Market Issues

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

In October 2023, PJM submitted two related filings at FERC proposing reforms to its capacity market design, including (i) enhanced risk modeling to better account for winter risk; (ii) changes to supply-side market power mitigation rules; and (iii) more stringent capacity qualification and performance requirements. In January 2024, FERC issued an order approving PJM’s reforms relating to enhanced risk modeling and qualification and performance requirements. However, in February 2024, FERC issued an order rejecting PJM’s second package of reforms, including PJM’s proposed changes to its supply-side market power mitigation rules. At the same time, in this order FERC provided guidance to PJM should PJM choose to develop an alternate proposal in the future. Various parties may seek rehearing of FERC’s rejection order. In February 2024, PJM submitted a request asking FERC to delay the commencement of the base residual auction for the 2025/26 Delivery Year to mid-July 2024. This request is pending before FERC.

In late December 2022, PJM called its first ISO-wide Maximum Generation Emergency Action during Winter Storm Elliott, which triggered a Performance Assessment Interval (PAI) event. As a result of this event, PSEG both incurred penalties and received bonuses under PJM’s capacity performance rules, neither of which were material to PSEG’s financial results in 2022

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or 2023. Many generators filed complaints at PJM seeking to reduce or eliminate their obligations to pay non-performance penalties incurred during the event. Parties ultimately reached a settlement effectuating a penalty reduction that was not material to PSEG. In December 2023, FERC approved the settlement.

Compliance

**Reliability Standards—**Congress has required FERC to put in place, through the North American Electric Reliability Corporation (NERC), national and regional reliability standards to ensure the security and reliability of the U.S. electric transmission and generation system (grid) and to prevent major system blackouts. As a result, under NERC’s physical security standard, approved by FERC in 2015, utilities are required to identify critical substations as well as develop threat assessment plans to be reviewed by independent third parties. In our case, the third party is PJM. As part of these plans, utilities can decide or be required to build additional redundancy into their systems. As a result of physical attacks in 2022 to electric infrastructure, NERC is studying whether the physical security standard should be revised. Moreover, under NERC’s supply chain standard approved by FERC in 2018, PSEG has developed physical and cybersecurity controls for supply chain management associated with the procurement of industrial control system hardware, software, and services related to grid operations.

In February 2023, FERC approved additional reliability standards governing extreme cold weather preparedness and operations, which will begin going into effect in 2024. We continue to analyze these new standards. FERC and NERC continue to study potential revisions to reliability standards regarding extreme cold weather. Relatedly, in November 2023, FERC and NERC released a report regarding the operation of the Bulk Power System (BPS) during Winter Storm Elliott that struck in late 2022, causing power outages for millions and significantly straining the BPS in certain regions of the country, and proposed recommendations. These recommendations for extreme cold weather events include: (i) creation of additional reliability standards to strengthen generator operations; (ii) legislation or regulations to ensure the reliability of natural gas infrastructure; (iii) identification of high risk generating units and conducting cold weather verifications of these units; and (iv) improving short-term load forecasts for extreme cold weather events.

In June 2023, FERC issued a rule directing NERC to either change existing reliability standards or create a new standard that will require RTOs like PJM to plan for extreme weather events. In October 2023, pursuant to FERC’s rule, PSE&G, along with PJM and other RTOs, jointly submitted an informational report describing their policies and processes for conducting extreme weather vulnerability assessments.

**Investor Ownership of Public Utilities—**In December 2023, FERC proposed new rules that, if finalized, would mean that institutional investors in FERC-regulated public utilities or in holding companies with public utility affiliates will need to obtain approval from FERC before acquiring such an ownership interest that exceeds a defined monetary threshold. Under current rules, investors are able to rely upon blanket authorizations to make such investments and are not required to obtain FERC approval for specific stock acquisitions. FERC is concerned that there is insufficient oversight to protect consumers and is seeking public comment on the proposed rules. We cannot predict the outcome of this rulemaking proceeding.

CFTC

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

Nuclear

Nuclear Regulatory Commission (NRC)

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

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

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

			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

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

State Regulation

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

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

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

New Jersey Energy Master Plan (EMP) and Future of Gas Stakeholder Proceeding—In January 2020, the State of New Jersey released its EMP. While the EMP does not have the force of law and does not impose any obligations on utilities, it outlines current expectations regarding the 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.

In February 2023, the governor of New Jersey issued three Executive Orders (EOs), one of which directs the BPU to immediately 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. This proceeding will consider the possible development of a “clean heat standard” or other market mechanisms to support New Jersey’s goals, among other things. The BPU Board is seeking to retain a consultant to assist with this proceeding, and is expected to convene additional working groups and/or stakeholder sessions in 2024. Additionally, in April of 2023 the governor’s office Council on the Green Economy initiated a “Clean Buildings Working Group” that is considering pathways for building electrification and meeting gas utility emissions reduction goals, including development of a clean heat standard. PSE&G was invited to participate in this working group focused on strategic planning. 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, particularly as they may relate to PSEG Power’s nuclear energy generating stations and PSE&G’s electric transmission and gas distribution assets.

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. In April-May 2023 the BPU Board conducted an initial stakeholder meeting and received written comments identifying any issues to be examined, presumably in a future portion of this proceeding following BPU Staff recommendation and BPU Board adoption. There has been no public activity in this matter since the submissions in May 2023.

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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. The BPU retained a consultant and in June 2022 accepted the consultant’s key finding that, through 2030, New Jersey’s firm gas capacity can meet firm demand under normal design day conditions. The only potential gas supply shortfall was found during extreme weather (i.e., a winter day that could be expected to occur only once in 90 years) and/or a “perfect storm,” which occurs when there is an outage on a transcontinental pipeline during a design day. The BPU noted that its consultant’s analysis supports 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.

Energy Efficiency, Triennial Review—During 2023, the BPU issued two Energy Efficiency Framework Orders which address, among other things, program administration and design, cost recovery and filing requirements, goals, a performance incentive mechanism, building decarbonization and demand response (DR), and required utilities to submit EE programs aligned with this framework.

In September 2023, the BPU directed utilities to apply for a six-month extension of the first triennial programs. PSE&G filed for its six-month extension of the existing program in November 2023, and filed its second triennial EE program proposal in December 2023. Both filings are subject to BPU approval.

BGS Process—In June 2023, New Jersey’s EDCs, including PSE&G, filed their annual joint proposal for the conduct of the February 2024 BGS auction covering energy years 2025 through 2027. As was directed by a November 2022 BPU order, PSE&G participated in a working group led by BPU Staff to consider proposals for a commercial dc, fast-charging (DCFC) rate solution. PSE&G’s proposal included in the June 2023 joint EDC BGS filing is for a two-year DCFC BGS rate pilot program to begin June 1, 2024. Also, in accordance with the November 2022 order’s directive that the EDCs implement a rate solution for residential EV charging customers, in May 2023, the BPU approved PSE&G’s proposal for a BGS time-of-use rate solution for residential EV charging, with rates effective June 1, 2023. In November 2023, the BPU issued its decision to approve the joint EDCs’ proposal regarding the BGS auction process, including approving the EDCs’ proposed DCFC BGS rate pilot programs.

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 June 2021, the BPU issued an initial straw proposal for the establishment of an EV infrastructure ecosystem for medium-and heavy-duty EVs in New Jersey, and conducted a series of stakeholder meetings to discuss that ecosystem. In December 2022, the BPU issued a revised straw proposal for public comment. Although we cannot predict the outcome of the stakeholder process, we anticipate that this effort will result in opportunities for EDCs to target infrastructure investments for the medium- and heavy-duty EV market.

Grid Modernization—In October 2021, the BPU commenced a stakeholder proceeding to develop and implement a systemic Grid Modernization plan in accordance with strategies outlined in the New Jersey EMP. The BPU retained a consultant that gathered detailed and comprehensive information from New Jersey’s EDCs, including PSE&G, regarding resource issues and policy changes needed to interconnect the clean energy capacity required under state policy. In June 2022, the BPU’s consultant issued a draft report with its findings and recommendations to update the BPU’s interconnection regulations and processes. The BPU is currently considering revising its interconnection rules to speed up the interconnection of renewable resources to the distribution grid. 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.

New Jersey Solar Initiatives—In July 2021, the BPU issued an order formally establishing the Successor Solar Incentive (SuSI) Program, heavily drawing upon the predecessor Transition Renewable Energy Certificates program, to serve as the permanent program for providing solar incentives to qualified solar electric generation facilities. New Jersey’s EDCs role in the program is to acquire all of the Solar Renewable Energy Certificates-II received each year by eligible solar generation projects and each EDC may recover from its customers the reasonable and prudent costs incurred in the disposition of SuSI obligations. During 2023, the BPU rejected the first round of bids for the SuSI program projects as they exceeded pre-determined, confidential price caps. In September 2023, the BPU issued an Order opening a second round of solicitations which closes in February 2024.

In August 2023, the BPU established a permanent Community Solar Energy Program (CSEP) including eligibility requirements, registration processes, the implementation of consolidated billing for the benefit of project developers and participants and allowing for the electric and natural gas utilities to recover costs related to implementing and administering the CSEP program. The program does not include the opportunity for utilities to develop or operate CSEP projects.

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Cybersecurity Regulation

Federal—NERC Critical Infrastructure Protection standards establish cybersecurity and physical security protections for critical systems and facilities. These standards are also designed to promote coordination, threat sharing and interaction between utilities and various government agencies regarding potential cyber and physical threats against the nation’s electric grid. The scope of the Critical Infrastructure Protection standards is limited to 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.

ENVIRONMENTAL MATTERS

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.

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Air Pollution Control

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.

Water Pollution Control

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.

Hazardous Substance Liability

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.

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.

Fuel and Waste Disposal

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. Low-Level Radioactive Waste is periodically being shipped to the South Carolina waste disposal facility from Salem and Hope Creek. 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.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS (PSEG)

Name						Age as of December 31, 2023						Office						Effective Date First Elected to Present Position
Ralph A. LaRossa						60						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						60						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						60						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
												SVP - Delivery, Projects and Construction - PSE&G						July 2014 to September 2018
Tamara L. Linde						59						EVP and General Counsel - PSEG						July 2014 to present
												EVP and General Counsel - PSE&G						July 2014 to present
												EVP and General Counsel - PSEG Power						July 2014 to present
Charles V. McFeaters						64						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
Sheila J. Rostiac						53						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
												VP - Talent, Development and Diversity						October 2012 to September 2019
Richard T. Thigpen						63						SVP - Corporate Citizenship - Services						July 2018 to present
												VP - State Government Affairs - Services						March 2007 to July 2018
Rose M. Chernick						60						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
												VP-Finance, Corporate Strategy and Planning - Services						November 2017 to March 2019

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