filings.toolsItem 1. BUSINESS
74K characters. Original on sec.gov · Markdown
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 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.
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.
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.
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 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.
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 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 2024 and Future Outlook for additional information.
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. 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:
| % of 2024 Sales | ||||||||||
| Customer Type | Electric | Gas | ||||||||
| Commercial | 57 | % | 38 | % | ||||||
| Residential | 34 | % | 58 | % | ||||||
| Industrial | 9 | % | 4 | % | ||||||
| Total | 100 | % | 100 | % | ||||||
Our customer base has modestly increased since 2020, with electric and gas loads changing as illustrated in the following table:
| 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)% | ||||||
(A)
Excludes sales from Gas rate classes that do not impact margin, specifically Contract, Non-Firm Transportation, Cogeneration Interruptible and Interruptible Services.
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.
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 | |||||||
| 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 | |||||||
(A)
Rolling three-year program with over 80% of spending within 5 years, with limited spending thereafter.
(B)
The program has a small amount of trailing costs expected to be spent in year 5.
(C)
The program has a small amount of trailing costs expected to be spent in year 3.
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.
Energy Cloud (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.
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.
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).
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
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 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.
How PSEG Power’s Nuclear Generation Operates
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.
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.
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.
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, 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.
Markets and Market Pricing
All of PSEG Power’s nuclear generation assets are located within the PJM RTO.
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.
Hedging Strategy
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.
LIPA Operations Services Agreement (OSA)
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.
Competitively Bid, FERC Regulated Transmission Projects
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
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.
COMPETIT****IVE 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 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.
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.
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.
HUMAN CAPI****TAL MANAGEMENT
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.
Safety and Security
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.
Employee Experience & Engagement
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.
Talent Management
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.
Total Rewards Program
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.
REGULAT****ORY 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.
Transmission Regulation
FERC has exclusive jurisdiction to establish the rates and terms and conditions of service for interstate transmission. We currently have FERC-approved formula rates in effect to recover the costs of our transmission facilities. Under this formula, rates are put into effect in January of each year based upon our internal forecast of annual expenses and capital expenditures. Rates are subsequently trued up to reflect actual annual expenses and capital expenditures.
Transmission Rate Proceedings and ROE—From time to time, various matters are pending before FERC relating to, among other things, transmission planning and transmission rates and returns, including incentives. Depending on their outcome, any of these matters could materially impact our results of operations and financial condition.
In a rulemaking proceeding issued in 2021, FERC proposed to eliminate the existing 50 basis point adder for RTO membership, which is currently available to PSE&G and other transmission owners in RTOs. Elimination of the RTO adder for RTO membership would reduce PSE&G’s annual Net Income and annual cash inflows by approximately $40 million.
Transmission Planning Proceedings—Through rulemaking proceedings, FERC continues to determine whether changes are needed to current transmission and interconnection planning rules to facilitate the integration of renewable resources onto the grid. FERC is also examining whether there is sufficient oversight over transmission costs to protect customers. Among other issues, FERC is considering whether transmission competitive solicitations are working as intended, whether interconnection queue rules for new generation should dramatically change and whether some type of transmission monitor construct to oversee costs should be imposed.
On the interconnection front, in July 2023, FERC issued a Final Rule, which parties have challenged on rehearing, that will require RTOs to implement rules to speed up the processing of interconnection queue requests. This rule may also result in penalties being imposed on generators, RTOs and transmission owners that fail to meet certain process deadlines. In December 2024, PJM submitted proposed revisions to the PJM Tariff to provide for a reliability based expansion of the interconnection queue window so that a limited number of additional generating resources (50 projects) needed to address PJM’s reliability challenges can be added to this interconnection cycle. FERC accepted this proposal in February 2025, which will allow PJM to accelerate the interconnection of new, "shovel-ready" generation capacity resources and may facilitate PSEG's plan to implement power uprates for both Salem Unit 1 and Unit 2.
In May 2024, FERC issued a Final Rule on transmission planning and cost allocation. As a result of this rule, RTOs like PJM will be required to engage in 20-year transmission planning, applying certain scenarios to the planning process. FERC also reinstated the Right of First Refusal for a discrete category of transmission projects. On rehearing, FERC expanded the states' role in the process for determining how transmission costs will be allocated to various sets of customers. PJM is currently in the process of developing a plan to implement the rule.
In December 2024, a coalition of industrial customers and state ratepayer advocates filed a complaint at FERC against various named public utilities and RTOs/ISOs, including PJM. The complaint alleges that local planning has produced inefficient planning and projects that are not cost-effective, and therefore requests that FERC require the application of regional planning requirements, including relevant competitive solicitation processes, to all transmission facilities over 100kV. The complaint also requests that FERC require RTOs/ISOs to appoint an “Independent System Planner” to oversee transmission planning. While PSEG is not a named party in the complaint, our local planning authority and rights may be impacted by the resolution of this proceeding. We cannot predict the outcome of this proceeding.
Regulation of Wholesale Sales—Generation/Market Issues/Market Power
Under FERC regulations, public utilities that wish to sell power at market rates must receive FERC authorization (market-based rate (MBR) authority) to sell power in interstate commerce before making power sales. They can sell power at cost-based rates or apply to FERC for authority to make MBR sales. For a requesting company to receive MBR authority, FERC
must first determine that the requesting company lacks market power in the relevant markets and/or that market power in the relevant markets is sufficiently mitigated. Certain PSEG companies are public utilities and currently have MBR authority. These companies, which include PSEG Energy Resources & Trading LLC, PSEG Nuclear LLC and PSE&G must file at FERC every three years to update their market power analyses. At the end of 2022, PSEG filed such a market power update at FERC, which remains pending.
In October 2024, FERC issued a Final Rule that eliminates compensation for reactive power in circumstances when the generator is operating within the normal power factor range specified in its interconnection agreement. PSEG Power currently receives reactive power compensation, and we have sought rehearing of this Final Rule. In January 2025, PJM made a compliance filing at FERC seeking approval to delay implementation of the rule, and the resulting prospective loss of reactive power compensation for generators like PSEG Power within the PJM footprint, until June 1, 2026. The loss of reactive power compensation is not expected to have a material impact on PSEG's results of operations.
In addition, there are several ongoing proceedings at FERC that may impact future co-located customer arrangements, such as data centers, involving the supply of power from nuclear units, including whether certain data center customers, depending on their configuration, will pay transmission service charges. FERC is also broadly examining issues concerning whether and to what extent there are potential reliability, cost and customer impacts raised by the location of large customers at generating facilities. In February 2025, FERC issued a show cause order directing PJM and PJM transmission owners to explain within 30 days why the PJM tariff is just and reasonable or, alternatively, what revisions might be necessary, to address perceived gaps in the PJM tariff with respect to co-located load arrangements. We cannot predict the outcome of these proceedings.
Energy Clearing Prices
Energy clearing prices in the markets in which we operate are generally based on bids submitted by generating units. Under FERC-approved market rules, bids are subject to price caps and mitigation rules applicable to certain generation units. FERC rules also govern the overall design of these markets. At present, all units, including those owned by PSEG, within a delivery zone receive a clearing price based on the bid of the marginal unit (i.e., the last unit that must be dispatched to serve the needs of load) which can vary by location.
Capacity Market Issues
PJM operates a capacity market called the Reliability Pricing Model (RPM), the rules for which are approved by FERC. RPM incorporates a forward auction for installed capacity. Under the RPM, generators located in constrained areas within PJM are paid more for their capacity as an incentive to ensure adequate supply where generation capacity is most needed. The mechanics of the RPM in PJM continue to evolve and be refined in stakeholder proceedings and FERC proceedings in which we are active.
Over the past several months, there have been significant activities related to PJM’s capacity market. PJM has delayed capacity auctions for the next three delivery years (2027/28, 2028/29 and 2029/30). Three complaints were filed against PJM alleging that PJM’s capacity market rules have resulted in unjust and unreasonable capacity prices, and seeking to produce short-term increases in supply in the market and a short-term decrease in clearing prices. PJM has also made filings to change its rules to address concerns raised in the complaints, including tariff revisions filed in February 2025 with FERC proposing a collar of $175 per MW-day floor and $325 per MW-day ceiling on capacity prices for the next two delivery years. These ongoing proceedings, as well as potential future proceedings, may affect the future design of the capacity market. We cannot predict the outcome of these proceedings or their impact on our business, results of operations and cash flows.
Compliance
**Reliability Standards—**PSEG is required to comply with the North American Electric Reliability Corporation (NERC) Reliability Standards, promulgated by NERC and approved by FERC, which are designed to ensure the security and reliability of the United States electric transmission and generation system (the “electric grid”). As a result, PSEG is subject to requirements governing the planning and operation of the electric grid, and requirements governing the physical and cyber security of PSEG assets that are used to protect and operate the electric grid. Due to the increasing sophistication of physical and cyber security threats to the security and reliability of the electric grid, it is anticipated that FERC and NERC will continue to promulgate new Reliability Standards, and modify existing Reliability Standards, to meet these challenges.
CFTC
In accordance with the Dodd-Frank Wall Street Reform and Consumer Protection Act, the SEC and the CFTC continue to implement a regulatory framework for swaps and security-based swaps. The rules are intended to reduce risk, increase transparency and promote market integrity within the financial system by providing for the registration and comprehensive regulation of swap dealers and by imposing recordkeeping, data reporting, margin and clearing requirements with respect to swaps. We are currently subject to recordkeeping and data reporting requirements applicable to commercial end users. The CFTC finalized new rules establishing federal position limits for trading in certain commodities, such as natural gas. Entities such as PSEG began complying with the rules on January 1, 2022.
Nuclear
Nuclear Regulatory Commission (NRC)
Our operation of nuclear generating facilities is subject to comprehensive regulation by the NRC, a federal agency established to regulate nuclear activities to ensure the protection of public health and safety, as well as the environment. Such regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety, security, cybersecurity, and environmental requirements. Continuous demonstration to the NRC that plant operations meet requirements is necessary.
The NRC has the ultimate authority to determine whether any U.S. nuclear generating unit may operate. The NRC conducts ongoing reviews of nuclear industry operations experience and may issue or revise regulatory requirements. We are unable to predict the final outcome of these reviews or the cost of any actions we would need to take to comply with any new regulations, including possible modifications to the Salem, Hope Creek and Peach Bottom facilities, but such costs could be material.
The current operating licenses of our nuclear facilities expire in the years shown in the following table:
| 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.
In 2024, PSEG submitted a letter to the NRC regarding a potential timeline to seek a second license renewal for our Salem and Hope Creek units. This second license renewal would extend the operating licenses through 2056 and 2060 for Salem Units 1 and 2, respectively, and 2066 for Hope Creek.
State Regulation
Our principal state regulator is the BPU, which oversees electric and natural gas distribution companies in New Jersey. We are also subject to various other states’ regulations due to our operations in those states.
Our New Jersey utility operations are subject to comprehensive regulation by the BPU including, among other matters, regulation of retail electric and gas distribution rates and service, the issuance and sale of certain types of securities and compliance matters.
In addition to base rates, we recover certain costs or earn on certain investments pursuant to mechanisms known as adjustment clauses. These clauses permit the flow-through of costs to, or the recovery of investments from, customers related to specific programs, outside the context of base rate proceedings. Recovery of these costs or investments is subject to BPU approval for which we make periodic filings. Delays in the pass-through of costs or recovery of investments under these
mechanisms could result in significant changes in PSE&G’s cash flow. PSE&G’s participation in solar, EV and EE programs is also regulated by the BPU, as the terms and conditions of these programs are approved by the BPU. BPU regulation can also have a direct or indirect impact on our power generation business as it relates to energy supply agreements and energy policy in New Jersey.
New Jersey Energy Master Plan (EMP) and Future of Gas Stakeholder Proceeding—In January 2020, the State of New Jersey released its EMP. While the EMP does not have the force of law and does not impose any obligations on utilities, it outlines current expectations regarding New Jersey’s role in the use, management, and development of energy. The EMP recognizes the goals of New Jersey’s Clean Energy Act of 2018 (the Clean Energy Act) to achieve, by 2026, annual reductions of electric and gas consumption of at least 2% and 0.75%, respectively, of the average of the prior three years of retail sales. The annual reductions were subsequently adjusted to 2.15% for electric and 1.10% for gas by 2027 in the BPU’s EE framework approved in June 2020. The EMP outlines several strategies, including statewide EE programs; expansion of renewable generation (solar and offshore wind), energy storage and other carbon-free technologies; preservation of existing nuclear generation; electrification of the transportation sector; and reduced reliance on natural gas. The BPU began proceedings to update the State’s EMP via public input hearings in May and June 2024.
In February 2023, the governor of New Jersey issued three Executive Orders (EOs), one of which directed the BPU to convene a stakeholder process on the future of gas to develop a plan to meet the State’s current EMP goal to reduce emissions by 50% versus 2006 levels by 2030. In March 2023, the BPU opened a stakeholder proceeding to implement such EO that commenced in August 2023 with a two-day technical conference. We cannot predict the impact on our business or results of operations from these stakeholder proceedings, or any laws, rules, or regulations promulgated as a result thereof.
Stakeholder Proceeding on Gas Competition, BGSS—In February 2023, the BPU announced that it would open a new docket to conduct a stakeholder proceeding regarding gas supply issues previously raised by competitive gas suppliers, including third-party suppliers’ participation in New Jersey gas distribution companies’ annual BGSS filings, and other aspects of the existing BGSS construct. There has been no public activity in this matter since May 2023.
Gas Capacity Review—In September 2019, the BPU formally opened a stakeholder proceeding to explore gas capacity procurement service to all New Jersey natural gas customers and in June 2022 accepted a consultant’s finding that, through 2030, New Jersey’s firm gas capacity can meet firm demand under normal design day conditions. The BPU noted that its consultant’s analysis supported the argument against the need for additional interstate pipeline capacity and also supports the BPU’s aggressive policy approach to reduce New Jersey’s overall reliance on fossil fuels and achieve the New Jersey governor’s goal of 100% clean energy by 2050.
Regional Energy Access (REA) Expansion Project — In September 2024, the United States Circuit Court for the District of Columbia Circuit vacated FERC approval of the REA Expansion Project, which involves a natural gas pipeline running through New Jersey and several other states, and in which PSEG Energy Resources & Trade, LLC, the provider of gas supplies to satisfy PSE&G’s BGSS customers, is a customer. The court found that FERC failed to properly consider the environmental consequences of the project, and the alleged lack of market demand for additional natural gas capacity in New Jersey. In January 2025, FERC responded to the Circuit Court’s concerns and reinstated its approval of the project. PSEG is continuing to monitor this proceeding.
Energy Efficiency, Triennial Review—In May 2024, the BPU approved an approximate $300 million extension of our CEF-EE program covering a commitment period from July 2024 through December 2024. In October 2024, the BPU approved our CEF-EE II filing authorizing a total spend of approximately $2.9 billion for energy efficiency projects committed between January 1, 2025 through June 30, 2027, and completed over an expected six-year period. The Order approved a program investment budget of approximately $1.9 billion, net of administrative expenses, and approximately $1 billion to continue our customer on-bill repayment program. This EE filing is a significant increase from our prior filings, driven by an increase in the savings targets required under the BPU Energy Efficiency Framework and higher costs to achieve those targeted savings. The filing also includes demand response programs and building decarbonization programs.
BGS Process—In June 2024, New Jersey’s EDCs, including PSE&G, filed their annual joint proposal for the conduct of the February 2025 BGS auction covering energy years 2026 through 2028. PSE&G’s company-specific addendum to the joint filing includes a proposal for an optional, two-year pilot program for time-of-use rates for residential customers.
EV Activity—Consistent with the policy set forth in New Jersey’s EMP, the BPU has supported electrification of the transportation sector. EDCs in New Jersey, including PSE&G, are making investments, approved by the BPU for recovery in rates, initially focused on light duty vehicles, such as preparatory work to deliver infrastructure to the EV charging point. In October 2024, the BPU released an Order that provided program guidance and minimum filing requirements for electric utility operated medium- and heavy-duty charging incentive programs. The Order caps PSE&G’s program investment at $30 million and requires electric utilities to submit program filings by February 27, 2025.
Grid Modernization—In June 2022, following a stakeholder proceeding, the BPU Staff issued a report containing findings and recommendations to update the BPU’s interconnection regulations and processes. In furtherance of the recommendations, in June 2024 the BPU amended its interconnection rules to speed up the interconnection of renewable resources to the distribution grid. Separately, in July 2024, BPU Staff convened a working group to develop recommendations for integrated distribution planning for distributed energy resources. We cannot predict the impact on our business or results of operations from this Grid Modernization plan or any laws, rules or regulations promulgated as a result thereof, particularly as they may relate to PSE&G’s electric distribution assets.
Cybersecurity Regulation
Federal—NERC Critical Infrastructure Protection standards establish cybersecurity and physical security protections for critical systems and facilities. These standards are also designed to promote coordination, threat sharing and interaction between utilities and various government agencies regarding potential cyber and physical threats against the nation’s electric grid. The Critical Infrastructure Protection standards are designed to protect Bulk Electric System (BES) Cyber Systems that would impact the reliable operation of the BES. PSE&G is obligated to comply with the NERC Critical Infrastructure Protection standards.
NERC Critical Infrastructure Protection standards do not apply to nuclear facilities which are instead governed by the NRC for purposes of physical and cyber security. NRC has a number of risk-informed, performance-based security programs in place to effectively protect U.S. commercial nuclear facilities. NRC has existing requirements, effective processes, and the expertise to regulate and inspect cybersecurity to ensure the federal requirements are met. NERC continues to examine revising criteria for low-impact cyber systems, which could result in expanding the Critical Infrastructure Protection standards to a larger set of applicable cyber assets.
NRC requires operating nuclear power plant licensee and license applicants to ensure that digital computer and communication systems associated with a nuclear power plant’s safety, security, and emergency preparedness functions are protected from cyberattacks. As a result, computer systems at operating power plants that monitor and control safety systems and help the reactor operate are isolated from external communications. Security systems that provide safeguards of the facility are also isolated from external communications, including the Internet.
NRC’s Office of Nuclear Security and Incident Response established the Cyber Security Branch (CSB) to strengthen internal governance of the agency’s regulatory activities. The CSB plans, coordinates, and manages agency activities related to cybersecurity for NRC applicants and licensees, such as security programs’ development and policy enhancements to prevent malevolent cyber acts against NRC-licensed facilities. The CSB’s cybersecurity-related responsibilities include developing rules and guidance, reviewing licensing actions, developing policy enhancements, and overseeing NRC-licensed facilities.
NRC regularly monitors the threats associated with cybersecurity, including potential threats against NRC-licensed facilities. Within the CSB there is a cyber assessment team that assesses real-world cyber events at NRC-licensed facilities. The team evaluates whether an identified threat could impact licensed facilities and makes recommendations for NRC actions and communications to the licensees. Furthermore, the NRC has established liaison relationships with the intelligence and law enforcement communities to include the National Counterterrorism Center, the U.S. Department of Homeland Security’s (DHS) Computer Emergency Response Team, and the Federal Bureau of Investigation.
The Transportation Security Administration, an agency of the U.S.DHS, has issued multiple security directives since May 2021 designed to mitigate cybersecurity threats to natural gas pipelines.
State—The BPU requires utilities, including PSE&G, to, among other things, implement a cybersecurity program that defines and implements organizational accountabilities and responsibilities for cyber risk management activities, and
establishes policies, plans, processes and procedures for identifying and mitigating cyber risk to critical systems. Additional requirements of this order include, but are not limited to (i) annually inventorying critical utility systems; (ii) annually assessing risks to critical utility systems; (iii) implementing controls to mitigate cyber risks to critical utility systems; (iv) monitoring log files of critical utility systems; (v) reporting cyber incidents to the BPU; and (vi) establishing a cybersecurity incident response plan and conducting biennial exercises to test the plan. In addition, New York’s Stop Hacks and Improve Electronic Data Security (SHIELD) Act, which became effective in March 2020, requires businesses that own or license computerized data that includes New York State residents’ private information to implement reasonable safeguards to protect that information.
ENVIRONMEN****TAL 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.
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.
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.
Wildlife and Habitat Protection
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.
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. 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.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS (PSEG)
| 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 | ||||||
Previous: Cover and table of contents · Next: Item 1A. RISK FACTORS