# Public Service Enterprise Group Inc: Form 10-K for the period ended Dec 31, 2025

- Company: [Public Service Enterprise Group Inc](/companies/peg.md) (CIK 788784)
- Form: 10-K
- Filed: 2026-02-26
- Accepted by EDGAR: Feb 26, 2026, 17:27 ET
- Period: 2025-12-31
- Accession: 0001193125-26-077446
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/788784/000119312526077446/peg-20251231.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/788784/000119312526077446/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2025-12-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 12 months, 2025-01-01 to 2025-12-31 | $12.17bn | us-gaap:Revenues |
| Operating income | 12 months, 2025-01-01 to 2025-12-31 | $2.98bn | us-gaap:OperatingIncomeLoss |
| Interest expense | 12 months, 2025-01-01 to 2025-12-31 | $1.00bn | us-gaap:InterestExpense |
| Income tax | 12 months, 2025-01-01 to 2025-12-31 | $263.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 12 months, 2025-01-01 to 2025-12-31 | $2.11bn | us-gaap:NetIncomeLoss |
| Diluted EPS | 12 months, 2025-01-01 to 2025-12-31 | $4.22 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 12 months, 2025-01-01 to 2025-12-31 | $4.23 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 12 months, 2025-01-01 to 2025-12-31 | 501,000,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 12 months, 2025-01-01 to 2025-12-31 | $3.30bn | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 12 months, 2025-01-01 to 2025-12-31 | $3.27bn | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Dividends paid | 12 months, 2025-01-01 to 2025-12-31 | $1.26bn | us-gaap:PaymentsOfDividendsCommonStock |
| Cash and equivalents | at 2025-12-31 | $132.0m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2025-12-31 | $4.60bn | us-gaap:AssetsCurrent |
| Total assets | at 2025-12-31 | $57.58bn | us-gaap:Assets |
| Current liabilities | at 2025-12-31 | $5.74bn | us-gaap:LiabilitiesCurrent |
| Long-term debt | at 2025-12-31 | $21.67bn | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2025-12-31 | $875.0m | us-gaap:LongTermDebtCurrent |
| Short-term borrowings | at 2025-12-31 | $1.53bn | us-gaap:CommercialPaper |
| Shareholders' equity | at 2025-12-31 | $16.98bn | us-gaap:StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest |

## Business

As filed, 68,282 characters.

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. Our business plan focuses on achieving growth by allocating capital primarily toward regulated investments in an effort to continue to improve the sustainability and predictability of our business and realizing the value of the consistent and reliable carbon-free generation from our nuclear units.

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.

- **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 primarily by selling energy and capacity from its nuclear generation units and from the sale of wholesale natural gas through a full-requirements contract with PSE&G. PSEG Power also enters into bilateral contracts for energy, gas and other energy-related contracts to optimize the value of its portfolio of generating assets and its gas supply obligations.

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 2025 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 provided 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 5. 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 2025 and Future Outlook.

Our load requirements are split among commercial, residential and industrial customers, as shown in the following table for 2025:

| Customer Type | % of 2025 Sales Electric | Gas |
| --- | ---: | ---: |
| Commercial | 57% | 38% |
| Residential | 34% | 58% |
| Industrial | 9% | 4% |
| **Total** | **100%** | **100%** |

Our customer base has modestly increased since 2021, with electric and gas loads changing as illustrated in the following table:

*Electric and Gas Distribution Statistics*

|  | Customers as of December 31, 2025 | Historical Annual Customer Growth 2021-2025 | Electric Sales and Firm Gas Sales for the Year Ended December 31, 2025 (A) | Historical Annual Load Increase 2021-2025 |
| --- | --- | ---: | --- | ---: |
| Electric | 2.4 million | 0.9% | 40,561 Gigawatt Hours | 0.4% |
| Gas | 1.9 million | 0.7% | 2,633 Million Therms | 2.1% |

(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 and 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 II | $2.9 billion | 2024 | 6 years |  | 2025 |
| CEF-EE | $1.6 billion | 2020 | 5 years | (A) | 2020 |
| Gas System Modernization Program (GSMP) III | $1.4 billion | 2025 | 3 years | (B) | 2026 |
| GSMP II Extension | $902 million | 2023 | 2 years | (C) | 2024 |
| Infrastructure Advancement Program (IAP) | $511 million | 2022 | 4 years |  | 2022 |
| CEF-EV | $166 million | 2021 | ~6 years |  | 2021 |

(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 4.

(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. This project was completed in 2024.
- **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 III—**designed to replace at least 600 miles of cast iron and unprotected steel mains and services in our gas system.

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

**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 2025 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 12. 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 hedged through exchange markets or bilaterally.

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, 2025, PSEG Power had 3,758 MW of nuclear generation capacity. All of our nuclear generation capacity is located in New Jersey and Pennsylvania.

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

### 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 2025 and Future Outlook and Item 8. Note 12. Commitments and Contingent Liabilities.

### Markets and Market Pricing

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

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 eligible 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 did not record any PTCs for any of its nuclear units in 2025 as gross receipts exceeded the level at which we would receive PTCs. However, the PTC continues to provide a benefit to our nuclear units by helping to mitigate the exposure to potential downside market volatility.

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

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

Generally, we seek to hedge the financial risks of our generation through sales at PJM West or other nodes corresponding to our nuclear 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 level at which we would receive PTCs.

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. Our hedging strategy also considers the risk reduction impact of the PTC, as the PTC is intended to provide sufficient and stable support for nuclear units. 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 up to three years, while also retaining the flexibility to add hedges for longer terms if market conditions are favorable. 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 level at which we would receive PTCs. As of December 31, 2025, we expect that our current portfolio position for 2026 will result in the realized value of our nuclear generation output being above the level at which we would receive PTCs. Our strategy may continue to evolve taking into account energy market conditions, PTC guidance uncertainty, and potential incremental changes upon receiving U.S. Treasury guidance.

Our fuel strategy is to maintain certain levels of uranium in inventory and to make periodic purchases to support such levels.

### 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 expired on December 31, 2025. In 2025, a five year extension of the contract was approved. A competitor in the contract bidding process filed litigation against LIPA challenging the process. LIPA filed a motion to dismiss the competitor’s claim as untimely, which was granted by the New York Supreme Court in December 2025. The competitor filed an appeal in January 2026.

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.

### Competitively Bid, FERC Regulated Transmission

PSEG continues to evaluate investment opportunities in regulated transmission. 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. However, based on the procedural timeline established by order of the Maryland Public Service Commission, we do not currently believe a 2027 in-service date for the project is reasonably achievable. We are continuing to take all available steps to obtain approvals for timely project execution. We cannot predict the outcome.

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 2025 and Future Outlook.

### Energy Holdings

Energy Holdings maintains our portfolio of legacy lease investments. See Item 8. Note 7. Long-Term Investments and Note 8. Financing Receivables for additional information.

### 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 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 energy infrastructure, including generation and storage, though 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, technological advances could impact the rate of growth of our gas and electric T&D businesses.

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 CAPITAL 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 leading indicators, serious injury rate, Occupational Safety and Health Administration (OSHA) recordable incidence rate, and OSHA days away from work rate, are regularly monitored and reported to our Board.

Fifty-nine 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, 2025, women constituted approximately 28% of our non-represented employees and 19% of our total workforce. People who are racially/ethnically diverse constituted approximately 36% of our non-represented employees and 31% 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 needed 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 trades roles. We have a comprehensive workforce planning strategy to support our hiring needs. It includes hiring ahead of attrition for skilled trades 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 roles to adapt to evolving technologies and digital advancements.

### Total Rewards Program

We support the wellbeing of our employees through a comprehensive total rewards program. We provide competitive compensation to our workforce and offer a benefits program that is designed to support physical, emotional, social and financial wellbeing.

### 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 12. Commitments and Contingent Liabilities. In addition, information regarding PSE&G’s specific filings pending before the BPU is discussed in Item 8. Note 5. 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—***In May 2024, FERC issued a Final Rule to reform regional transmission planning and cost allocation. This order requires transmission providers like PJM to engage in long-term regional planning of not less than 20 years. It also requires certain reforms to the local planning process, including enhancing the transparency of that process and evaluating whether local transmission facilities that need replacing can be “right-sized” to meet broader regional needs.

In December 2025, both PJM and its Transmission Owners made compliance filings at FERC seeking to implement the Final Rule’s requirements, including establishing a comprehensive set of long-term transmission needs based on a 20-year planning horizon, providing a role for the states in identifying needs and solutions, and establishing procedures for identifying and planning “right-sized” replacement facilities. If approved by FERC, these changes will provide a regulatory framework for the planning of transmission infrastructure to help address resource adequacy challenges in PJM. Separately, the PJM Transmission Owners, including PSE&G, are working with the states to develop cost allocation rules to decide who will pay for these long-term transmission facilities, with a FERC filing to be made later in 2026.

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 & Trade LLC, PSEG Nuclear LLC and PSE&G must file at FERC every three years to update their market power analyses. At the end of 2025, PSEG filed an updated market power analysis.

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. FERC denied rehearing of this order in June 2025 and in August 2025 accepted a PJM filing that establishes a June 1, 2026 date for elimination of reactive power compensation. In August 2025, PSEG sought judicial review of FERC’s decision. This appeal is pending and we cannot predict the outcome. The loss of reactive power compensation is not expected to have a material impact on PSEG's results of operations.

In addition, there are ongoing proceedings at FERC that may impact the interconnection of large loads such as data centers to the power grid, including addressing the issue of what transmission services and charges should be paid by future co-located customers. In February 2025, FERC issued a “show cause” order directing PJM and PJM transmission owners to explain 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. In December 2025, FERC issued an order in this proceeding finding the PJM tariff to be unjust and unreasonable, directing PJM to file tariff revisions to reflect new types of transmission services that will be made available to co-located loads and establishing a paper hearing to set the appropriate level of charges to be paid by co-located load customers.

Relatedly, in October 2025, in response to a directive by the Secretary of Energy, FERC initiated a rulemaking proceeding to establish rules by the end of April 2026 to facilitate the interconnection of large load customers to the transmission system through a queue process. We cannot predict the outcome of these matters.

### 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.

Over the past few years, RPM has been under considerable scrutiny at both the federal and state level as clearing prices in the capacity auctions have reached unprecedented levels and there is growing concern that the capacity market is not procuring sufficient generation to meet increasing demand for electricity.

In PJM’s most recent capacity auction run in December 2025, the auction cleared at the FERC-approved price cap of $333.44/MW-day, and PJM indicated that without the price cap the clearing price would have been $529.80/MW-day. Furthermore, for the first time, PJM was unable to procure enough generation to meet its reliability requirement, which incorporates a 20% reserve margin to meet demand during times of system stress. In fact, PJM fell 6,625 MW short of meeting this reliability requirement.

In January 2026, the White House’s National Energy Dominance Council and governors from all 13 states in PJM signed an agreement urging PJM to expeditiously reform its capacity market to ensure reliability and lower costs to consumers. Specifically, the agreement seeks to provide “15 year price certainty,” which may be accomplished by having PJM conduct a reliability backstop auction to procure new generation capacity. The agreement also supports an extension of the existing price collar for two more Base Residual Auctions, which PJM has recently indicated it supports. Over the next few months, PJM will be developing rules that will enable it to run such an auction in September 2026 following FERC approval of rules changes. One of the open questions is which set of customers will pay the generation procurement costs, and whether zones where demand exceeds supply will pay a proportionately larger allocation of costs. PJM will also be considering other reforms to its markets.

### 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 rules establishing federal position limits for trading in certain commodities, such as natural gas. Entities such as PSEG began complying with the rules in 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 | 2053 |
| Peach Bottom Unit 3 | 2054 |

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.

In 2022, the NRC issued an order related to its review of the subsequent license renewal (SLR) application for the Peach Bottom nuclear units which concluded that the previous environmental review required by the National Environmental Policy Act (NEPA) was incomplete and changed the expiration dates for the licenses to 2033 and 2034, until the completion of the NEPA analysis. The NEPA analysis was completed in 2025 and the NRC reinstated the 2053 and 2054 license expiration dates for the Peach Bottom units.

### 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 flowthrough 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 June 2022, the BPU commenced a proceeding to update New Jersey’s EMP. An effort was subsequently undertaken during 2023 through early 2025 to create a revised plan, including a series of stakeholder meetings and comments. In March 2025, BPU Staff and a third-party consultant discussed the results of their modeling. The main themes presented were: a need for continued reliability and affordability; challenges for New Jersey to achieve greenhouse gas reduction goals; the new capacity additions that are needed to maintain system reliability, and that these additions can be “clean firm” additions (without details of the meaning of “clean firm”); and the need for new strategies to guide the evolution of natural gas. Following the receipt of additional comments, in November 2025 the BPU released the updated EMP.

The updated EMP included a set of what was presented as “No Regrets” recommendations, described as strategies the state should pursue regardless of any other planning scenarios or steps taken as a broader energy planning strategy. These recommendations include accelerated deployment of clean energy generation sources (for example, solar, wind, advanced nuclear); continued investment in energy efficiency; grid modernization; transportation electrification; workforce development; and expansion of customer assistance programs. In addition to these strategies, the EMP also presents modeling based on 2023-2024 data for alternative pathways to achieve state goals (high electrification, hybrid electrification and remaining at the current state). Given the new administration took office in January 2026, it is not clear how the EMP might influence New Jersey’s energy policy and we cannot predict the impact on our business that might result.

***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.

***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. In February 2025, a subset of intervenors filed a rehearing request seeking to overturn FERC’s reinstatement of the REA certificate. The same subset of intervenors also filed a motion for an evidentiary hearing. In March 2025, the rehearing request was denied by operation of law, and in August 2025 FERC addressed the arguments raised on rehearing while confirming the denial of the rehearing request and motion for evidentiary hearing.

***Energy Efficiency, Triennial Review—***In November 2025, BPU Staff issued its straw proposal for the third triennium framework and requirements for energy efficiency programs. The proposed framework suggests changes that, if adopted as proposed, would increase risk to utilities implementing these programs to meet energy efficiency targets that are required by law. PSE&G submitted responsive comments recommending changes to the proposed framework that, if accepted, could better enable optimization of investments and benefits including achieving energy savings targets. Depending on the timing of BPU approval of a final framework, utilities could be expected to file triennium 3 program proposals during 2026 for a program to begin in July 2027. We cannot predict the outcome of this review and straw proposal at this time.

***BGS Process—***In July 2025, New Jersey’s EDCs, including PSE&G, filed their annual joint proposal for the conduct of the February 2026 BGS auction covering energy years 2027 through 2029. The February 2025 BGS auction resulted in a significant cost increase for electricity supplied by PSE&G and all other New Jersey electric distribution companies that was reflected in customers’ rates beginning June 1, 2025. The cost increases were in large part due to higher prices from the PJM capacity market (base residual auction). Rates resulting from the February 2026 BGS auction will become effective June 1, 2026.

***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. In July 2025 and January 2026, the BPU adopted various regulations intended to streamline the process for utility interconnection applications and ensure compliance with a recently enacted law mandating that EDCs in New Jersey improve the interconnection process for certain grid supply solar and energy storage facilities. 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 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.

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.

NRC requires operating nuclear power plant licensees 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 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. 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 12. 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.

***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, 2025 | Office | Effective Date First Elected to Present Position |
| --- | ---: | --- | --- |
| **Ralph A. LaRossa** | 62 | 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** | 62 | 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** | 62 | President and COO - PSE&G | June 2021 to present |
|  |  | Senior Vice President (SVP) and COO - PSE&G | January 2020 to June 2021 |
| **Charles V. McFeaters** | 66 | President and Chief Nuclear Officer - PSEG Nuclear LLC | May 2023 to present |
|  |  | SVP - Nuclear Operations - PSEG Nuclear LLC | November 2020 to May 2023 |
| **Grace Park** | 50 | 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** | 55 | SVP - Chief Administrative Officer and Chief Human Resources Officer - Services | January 2020 to present |
| **Richard T. Thigpen** | 65 | SVP - Corporate Citizenship - Services | July 2018 to present |
| **Rose M. Chernick** | 62 | 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 |

18

## Risk factors

As filed, 70,126 characters.

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

### GENERAL OPERATIONAL AND FINANCIAL RISKS

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

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

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

- obtain necessary governmental and regulatory approvals;
- obtain environmental permits and approvals;
- obtain governmental and community support for such projects to avoid delays in the receipt of permits and approvals from regulatory authorities;
- obtain customer support for investments made at their premises;
- obtain property/land rights in property-constrained areas and for greenfield locations, and at a reasonable cost;
- complete such projects within budgets and on commercially reasonable terms and conditions;
- complete supporting information technology (IT), cybersecurity and physical security upgrades;
- obtain any necessary debt financing on acceptable terms and/or necessary governmental financial incentives;
- ensure that contracting parties, including suppliers, perform under their contracts in a timely and cost-effective manner; and
- timely recovery of these investments through rates.

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

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

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

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

**Significant resource adequacy challenges present affordability and reliability concerns that could cause policymakers to implement responsive measures that could have a material, adverse impact on our business, strategy, growth rates, cash flows, results of operation, and financial condition and increase regulatory uncertainty for utility investment initiatives and programs.**

PJM continues to face significant resource adequacy challenges, driven by a lack of sufficient supply to meet electric demand, which has increased significantly over the past several years and is expected to continue to increase going forward. Increasing demand is caused by data centers, EV adoption, electrification and other factors. Insufficient supply to meet forecasted demand has caused increases in energy and capacity prices which, in turn, have caused the customer rates by which we recover electric supply costs to materially increase. This has resulted in continuing affordability concerns that have caused regulators and other policymakers to consider ways to reduce utility rates, including proposing to mitigate electric rate increases, and create increased regulatory uncertainty for utility investment initiatives and programs. Actions that policymakers could implement in response to these affordability concerns could have a material, adverse impact on our business, strategy, growth rates, cash flows, results of operation, and financial condition.

In addition, both lack of supply and increasing demand pose reliability risk for customers. Substantial investments in generation, transmission and distribution will be required to meet current projections of increasing customer demand. Sustained distribution grid modernization will also be required to accommodate increased EE, EV infrastructure, increased penetration of distributed energy resources on the electric system, such as on-site solar generation and also potential deployment of energy storage, fuel cells, and distributed resources technologies. In addition, inability of PJM to procure sufficient capacity to meet demand plus its reserve margin increase future risk of blackouts and load reduction, which may in turn result in litigation, political and regulatory scrutiny and reputational impacts.

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

Climate change may drive change to existing or additional legislation and regulation that may impact our business and shape our customers’ energy preference and sustainability goals, including impacts of potential changes in use of natural gas and electricity due to electrification over the long-term and the impact on need for additional generation to meet those electric needs. These factors could impact the need to invest in our electric and gas T&D systems and, therefore, our growth rate.

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

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

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

While the CIP protects PSE&G’s margin variances against changes in customer usage of gas and electricity, climate change-related state policy goals, including but not limited to those related to GHG emissions reductions, energy efficiency targets, solar targets, energy storage targets, encouragement of electrification through EV adoption, policies to encourage electrification of end use equipment currently fueled by natural gas, and the associated legislative and regulatory responses, may create additional costs for our customers and/or our business, which could be material.

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

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

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

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

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

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

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

Long-lived assets represent approximately 73% and 80% of the total assets of PSEG and PSE&G, respectively, as of December 31, 2025. Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, including a disallowance of certain costs, a potential sale or disposition of an asset significantly before the end of its useful life, business climate or market conditions, including prolonged periods of adverse commodity and capacity prices, could potentially indicate an asset’s or group of assets’ carrying amount may not be recoverable. Significant reductions in our expected revenues or cash flows for an extended period of time resulting from such events could result in future asset impairment charges, which could have a material adverse impact on our financial condition and results of operations.

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

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

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

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

- general economic and capital market conditions, including but not limited to, prevailing interest rates;
- the availability of credit from banks and other financial institutions;
- tax, regulatory and securities law developments;
- for PSE&G, our ability to obtain necessary regulatory approvals for the incurrence of additional indebtedness;
- investor confidence in us, our regulatory environment and our industry;
- our current level of indebtedness and compliance with covenants in our debt instruments and credit agreements;
- the success of current projects and the quality of new projects;
- the predictability of our cash flows;
- our current and future capital structure;
- our financial performance and the continued reliable operation of our business; and
- maintenance of our investment grade credit ratings.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

PSEG Power sells wholesale natural gas, primarily through a full-requirements BGSS contract with PSE&G to meet the needs of PSE&G’s default gas supply service customers. In 2022, the BPU approved an extension of the long-term BGSS contract to March 31, 2027, and thereafter the contract remains in effect unless terminated by either party with a two-year notice. PSEG LI has an OSA with LIPA to operate LIPA’s electric T&D system in Long Island which was recently extended through 2030. Any discontinuation of these contracts may negatively affect our financial condition and operating results.

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

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

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

### RISKS RELATED TO OUR GENERATION BUSINESS

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

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

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

- changes in demand on the system, which could be impacted by new large customers, including data centers, electrification and other factors;
- increases and decreases in generation capacity, including the addition of new supplies of power as a result of the development of new power plants, expansion of existing power plants, continuing retirement of existing generation units, inability of, or delay in, new generating units being placed online, the retention of power plants that were expected to be

retired or recently retired units being returned to service, the extent to which those generating units are firm or intermittent, or additional transmission capacity;

- severe weather conditions;
- power supply disruptions, including power plant outages and transmission disruptions;
- climate change, and weather conditions, particularly unusually mild summers or warm winters in our market areas;
- seasonal fluctuations;
- economic and political conditions that could negatively impact the demand for power or PTCs on our nuclear generation units;
- changes in the supply of, and demand for, energy commodities;
- development of new fuels or new technologies for the production or storage of power;
- incurring penalties due to generation performance failure when called on by PJM during emergency situations;
- federal and state regulations and actions of PJM and changing PJM market rules, including capacity market auction delays and/or rule changes that could materially impact prices; and
- federal and state power, market and environmental regulation and legislation, including financial incentives for new renewable energy generation capacity that could lead to oversupply and price suppression.

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

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

### We may be unable to obtain an adequate nuclear fuel supply in the future.

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

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

- creditworthiness of third-party suppliers, defaults by third-party suppliers on supply obligations and our ability to replace supplies currently under contract may delay or prevent timely delivery;
- market liquidity for physical supplies of such fuels or availability of related services (e.g., fabrication) may be insufficient or available only at prices that are not acceptable to us;
- variation in the quality of such fuels may adversely affect our power plant operations;
- domestic and foreign legislative or regulatory actions or requirements may impact the availability of and/or increase the cost of such fuels; and
- the loss of critical infrastructure, acts of war or terrorist attacks (including cybersecurity breaches) or catastrophic events such as fires, earthquakes, explosions, floods, severe storms or other similar occurrences could impede the delivery of such fuels.

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

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

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

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

Advances in distributed generation technologies, such as fuel cells, micro turbines, micro grids, windmills and net-metered solar installations, coupled with subsidies, could (i) affect the price of energy, (ii) reduce energy deliveries as customer-owned generation becomes more cost-effective, (iii) require further improvements to our distribution systems to address changing load demands, and (iv) make portions of our transmission and/or distribution facilities obsolete prior to the end of their useful lives. These technologies could also result in further declines in commodity prices or demand for delivered energy.

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

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

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

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

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

- breakdown or failure of equipment, IT, processes or management effectiveness;
- disruptions in the transmission of electricity;
- labor disputes or work stoppages;
- fuel supply interruptions;
- limitations which may be imposed by environmental or other regulatory requirements; and
- operator error, acts of war or terrorist attacks (including physical or cybersecurity breaches) or catastrophic events such as fires, earthquakes, explosions, floods, severe weather or other similar occurrences.

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

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

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

**Generation activities at the Peach Bottom plants present risks similar to those to which nuclear generation plants that we operate are subject.**

Generation activities at, and the operation of, the Peach Bottom plants present risks similar to those described above in GENERAL OPERATIONAL AND FINANCIAL RISKS and RISKS RELATED TO OUR GENERATION BUSINESS and below in REGULATORY, LEGISLATIVE AND LEGAL RISKS.

While we have a 50% ownership interest in the Peach Bottom nuclear generation plants, these plants are operated by a third party and, therefore, we have limited control over the risks associated with these plants.

### REGULATORY, LEGISLATIVE AND LEGAL RISKS

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

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

The BPU also conducts periodic combined management/competitive service audits of New Jersey utilities related to affiliate standard requirements, competitive services, cross-subsidization, cost allocation and other issues. A finding by the BPU of non-compliance with these requirements could potentially impact our business, results of operations and cash flows. For information regarding PSE&G’s most recent affiliate and management audit, see Item 8. Note 12. Commitments and Contingent Liabilities.

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

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

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

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

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

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

***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 can also impose strict and joint and several liability for damages to the environment, including cash penalties. Federal and state environmental laws and regulations require the cleanup of discharged hazardous substances.

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

In April 2021, FERC issued a supplemental notice of proposed rulemaking to eliminate the incentive for RTO membership for transmitting utilities that have already received the incentive for three or more years. PSE&G began receiving a 50 basis point adder for RTO membership in 2008. Elimination of the adder for RTO membership would reduce PSE&G’s annual Net Income and annual cash inflows by approximately $40 million.

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

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

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

***MBR Authority and Other Regulatory Approvals—***Under FERC regulations, public utilities that sell power at market rates must receive MBR authority before making power sales, and the majority of our businesses operate with such authority. Failure to maintain MBR authorization, or the effects of any severe mitigation measures that would be required if market power was evaluated differently in the future, could have a material adverse effect on our business, financial condition and results of operations. In December 2025, all of PSEG’s operating companies with MBR authority filed at FERC for acceptance of the companies’ updated triennial market power analysis. This filing remains pending at FERC.

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

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

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

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

In August 2022, the IRA was signed into law expanding incentives promoting carbon-free generation. The enacted legislation established a PTC for electricity generation using nuclear energy which begins January 1, 2024 and continues through 2032. The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts. The PTC rate and the gross receipts threshold are subject to annual inflation adjustments. The U.S. Treasury has not yet defined gross receipts. The ZEC payment will be adjusted by the BPU to offset environmental or fuel diversity payments that a selected nuclear plant may receive from another source. We continue to estimate the PTC while we await additional guidance from the U.S. Treasury. The U.S. Treasury may issue guidance related to the PTC and/or the Federal government could amend the IRA, either of which could have an adverse impact on our financial condition, results of operations and cash flows.

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

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

The energy industry continues to be regulated and the rules to which our businesses are subject are always at risk of being changed. PJM’s capacity market design rules continue to evolve and change, including in response to projections of higher demand, lack of sufficient generation capacity and extreme weather events. These changes have led to capacity market auction delays and rules changes that have created regulatory and business uncertainty. For a discussion of recent changes in energy regulatory policies that may affect our business and results of operations, see Item 1. Business—Regulatory Issues—Federal Regulation.

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

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

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

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

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

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

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

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

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

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

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

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

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

Environmental laws and regulations have generally become more stringent over time, and this trend is likely to continue. For further discussion of environmental laws and regulations impacting our business, results of operations and financial condition, including the impact of federal and state laws and regulations relating to remediation of environmental contamination, see Item 8. Note 12. Commitments and Contingent Liabilities.

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

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

- prevent construction of new facilities,
- limit or prevent continued operation of existing facilities,
- limit or prevent the sale of energy from these facilities, or
- result in significant additional costs,

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

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

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

## Cybersecurity

As filed, 14,283 characters.

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

### Risk Management and Strategy

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

- ***Ongoing Assessment—***Cybersecurity, led by the VP, Chief Information Security Officer (CISO), reporting to the SVP, Chief Information and Digital Officer (CIDO), is staffed with cyber professionals who assess material risks from cybersecurity threats. In addition, the Cybersecurity Council, comprised of senior management, is kept apprised of PSEG’s cybersecurity program, including any emerging risks, and provides guidance on the strategic direction of the program.
- ***Engagement of Nth Parties—***We engage Nth parties (third parties and other business relationships, including fourth parties, etc.), such as cybersecurity service providers, risk management firms, and external legal counsel, to assess

material risks from cybersecurity threats, assess our internal incident response preparedness and cyber posture, support incident response, conduct tabletop exercises, and comply with applicable laws and regulations. We also carry cybersecurity insurance that provides certain protection against losses from a cybersecurity incident. Regulatory agencies, including, but not limited to, the NRC, Transportation Security Administration (TSA), and NERC, inspect applicable components of our cybersecurity program.

- ***Nth-Party Service Provider Management—***We maintain processes to oversee and identify risks from cybersecurity threats associated with our use of Nth-party service providers, including a risk-based vendor management program, which incorporates cybersecurity contractual provisions, vendor security assessments and, if appropriate, periodic audits.
- ***Technical Safeguards—***We manage controls to protect our network perimeter, internal IT, and Operational Technology (OT) environments, including internal and external firewalls, network intrusion detection and prevention tools, penetration testing, vulnerability assessments, threat intelligence, endpoint security, and access controls.
- ***Training and Awareness—***We provide mandatory annual cybersecurity training to all personnel with network access, and additional education to personnel with access to industrial control systems and/or customer information systems. We conduct phishing exercises with progressive consequences for failures. We also share periodic cybersecurity awareness messages and each year, in recognition of Cybersecurity Awareness Month, we host presentations from internal and external cyber experts on diverse cyber topics. These efforts better enable those with network access to identify potential cybersecurity risks and escalate them appropriately.
- ***Incident Response Plans—***We maintain and periodically update a cyber incident response plan that covers technical (i.e., detection, response, and recovery) and collaborative (i.e. external communication/disclosure and legal compliance) aspects of cyber incident and breach response; and conduct tabletop exercises to test plan effectiveness (both internally and through external exercises).
- ***Mobile Security—***We maintain controls to prevent loss of data through mobile devices.
- ***Artificial Intelligence Security—***We maintain AI governance, including policies and a council, incorporating AI into our Nth Party Risk Assessment process, and implementing technical controls that enable people to use AI to complete tasks more efficiently and our cyber team to better combat more sophisticated threats that make use of AI.
- ***Physical Security—***We maintain physical security measures to protect our OT systems, consistent with a defense in-depth and risk-tiered approach. Physical security measures may include access control systems, video surveillance, around-the-clock command center monitoring, and physical barriers (e.g. fencing, walls, and bollards). Additional features of PSEG’s physical security program include threat intelligence, insider threat mitigation, background checks, a threat level advisory system, a business interruption management model, and active coordination with federal, state, and local law enforcement officials. See Item 1. Business. Regulatory Issues—Federal Regulation for a discussion of Critical Infrastructure Protection standards that the NERC promulgated that mitigate risk associated with both cybersecurity and physical security of PSEG’s critical facilities.

These processes are integral to our overall risk management system/processes and inform the identification and assessment of risks and mitigations through our Enterprise Risk Management (ERM) program. The ERM team, led by the SVP, Audit, Enterprise, Risk and Compliance (AERC) considers cybersecurity risks alongside other PSEG risks, and facilitates discussion with PSEG subject matter experts to identify cybersecurity risks, evaluate their potential severity and likelihood, identify mitigations, including those identified above, and assess the impact of those mitigations on residual risk. In addition, PSEG maintains a Risk Management Committee (RMC), responsible for assessing exposure to and determining PSEG's overall risk management strategy, including with respect to cybersecurity. The RMC, supported by the ERM function, is chaired by the SVP, AERC and consists of members of senior management including the CIDO and six of the CEO’s other direct reports. In discharging its responsibilities related to cybersecurity threats, the RMC has received presentations from the CISO. To date, there has been no material impact or reasonably likely material impact on our business strategy, results of operations or financial condition from cybersecurity attacks or incidents.

### Governance

- PSEG Board of Directors (Board) Oversight of Risks from Cybersecurity Threats:
- ***PSEG Board—***The PSEG Board has ultimate responsibility for the oversight of risk management at PSEG, overseeing PSEG’s risk management program and reviewing the most significant risks facing PSEG, including

cybersecurity risks. The Governance, Nominating and Sustainability Committee of the PSEG Board reviews key enterprise risks, including cybersecurity risks, and recommends to the Board the mapping of each risk to an appropriate committee or the full Board, in accordance with the allocation of risk categories reflected in the charter of each committee. Through this process, cybersecurity risks are mapped primarily to the Board’s Industrial Operations Committee (IOC), and also the Audit Committee. In providing oversight of risks from cybersecurity threats, the Board is informed of cybersecurity incidents as appropriate, by way of updates from Senior Management, pursuant to PSEG’s Cybersecurity Incident Response Plan, as administered by the CISO.

- ***IOC—***At the PSEG Board level, the IOC holds the primary responsibility, as enumerated in its charter, for overseeing PSEG’s cybersecurity program and assessing overall compliance through active, independent and critical oversight. The IOC is informed of cybersecurity risks by the CIDO and/or the CISO, during the IOC’s four regularly scheduled meetings per year, which each include cybersecurity as a standing agenda item. Cybersecurity updates to the IOC include discussions on OT and IT cyber risks, cybersecurity updates from the CISO and/or CIDO, and reviews of a corporate cybersecurity scorecard and other performance indicators. The CIDO and CISO regularly attend IOC meetings. In addition, the IOC meets with the CISO in executive session with no other members of management present. To ensure the full Board is kept informed about the cybersecurity risks discussed at the IOC meetings, the cybersecurity materials provided to the IOC are available for full viewing by all members of the Board, members of the Board who are not IOC members have a courtesy invitation to each IOC meeting, and the Chair of the IOC provides a summary of IOC meetings to the full Board, typically the day after the meeting takes place.
- ***Audit Committee—***The Audit Committee is responsible for overseeing cybersecurity risks related to financial reporting and internal controls. The Audit Committee receives an annual cybersecurity update from the CISO, either with the full Board or the IOC in attendance. Audit Committee members have an invitation to all IOC meetings, have full access to IOC meeting materials, and receive the summary of IOC meetings from the IOC Chair as noted above.
- ***Governance, Nominating and Sustainability Committee and Audit Committee—***These committees are briefed at least annually on enterprise-level risks and emerging risks, including those related to cybersecurity, and receive regular updates on PSEG RMC activities, including those related to cybersecurity.
- ***Board of Directors, IOC, and Audit Committee—***In providing oversight of risks from cybersecurity threats, the Board, IOC, and Audit Committee are informed of cybersecurity risks through frequent reports on such topics as personnel and resources to monitor and address cybersecurity threats, technological advances in cybersecurity protection, rapidly evolving cybersecurity threats that may affect us and our industry, cybersecurity incident response and applicable cybersecurity laws, regulations and standards, as well as collaboration mechanisms with intelligence and enforcement agencies and industry groups to assure timely threat awareness and response coordination. In addition, risks associated with cybersecurity incidents, or potential incidents, are escalated by senior management promptly to the Board outside of regularly scheduled meetings, if appropriate.
- Management’s Role in Assessing and Managing Material Cybersecurity Risks:

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

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

As noted above, the CIDO regularly attends and provides updates with the CISO to the IOC.

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

- ***CISO—***The CISO has day-to-day responsibility for PSEG’s cybersecurity, including the assessment and management of material risks to PSEG from cybersecurity threats, and leads the cybersecurity team. The CISO served in this role since July 2024. Our CISO has over 24 years of experience in cybersecurity and served as a VP, CISO in the manufacturing/chemicals sector prior to joining PSEG. Our CISO started her career at the Department of Defense and led cyber teams in the financial and retail sectors. Our CISO holds an MBA in strategy, an MSE in Computer Science, a BS in Computer Science, and multiple cybersecurity certifications, including Certified Information Systems Security Professional.

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

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

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

## Properties

As filed, 3,011 characters.

All of our owned physical property is held by our subsidiaries. We believe that we and our subsidiaries maintain adequate insurance coverage against loss or damage to plants and properties, subject to certain exceptions and deductibles, to the extent such property is usually insured and insurance is available at a reasonable cost. For a discussion of nuclear insurance, see Item 8. Note 12. Commitments and Contingent Liabilities.

### PSE&G

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

### Electric Property and Facilities

As of December 31, 2025, PSE&G’s electric T&D system included approximately 25,000 circuit miles and 871,000 poles, of which 64% are jointly-owned. In addition, PSE&G owns and operates 58 switching stations with an aggregate installed capacity of approximately 40,000 megavolt-amperes (MVA) and 238 substations with an aggregate installed capacity of approximately 10,890 MVA. In addition, PSE&G owns four electric distribution headquarters and five electric sub-headquarters.

### Gas Property and Facilities

As of December 31, 2025, PSE&G’s gas system included approximately 18,000 miles of gas mains, 12 gas distribution headquarters, two sub-headquarters, and two meter shops serving all of its gas territory in New Jersey. In addition, PSE&G operates 54 natural gas metering and regulating stations, of which 25 are located on land owned by customers or natural gas pipeline suppliers and are operated under lease, easement or other similar arrangement. In some instances, the pipeline companies own portions of the metering and regulating facilities. PSE&G also owns one liquefied natural gas and three liquid petroleum air gas peaking facilities. The daily gas capacity of these peaking facilities (the maximum daily gas delivery available during the three peak winter months) is approximately 2.9 million therms in the aggregate.

### Solar

As of December 31, 2025, PSE&G owned 158 MW dc of installed PV solar capacity throughout New Jersey.

### PSEG Power

### Generation Facilities

As of December 31, 2025, PSEG Power’s share of installed nuclear generating capacity is shown in the following table:

| Name Nuclear: | Location | Total Capacity (MW) | % Owned | Owned Capacity (MW) |
| --- | --- | ---: | ---: | ---: |
| Hope Creek | NJ | 1,174 | 100% | 1,174 |
| Salem 1 & 2 | NJ | 2,280 | 57% | 1,309 |
| Peach Bottom 2 & 3 (A) | PA | 2,549 | 50% | 1,275 |
| **Total Nuclear** |  | **6,003** |  | **3,758** |

(A) Operated by Constellation Energy Generation, LLC.

## Legal proceedings

As filed, 300 characters.

We are party to various lawsuits and environmental and regulatory matters, including in the ordinary course of business. For information regarding material legal proceedings, see Item 1. Business—Regulatory Issues and Environmental Matters and Item 8. Note 12. Commitments and Contingent Liabilities.

## Management's discussion and analysis

As filed, 84,966 characters.

This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG) and Public Service Electric and Gas Company (PSE&G). Information contained herein relating to any individual company is filed by such company on its own behalf.

PSEG’s business consists of two reportable segments, PSE&G and PSEG Power LLC (PSEG Power) & Other, primarily comprised of our principal direct wholly owned subsidiaries, which are:

- **PSE&G—**which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU), the Federal Energy Regulatory Commission (FERC), and other federal and New Jersey state regulators. PSE&G also invests in regulated solar generation projects and regulated energy efficiency (EE) and related programs in New Jersey, which are regulated by the BPU, and
- **PSEG Power—**which is an energy supply company that consists of the operations of merchant nuclear generating assets and fuel supply functions engaged in competitive energy sales via its principal direct wholly owned subsidiaries. PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC) and other federal regulators and state regulators in the states in which they operate.

The PSEG Power & Other reportable segment also includes amounts related to the parent company as well as PSEG’s other direct wholly owned subsidiaries, which are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) transmission and distribution (T&D) system under an Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily holds legacy lease investments and competitively bid, FERC regulated transmission; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Our business discussion in Item 1. Business provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Item 1A. Risk Factors provides information about factors that could have a material adverse impact on our businesses. The following discussion provides an overview of the significant events and business developments that have occurred during 2025 and key factors that we expect may drive our future performance. This discussion refers to the Consolidated Financial Statements (Statements) and the related Notes to the Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements and Notes.

### EXECUTIVE OVERVIEW OF 2025 AND FUTURE OUTLOOK

We are a public utility holding company that, acting through our wholly owned subsidiaries, is a predominantly regulated electric and gas utility and a nuclear generation business. Our business plan focuses on achieving growth by allocating capital primarily toward regulated investments in an effort to continue to improve the sustainability and predictability of our business and realizing the value of the consistent and reliable carbon-free generation from our nuclear units. We are focused on investing to meet growing energy demand, modernize our energy infrastructure, improve reliability and resilience, increase EE to meet customer expectations and be well aligned with public policy objectives. With these investments and higher working capital recovery approved in the distribution rate case, our regulated rate base increased from approximately $34 billion as of December 31, 2024 to approximately $36 billion as of December 31, 2025. In addition, our nuclear facilities retain the downside price protection of a production tax credit (PTC) from 2024 through 2032.

For the years 2026-2030, our regulated capital investment program is estimated to be in a range of $22.5 billion to $25.5 billion. We expect these capital investments to result in a compound annual growth rate in our regulated rate base in a range of 6.0% to 7.5% from year-end 2025 to year-end 2030. The regulated capital investments represent the majority of PSEG’s total capital investment program of $24 billion to $28 billion. The low end of the range includes an extension of our Gas System Modernization Program (GSMP) and Clean Energy Future (CEF)-EE program, as these programs are expected to continue beyond their currently approved timeframes. The upper end of our capital investment range includes potential incremental investments to address continued demand growth and other investments to meet infrastructure needs and support New Jersey's clean energy goals.

### PSE&G

At PSE&G, our focus is on investing capital in T&D infrastructure and clean energy programs to meet growing demand, enhance the reliability and resiliency of our T&D system, meet customer expectations and support public policy objectives.

In October 2024, the BPU approved our CEF-EE II filing authorizing approximately $2.9 billion for energy efficiency projects committed between January 1, 2025 through June 30, 2027, and completed over an expected six-year period. The Order approved a program investment budget of approximately $1.9 billion, net of administrative expenses, and approximately $1 billion to continue our customer on-bill repayment program. This EE filing is a significant increase from our prior filings, driven by an increase in the savings targets required under the BPU Energy Efficiency Framework and higher costs to achieve those targeted savings.

Our GSMP II program extension provided for main replacement through December 2025 plus trailing services replacement and paving costs into 2026 totaling approximately $900 million of investment. Of the $900 million, $750 million is recovered through three periodic rate adjustments with the balance recovered through a future base rate case. In November 2025, the BPU issued an Order approving PSE&G’s GSMP III program, authorizing $1.05 billion of capital investment to replace 525 miles of high pressure cast iron gas mains and unprotected steel mains, with cost recovery through three periodic rate adjustments as portions of the investment are put into service. In that Order, the BPU also authorized $360 million of investment to replace an additional 75 miles of gas main, with cost recovery to be requested in a future base rate case. Investment under the GSMP III program will begin in 2026 and continue through December 2028 plus trailing services replacement and paving costs into 2029.

In October 2024, the BPU issued an Order approving the settlement of PSE&G's distribution rate case with new rates effective October 15, 2024. The Order provided 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. In addition, the Order approved mechanisms beginning January 1, 2025 associated with the recovery of future storm costs as well as the recovery of annual pension and OPEB expenses.

### PSEG Power

At PSEG Power, we seek to produce low-cost electricity by efficiently operating our nuclear generation assets, mitigate earnings volatility through hedging and the PTC mechanism, and support public policies that preserve these existing carbon-free base load nuclear generating plants. During 2025, our nuclear units generated approximately 30.9 terawatt hours and operated at a capacity factor of 91.2%. Effective April 2025, PSEG Power revised the estimated useful lives for the Salem 1, Salem 2 and Hope Creek nuclear plants due to our expectation that a 20-year license extension will be approved for these facilities. In October 2025, we completed work to extend the refueling cycle at our Hope Creek facility from 18 months to 24 months. In addition, we are planning power uprates at Salem Units 1 and 2 that will increase generation capacity and reliability and support long-term operation of these units, including through a potential subsequent license renewal.

Our hedging strategy continues to incorporate an estimated range of risk reduction impacts from the PTCs on our nuclear generation portfolio while retaining the ability to benefit when market pricing exceeds the level at which we would receive PTCs. As of December 31, 2025, we expect that our current portfolio position for 2026 will result in the realized value of our nuclear generation output being above the level at which we would receive PTCs. Our strategy will continue to evolve taking into account energy market conditions, PTC guidance uncertainty, and potential incremental changes upon receiving U.S.

Treasury guidance. In addition, we continue to explore opportunities for the potential sale of power, capacity and/or emission credits from our nuclear facilities pursuant to long-term agreements.

### Climate Strategy and Sustainability Efforts

We remain guided by our vision to power a future where people use energy more efficiently, and it’s safer and delivered more reliably than ever. Our investments remain focused on infrastructure modernization, energy efficiency, and supporting growing customer demand, as well as New Jersey's long-term energy goals. We have adjusted our net zero greenhouse gas (GHG) emissions goal that includes direct GHG emissions (Scope 1) and indirect GHG emissions from operations (Scope 2) across our business operations, which supports New Jersey's clean energy and climate goals, from 2030 to 2050. Transition risks, including federal and/or state policy and regulation, technology availability and affordability, market demands, and customer needs likely will impact the pace of our net zero progress and our ability to achieve the 2050 goal.

PSE&G has undertaken a number of initiatives that support the reduction of GHG emissions, including our implementation of New Jersey's EE and related programs that are intended to support New Jersey’s Energy Master Plan (EMP) and Gubernatorial Executive Orders through programs designed to help customers use energy more efficiently, reduce GHG emissions, support the expansion of the EV infrastructure in New Jersey, install energy storage capacity to supplement solar generation and enhance grid resiliency, install smart meters and supporting infrastructure to allow for the integration of other clean energy technologies and to more efficiently respond to weather and other outage events.

We continue to assess physical risks of climate change and adapt our capital investment program to improve the reliability and resiliency of our system in an environment of increasing frequency and severity of weather events. PSE&G is committed to the safe and reliable delivery of natural gas to approximately 1.9 million customers throughout New Jersey and we are equally committed to reducing GHG emissions associated with such operations. The GSMP is designed to improve safety and reliability and significantly reduce natural gas leaks in our distribution system, which would reduce the release of methane, a potent GHG, into the air. From 2018 through 2025 we reduced reported methane emissions by over 30% system wide.

We also continue to focus on working to preserve the economic viability of our nuclear units, which provide over 80% of the carbon-free energy in New Jersey. These efforts include reducing market risk by advocating for state and federal policies, such as the PTC established by the IRA, and capacity market reform and related generator interconnection policies at PJM Interconnection, L.L.C. (PJM) that recognize the value of our nuclear fleet’s carbon-free generation and its contribution to grid reliability and resource adequacy, and potential long-term contracts that recognize the value of its consistent and reliable carbon-free energy.

### Competitively Bid, FERC Regulated Transmission

PSEG continues to evaluate additional investment opportunities in regulated transmission. In December 2023, PJM awarded us an approximately $424 million project to address increasing load and reliability issues in Maryland and northern Virginia as part of its 2022 Window 3 competitive solicitation. PJM has directed that the project be placed in service in 2027. However, based on the procedural timeline established by order of the Maryland Public Service Commission, we do not currently believe a 2027 in-service date for the project is reasonably achievable. We are continuing to take all available steps to obtain approvals for timely project execution. We cannot predict the outcome.

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.

### PSEG LI

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 expired on December 31, 2025. In 2025, a five year extension of the contract was approved. A competitor in the contract bidding process filed litigation against LIPA challenging the process. LIPA filed a motion to dismiss the competitor’s claim as untimely, which was granted by the New York Supreme Court in December 2025. The competitor filed an appeal in January 2026.

### Financial Results

The financial results for PSEG, PSE&G and PSEG Power & Other for the years ended December 31, 2025 and 2024 are presented as follows:

*Millions, except per share data*

|  | Years Ended December 31, 2025 | 2024 |
| --- | ---: | ---: |
| PSE&G | $1,745 | $1,547 |
| PSEG Power & Other | 366 | 225 |
| **PSEG Net Income** | **$2,111** | **$1,772** |
| **PSEG Net Income Per Share (Diluted)** | **$4.22** | **$3.54** |

For a detailed discussion of our financial results, see Results of Operations.

### Regulatory, Legislative and Other Developments

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

### Transmission Rate Proceedings and Return on Equity (ROE)

Under current FERC rules, PSE&G continues to earn a 50 basis point adder to its base ROE for its membership in PJM as a transmission owner. However, certain regulatory or legislative actions could potentially lead to the loss of this adder which, if eliminated, would prospectively reduce PSE&G’s annual Net Income and annual cash inflows by approximately $40 million.

### New Jersey Clean Energy Stakeholder Proceedings

In February 2023, the previous governor of New Jersey issued executive orders (EOs) that establish or accelerate previously established 2050 targets for clean-sourced energy, building decarbonization, and EV adoption goals, with new target dates of 2030 or 2035, as applicable. In November 2025 the BPU released the updated Energy Master Plan (EMP) that presents potential pathways toward meeting New Jersey’s clean energy and decarbonization goals. Given the new administration took office in January 2026, it is not clear how the EMP might influence New Jersey’s energy policy and we cannot predict the impact on our business that might result.

### Environmental Regulation

We are subject to liability under environmental laws for the costs and penalties of remediating contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. In particular, the historic operations of PSEG companies and the operations of numerous other companies within the Newark Bay Complex are alleged by federal and state agencies to have discharged substantial contamination into the Newark Bay Complex in violation of various statutes. The Newark Bay Complex is a tidal estuary in northern New Jersey that includes Newark Bay, as well as portions of the Passaic River, the Hackensack River and other surrounding waterways. The U.S. Environmental Protection Agency (EPA) has designated various portions of the Newark Bay Complex as federal Superfund sites that must be investigated and remediated under the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA).

In addition, PSEG Power has retained ownership of certain liabilities excluded from the sale of its fossil generation portfolio, primarily related to obligations under New Jersey and Connecticut state laws to investigate and remediate the sites. We are also currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, and the costs and penalties of any such remediation efforts could be material.

For further information regarding the matters described above, as well as other matters that may impact our financial condition and results of operations, see Item 8. Note 12. Commitments and Contingent Liabilities.

### Nuclear

In May 2025, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants zero emission certificate (ZEC) sales concluded. Pursuant to a process established by the BPU, ZECs were purchased from these nuclear plants by the electric distribution companies (EDCs) in New Jersey. As previously noted, the Federal government established a PTC for electricity generated using existing nuclear energy, which began January 2024 and continues through 2032 and impacted PSEG Power's decision not to apply for the next ZEC three-year eligibility period starting June 2025. The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts. The PTC rate and the gross receipts threshold are subject to annual inflation adjustments. ZEC revenue recorded has been reduced by the estimated PTCs generated from these nuclear plants. The PTC amounts recorded to date are subject to change based on several factors, including but not limited to, adjustments to estimated market prices and generation and the issuance of authoritative guidance by Treasury/the Internal Revenue Service, including clarification of the definition of “gross receipts” used to determine the phase out. Any adjustments to amounts previously recorded could be material. We continue to analyze the impact of the PTC, including any future guidance from the U.S. Treasury to assess any impact of PTCs on expected ZEC payments and/or any future ZEC application periods.

### Demand, Supply and Energy Costs

An increasing demand for power and a lack of sufficient new generation resources in PJM and in New Jersey, has raised resource adequacy concerns and has resulted in higher electricity costs for our customers in 2025. Prices from the July 2024 PJM annual capacity market auction, which were approximately 10 times higher than prices from the 2023 auction and which impacted customer bills, provoked concern from state regulators and legislators and have created regulatory uncertainty. Prices from the July 2025 capacity market auction were higher than those produced by the July 2024 auction and PJM indicated that the prices would have been even higher if not for the existence of a FERC-approved ceiling, which remained in effect for the December 2025 auction and which PJM has recently indicated it will seek to extend for two more auction cycles. In January 2026, the White House’s National Energy Dominance Council signed an agreement with the governors of all 13 states in the PJM region that memorializes a “statement of principles” intended to prompt PJM to make major changes to its capacity market, including running a “reliability backstop auction” to procure new generation capacity to provide 15-year “price certainty”. PJM has committed to run this backstop auction and is targeting a September 2026 date following FERC approval of all needed rule changes. There are outstanding questions associated with this auction, including whether the procurement costs will be disproportionately allocated to zones where demand exceeds supply. In addition, in 2025, FERC both issued an order that will encourage optionality for “large load” customers like data centers by facilitating co-location with generation, and initiated a rulemaking to establish definitive rules for future large customer connections intended to ensure reliability and address resource adequacy concerns. See Item 1. Business—Regulatory Issues—Federal Regulation.

As a result of the capacity market price increases, the costs of which are flowed through to customers, and per direction to EDCs from the BPU, PSE&G filed a petition in May 2025 that provided proposals to mitigate bill impacts to customers. In June 2025, the BPU approved a settlement under which PSE&G applied a credit to each residential electric customer’s monthly bill for July 2025 and August 2025, with the offset being charged on monthly bills for September 2025 through February 2026. PSE&G agreed to waive carrying costs on the outstanding credit amount. In addition, PSE&G agreed to: extend protections precluding the shut-off of eligible residential customers, normally available during the winter months, to the period from July 1, 2025 through September 30, 2025; offer residential customers deferred payment arrangements with terms of up to twenty-four months for the payment of overdue billed amounts; and waive all reconnection fees for residential customers during the period from July 1, 2025 through September 30, 2025. In September 2025, the New Jersey Legislature enacted a law prohibiting disconnection for non-payment during the period June 15 through August 31, beginning in 2026, and for such period annually thereafter, for certain qualified electric and gas customers. This new requirement for a summer shutoff moratorium and the extended deferred payment arrangements have increased our Accounts Receivable and bad debt expense in 2025 with potential additional increases in the future.

### Federal and State Executive Orders and State Legislative and Other Activity

There have been a number of federal executive orders during the past year, including but not limited to orders requiring retiring generating units to stay on-line beyond their retirement date to mitigate system reliability risk and orders imposing widespread and substantial tariffs on imports.

There has been increased New Jersey state legislative activity and executive orders regarding energy affordability, resource adequacy and regulatory topics.

We are continuing to monitor the federal and state legislative activity and executive orders, certain of which may require regulatory actions to implement, and their impacts on our supply chain, business, cash flow, results of operations and financial condition.

### Interest Rate Matters

PSEG’s long-term financing plan is designed to replace maturities and support funding its capital program. Given our financing needs, the prevailing interest rate environment will be a key factor in determining interest expense on variable-rate debt and long-term rates on future financing plans. In order to increase the predictability of interest expense, we may use interest rate hedges to help limit our exposure to fluctuating interest rates and fix a portion of our interest rate exposure for anticipated long-term financing plans at PSEG and PSEG Power. PSE&G’s interest rate risk is moderated due to annual transmission rate filings and distribution recoveries through periodic rate filings.

### Tax Legislation

The enactment, amendment or repeal of federal or state tax legislation and/or the clarification of previously enacted tax laws could have a material impact on our effective tax rate and cash tax position.

In August 2022, the IRA enacted a 15% corporate alternative minimum tax (CAMT), which is based on adjusted financial statement income, and established a PTC for existing qualified nuclear facilities. In February 2026, the U.S. Treasury issued Notice 2026-07 (CAMT Notice) which clarifies AFSI computation by allowing an adjustment to deduct certain repair and maintenance costs that are capitalized in the applicable financial statement. This CAMT Notice will result in a reduction to PSEG’s and PSE&G’s AFSI for CAMT purposes. However, aspects of the IRA provisions for CAMT and PTCs remain unclear; therefore, the issuance of future authoritative guidance could materially impact PSEG’s and PSE&G’s results of operations, financial condition and cash flows.

In April 2023, the U.S. Treasury issued Revenue Procedure 2023-15 that provides a Natural Gas Safe Harbor (NGSH) method of accounting to determine the annual repair tax deduction for gas T&D property. As a result of the CAMT Notice, PSE&G intends to adopt the NGSH method for its gas distribution assets in its 2025 Federal tax return, including a historical cumulative IRC Section 481(a) adjustment. While PSEG is still evaluating this guidance, it expects that the additional repair deductions will reduce our taxable income and AFSI, and will result in lower cash taxes.

In July 2025, “An Act to Provide for Reconciliation Pursuant to Title II of H. Con. Res. 14” (the Act) was signed into law. The Act made no material changes to the PTC for existing qualified nuclear generation facilities. The Act permanently extends 100% bonus depreciation to qualified business property retroactive to January 19, 2025. The impact of the Act on PSEG’s and PSE&G’s financial statements is subject to continued evaluation.

### Future Outlook

Our future success will be influenced by our ability to continue to maintain strong operational and financial performance, address regulatory and legislative developments that impact our business and respond to the issues and challenges described below. In order to do this, we will seek to:

- obtain approval of and execute on our utility capital investment program to meet increasing customer demand, modernize our infrastructure, improve the reliability and resilience of the service we provide to our customers, and align our sustainability and climate goals with New Jersey’s energy policy;
- obtain a fair return for our T&D investments through our transmission formula rate, existing rate incentives, distribution infrastructure and clean energy investment programs and periodic distribution base rate case proceedings;
- focus on controlling costs while maintaining safety, reliability and customer satisfaction and complying with applicable standards and requirements;
- manage the risks and opportunities in federal and state policies related to energy;
- advocate for appropriate regulatory guidance on the PTC to ensure long-term support for New Jersey’s largest carbon-free generation resource, and adapt our hedging program accordingly, and realize the value of our consistent and reliable, carbon-free nuclear output;
- engage constructively with our multiple stakeholders, including regulators, government officials, customers, employees, investors, suppliers and the communities in which we do business or are seeking to do business; and
- deliver on our human capital management strategy to attract, develop and retain a high-performing diverse workforce.

In addition to the risks described elsewhere in this Form 10-K for 2025 and beyond, the key issues and challenges we expect our business to confront include:

- regulatory and political uncertainty with regard to Federal and State energy and related policies, including transmission planning and rates policy, the role of distribution utilities and decarbonization impacts, design of energy and capacity markets, resource adequacy and affordability, tax regulation and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceedings;
- performance of the financial markets, including the impact on our pension funding requirements and interest rates on our future financing plans;
- continuing to manage costs and maintain affordable customer rates, which could impact customer collections, investment programs and have other impacts;
- the increasing frequency, sophistication and magnitude of cybersecurity attacks against us and our respective vendors and business partners who may have our sensitive information and/or access to our environment, and the increasing frequency and magnitude of physical attacks on electric and gas infrastructure;
- future changes in federal and state tax laws or any other associated tax guidance; and
- the impact of changes in energy demand, natural gas and electricity prices and PJM’s challenge to ensure resource adequacy to meet demand growth amidst efforts to decarbonize several sectors of the economy.

We continually assess a broad range of strategic options to maximize long-term shareholder value and address the interests of our multiple stakeholders. We consider a wide variety of factors when determining how and when to efficiently deploy capital, including the performance and prospects of our businesses; returns and the sustainability and predictability of future earnings streams; the views of investors, regulators, public policy initiatives, rating agencies, customers and employees; our existing indebtedness and restrictions it imposes; and tax considerations, among other things. Strategic options available to us include:

- investments in PSE&G, including T&D facilities to enhance reliability, resiliency and modernize the system to meet the growing needs and increasingly higher expectations of customers, and clean energy investments, particularly our EE programs;
- continued operation of our nuclear generation facilities that are expected to be supported by the PTC through 2032, nuclear capacity uprates, such as our planned Salem power uprate supported by a clean energy PTC, as well as obtaining license extensions and energy and/or emission credit sales with potential customers seeking consistent and reliable carbon-free power, as well as opportunities that may arise from our enabling of new nuclear projects, including providing services for these projects;
- investments in competitive, regulated transmission and the potential enabling of investments in generation through PJM processes and BPU solicitations that provide revenue predictability and reasonable risk-adjusted returns; and
- acquisitions, dispositions, development and other transactions involving our common stock, assets or businesses that could provide value to customers and shareholders.

There can be no assurance, however, that we will successfully develop and execute any of the strategic options noted above, or any additional options we may consider in the future. The execution of any such strategic plan may not have the expected benefits or may have unexpected adverse consequences.

### RESULTS OF OPERATIONS

*Millions, except per share data*

| Earnings | Years Ended December 31, 2025 | 2024 | 2023 |
| --- | ---: | ---: | ---: |
| PSE&G | $1,745 | $1,547 | $1,515 |
| PSEG Power & Other (A)(B) | 366 | 225 | 1,048 |
| **PSEG Net Income** | **$2,111** | **$1,772** | **$2,563** |
| **PSEG Net Income Per Share (Diluted)** | **$4.22** | **$3.54** | **$5.13** |

(A) PSEG Power & Other results in 2023 include a $239 million after-tax pension charge due to the settlement of a portion of the qualified pension plans.

(B) Other includes after-tax activities at the parent company, PSEG LI and Energy Holdings as well as intercompany eliminations.

PSEG Power’s results above include the Nuclear Decommissioning Trust (NDT) Fund activity and the impacts of non-trading commodity mark-to-market (MTM) activity, which consist of the financial impact from positions with future delivery dates.

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

|  | Years Ended December 31, 2025 Millions, after tax | 2024 | 2023 |
| --- | ---: | ---: | ---: |
| NDT Fund and Related Activity (A) (B) | $136 | $81 | $109 |
| Non-Trading MTM Gains (Losses) (C) | $(54) | $(151) | $959 |

(A) NDT Fund activity includes gains and losses on NDT securities which are recorded in Net Gains (Losses) on Trust Investments. See Item 8. Note 9. Trust Investments for additional information. NDT Fund activity also includes interest and dividend income and other costs related to the NDT Fund recorded in Net Other Income (Deductions), interest accretion expense on PSEG Power’s nuclear Asset Retirement Obligation (ARO) recorded in Operation & Maintenance (O&M) Expense and the depreciation related to the ARO asset recorded in Depreciation and Amortization (D&A) Expense.

(B) Net of tax (expense) benefit of $(87) million, $(56) million, and $(74) million for the years ended December 31, 2025, 2024 and 2023, respectively.

(C) Net of tax (expense) benefit of $21 million, $59 million, and $(376) million for the years ended December 31, 2025, 2024 and 2023, respectively.

Our increase in Net Income for 2025 as compared to 2024 was driven primarily by

- higher earnings as a result of the 2024 distribution base rate case settlement and continued investments in T&D clause programs at PSE&G and higher energy and capacity prices at PSEG Power, and
- changes in the NDT Fund and MTM gains (losses) as shown in the table above.

Our results of operations are primarily comprised of the results of operations of our principal operating segments, PSE&G and PSEG Power, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 8. Note 23. Related-Party Transactions.

### PSEG

|  | Years Ended December 31, 2025 Millions | 2024 | 2023 | Increase / (Decrease) 2025 vs. 2024 Millions% |  | Increase / (Decrease) 2024 vs. 2023 Millions% |  |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating Revenues | $12,168 | $10,290 | $11,237 | $1,878 | 18 | $(947) | (8) |
| Energy Costs | 4,159 | 3,393 | 3,260 | 766 | 23 | 133 | 4 |
| Operation and Maintenance (A) | 3,772 | 3,362 | 3,157 | 410 | 12 | 205 | 6 |
| Depreciation and Amortization | 1,257 | 1,182 | 1,135 | 75 | 6 | 47 | 4 |
| Net Gains (Losses) on Trust Investments | 189 | 127 | 189 | 62 | 49 | (62) | (33) |
| Net Other Income (Deductions) | 145 | 154 | 173 | (9) | (6) | (19) | (11) |
| Net Non-Operating Pension and OPEB (Costs) Credits | 65 | 73 | (218) | (8) | (11) | 291 | N/A |
| Interest Expense | 1,005 | 882 | 748 | 123 | 14 | 134 | 18 |
| Income Tax Expense | 263 | 53 | 518 | 210 | N/A | (465) | (90) |

(A) Includes amortization of EE programs regulatory investment expenditures of $169 million, $125 million and $82 million for the years ended December 31, 2025, 2024 and 2023, respectively.

The 2025, 2024 and 2023 amounts in the preceding table for Operating Revenues and O&M costs each include $644 million, $592 million and $533 million, respectively, for PSEG LI’s subsidiary, Long Island Electric Utility Servco, LLC (Servco). These amounts represent the O&M pass-through costs for the Long Island operations, the full reimbursement of which is reflected in Operating Revenues. See Item 8. Note 3. Variable Interest Entity for additional information. The following discussions for PSE&G and PSEG Power provide a detailed explanation of their respective variances.

### PSE&G

|  | Years Ended December 31, 2025 Millions | 2024 | 2023 | Increase / (Decrease) 2025 vs. 2024 Millions% |  | Increase / (Decrease) 2024 vs. 2023 Millions% |  |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating Revenues | $9,558 | $8,449 | $7,807 | $1,109 | 13 | $642 | 8 |
| Energy Costs | 3,782 | 3,189 | 3,010 | 593 | 19 | 179 | 6 |
| Operation and Maintenance (A) | 2,253 | 1,949 | 1,843 | 304 | 16 | 106 | 6 |
| Depreciation and Amortization | 1,116 | 1,025 | 980 | 91 | 9 | 45 | 5 |
| Net Other Income (Deductions) | 64 | 64 | 80 | — | — | (16) | (20) |
| Net Non-Operating Pension and OPEB Credits | 70 | 77 | 114 | (7) | (9) | (37) | (32) |
| Interest Expense | 644 | 582 | 493 | 62 | 11 | 89 | 18 |
| Income Tax Expense | 152 | 298 | 160 | (146) | (49) | 138 | 86 |

(A) Includes amortization of EE programs regulatory investment expenditures of $169 million, $125 million and $82 million for the years ended December 31, 2025, 2024 and 2023, respectively.

### Year Ended December 31, 2025 as compared to 2024

**Operating Revenues** increased $1,109 million due to changes in delivery, clause, commodity and other operating revenues.

***Delivery Revenues*** are primarily derived from revenues recovered on our regulated investments in rate base and costs through periodic filings of distribution rate cases, approved distribution investment recovery programs and the annual filing of transmission formula rates. Due to PSE&G’s electric and gas distribution CIP decoupling mechanism, there is minimal impact from sales volumes on most distribution delivery revenues. Also included in delivery revenues are revenue credits to customers to flowback tax benefits realized by PSE&G. These revenue credits are offset in Income Tax Expense.

Delivery revenues increased $584 million due primarily to $577 million from increased electric and gas revenues primarily as a result of the 2024 distribution base rate case, $87 million from higher GPRC revenues and a $44 million increase in transmission revenues due primarily to higher rate base investments, offset primarily by a $146 million increase in revenue credits flowed back to customers as part of our TAC mechanism.

***Clause Revenues*** are revenues from various pass through regulatory programs for which PSE&G earns no margin. These revenues are entirely offset by the amortization of related costs in O&M, D&A and Interest and Income Tax Expense, which were originally recognized as regulatory assets.

Clause Revenues decreased $94 million due primarily to a $186 million decrease in Tax Adjustment Credits (TAC) and Green Program Recovery Charge (GPRC) deferrals, offset by $91 million in higher Societal Benefits Clause (SBC) collections.

***Commodity Revenues*** are revenues from customers choosing default electric (basic generation service or BGS) and gas supply (basic gas supply service or BGSS) from PSE&G. PSE&G procures the BGS and BGSS on behalf of these retail customers and earns no margin on this service as all costs are passed back to the BGS and BGSS customers. The changes in Commodity Revenues for both electric and gas are entirely offset by changes in Energy Costs.

Commodity Revenues increased $706 million due to higher electric BGS revenues of $575 million primarily from higher prices, and higher gas BGSS revenues of $131 million primarily from higher sales volumes.

***Other Operating Revenues*** are primarily comprised of revenues derived from various GPRC programs including Transition Renewable Energy Certificates (TREC) revenues, Community Solar collections and the Successor Solar Incentive Program (SuSI) and ZECs. The revenues from these programs offset costs included in Energy Costs. In addition, other operating revenues include revenues from our Appliance Service Business (ASB) which offers various appliance protection and repair plans to customers.

Other Operating revenues decreased $87 million due primarily to a decrease in ZECs as a result of the ZEC collection ending effective May 31, 2025.

### Operating Expenses

**Energy Costs** increased $593 million. This is offset by changes in Commodity Revenues and Other Operating Revenues.

**Operation and Maintenance** increased $304 million due primarily to $178 million in higher clause and renewable expenditures, $72 million in higher distribution and transmission operational expenditures and $49 million in higher other operating and service company expenses.

**Depreciation and Amortization** increased $91 million due primarily to an increase in depreciation due to higher plant placed in service and increases in the amortization of software and Regulatory Assets and Liabilities.

**Net Non-Operating Pension and OPEB Credits** decreased $7 million due primarily to a decrease in the expected return on plan assets.

**Interest Expense** increased $62 million due primarily to incremental debt and the replacement of maturing debt at higher rates.

**Income Tax Expense** decreased $146 million primarily due to an increase in the flowback of excess deferred income tax benefits to customers, partially offset by higher pre-tax income.

### Year Ended December 31, 2024 as compared to 2023

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2024 as filed with the SEC on February 25, 2025 for information related to the year ended December 31, 2024 as compared to 2023, which information is incorporated herein by reference.

### PSEG Power & Other

|  | Years Ended December 31, 2025 Millions | 2024 | 2023 | Increase / (Decrease) 2025 vs. 2024 Millions% |  | Increase / (Decrease) 2024 vs. 2023 Millions% |  |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating Revenues | $3,722 | $2,807 | $4,533 | $915 | 33 | $(1,726) | (38) |
| Energy Costs | 1,489 | 1,170 | 1,353 | 319 | 27 | (183) | (14) |
| Operation and Maintenance | 1,519 | 1,413 | 1,314 | 106 | 8 | 99 | 8 |
| Depreciation and Amortization | 141 | 157 | 155 | (16) | (10) | 2 | 1 |
| Net Gains (Losses) on Trust Investments | 189 | 127 | 189 | 62 | 49 | (62) | (33) |
| Net Other Income (Deductions) | 84 | 95 | 97 | (11) | (12) | (2) | (2) |
| Net Non-Operating Pension and OPEB Costs | 5 | 4 | 332 | 1 | 25 | (328) | (99) |
| Interest Expense | 364 | 305 | 259 | 59 | 19 | 46 | 18 |
| Income Tax Expense (Benefit) | 111 | (245) | 358 | 356 | N/A | (603) | N/A |

### Year Ended December 31, 2025 as compared to 2024

**Operating Revenues** increased $915 million due primarily to changes in generation and gas supply and other operating revenues.

***Generation Revenues*** increased $493 million due primarily to

- a net increase of $192 million due primarily to higher average realized energy prices and volumes sold in 2025,
- a net increase of $153 million in capacity revenue due primarily to higher capacity prices, and
- a net increase of $120 million due to lower MTM losses in 2025 as compared to 2024. Of this amount, there was a $101 million increase due to positions reclassified to realized upon settlement, coupled with a $19 million increase due to changes in forward prices in 2025 as compared to 2024.

***Gas Supply Revenues*** increased $362 million due primarily to

- a net increase of $246 million in sales under the BGSS contract due primarily to $126 million from higher sales prices, and $120 million from higher sales volumes,
- a net increase of $97 million related to sales to third parties due primarily to $112 million from higher sales prices, partially offset by $15 million from lower sales volumes, and
- a net increase of $19 million due primarily to MTM gains in 2025 as compared to MTM losses in 2024, primarily from positions reclassified to realized upon settlement.

### Operating Expenses

**Energy Costs** represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet PSEG Power’s obligation under its BGSS contract with PSE&G. Energy Costs increased $319 million due to

***Gas costs*** increased $313 million due primarily to

- a net increase of $231 million related to sales under the BGSS contract, of which $133 million was due to higher average prices, and $98 million was due to higher send out volumes, and
- a net increase of $78 million related to sales to third parties due primarily to $81 million from higher average prices.

***Generation costs*** increased $6 million due primarily to increased fuel costs at nuclear.

**Operation and Maintenance** increased $106 million due primarily to higher Servco operating costs, and increased planned refueling outage costs in 2025.

**Depreciation and Amortization** decreased $16 million due primarily to revised estimated useful lives in April 2025 for the Salem and Hope Creek nuclear plants based on the expectation that a 20-year license extension will be approved for these facilities.

**Net Gains (Losses) on Trust Investments** increased $62 million due primarily to NDT investments with a $59 million increase in net unrealized gains in 2025 on equity securities, and a $4 million increase in net realized gains in 2025.

**Net Other Income (Deductions)** decreased $11 million due primarily to an increase in donations, partially offset by higher NDT dividend income.

**Interest Expense** increased $59 million due primarily to incremental debt and the replacement of maturing long-term debt at higher rates.

**Income Tax Expense (Benefit)** variance of $356 million due primarily to the absence of the benefit from nuclear PTCs in 2025 and higher pre-tax income.

### Year Ended December 31, 2024 as compared to 2023

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2024 as filed with the SEC on February 25, 2025 for information related to the year ended December 31, 2024 as compared to 2023, which information is incorporated herein by reference.

### LIQUIDITY AND CAPITAL RESOURCES

The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our two direct major operating subsidiaries.

### Financing Methodology

We expect our capital requirements to be met through internally generated cash flows and external financings, consisting of short-term debt for working capital needs and long-term debt for capital investments.

PSE&G’s sources of external liquidity include a $1 billion multi-year revolving credit facility. PSE&G uses internally generated cash flow and its commercial paper program to meet seasonal, intra-month and temporary working capital needs. PSE&G does not engage in any intercompany borrowing or lending arrangements. PSE&G maintains a back-up credit facility in an amount sufficient to cover the commercial paper and letters of credit outstanding. PSE&G’s dividend payments to/capital contributions from PSEG are consistent with its capital structure objectives which have been established to maintain investment grade credit ratings. PSE&G’s long-term financing plan is designed to replace maturities, fund a portion of its capital program and manage short-term debt balances. Generally, PSE&G uses either secured medium-term notes or first mortgage bonds to raise long-term capital.

PSEG, PSEG Power, Energy Holdings, PSEG LI and Services participate in a corporate money pool, an aggregation of daily cash balances designed to efficiently manage their respective short-term liquidity needs, which are accounted for as intercompany loans. Servco does not participate in the corporate money pool. Servco’s short-term liquidity needs are met through an account funded and owned by LIPA.

PSEG and PSEG Power have access through sub-limits to a revolving Master Credit Facility, which provides for $2.75 billion of multi-year credit capacity. The current PSEG sub-limit is $1.5 billion and current PSEG Power sub-limit is $1.25 billion. Sub-limits can be adjusted subject to the terms of the Master Credit Facility.

PSEG’s available sources of external liquidity may include the issuance of long-term debt securities and the incurrence of additional indebtedness through our commercial paper program back-stopped by our credit facility. Our current sources of external liquidity include the Master Credit Facility. This facility is available to back-stop PSEG’s commercial paper program, issue letters of credit and for general corporate purposes. PSEG’s Master Credit Facility and the commercial paper program are available to support PSEG’s working capital needs and are also available to make equity contributions or provide liquidity support to its subsidiaries. Additionally, from time to time, PSEG enters into short-term loan agreements designed to enhance its liquidity position.

PSEG Power’s sources of external liquidity include the Master Credit Facility and PSEG Power’s letter of credit facilities and may include the issuance of long-term debt securities and entering into short-term loan agreements. Credit capacity is primarily used to provide collateral in support of PSEG Power’s sales and purchases of electricity and natural gas as the market prices for energy and fuel fluctuate, and to meet potential collateral postings in the event that PSEG Power is downgraded to below investment grade by Standard & Poor’s (S&P) or Moody’s. PSEG Power’s dividend payments to PSEG are also designed to be consistent with its capital structure objectives which have been established to maintain investment grade credit ratings and provide sufficient financial flexibility.

### Operating Cash Flows

We continue to expect our operating cash flows combined with cash on hand and financing activities to be sufficient to fund planned capital expenditures and shareholder dividends.

For the year ended December 31, 2025, our operating cash flow increased $1,165 million, as compared to 2024. The net increase was primarily due to a net change at PSE&G, as discussed below, combined with an inflow of $22 million in net cash collateral postings in 2025 as compared to a $131 million outflow in 2024 at PSEG Power, and an $89 million decrease in payments to counterparties at PSEG Power.

### PSE&G

PSE&G’s operating cash flow increased $643 million from $1,725 million to $2,368 million for the year ended December 31, 2025, as compared to 2024. The increase was due primarily to a decrease in net regulatory deferrals, a decrease in materials and supplies inventory, lower tax payments, and the timing of vendor payments, partially offset by an increase in accounts receivable.

### Short-Term Liquidity

PSEG meets its short-term liquidity requirements, as well as those of PSEG Power, primarily through the issuance of commercial paper and, from time to time, short-term loans. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facility.

Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs.

In March 2025, PSEG, PSEG Power and PSE&G executed a one year extension to their existing $3.75 billion revolving credit facilities, extending the maturity through March 2029 and PSEG Power amended certain provisions in the Master Credit Facility including removal of subsidiary guarantees of PSEG Power. The PSEG Power letter of credit facilities and term loans were also amended to be consistent with the Master Credit Facility, and the $150 million uncommitted credit facility at a subsidiary of PSEG Power was terminated.

In December 2025, PSEG Power amended its existing $400 million 364-day variable rate term loan, which increased the balance to $500 million and extended the maturity to December 2026.

In February 2026, PSEG entered into a 364-day variable rate term loan agreement for $500 million.

PSEG Power has uncommitted credit facilities totaling $425 million, which can be utilized for letters of credit. As of December 31, 2025, PSEG Power had $243 million in letters of credit outstanding under these uncommitted credit facilities.

PSE&G has an uncommitted credit facility totaling $30 million, which can be utilized for letters of credit. As of December 31, 2025, PSE&G's letters of credit outstanding were immaterial under this uncommitted credit facility.

Our total committed credit facilities and available liquidity as of December 31, 2025 were as follows:

| Company/Facility | As of December 31, 2025 Total Facility Millions | Usage | Available Liquidity |
| --- | ---: | ---: | ---: |
| PSEG | $1,500 | $719 | $781 |
| PSE&G | 1,000 | 351 | 649 |
| PSEG Power | 1,325 | 82 | 1,243 |
| **Total** | **$3,825** | **$1,152** | **$2,673** |

For additional information, see Item 8. Note 13. Debt and Credit Facilities.

We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements, including to satisfy any additional collateral requirements. As of December 31, 2025, our liquidity position, including our credit facilities and access to external financing, was expected to be sufficient to meet our projected stressed requirements over our 12-month planning horizon. PSEG analyzes its liquidity requirements using stress scenarios that consider different events, including changes in commodity prices and the potential impact of PSEG Power losing its investment grade credit rating from S&P or Moody’s, which would represent a two-level downgrade from its current Moody’s and S&P ratings. In the event of a deterioration of PSEG Power’s credit rating, certain of PSEG Power’s agreements allow the counterparty to demand further performance assurance. The potential additional collateral that we would be required to post under these agreements if PSEG Power were to lose its investment grade credit rating was approximately $703 million and $618 million as of December 31, 2025 and 2024, respectively. See Item 8. Note 12. Commitments and Contingent Liabilities for additional discussion of PSEG Power’s agreements.

### Long-Term Debt Financing

During the next twelve months,

- PSE&G has $450 million of 0.95% Secured Medium-Term Notes Series N, due March 2026, and
- PSE&G has $425 million of 2.25% Secured Medium-Term Notes Series L, due September 2026.

For additional information, see Item 8. Note 13. Debt and Credit Facilities.

### Debt Covenants

Our credit agreements contain maximum debt to equity ratios and other restrictive covenants and conditions to borrowing. We are currently in compliance with all of our debt covenants. Continued compliance with applicable financial covenants will depend upon our future financial position, level of earnings and cash flows, as to which no assurances can be given.

In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As of December 31, 2025, PSE&G’s Mortgage coverage ratio was 3.9 to 1 and the Mortgage would permit up to approximately $10.2 billion aggregate principal amount of new Mortgage Bonds to be issued against additions and improvements to its property.

### Default Provisions

Our bank credit agreements and indentures contain various, customary default provisions that could result in the potential acceleration of indebtedness under the defaulting company’s agreement.

In particular, PSEG’s bank credit agreement contains provisions under which certain events, including an acceleration of material indebtedness under PSE&G’s and PSEG Power’s respective financing agreements, a failure by PSEG, PSE&G or PSEG Power to satisfy certain final judgments and certain bankruptcy events by PSEG, PSE&G or PSEG Power, would constitute an event of default under the PSEG bank credit agreements. Under the PSEG bank credit agreements, it would also be an event of default if, in certain circumstances, either PSE&G or PSEG Power ceases to be wholly owned by PSEG. The PSE&G and PSEG Power bank credit agreements include certain similar default provisions; however, such provisions only relate to the respective borrower under such agreement and its subsidiaries and do not contain cross default provisions to each other. The PSE&G and PSEG Power bank credit agreements do not include cross default provisions relating to PSEG. Each of PSEG's, PSE&G’s and PSEG Power’s bank credit agreements also contain limitations on the incurrence of liens by it and certain of its subsidiaries and PSEG Power’s bank credit agreements contain restrictions on the incurrence of certain subsidiary debt.

PSEG’s senior notes include a cross acceleration provision that may be triggered upon the acceleration of more than $75 million of indebtedness incurred by PSEG. Such provision does not extend to an acceleration of indebtedness by any of PSEG’s subsidiaries. PSEG Power’s senior notes contain a similar provision with respect to the acceleration of more than $75 million of indebtedness incurred by PSEG Power but such provision does not extend to an acceleration of indebtedness by any of PSEG Power’s subsidiaries. Under PSE&G’s medium-term note indenture, an event of default under PSE&G’s mortgage indenture and acceleration of the mortgage bonds would constitute an event of default.

### Ratings Triggers

Our debt indentures and credit agreements do not contain any material “ratings triggers” that would cause an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a downgrade, any one or more of the affected companies may be subject to increased interest costs on certain bank debt and certain collateral requirements. In the event that we are not able to affirm representations and warranties on credit agreements, lenders would not be required to make loans.

In accordance with BPU requirements under the BGS contracts, PSE&G is required to maintain an investment grade credit rating. If PSE&G were to lose its investment grade rating, it would be required to file a plan to assure continued payment for the BGS requirements of its customers.

Fluctuations in commodity prices or a deterioration of PSEG Power’s credit rating to below investment grade could increase PSEG Power’s required margin postings under various agreements entered into in the normal course of business. PSEG Power believes it has sufficient liquidity to meet the required posting of collateral which would result from a credit rating downgrade to below investment grade by S&P or Moody’s at today’s market prices.

### Common Stock Dividends

| Dividend Payments on Common Stock | Years Ended December 31, 2025 | 2024 | 2023 |
| --- | ---: | ---: | ---: |
| Per Share | $2.52 | $2.40 | $2.28 |
| in Millions | $1,258 | $1,196 | $1,137 |

On February 24, 2026, our Board of Directors approved a $0.67 per share common stock dividend for the first quarter of 2026. This reflects an indicative annual dividend rate of $2.68 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. For additional information related to cash dividends on our common stock, see Item 8. Note 21. Earnings Per Share (EPS) and Dividends.

### Credit Ratings

If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Credit ratings shown are for securities that we typically issue. Outlooks are shown for the credit ratings at each entity and can be Stable, Negative, or Positive. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.

|  | Moody’s (A) | S&P (B) |
| --- | --- | --- |
| **PSEG** |  |  |
| Outlook | **Stable** | **Stable** |
| Senior Notes | Baa2 | BBB |
| Commercial Paper | P2 | A2 |
| **PSE&G** |  |  |
| Outlook | **Stable** | **Stable** |
| Mortgage Bonds | A1 | A |
| Commercial Paper | P2 | A2 |
| **PSEG Power** |  |  |
| Outlook | **Stable** | **Stable** |
| Senior Notes | Baa2 | BBB |

(A) Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.

(B) S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.

### Other Comprehensive Income

For the year ended December 31, 2025, we had Other Comprehensive Income of $42 million on a consolidated basis. The Other Comprehensive Income was due primarily to $34 million of net unrealized gains related to available-for-sale debt securities, $20 million related to pension and other postretirement benefits, partially offset by $12 million of unrealized losses on derivative contracts accounted for as hedges. See Item 8. Note 20. Accumulated Other Comprehensive Income (Loss), Net of Tax for additional information.

### CAPITAL REQUIREMENTS

We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. Projected capital construction and investment expenditures, excluding nuclear fuel purchases, for the next three years are presented in the following table. These projections include Allowance for Funds Used During Construction for PSE&G and Interest Capitalized During Construction for PSEG’s other subsidiaries. These amounts are subject to change, based on various factors. Amounts shown below for PSE&G include currently approved programs. We intend to continue to invest in infrastructure modernization and will seek to extend these and related programs as appropriate.

| PSE&G: | 2026 | 2027 Millions | 2028 |
| --- | ---: | ---: | ---: |
| Transmission | $835 | $950 | $975 |
| Electric Distribution | 1,410 | 1,440 | 1,520 |
| Gas Distribution | 1,130 | 1,115 | 1,165 |
| Clean Energy | 810 | 885 | 700 |
| **Total PSE&G** | **$4,185** | **$4,390** | **$4,360** |
| Competitively Bid, FERC Regulated Transmission | 20 | 115 | 195 |
| PSEG Power & Other | 435 | 330 | 275 |
| **Total PSEG** | **$4,640** | **$4,835** | **$4,830** |

57

### PSE&G

PSE&G’s projections for future capital expenditures include material additions and replacements to its T&D systems to meet expected growth and to manage reliability. As project scope and cost estimates develop, PSE&G will modify its current projections to include these required investments. PSE&G’s projected expenditures for the various items reported above are primarily comprised of the following:

- Transmission—investments focused on growing demand, reliability improvements and replacement of aging infrastructure.
- Electric and Gas Distribution—investments for new business and demand, reliability improvements and modernization and replacement of equipment that has reached the end of its useful life.
- Clean Energy—investments associated with customer EE programs, infrastructure supporting EVs and grid-connected solar.

In 2025, PSE&G made $2,731 million of capital expenditures, primarily for T&D system reliability. In addition, PSE&G had $145 million associated with CEF-EE II on-bill repayments included in investing cash flows, as well as cost of removal, net of salvage, of $156 million associated with capital replacements, and expenditures for EE programs of approximately $552 million, which are included in operating cash flows.

### Competitively Bid, FERC Regulated Transmission

In December 2023, PJM awarded us an approximately $424 million project to address increasing load and reliability issues in Maryland and northern Virginia as part of its 2022 Window 3 competitive solicitation.

### PSEG Power & Other

PSEG’s other projected expenditures are primarily comprised of investments to maintain and enhance current nuclear operations and opportunities to increase nuclear generation at PSEG Power and to purchase hardware, software and office equipment at Services.

In 2025, PSEG Power & Other made capital expenditures of $236 million, excluding $336 million for nuclear fuel, primarily related to various nuclear projects at PSEG Power and various IT projects at Services.

### Other Material Cash Requirements

The following table reflects our other material cash requirements which include debt maturities and interest payments, operating lease payments and energy related purchase commitments in the respective periods in which they are due. For additional information, see Item 8. Note 13. Debt and Credit Facilities and Note 6. Leases.

The table below does not reflect any anticipated cash payments for pension and OPEB or AROs due to uncertain timing of payments. See Item 8. Note 11. Pension, Other Postretirement Benefits (OPEB) and Savings Plans and Note 10. Asset Retirement Obligations (AROs) for additional information.

| Long-Term Recourse Debt Maturities | Total Amount Committed Millions | Less Than 1 Year | 2 - 3 Years | 4 - 5 Years | Over 5 Years |
| --- | ---: | ---: | ---: | ---: | ---: |
| PSEG | $5,346 | $— | $1,300 | $1,900 | $2,146 |
| PSE&G | 16,115 | 875 | 1,125 | 675 | 13,440 |
| PSEG Power | 1,250 | — | — | 750 | 500 |
| **Interest on Recourse Debt** |  |  |  |  |  |
| PSEG | 1,385 | 253 | 466 | 296 | 370 |
| PSE&G | 10,318 | 653 | 1,256 | 1,183 | 7,226 |
| PSEG Power (A) | 449 | 68 | 136 | 116 | 129 |
| **Operating Leases** |  |  |  |  |  |
| PSE&G | 103 | 18 | 26 | 20 | 39 |
| PSEG Power & Other | 76 | 16 | 32 | 28 | — |
| **Energy-Related Purchase Commitments** |  |  |  |  |  |
| PSEG Power (B) | 3,049 | 861 | 997 | 489 | 702 |
| **Total** | **$38,091** | **$2,744** | **$5,338** | **$5,457** | **$24,552** |

(A) Based on a blended rate including effects of floating to fixed rate hedging transacted at the Parent level.

(B) Represents the nuclear fuel and natural gas commitments for the facilities we operate.

### CRITICAL ACCOUNTING ESTIMATES

Under accounting guidance generally accepted in the United States (GAAP), many accounting standards require the use of estimates, variable inputs and assumptions (collectively referred to as estimates) that are subjective in nature. Because of this, differences between the actual measure realized versus the estimate can have a material impact on results of operations, financial position and cash flows. We have determined that the following estimates are considered critical to the application of rules that relate to the respective businesses.

### Accounting for Pensions and Other Postretirement Benefits (OPEB)

The market-related value of plan assets held for PSEG’s qualified pension and OPEB plans is equal to the fair value of these assets as of year-end. The plan assets are comprised of investments in both debt and equity securities which are valued using quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Plan assets also include investments in unlisted real estate which is valued via third-party appraisals. We calculate pension and OPEB costs using various economic and demographic assumptions.

***Assumptions and Approach Used:*** Economic assumptions include the discount rate and the expected rate of return on plan assets. Demographic pension and OPEB assumptions include projections of future mortality rates, pay increases and retirement patterns, as well as projected health care costs for OPEB.

| Assumption Qualified Pension | 2025 | 2024 | 2023 |
| --- | ---: | ---: | ---: |
| Discount Rate | 5.50% | 5.68% | 5.02% |
| Expected Rate of Return on Plan Assets | 8.10% | 8.10% | 8.10% |
| **OPEB** |  |  |  |
| Discount Rate | 5.31% | 5.59% | 4.96% |
| Expected Rate of Return on Plan Assets | 8.10% | 8.10% | 8.10% |

59

The discount rate used to calculate PSEG’s pension and OPEB obligations is determined as of December 31 each year, our measurement date. The discount rate is determined by developing a spot rate curve based on the yield to maturity of a universe of high quality corporate bonds with similar maturities to the plan obligations. The spot rates are used to discount the estimated plan distributions. The discount rate is the single equivalent rate that produces the same result as the full spot rate curve.

Our expected rate of return on plan assets reflects current asset allocations, historical long-term investment performance and an estimate of future long-term returns by asset class, long-term inflation assumptions and a premium for active management.

We utilize a corridor approach that reduces the volatility of reported costs/credits. The corridor requires differences between actuarial assumptions and plan results be deferred and amortized as part of the costs/credits. Amortization occurs only when the accumulated differences exceed 10% of the greater of the benefit obligation or the fair value of plan assets as of each year-end. For PSEG’s qualified pension plan, the excess would be amortized over the average remaining service period of active employees, which is approximately fifteen years.

***Effect if Different Assumptions Used***: As part of the business planning process, we have modeled future costs assuming an 8.00% expected rate of return and a 5.50% discount rate for 2026 pension costs/credits and a 5.31% discount rate for 2026 OPEB costs/credits. Based upon these assumptions, we have estimated a net periodic pension expense in 2026 of approximately $27 million, or pension income of $10 million, net of amounts capitalized, and net periodic OPEB income in 2026 of approximately $8 million, or $8 million, net of amounts capitalized. Beginning in 2023, our net periodic pension amounts include the impact of the accounting order approved by the BPU authorizing PSE&G to modify its pension accounting for ratemaking purposes. Actual future pension costs/credits and funding levels will depend on future investment performance, changes in discount rates, market conditions, funding levels relative to our projected benefit obligation and accumulated benefit obligation and various other factors related to the populations participating in the pension plans. Actual future OPEB costs/credits will depend on future investment performance, changes in discount rates, market conditions, and various other factors.

The following chart reflects the sensitivities associated with a change in certain assumptions.

| Assumption Qualified Pension | % Change | Impact on Benefit Obligation as of December 31, 2025 Millions | Increase to Costs in 2026 | Increase to Costs, net of Amounts Capitalized in 2026 |
| --- | ---: | ---: | ---: | ---: |
| Discount Rate | (1)% | $458 | $19 | $13 |
| Expected Rate of Return on Plan Assets | (1)% | N/A | $41 | $41 |
| **OPEB** |  |  |  |  |
| Discount Rate | (1)% | $58 | $(1) | $(1) |
| Expected Rate of Return on Plan Assets | (1)% | N/A | $4 | $4 |

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

### Derivative Instruments

The operations of PSEG, PSEG Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through executing derivative transactions. Derivative instruments are used to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.

Current accounting guidance requires us to recognize all derivatives on the balance sheet at their fair value, except for derivatives that qualify for and are designated as normal purchases and normal sales contracts.

***Assumptions and Approach Used:*** In general, the fair value of our derivative instruments is determined primarily by end of day clearing market prices from an exchange, such as the Intercontinental Exchange and Nodal Exchange, among others, or auction prices.

For our wholesale energy business, many of the forward sale, forward purchase, option and other contracts are derivative instruments that hedge commodity price risk, but do not meet the requirements for, or are not designated as, either cash flow or fair value hedge accounting. The changes in value of such derivative contracts are marked to market through earnings as the related commodity prices fluctuate. As a result, our earnings may experience significant fluctuations depending on the volatility of commodity prices.

***Effect if Different Assumptions Used:*** Any significant changes to the fair market values of our derivatives instruments could result in a material change in the value of the assets or liabilities recorded on our Consolidated Balance Sheets and could result in a material change to the unrealized gains or losses recorded in our Consolidated Statements of Operations.

For additional information regarding Derivative Financial Instruments, see Item 8. Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies, Note 15. Financial Risk Management Activities and Note 16. Fair Value Measurements.

### Long-Lived Assets

Management evaluates long-lived assets for impairment and reassesses the reasonableness of their related estimated useful lives whenever events or changes in circumstances warrant assessment. Such events or changes in circumstances may be as a result of significant adverse changes in regulation, business climate, counterparty credit worthiness, market conditions, or a determination that it is more-likely-than-not that an asset or asset group will be sold or retired before the end of its estimated useful life.

***Assumptions and Approach Used:*** In the event certain triggers exist indicating an asset/asset group may not be recoverable, an undiscounted cash flow test is performed to determine if an impairment exists. When the carrying value of a long-lived asset/asset group exceeds the undiscounted estimate of future cash flows associated with the asset/asset group, an impairment may exist to the extent that the fair value of the asset/asset group is less than its carrying amount.

For PSEG Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the nuclear generation units are evaluated at the portfolio level. These tests require significant estimates and judgment when developing expected future cash flows. Significant inputs may include, but are not limited to, forward power prices, the impact of PTCs, fuel costs, other operating and capital expenditures, the cost of borrowing and asset sale prices and probabilities associated with any potential sale prior to the end of the estimated useful life or the early retirement of assets. The assumptions used by management incorporate inherent uncertainties that are at times difficult to predict and could result in impairment charges or accelerated depreciation in future periods if actual results materially differ from the estimated assumptions utilized in our forecasts.

In addition, long-lived assets are depreciated under the straight-line method based on estimated useful lives. An asset’s operating useful life is generally based upon operational experience with similar asset types and other non-operational factors. In the ordinary course, management, together with an asset’s co-owners in the case of certain of our jointly-owned assets, make a number of decisions that impact the operation of our generation assets beyond the current year. These decisions may have a direct impact on the estimated remaining useful lives of our assets and will be influenced by the financial outlook of the assets, including future market conditions such as forward energy, capacity prices, and long-term agreements to supply large power users, such as data centers, operating and capital investment costs and any state or federal legislation and regulations, among other items.

***Effect if Different Assumptions Used:*** The above cash flow tests, and fair value estimates and estimated remaining useful lives may be impacted by a change in the assumptions noted above and could significantly impact the outcome, triggering additional impairment tests, write-offs or accelerated depreciation.

### Asset Retirement Obligations (ARO)

PSE&G, PSEG Power and Services recognize liabilities for the expected cost of retiring long-lived assets for which a legal obligation exists. These AROs are recorded at fair value in the period in which they are incurred and are capitalized as part of the carrying amount of the related long-lived assets. PSE&G, as a rate-regulated entity, recognizes Regulatory Assets or Liabilities as a result of timing differences between the recording of costs and costs recovered through the rate-making process. We accrete the ARO liability to reflect the passage of time with the corresponding expense recorded in O&M Expense.

***Assumptions and Approach Used:*** Because quoted market prices are not available for AROs, we estimate the initial fair value of an ARO by calculating discounted cash flows that are dependent upon various assumptions, including:

- estimation of dates for retirement, which can be dependent on environmental and other legislation,
- amounts and timing of future cash expenditures associated with retirement, settlement or remediation activities,
- discount rates,
- cost escalation rates,
- market risk premium,
- inflation rates, and
- if applicable, past experience with government regulators regarding similar obligations.

We obtain updated nuclear decommissioning cost studies triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2024. When we revise any assumptions used to calculate fair values of existing AROs, we adjust the ARO balance and corresponding long-lived asset which generally impacts the amount of accretion and depreciation expense recognized in future periods.

### Nuclear Decommissioning AROs

AROs related to the future decommissioning of PSEG Power’s nuclear facilities comprised nearly 100% or $916 million of PSEG Power’s total AROs as of December 31, 2025. PSEG Power determines its AROs for its nuclear units by assigning probability weighting to various discounted cash flow outcomes for each of its nuclear units that incorporate the assumptions above as well as:

- potential retirement dates including the probability of license renewals,
- SAFSTOR alternative, which assumes the nuclear facility can be safely stored and subsequently decommissioned in a period within 60 years after operations,
- DECON alternative, which assumes decommissioning activities begin after operations, and
- recovery from the federal government of assumed specific costs incurred for spent nuclear fuel.

***Effect if Different Assumptions Used:*** Changes in the assumptions could result in a material change in the ARO balance sheet obligation and the period over which we accrete to the ultimate liability. Had the following assumptions been applied, our estimates of the approximate impacts on the Nuclear ARO as of December 31, 2025 are as follows:

- A decrease of 1% in the discount rate would result in a $61 million increase in the Nuclear ARO.
- An increase of 1% in the inflation rate would result in a $360 million increase in the Nuclear ARO.
- If we were not reimbursed by the federal government for the spent costs, as prescribed under the Nuclear Waste Policy Act, the Nuclear ARO would increase by $94 million.

### Accounting for Regulated Businesses

PSE&G prepares its financial statements to comply with GAAP for rate-regulated enterprises, which differs in some respects from accounting for non-regulated businesses. In general, accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (Regulatory Asset)

or recognize obligations (Regulatory Liability) if the rates established are designed to recover the costs and if the competitive environment makes it probable that such rates can be charged or collected. This accounting results in the recognition of revenues and expenses in different time periods than that of enterprises that are not regulated.

***Assumptions and Approach Used:*** PSE&G recognizes Regulatory Assets where it is probable that such costs will be recoverable in future rates from customers and Regulatory Liabilities where it is probable that refunds will be made to customers in future billings. The highest degree of probability is an order from the BPU either approving recovery of the deferred costs over a future period or requiring the refund of a liability over a future period.

Virtually all of PSE&G’s Regulatory Assets and Regulatory Liabilities are supported by BPU orders. In the absence of an order, PSE&G will consider the following when determining whether to record a Regulatory Asset or Liability:

- past experience regarding similar items with the BPU,
- treatment of a similar item in an order by the BPU for another utility,
- passage of new legislation, and
- recent discussions with the BPU.

All deferred costs are subject to prudence reviews by the BPU. When the recovery of a Regulatory Asset or payment of a Regulatory Liability is no longer probable, PSE&G charges or credits earnings, as appropriate.

***Effect if Different Assumptions Used:*** A change in the above assumptions may result in a material impact on our results of operations or our cash flows. See Item 8. Note 5. Regulatory Assets and Liabilities for a description of the amounts and nature of regulatory balance sheet amounts.

### Uncertain Tax Positions - Nuclear Production Tax Credits (PTCs)

We are required to make judgments in developing our provision for income tax expense (benefit), including those related to the uncertainty of tax positions taken, or expected to be taken, on a tax return. Our most significant uncertain tax position relates to the estimated benefit associated with PTCs.

***Assumptions and Approach Used:*** We account for uncertain income tax positions using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold.

Management uses judgments in determining the amount of income tax benefit to recognize due to the uncertainties associated with the technical merits of each position and with consideration to the amount of benefit to be sustained upon examination by a taxing authority. The estimated PTC benefits are subject to change based on the issuance of authoritative guidance by the U.S. Treasury. Specifically, clarification of the definition of “gross receipts”, which is used to determine the reduction amount of the PTC, by the U.S. Treasury could affect the amount to be recognized.

***Effect if Different Assumptions Used:*** There were no PTCs recorded for the year ended December 31, 2025. While we believe the amount of PTCs recognized for the year ended December 31, 2024, is more-than-likely to be sustained upon examination, the ultimate outcome could result in material favorable or unfavorable adjustments to our consolidated financial statements. Guidance issued by the U.S. Treasury supporting or not supporting our tax position could result in an additional income tax benefit (expense) between approximately $89 million and $(89) million, respectively. Further, ZEC revenue was reduced by the estimated PTCs generated from PSEG Power’s Salem 1, Salem 2, and Hope Creek nuclear plants for the year ended December 31, 2024. ZEC revenue will be adjusted based upon the actual value of the PTCs generated which is dependent on the U.S. Treasury issuing additional guidance. This would result in an additional adjustment to Net Income between $(29) million and $44 million if our tax position discussed above is, or is not supported, respectively. See Item 8. Note 19. Income Taxes and Note 2. Revenues for more information.

## Market risk

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

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

### Commodity Contracts

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

### Value-at-Risk (VaR) Models

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

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

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

| 95% Confidence Level, Loss could exceed VaR one day in 20 days | MTM VaR Years Ended December 31, 2025 Millions | 2024 |
| --- | ---: | ---: |
| Period End | $63 | $36 |
| Average for the Period | $41 | $44 |
| High | $71 | $152 |
| Low | $17 | $25 |
| **99.5% Confidence Level, Loss could exceed VaR one day in 200 days** |  |  |
| Period End | $99 | $57 |
| Average for the Period | $64 | $69 |
| High | $111 | $238 |
| Low | $27 | $39 |

See Item 8. Note 15. Financial Risk Management Activities for a discussion of credit risk.

### Interest Rates

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

As of December 31, 2025, a hypothetical 10% increase in market interest rates would result in an additional $1 million in pre-tax annual interest costs related to either the current or the long-term portion of long-term debt, and term loan agreements.

### Debt and Equity Securities

As of December 31, 2025, we had $4.8 billion of net assets in trust for our pension and OPEB plans. Although fluctuations in market prices of securities within this portfolio do not directly affect our earnings in the current period, changes in the value of these investments could affect

- our future contributions to these plans,
- our financial position if our accumulated benefit obligation under our pension plans exceeds the fair value of the pension trust funds, and
- future earnings, as we could be required to adjust pension expense and the assumed rate of return.

The NDT Fund is comprised primarily of fixed income and equity securities. As of December 31, 2025, the portfolio included $1.5 billion of equity securities inclusive of $0.3 billion of investments in listed real assets, and $1.4 billion in fixed income securities. The fair market value of the assets in the NDT Fund will fluctuate primarily depending upon the performance of equity markets. As of December 31, 2025, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $155 million.

We use duration to measure the interest rate sensitivity of the fixed income portfolio. Duration is a summary statistic of the effective average maturity of the fixed income portfolio. The benchmark for the fixed income component of the NDT Fund currently has a duration of 5.98 years and a yield of 4.32%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2025, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $81 million.

## Controls and procedures

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### Disclosure Controls and Procedures

### PSEG and PSE&G

We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer (CEO) and Chief Financial Officer (CFO) of each respective company, as appropriate, by others within the entities to allow timely decisions regarding required disclosure. We have established a disclosure committee which includes several key management employees and which reports directly to the CFO and CEO of each of PSEG and PSE&G. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The CFO and CEO of each of PSEG and PSE&G have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.

### Internal Controls

### PSEG and PSE&G

We have conducted assessments of our internal control over financial reporting as of December 31, 2025, as required by Section 404 of the Sarbanes-Oxley Act, using the framework promulgated by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO.” Managements’ reports on PSEG’s and PSE&G’s internal control over financial reporting are included on pages 160 and 161, respectively. The Independent Registered Public Accounting Firm’s report with respect to the effectiveness of PSEG’s internal control over financial reporting is included on page 162. Management has concluded that internal control over financial reporting is effective as of December 31, 2025.

We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of our financial reporting. There have been no changes in internal control over financial reporting that occurred during the fourth quarter of 2025 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

Filed Feb 26, 2026.
Source: SEC EDGAR, the filing index for accession 0001193125-26-077446. Last ingested by Listed: Nov 6, 2026, 17:31 ET. No prices; not investment advice.