What changed in this filing

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Item 1. Business

2024-02-26 compared with 2023-02-22 · 221 added, 255 removed, 346 unchanged (58% of the section changed)

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

We are an energy company consisting primarily of a regulated electric and gas utility and a nuclear generation business.

Over the past few years, our investments resulted in a higher percentage of earnings contribution by PSE&G.

The sale of the fossil generating portfolio further simplified our business mix, resulting in an even higher percentage of earnings contribution by PSE&G going forward and provides more financial flexibility.

Our operations are located primarily in the Mid-Atlantic United States.

We are a public utility holding company consisting primarily of a regulated electric and gas utility and a nuclear generation business.

Over the past several years, our investments resulted in a higher percentage of earnings contribution by PSE&G.

The sale of the fossil generating portfolio in 2022 further simplified our business mix, resulting in an even higher percentage of earnings contribution by PSE&G going forward and provides more financial flexibility.

Our business approach focuses on operational excellence, financial strength and disciplined investment.

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

Early Plant Retirements/Asset Dispositions and Impairments for additional information.

Asset Dispositions and Impairments for additional information.

Our other direct wholly owned subsidiaries are:

PSEG Energy Holdings L.L.C.

(Energy Holdings), which holds our legacy portfolio of lease investments and interests in offshore wind ventures;

PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under a contractual agreement;

PSEG Energy Holdings L.L.C.

(Energy Holdings), which primarily holds our legacy lease investments and competitively bid, FERC regulated transmission;

and PSEG Services Corporation (Services), which provides us and our operating subsidiaries with certain management, administrative and general services at cost.

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OPERATIONS AND STRATEGY

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(PJM) which is an Independent System Operator (ISO) and Regional Transmission Organization (RTO) that operates the electric transmission system in the Mid-Atlantic Region, including

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New Jersey and the surrounding states.

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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 depreciation expense and deferred taxes (also known as rate base) using an approved return on equity (ROE) in developing the weighted average cost of capital.

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 current approved rates provide for a base ROE of 9.90% and a 50 basis point adder for our membership in PJM as an RTO.

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.

MD&A—Executive Overview of 2023 and Future Outlook.

We continue to invest in transmission projects as part of PJM’s FERC-approved transmission expansion planning process.

These projects focus on reliability improvements and replacement of aging infrastructure with planned capital spending of $1.8 billion for transmission in 2023-2025 as disclosed in Item 7.

MD&A—Capital Requirements.

PSE&G distributes electricity and natural gas to end users in our respective franchised service territories.

In October 2018, the BPU issued an Order approving the settlement of our distribution base rate proceeding with new rates effective November 1, 2018.

The Order provides for a distribution rate base of $9.5 billion, a 9.60% ROE for our distribution business and a 54% equity component of our capitalization structure.

Our distribution rates are subject to periodic rate cases approved by the BPU.

The BPU has also approved a series of PSE&G infrastructure, EE, EV and renewable energy investment programs with cost recovery through various clause mechanisms.

For a discussion of proposed and approved programs, see Investment Clause Programs below and Item 7.

Our current approved

distribution base rates provide for an ROE of 9.6%.

In December 2023, we filed a distribution base rate case as required by the BPU.

For a discussion of our recent distribution base rate case filing, see Item 7.

MD&A—Executive Overview of 2023 and Future Outlook.

For a discussion of proposed and approved programs, see Investment Clause Programs as follows and Item 7.

MD&A—Executive Overview of 2023 and Future Outlook.

Our load requirements are split among residential, C&I customers, as described in the following table for 2023:

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Sales as of December 31, 2023 (A)

Historical Annual Load Growth 2018-2022

Historical Annual Load Decline 2019-2023

Electric 2.4 Million 0.9 % 39,085 Gigawatt hours (1.4)%

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

Effective June 1 and October 1, 2021 for electric and gas, respectively, as part of the BPU’s approval of the Clean Energy Future-Energy Efficiency (CEF-EE) filing, we implemented the Conservation Incentive Program (CIP) that trues up PSE&G’s margin to a baseline per customer from our 2018 base rate case for the majority of our customers.

As a result, electric gas sales volumes and demands are no longer a driver of our margin and over 90% of our Electric and Gas Distribution margin will only vary based upon the number of customers.

While there has been a recent decrease in load due to a decline in larger industrial customers, greater EE and other factors, PJM’s most recent forecast indicates an increase in load over the next several years due to the increasing adoption of EVs, the expansion of data centers and other large users in our area, ongoing growth in the number of customers, other sources of electrification and other factors, which will collectively drive the need for increased system investment in the future.

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Investment Clause Programs

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Program Investment Approval Date Term of Investment Year Started

Gas System Modernization Program II (GSMP II) $1.9 billion 2018 5 years 2019

Energy Strong II (ES II) Program $842 million 2019 4 years (A) 2019

CEF-EE $1 billion 2020 3 years (B) 2020

Gas System Modernization Program II (GSMP II) Extension $902 million 2023 2 years (A) 2024

Energy Strong II Program $842 million 2019 4 years (B) 2019

CEF-EE Extension $280 million 2023 9 months 2023

CEF-Energy Cloud (EC) $707 million 2021 4 years 2021

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

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

GSMP II —designed to replace approximately 875 miles of cast iron and unprotected steel mains in addition to other improvements to the gas system.

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

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

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

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

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

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and direct current (dc) fast charging.

A remaining component of our program related to medium and heavy duty charging infrastructure is the subject of a stakeholder process that began in 2021 at the BPU.

In December 2022, the BPU issued a revised straw proposal on medium and heavy duty vehicle support for public comment.

Our CEF-Energy Storage program is being held in abeyance pending future policy guidance from the BPU.

Our proposed Energy Storage program is for a $109 million investment that encompasses solar smoothing, whereby a battery energy solar system is used to neutralize fluctuations in solar output to facilitate its entry into the grid, distribution investment deferral, outage management, microgrids and peak reduction for municipal facilities.

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

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

Our proposed ES program is for a $109 million investment that encompasses solar smoothing, whereby a battery energy solar system is used to neutralize fluctuations in solar output to facilitate its entry into the grid, distribution investment deferral, outage management, microgrids and peak reduction for municipal facilities.

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

MD&A—Executive Overview of 2023 and Future Outlook for additional information.

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The second type provides default supply for larger customers, with energy priced at hourly PJM real-time market prices for a contract term of 12 months (BGS-Commercial Industrial Energy Pricing).

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We procure the supply to meet our BGS obligations through auctions authorized by the BPU for New Jersey’s total BGS requirement.

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These customers are charged a market-based price largely determined by prices for commodity futures contracts.

Markets and Market Pricing

Historically, there has been significant volatility in commodity prices.

A rising commodity price environment results in higher delivered electric and gas rates for customers, which could result in decreased demand for electricity and gas, increased regulatory pressures and greater working capital requirements as the collection of higher commodity costs from our customers may be deferred under our regulated rate structure.

A declining commodity price, on the other hand, would be expected to have the opposite effect.

Through PSEG Power, we have sought to produce low-cost electricity by efficiently operating our nuclear generation assets while balancing fuel requirements and natural gas supply obligations through energy portfolio management.

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.

In June 2021, we completed the sale of PSEG Power’s solar portfolio.

In February 2022, we completed the sale of PSEG Power’s 6,750 MW fossil generating portfolio.

Early Plant Retirements/Asset Dispositions and Impairments for further discussion.

Products and Services

As a merchant generator, our revenue is derived primarily from energy, capacity and ancillary services to counterparties in the open markets.

These products and services may be transacted 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 customers.

As a nuclear generation owner and operator, our revenue has been derived primarily from energy, capacity and ancillary services sold to PJM in the spot markets.

These products and services may also be transacted through exchange markets or bilaterally.

In August 2022, the Inflation Reduction Act (IRA) was signed into law expanding incentives that promote carbon-free generation.

The enacted legislation established the production tax credit (PTC) for electricity generation using nuclear energy, which begins January 1, 2024 and is available through 2032.

PSEG Power’s Salem 1, Salem 2, Hope Creek, Peach Bottom 2 and Peach Bottom 3 nuclear plants are expected to benefit from the PTC.

The expected PTC rate is up to $15 per megawatt hour (MWh) subject to adjustment based upon a facility’s gross receipts and meeting prevailing wage rules.

The PTC rate and the gross receipts threshold are subject to annual inflation adjustments.

Until additional guidance is issued by the U.S.

Treasury, we are unable to fully determine the impacts of the PTC.

PSEG Power also sells wholesale natural gas, primarily through a full-requirements BGSS contract with PSE&G to meet the needs of PSE&G’s default service customers.

In 2022, the BPU approved an extension of the long-term BGSS contract to March 31, 2027, and thereafter the contract remains in effect unless terminated by either party with a two-year notice.

Approximately 47% of PSE&G’s peak daily gas requirements is provided from PSEG Power’s firm gas transportation capacity.

PSEG Power satisfies the remainder of PSE&G’s requirements from storage contracts, contract peaking supply, liquefied natural gas and propane.

Based upon the availability of natural gas beyond PSE&G’s daily needs, PSEG Power sells gas to other customers and shares these proceeds with PSE&G’s customers.

PSEG Power also has a 50% ownership interest in a 208 MW generation facility in Hawaii.

PSEG Power supplies PSE&G’s peak daily gas requirements through its balanced portfolio of firm gas transportation capacity, storage contracts, contract peaking supply, and liquefied natural gas and propane.

Based upon the availability of natural gas beyond PSE&G’s actual daily needs, PSEG Power sells gas to other customers and shares these proceeds with PSE&G’s customers.

How PSEG Power’s Nuclear Generation Operates

As of December 31, 2023, PSEG Power had 3,761 MW of nuclear generation capacity.

All of our nuclear generation capacity is located in the Mid-Atlantic region of the United States in one of the country’s largest and most developed electricity markets.

All of our nuclear generation capacity is located in New Jersey and Pennsylvania.

Generation Dispatch

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Typically, the bid price of the last unit dispatched by PJM establishes the energy market-clearing price.

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This method of determining supply and pricing creates a situation where natural gas prices often have a major influence on the price that generators will receive for their output, especially in periods of relatively strong or weak demand.

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Forward prices are volatile and there can be no assurance that current forward prices will remain in effect or that we will be able to contract output at these forward prices.

The PTC is expected to mitigate our exposure to this volatility and provide support for the nuclear units.

Nuclear Fuel Supply

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• fabrication of nuclear fuel assemblies.

We expect to be able to meet the fuel supply demands of our customers and our operations.

However, the ability to maintain an adequate fuel supply could be affected by several factors not within our control, including changes in prices and demand, curtailments by suppliers, severe weather, environmental regulations, and other factors.

We expect to be able to meet the nuclear fuel supply demands of our operations.

For additional information and a discussion of risks, see Item 1A.

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

Prior to the sale of its fossil generation assets, PSEG Power also had significant sales within the New York ISO (NYISO) and New England ISO (ISO-NE).

The price of electricity varies by location in the PJM RTO.

Commodity prices, as well as the availability of our fleet of nuclear generation units to operate, have a considerable effect on our profitability.

Over the long-term, the higher the forward energy prices are, the more attractive an environment exists for us to contract for the sale of our anticipated output.

However, a rising price environment, such as what has been experienced in the past year, also increases the cost of replacement power;

thereby placing us at greater risk should our generating units fail to operate effectively or otherwise become unavailable.

PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants have been awarded Zero Emission Certificates (ZECs) by the BPU through May 2025.

These nuclear plants are expected to receive ZEC revenue from the electric distribution companies (EDCs) in New Jersey, which is equivalent to approximately $10 per megawatt hour (MWh) in payments to selected nuclear plants.

Our nuclear generating units’ performance, together with the PTC, have a considerable effect on our profitability.

The PTC is designed to increase with inflation, and therefore, future inflation levels will impact the financial support of the nuclear units.

In addition, market revenues in excess of the PTC threshold would provide incremental benefit.

PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants have also been awarded zero emission certificates (ZECs) by the BPU through May 2025.

These nuclear plants are expected to receive ZEC revenue from the electric distribution companies (EDCs) in New Jersey, which is equivalent to approximately $10/MWh.

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

In addition to energy sales, we earn revenue from capacity payments for our generating assets.

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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.

MD&A—Executive Overview of 2022 and Future Outlook—Wholesale Power Market Design.

In PJM the market design for capacity payments provides for a structured, forward-looking, capacity pricing mechanism through the Reliability Pricing Model (RPM).

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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.

We have obtained price certainty for our PJM capacity through May 2024 through the RPM pricing mechanism.

However, there is currently regulatory and timing uncertainty regarding the June 2024 through May 2025 planning year as discussed in Regulatory Issues—Federal Regulation.

In addition, the PJM capacity market imposes rigorous performance obligations and non-performance penalties on resources during times of system stress.

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Hedging Strategy

To mitigate volatility in our results, we seek to contract in advance for a significant portion of our anticipated electric output, capacity and fuel needs.

We seek to sell a portion of our anticipated lower-cost generation over a multi-year forward horizon,

normally over a period of two to three years.

We believe this hedging strategy increases the stability of earnings.

The PTC is intended to provide sufficient and stable support for nuclear units and is effective January 1, 2024.

To mitigate volatility in our results, we seek to contract in advance to hedge the price exposure for a significant portion of our anticipated electric output, capacity and fuel needs.

We historically have sold a portion of our anticipated generation over a multi-year forward horizon, normally over a period of two to three years.

As of the end of 2023, we have hedged approximately 90% to 95% of its expected generation output for 2024.

Beginning in 2024, our hedging strategy will incorporate an estimated range of risk reduction impacts from the PTCs on our nuclear generation portfolio.

This is expected to result in changes to our current approach given PTC guidance uncertainty, and potential incremental changes upon final U.S.

Treasury guidance.

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Generally, we seek to hedge our output through sales at PJM West or other nodes corresponding to our generation portfolio.

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Although we enter into these hedges to provide price certainty for a large portion of our anticipated generation, there is variability in both our actual output as well as in the effectiveness of our hedges.

Our hedging practices help to manage some of the volatility of the merchant power business.

While this limits our exposure to decreasing prices, our ability to realize benefits from rising market prices, as experienced in the past two years, is also limited.

Therefore, our realized prices in 2022 were significantly lower than market pricing due to forward sales contracts executed in prior years for delivery in 2022.

For this same reason, expected realized prices in forward periods will also be limited to when hedges were transacted and not based upon forward market prices.

In August 2022, the Inflation Reduction Act (IRA) was signed into law expanding incentives promoting carbon-free generation.

The enacted legislation established the production tax credit (PTC) for electricity generation using nuclear energy set to begin in 2024 through 2032.

PSEG Power’s Salem 1, Salem 2, Hope Creek, Peach Bottom 2 and Peach Bottom 3 nuclear plants will each benefit from the PTC.

Our hedging practices help to manage some of the volatility of the nuclear generation business.

While this limits our exposure to decreasing prices, our ability to realize benefits from rising market prices is also limited.

The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts.

The PTC rate and the gross receipts cap are subject to annual inflation adjustments.

Treasury is expected to clarify the definition of gross receipts prior to when the eligibility period begins in 2024.

Treasury is expected to clarify the definition of gross receipts as the eligibility period begins January 1, 2024.

We are continuing to analyze the impact of the IRA on our nuclear units, including additional future guidance from the U.S.

Treasury, potential impacts on hedging strategies and the impact of PTCs on expected ZEC payments.

Treasury, potential impacts on hedging strategies and overall financial support.

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

Our nuclear fuel commitments cover approximately 100% of our estimated uranium, enrichment and fabrication requirements through 2026 and a significant portion through 2027.

More than 90% of PSEG Power’s expected gross margin in 2023 from the nuclear generation assets relates to our energy hedging strategy, our expected revenues from the capacity market mechanisms described above, ZEC revenues and certain gas operations and ancillary service payments such as reactive power.

The contracted percentages of our anticipated base load generation output for the next two years are as follows:

Nuclear Generation 2023 2024

Generation Sales 95%-100% 55%-60%

LIPA Operations Services Agreement

In accordance with a 12-year OSA entered into by PSEG LI and LIPA, PSEG LI commenced operating LIPA’s electric T&D system in Long Island, New York on January 1, 2014.

The OSA contract term continues through 2025, but can be extended subject to a mutual agreement of the parties.

Under the OSA, PSEG LI acts as LIPA’s agent in performing many of its obligations and in return (a) is prefunded for pass-through operating expenditures, (b) receives a fixed management fee and (c) is eligible to receive an incentive fee contingent on meeting established performance metrics.

Further, since January 2015, PSEG Power provides fuel procurement and power management services to LIPA under separate agreements that expire at the end of 2025.

It is uncertain whether the OSA and the separate agreements will be renewed on terms acceptable to us or at all.

Energy Holdings

Energy Holdings maintains our legacy portfolio of domestic lease investments and offshore wind interests.

Energy Holdings maintains our portfolio of legacy lease investments.

Long-Term Investments and Note 9.

Financing Receivables for additional information.

Offshore Wind

PSEG holds a 25% equity interest in Ørsted North America Inc.’s (Ørsted) Ocean Wind 1 project which is currently in development.

In January 2023, PSEG agreed to sell to Ørsted its 25% equity interest in Ocean Wind 1.

The sale is not contingent upon Ørsted electing to proceed to the construction phase of the project.

The sale is contingent upon finalization of a purchase and sale agreement with Ørsted and other closing conditions as well as any potential state regulatory approval that may be required to close on the transaction.

Additionally, PSEG and Ørsted each owns 50% of Garden State Offshore Energy LLC (GSOE) which holds rights to an offshore wind lease area just south of New Jersey.

PSEG has decided not to exercise its option to purchase 50% of Ørsted’s Skipjack projects in Maryland (one of which would utilize a portion of the GSOE lease area) or pursue an ownership interest in Ørsted’s Ocean Wind 2 offshore wind project or other offshore wind generation projects.

PSEG is evaluating its options for the potential sale of its interest in GSOE .

Variable Interest Entities for additional information.

LIPA Operations Services Agreement

In accordance with a twelve year Operations Services Agreement (OSA) entered into by PSEG LI and LIPA, PSEG LI commenced operating LIPA’s electric T&D system in Long Island, New York on January 1, 2014.

Following the effects of Tropical Storm Isaias, LIPA and PSEG LI agreed to an amended OSA which became effective in 2022.

The OSA contract term continues through 2025, but can be extended for five years subject to a mutual agreement of the parties.

Under the OSA, PSEG LI acts as LIPA’s agent in performing many of its obligations and in return (a) receives reimbursement for pass-through operating expenditures, (b) receives a fixed management fee and (c) is eligible to receive an incentive fee contingent on meeting established performance metrics.

Further, since January 2015, PSEG Power provides fuel procurement and power management

services to LIPA under separate agreements.

It is uncertain whether the OSA and the separate agreements will be renewed on terms acceptable to us or at all.

Energy Holdings also owns 50% of Garden State Offshore Energy LLC (GSOE) which holds rights to an offshore wind lease area just south of New Jersey.

We are evaluating our options for the potential sale of our interest in GSOE .

In December 2023, PJM awarded a subsidiary of Energy Holdings an approximately $424 million project to construct a 500 kV transmission line in Maryland.

PSEG’s project was part of a larger set of projects designed to address reliability issues driven by load growth and retirement of fossil generation.

Our project is expected to be placed in service in 2027.

COMPETITIVE ENVIRONMENT

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Conversely, an increase in EV adoption and other factors could lead to an increase in system usage, require incremental investments to meet higher peak demands and result in a larger customer usage base.

There is also an expected shift toward greater electrification and less gas usage in the coming decades, with several jurisdictions setting targets to move new construction to be exclusively electric.

While current costs and relative emission savings would limit any substantial change in the near term, technological advances for heat pumps, actions by certain jurisdictions in our service territory and other factors could accelerate these potential changes, resulting in a slowing in the growth of our gas distribution and an increase in the growth of our electric T&D business.

There is also an expected shift toward greater electrification and less gas usage in the coming decades.

While current costs and relative emission savings would limit any substantial change in the near term, technological advances for heat pumps, actions by certain jurisdictions in our service territory and other factors could accelerate these potential changes, which could result in a slowing in the growth of our gas distribution and an increase in the growth of our electric T&D business.

Our CIP reduces the impact on our distribution revenues from changes in sales volumes and demand for most customers.

The CIP, which is calculated annually, provides for a true-up of our current period revenue as compared to revenue thresholds established in our most recent distribution base rate proceeding.

The CIP, which is calculated annually, provides for a true-up of our current period revenue as compared to revenue

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thresholds established in our most recent distribution base rate proceeding.

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

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Various market participants compete with us and one another in transacting in the wholesale energy markets and entering into bilateral contracts.

Our competitors include (i) merchant generators, (ii) domestic and multi-national utility generators, (iii) energy marketers and retailers, (iv) private equity firms, banks and other financial entities, (v) fuel supply companies, and (vi) affiliates of other industrial companies, and companies that promote and aggregate demand side management (DSM) and other EE efforts that could reduce load.

New additions of lower-cost or more efficient generation capacity, as well as subsidized generation capacity, or technological advances such as distributed generation and microgrids could make our plants less economic in the future.

Such capacity could impact market prices and our competitiveness.

Adverse changes in energy industry law, policies and regulation could have significant economic, environmental and reliability consequences.

For example, PJM has a capacity market that has been approved by FERC.

Our competitors include but are not limited to merchant generators, utility generators, energy marketers , retailers , private equity firms , and other financial entities.

New additions of lower-cost or more efficient generation capacity, as well as subsidized generation capacity, or technological advances could impact forward market prices in the future.

PJM has a capacity market that has been approved by FERC.

FERC regulates this market and continues to examine whether this market design is working optimally.

PJM itself often changes capacity market rules, which can cause uncertainty for market participants.

Various forums are considering how the competitive market framework can incorporate or be reconciled with state public policies that support particular resources, resource attributes or emerging technologies, whether generators are being sufficiently compensated in the capacity market and whether subsidized resources may be adversely affecting capacity market prices.

For information regarding recent actions by FERC relating to capacity market design, see the discussion in Regulatory Issues—Federal Regulation.

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

While it is our expectation that continued efforts may be undertaken by the federal and state governments to preserve the existing base nuclear generating plants, we still believe that pressures from renewable resources will continue to increase.

HUMAN CAPITAL MANAGEMENT

Our human capital management strategy is integrated with our overall environmental, social, and governance (ESG) goals and is designed to support our ability to attract, develop, and retain a high performing diverse workforce and to continue building on our culture of inclusion to sustain our business, both today and in the future.

We strive for a fair, equitable and transparent approach to human capital management.

The Organization and Compensation Committee of the PSEG Board of Directors is responsible for oversight of PSEG’s human capital management practices and is updated regularly on matters related to diversity, equity and inclusion (DEI), workforce development and succession planning.

Our Core Commitments – safety, integrity, continuous improvement, customer service and diversity, equity and inclusion (DEI) – are at the center of our workplace culture.

They guide us in important aspects of our Human Capital Management strategy, including recruitment, employee development, retention, performance, safety, and collaboration.

We rely on our inclusive culture to support our many stakeholders including employees, customers, and the many diverse communities we serve.

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

Our human capital management strategy is integrated with our overall business strategy.

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

Over 60% of our workforce is represented by six unions under various collective bargaining agreements that cover wages, benefits and other terms and conditions of employment.

In 2023, we negotiated new agreements with all six of our unions in advance of contract expiration.

These agreements contain four-year terms, expiring in 2027 and support strategic objectives and business goals.

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

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

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

In 2022, of our external hires, including temporary employees, 23% were women and 40% were racially and/or ethnically diverse.

PSEG’s voluntary attrition rate for the year was 6.5% (3.3% retirements and 3.2% resignations).

The average employee tenure is 14 years.

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Health, Safety and Well-Being

We emphasize the priority of protecting the health, safety and well-being of our employees, contractors and the communities that we serve.

We value the health, safety, security and well-being of our employees, contractors and the communities that we serve.

We demonstrate this by providing support to employees so that everyone is empowered and encouraged to question, stop and correct any unsafe act or condition.

In the event that there is a safety issue, our employees take responsibility for the accurate, honest, and timely reporting of all incidents and injuries.

To hold ourselves accountable, we have annual performance goals related to compliance with health and safety policies, practices and procedures.

We take measures to provide employees and contractors with proper knowledge, training and protective equipment to maintain their personal health and safety and to mitigate workplace risks.

Culture, Diversity, Equity and Inclusion

We aspire for a culture of belonging and equity, where diversity is celebrated and inclusion is the norm.

Since publishing our first DEI report in 2021, we have continued to build on our Inclusion for All strategy.

Our DEI program combines individual and site-specific efforts with leadership development and training activities.

Our 12 Employee Business Resource Groups support key business goals and priorities;

help build meaningful connections through community outreach and volunteerism, mentorship and professional development;

elevate diverse perspectives;

and create spaces for employees to learn from each other.

To measure the effectiveness of our DEI and workplace culture efforts, we solicit feedback from employees through focus groups, listening sessions and employee experience surveys.

In 2022, we saw improvements in many areas, including comfort speaking up, belonging, and manager relationship, with an overall engagement score of 82%.

Our initiatives to advance DEI includes doing business with certified minority, women, veteran & LGBT-owned businesses and maintaining a supplier diversity process that is integrated into our company culture.

PSEG achieved its goal to spend 30% with diverse suppliers by 2023 in 2021, two years ahead of schedule.

Talent, Attraction and Development

Our talent acquisition strategy is focused on hiring the workforce necessary to serve our customers and meet our business objectives.

We incorporate DEI throughout the employee life cycle and build on our Inclusion for All strategy.

Since everyone is responsible for DEI and work-place culture, employees have many opportunities to influence the work environment, let their voices be heard and to step up and lead.

Our efforts are led by the PSEG Office of DEI.

It is supported by our Employee Business Resource Groups and the Local Inclusion Teams within our business units and field locations.

The Office of DEI works to make sure our programs such as community outreach and volunteerism, mentorship, recognition and professional development, are relevant and accessible to all employees.

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

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

Talent, Attraction and Workforce Development

Our talent acquisition strategy is focused on hiring a diverse, high-performing workforce to meet our business objectives, including the critical skilled trade roles needed to provide energy that is safer and delivered more reliably than ever.

As part of these efforts, we work to attract employees who reflect broad dimensions of diversity, including race, gender, disability, generation, education, and other traits and characteristics that make each person who they are.

Our employees grow through a variety of training and development opportunities offered to individual contributors, front line supervisors, managers and leaders.

Talent reviews and succession planning for senior and critical positions are key components of our workforce planning strategy.

We continue to identify and develop internal talent to step into key roles, minimizing any potential disruptions to our operations.

We invest in technical and operational training for our craft and field workers to support safe and reliable operations.

We utilize data-driven workforce planning and succession processes to prepare for the future of work.

We continue to focus on hiring ahead of attrition and upskilling our skilled trade roles to adapt to evolving technologies and digital advancements.

Total Rewards

In addition to our competitive pay, incentives, and health, welfare and retirement programs, our Total Rewards offerings consider the safety and overall well-being of our employees.

We offer an array of programs designed to support physical, emotional, and financial wellness.

Labor Relations

We are proud of the partnership we have with union leadership across our six unions and the employees they represent in our workforce.

We believe our strong relationship with our unions allowed for negotiation of permanent agreements that support PSEG’s flexible work model and other mid-term agreements that support strategic objectives and business goals.

We support the well-being of our employees through a comprehensive total rewards program.

We provide compensation to our workforce and a benefit program that is designed to support mental and physical health and emotional and financial wellness.

In 2023, we performed a total rewards study, which included a comprehensive evaluation of our performance management process, compensation structure and design as well as pay fairness review.

REGULATORY ISSUES

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

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Transmission Regulation

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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 has 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 $30 million-$40 million.

Transmission Planning Proceedings —During 2022, FERC issued several rulemakings and notices that examine current transmission planning proceedings to determine whether the rules as currently implemented will facilitate the integration of renewable resources onto the grid and whether there is sufficient oversight over transmission costs to protect customers.

In a rulemaking proceeding issued in 2021, FERC proposed to eliminate the existing 50 basis point adder for RTO membership, which is currently available to PSE&G and other transmission owners in RTOs.

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

Transmission Planning Proceedings —Through rulemaking proceedings, FERC continues to determine whether changes are needed to current transmission and interconnection planning rules to facilitate the integration of renewable resources onto the grid.

FERC is also examining whether there is sufficient oversight over transmission costs to protect customers.

Among other issues, FERC is considering whether transmission competitive solicitations are working as intended, whether interconnection queue rules for new generation should dramatically change and whether some type of transmission monitor construct to oversee costs should be imposed.

FERC’s consideration of many of these issues is still in its early stages.

On the interconnection front, in July 2023, FERC issued a Final Rule, which parties have challenged on rehearing, that will require RTOs to implement rules to speed up the processing of interconnection queue requests.

This Rule may also result in penalties being imposed on generators, RTOs and transmission owners that fail to meet certain process deadlines.

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

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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.

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 that has been approved by FERC.

FERC regulates the capacity market and continues to examine whether the market design is working optimally.

Various forums are considering how the competitive market framework can incorporate or be reconciled with state public policies that support particular resources, resource and environmental attributes or emerging technologies, whether generators are being sufficiently compensated in the capacity market and whether subsidized resources may be adversely affecting capacity market prices.

We cannot predict what action, if any, FERC might take with regard to capacity market design.

The RPM is the locational installed capacity market design for the PJM region, including a forward auction for installed capacity.

PJM operates a capacity market called the Reliability Pricing Model (RPM), the rules for which are approved by FERC.

RPM incorporates a forward auction for installed capacity.

Under the RPM, generators located in constrained areas within PJM are paid more for their capacity as an incentive to ensure adequate supply where generation capacity is most needed.

The mechanics of the RPM in PJM continue to evolve and be refined in stakeholder proceedings and FERC proceedings in which we are active.

In July 2021, PJM submitted to FERC a proposal to scale back the PJM Minimum Offer Price Rule (MOPR) to accommodate state public policy programs that do not attempt to set the price of capacity.

Under the PJM proposal, PSEG Power’s New Jersey nuclear plants that receive ZEC payments are not subject to the MOPR.

In September 2021, FERC issued a notice that it was not able to act on PJM’s proposed changes to the MOPR because of a split among the Commissioners on the lawfulness of PJM’s proposal.

Therefore, PJM’s rules became automatically effective as of September 29, 2021 and they were applied to the June 2022 base residual auction.

In November 2021, a group of generators challenged these MOPR rules in the Court of Appeals for the Third Circuit on the grounds that FERC’s inaction was unlawful.

PSEG intervened in the proceeding in support of the MOPR rules.

Oral argument on the appeal was held in January 2023.

We cannot predict the outcome of this proceeding.

In another order related to the auction, FERC found that the current rules related to the Market Seller Offer Cap were unjust and unreasonable and ultimately eliminated the default offer cap.

In its place, FERC adopted a unit-specific approach to reviewing certain capacity market offers.

These new rules resulted in lower capacity prices for other market participants, including PSEG, and therefore, lower revenues for PSEG in the June 2022 base residual auction since market offers for many resource types need to be approved by the Independent Market Monitor and PJM.

PJM’s most recent base residual auction was held at the beginning of December 2022.

However, in mid-December, PJM communicated to all market participants that it is not announcing the results of this auction while it waits for FERC to act on emergent filings it has made at FERC proposing to change how the reliability requirement for a specific capacity market deliverability area will be calculated effective December 24, 2022.

PJM’s filings at FERC, and its related decision to postpone the announcement of base residual auction results, creates uncertainty for market participants, including PSEG.

We cannot predict the outcome of these developments at this time.

In October 2023, PJM submitted two related filings at FERC proposing reforms to its capacity market design, including (i) enhanced risk modeling to better account for winter risk;

(ii) changes to supply-side market power mitigation rules;

and (iii) more stringent capacity qualification and performance requirements.

In January 2024, FERC issued an order approving PJM’s reforms relating to enhanced risk modeling and qualification and performance requirements.

However, in February 2024, FERC issued an order rejecting PJM’s second package of reforms, including PJM’s proposed changes to its supply-side market power mitigation rules.

At the same time, in this order FERC provided guidance to PJM should PJM choose to develop an alternate proposal in the future.

Various parties may seek rehearing of FERC’s rejection order.

In February 2024, PJM submitted a request asking FERC to delay the commencement of the base residual auction for the 2025/26 Delivery Year to mid-July 2024.

This request is pending before FERC.

In late December 2022, PJM called its first ISO-wide Maximum Generation Emergency Action during Winter Storm Elliott, which triggered a Performance Assessment Interval (PAI) event.

As a result of this event, PSEG both incurred penalties and received bonuses under PJM’s capacity performance rules, neither of which were material to PSEG’s financial results in 2022

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Many generators filed complaints at PJM seeking to reduce or eliminate their obligations to pay non-performance penalties incurred during the event.

Parties ultimately reached a settlement effectuating a penalty reduction that was not material to PSEG.

In December 2023, FERC approved the settlement.

Reliability Standards— Congress has required FERC to put in place, through the North American Electric Reliability Corporation (NERC), national and regional reliability standards to ensure the security and reliability of the U.S.

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As part of these plans, utilities can decide or be required to build additional redundancy into their systems.

Additionally, under NERC’s supply chain standard approved by FERC in 2018, PSEG has developed security controls for supply chain management associated with the procurement of industrial control system hardware, software, and services related to grid operations.

These standards implement the Critical Infrastructure Protection standards that are already in place and that establish physical and cybersecurity protections for critical systems.

We have documented procedures and implemented new processes to comply with these standards.

The 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.

As a result of physical attacks in 2022 to electric infrastructure, NERC is studying whether the physical security standard should be revised.

Moreover, under NERC’s supply chain standard approved by FERC in 2018, PSEG has developed physical and cybersecurity controls for supply chain management associated with the procurement of industrial control system hardware, software, and services related to grid operations.

In February 2023, FERC approved additional reliability standards governing extreme cold weather preparedness and operations, which will begin going into effect in 2024.

We continue to analyze these new standards.

FERC and NERC continue to study potential revisions to reliability standards regarding extreme cold weather.

Relatedly, in November 2023, FERC and NERC released a report regarding the operation of the Bulk Power System (BPS) during Winter Storm Elliott that struck in late 2022, causing power outages for millions and significantly straining the BPS in certain regions of the country, and proposed recommendations.

These recommendations for extreme cold weather events include:

(i) creation of additional reliability standards to strengthen generator operations;

(ii) legislation or regulations to ensure the reliability of natural gas infrastructure;

(iii) identification of high risk generating units and conducting cold weather verifications of these units;

and (iv) improving short-term load forecasts for extreme cold weather events.

In June 2023, FERC issued a rule directing NERC to either change existing reliability standards or create a new standard that will require RTOs like PJM to plan for extreme weather events.

In October 2023, pursuant to FERC’s rule, PSE&G, along with PJM and other RTOs, jointly submitted an informational report describing their policies and processes for conducting extreme weather vulnerability assessments.

Investor Ownership of Public Utilities— In December 2023, FERC proposed new rules that, if finalized, would mean that institutional investors in FERC-regulated public utilities or in holding companies with public utility affiliates will need to obtain approval from FERC before acquiring such an ownership interest that exceeds a defined monetary threshold.

Under current rules, investors are able to rely upon blanket authorizations to make such investments and are not required to obtain FERC approval for specific stock acquisitions.

FERC is concerned that there is insufficient oversight to protect consumers and is seeking public comment on the proposed rules.

We cannot predict the outcome of this rulemaking proceeding.

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 systemic 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.

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.

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We are unable to predict the final outcome of these reviews or the cost of any actions we would need to take to comply with any new regulations, including possible modifications to the Salem, Hope Creek and Peach Bottom facilities, but such costs could be material.

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

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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) —In January 2020, the State of New Jersey released its EMP.

While the EMP does not have the force of law and does not impose any obligations on utilities, it outlines current expectations regarding the State’s role in the use, management, and development of energy.

New Jersey Energy Master Plan (EMP) and Future of Gas Stakeholder Proceeding —In January 2020, the State of New Jersey released its EMP.

While the EMP does not have the force of law and does not impose any obligations on utilities, it outlines current expectations regarding the New Jersey’s role in the use, management, and development of energy.

The EMP recognizes the goals of New Jersey’s Clean Energy Act of 2018 (the Clean Energy Act) to achieve, by 2026, annual reductions of electric and gas consumption of at least 2% and 0.75%, respectively, of the average of the prior three years of retail sales.

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and reduced reliance on natural gas.

We cannot predict the impact on our business or results of operations from the EMP or any laws, rules or regulations promulgated as a result thereof, particularly as they may relate to PSEG Power’s nuclear generating stations and PSE&G’s electric transmission and gas distribution assets.

In January 2023, the New Jersey governor’s office announced the commencement of planning for the development of a new EMP for release in 2024.

The 2024 EMP will update

and expand upon the existing EMP and consider recent state and federal policies and how federal funding can provide additional support for advancement of critical clean energy policies.

In February 2023, the governor of New Jersey issued three Executive Orders (EOs), one of which directs the BPU to immediately convene a stakeholder process on the future of gas to develop a plan to meet the State’s current EMP goal to reduce emissions by 50% versus 2006 levels by 2030.

In March 2023, the BPU opened a stakeholder proceeding to implement such EO that commenced in August 2023 with a two-day technical conference.

This proceeding will consider the possible development of a “clean heat standard” or other market mechanisms to support New Jersey’s goals, among other things.

The BPU Board is seeking to retain a consultant to assist with this proceeding, and is expected to convene additional working groups and/or stakeholder sessions in 2024.

Additionally, in April of 2023 the governor’s office Council on the Green Economy initiated a “Clean Buildings Working Group” that is considering pathways for building electrification and meeting gas utility emissions reduction goals, including development of a clean heat standard.

PSE&G was invited to participate in this working group focused on strategic planning.

We cannot predict the impact on our business or results of operations from these stakeholder proceedings, or any laws, rules, or regulations promulgated as a result thereof, particularly as they may relate to PSEG Power’s nuclear energy generating stations and PSE&G’s electric transmission and gas distribution assets.

Stakeholder Proceeding on Gas Competition, BGSS —In February 2023, the BPU announced that it would open a new docket to conduct a stakeholder proceeding regarding gas supply issues previously raised by competitive gas suppliers, including third-party suppliers’ participation in New Jersey gas distribution companies’ annual BGSS filings, and other aspects of the existing BGSS construct.

In April-May 2023 the BPU Board conducted an initial stakeholder meeting and received written comments identifying any issues to be examined, presumably in a future portion of this proceeding following BPU Staff recommendation and BPU Board adoption.

There has been no public activity in this matter since the submissions in May 2023.

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Gas Capacity Review —In September 2019, the BPU formally opened a stakeholder proceeding to explore gas capacity procurement service to all New Jersey natural gas customers.

The BPU retained a consultant and in June 2022 accepted the consultant’s key finding that, through 2030, New Jersey’s firm gas capacity can meet firm demand under normal design day conditions.

The only potential gas supply shortfall was found during extreme weather (i.e.

a winter day that could be expected to occur only once in 90 years) and/or a “perfect storm,” which occurs when there is an outage on a transcontinental pipeline during a design day.

The BPU noted that its consultant’s analysis supports the argument against the need for additional interstate pipeline capacity and also supports the BPU’s aggressive policy approach to reduce the State’s overall reliance on fossil fuels, and achieve the Governor’s goal of 100% clean energy by 2050.

BGS Process —In July 2022, the State’s EDCs, including PSE&G, filed their annual proposal for the conduct of the February 2023 BGS auction covering energy years 2024 through 2026.

In November 2022, the BPU issued its decision to approve the joint EDCs’ proposals regarding the BGS auction process.

In addition to addressing procedural issues for conducting the annual BGS auction, the BPU’s November 2022 order addressed EV charging supply rate issues and required that the EDCs must (i) continue to collect EV charging data and coordinate with BPU Staff in developing a BGS rate solution for commercial dc fast charging EV stations, and must include chargers and submit a proposal regarding the rate design in the June 1, 2023 joint EDC BGS filing;

and (ii) implement by June 1, 2023 a BGS rate solution for residential EV charging customers similar to distribution rate off-peak charging solutions put in place in some of the EDCs’ (including PSE&G’s) light duty EV incentive programs.

The only potential gas supply shortfall was found during extreme weather (i.e., a winter day that could be expected to occur only once in 90 years) and/or a “perfect storm,” which occurs when there is an outage on a transcontinental pipeline during a design day.

The BPU noted that its consultant’s analysis supports the argument against the need for additional interstate pipeline capacity and also supports the BPU’s aggressive policy approach to reduce New Jersey’s overall reliance on fossil fuels and achieve the New Jersey governor’s goal of 100% clean energy by 2050.

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

In September 2023, the BPU directed utilities to apply for a six-month extension of the first triennial programs.

PSE&G filed for its six-month extension of the existing program in November 2023, and filed its second triennial EE program proposal in December 2023.

Both filings are subject to BPU approval.

BGS Process —In June 2023, New Jersey’s EDCs, including PSE&G, filed their annual joint proposal for the conduct of the February 2024 BGS auction covering energy years 2025 through 2027.

As was directed by a November 2022 BPU order, PSE&G participated in a working group led by BPU Staff to consider proposals for a commercial dc, fast-charging (DCFC) rate solution.

PSE&G’s proposal included in the June 2023 joint EDC BGS filing is for a two-year DCFC BGS rate pilot program to begin June 1, 2024.

Also, in accordance with the November 2022 order’s directive that the EDCs implement a rate solution for residential EV charging customers, in May 2023, the BPU approved PSE&G’s proposal for a BGS time-of-use rate solution for residential EV charging, with rates effective June 1, 2023.

In November 2023, the BPU issued its decision to approve the joint EDCs’ proposal regarding the BGS auction process, including approving the EDCs’ proposed DCFC BGS rate pilot programs.

EV Activity —Consistent with the policy set forth in New Jersey’s EMP, the BPU has supported electrification of the transportation sector.

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Grid Modernization —In October 2021, the BPU commenced a stakeholder proceeding to develop and implement a systemic Grid Modernization plan in accordance with strategies outlined in the New Jersey EMP.

The BPU retained a consultant that gathered detailed and comprehensive information from the State’s EDCs, including PSE&G, regarding resource issues and policy changes needed to interconnect the clean energy capacity required under state policy.

The BPU retained a consultant that gathered detailed and comprehensive information from New Jersey’s EDCs, including PSE&G, regarding resource issues and policy changes needed to interconnect the clean energy capacity required under state policy.

In June 2022, the BPU’s consultant issued a draft report with its findings and recommendations to update the BPU’s interconnection regulations and processes.

The BPU is currently considering revising its interconnection rules to speed up the interconnection of renewable resources to the distribution grid.

We cannot predict the impact on our business or results of operations from this Grid Modernization plan or any laws, rules or regulations promulgated as a result thereof, particularly as they may relate to PSE&G’s electric distribution assets.

New Jersey Solar Initiatives —Pursuant to the Clean Energy Act, the BPU was required to undertake several initiatives in connection with New Jersey’s solar energy market.

In 2019, the BPU established a “Community Solar Energy Pilot Program,” permitting customers to participate in solar energy projects remotely located from their properties, and allowing for bill credits related to that participation.

Still pending with the BPU are certain issues, including minor modifications to the community solar pilot program, discussions regarding the potential implementation of consolidated billing for the benefit of project developers and participants, and development of a cost recovery mechanism for the EDCs.

The Clean Energy Act required the BPU to close the then-existing Solar Renewable Energy Certificate (SREC) program to new applications at the earlier of June 1, 2021 or the date at which 5.1% of New Jersey retail electric sales were derived from solar.

The 5.1% threshold was attained and the SREC market was closed to new applications on April 30, 2020, with limited exceptions related to the impact of COVID-19 on projects under development.

Solar projects that failed to achieve commercial operation before April 30, 2020 may be entitled to receive transition renewable energy certificates (TRECs) for each MWh of solar production.

The New Jersey EDCs, including PSE&G, are required to purchase, using the services of a TREC administrator, TRECs from solar projects at rates set by the BPU.

In July 2021, the BPU issued an order formally establishing the Successor Solar Incentive (SuSI) Program, heavily drawing upon the predecessor TREC program, to serve as the permanent program for providing solar incentives to qualified solar electric generation facilities.

The program provides for incentive payments at prices established in the BPU’s July 2021 order in the form of SREC-IIs for each MWh generated by net-metered projects of 5 MW or less, and an annual competitive solicitation, the Competitive Solar Incentive (CSI) program, to establish SREC-II prices applicable to grid-supply projects and net-metered projects in excess of 5 MW.

The State’s EDCs have retained an administrator to acquire all of the SREC-IIs received each year by eligible solar generation projects.

Each EDC, in turn, may recover from its customers the reasonable and prudent costs for

SREC-II procurement and SREC-II administrator fees, based on its proportionate share of retail electric sales, and other costs reasonably and prudently incurred in the disposition of its SuSI obligations.

Pursuant to an order issued by the BPU in December 2022, bids for the CSI program opened on February 1, 2023 and close on March 31, 2023.

Cybersecurity

In an effort to reduce the likelihood and severity of cybersecurity incidents, we have established a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of our technology systems.

The Board of Directors, its Industrial Operations Committee (IOC) and Audit Committee, and senior management receive 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.

Our cybersecurity program is focused on the following areas:

• Board Oversight—The Board’s IOC holds the primary responsibility, as enumerated in its charter, of overseeing PSEG’s cybersecurity program.

Cybersecurity is a standing agenda item at each IOC meeting, which includes discussion on operational technology cyber risk, a cybersecurity update from the Chief Information Security Officer (CISO), and review of a corporate cybersecurity scorecard.

In addition, the IOC meets with the CISO in executive session at each meeting with no other members of management present.

• Cybersecurity Council—which is comprised of members of senior management, meets regularly to discuss emerging cybersecurity issues and maintenance of the cybersecurity scorecard to measure performance of key risk indicators.

The Cybersecurity Council ensures that senior management, and ultimately, the Board, is given the information required to exercise proper oversight over cybersecurity risks and that escalation procedures are followed.

• The Senior Vice President, Chief Information and Digital Officer has the overall responsibility for cybersecurity.

• Documented corporate practice to ensure delineated cybersecurity incidents, or potential incidents, are escalated promptly to senior management.

• Training and Awareness—Providing annual cybersecurity training for all personnel with network access, as well as additional education for personnel with access to industrial control systems or customer information systems;

and conducting phishing exercises with progressive consequences for failures.

Employees also receive periodic cybersecurity awareness messages and each October are invited to presentations throughout the month from internal and external cyber experts covering diverse cyber topics.

• Technical Safeguards—Managing controls to protect our network perimeter, internal Information Technology (IT) and Operational Technology (OT) environments, such as internal and external firewalls, network intrusion detection and prevention, penetration testing, vulnerability assessments, threat intelligence, anti-malware and access controls.

• Vendor Management—Maintaining a risk-based vendor management program, including the development of robust security contractual provisions.

• Incident Response Plans—Maintaining and updating a cyber incident response plan that addresses the life cycle of a cybersecurity incident from a technical perspective (i.e., detection, response, and recovery), as well as data breach response (with a focus on external communication and legal compliance);

and conducting regular table top exercises to test plan effectiveness (both internally and through external exercises).

• Mobile Security—Maintaining controls to prevent loss of data through mobile device channels.

PSEG also maintains physical security measures to protect its OT systems, consistent with a defense in depth and risk-tiered approach.

Such physical security measures may include access control systems, video surveillance, around-the-clock command center monitoring, and physical barriers (such as fencing, walls, and bollards).

Additional features of PSEG’s physical security program include threat intelligence, insider threat mitigation, background checks, a threat level advisory system, a business interruption management model, and active coordination with federal, state, and local law enforcement officials.

See Regulatory Issues—Federal Regulation for a discussion of Critical Infrastructure Protection standards that the NERC has promulgated that mitigate risk associated with both cybersecurity and physical security of PSEG’s critical facilities.

In addition, we are subject to federal and state requirements designed to further protect against cybersecurity threats to critical infrastructure, as discussed below.

For a discussion of the risks associated with cybersecurity threats, see Item 1A.

Risk Factors.

Federal —NERC, at the direction of FERC, has implemented national and regional reliability standards to ensure the reliability and security of the grid and to prevent major system blackouts.

NERC Critical Infrastructure Protection standards establish

cybersecurity and physical security protections for critical systems and facilities.

These standards are also designed to develop coordination, threat sharing and interaction between utilities and various government agencies regarding potential cyber and physical threats against the nation’s electric grid.

The Transportation Security Administration (TSA), an agency of the U.S.

Department of Homeland Security (DHS), has issued three security directives since May 2021 designed to mitigate cybersecurity threats to natural gas pipelines.

The first security directive requires pipeline owners/operators to (i) report actual and potential cybersecurity incidents to the Cybersecurity and Infrastructure Security Agency, a DHS agency;

(ii) designate a “Cybersecurity Coordinator;” (iii) review their current cybersecurity practices;

and (iv) identify any gaps and related remediation measures to address cyber-related risks.

The second security directive requires pipeline owners/operators to (i) implement specific mitigation measures to protect against cyber threats;

(ii) implement a cybersecurity contingency and recovery plan;

and (iii) conduct a cybersecurity architecture design review.

The third security directive requires pipeline owners/operators to (i) establish and implement a TSA-approved Cybersecurity Implementation Plan;

(ii) develop and maintain a Cybersecurity Incident Response Plan to reduce the risk of operational disruption;

and (iii) establish a Cybersecurity Assessment Program, and submit an annual plan to the TSA that describes how the entity is assessing the effectiveness of its cybersecurity measures.

The 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.

N ew Jersey Solar Initiatives —In July 2021, the BPU issued an order formally establishing the Successor Solar Incentive (SuSI) Program, heavily drawing upon the predecessor Transition Renewable Energy Certificates program, to serve as the permanent program for providing solar incentives to qualified solar electric generation facilities.

New Jersey’s EDCs role in the program is to acquire all of the Solar Renewable Energy Certificates-II received each year by eligible solar generation projects and each EDC may recover from its customers the reasonable and prudent costs incurred in the disposition of SuSI obligations.

During 2023, the BPU rejected the first round of bids for the SuSI program projects as they exceeded pre-determined, confidential price caps.

In September 2023, the BPU issued an Order opening a second round of solicitations which closes in February 2024.

In August 2023, the BPU established a permanent Community Solar Energy Program (CSEP) including eligibility requirements, registration processes, the implementation of consolidated billing for the benefit of project developers and participants and allowing for the electric and natural gas utilities to recover costs related to implementing and administering the CSEP program.

The program does not include the opportunity for utilities to develop or operate CSEP projects.

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Cybersecurity Regulation

Federal —NERC Critical Infrastructure Protection standards establish cybersecurity and physical security protections for critical systems and facilities.

These standards are also designed to promote coordination, threat sharing and interaction between utilities and various government agencies regarding potential cyber and physical threats against the nation’s electric grid.

The scope of the Critical Infrastructure Protection standards is limited to Bulk Electric System (BES) Cyber Systems that would impact the reliable operation of the BES.

PSE&G is obligated to comply with the NERC Critical Infrastructure Protection standards.

NERC Critical Infrastructure Protection standards do not apply to nuclear facilities which are instead governed by the NRC for purposes of physical and cyber security.

NRC has a number of risk-informed, performance-based security programs in place to effectively protect U.S.

commercial nuclear facilities.

The NRC has existing requirements, effective processes, and the expertise to regulate and inspect cybersecurity to ensure the federal requirements are met.

NRC has existing requirements, effective processes, and the expertise to regulate and inspect cybersecurity to ensure the federal requirements are met.

NERC continues to examine revising criteria for low-impact cyber systems, which could result in expanding the Critical Infrastructure Protection standards to a larger set of applicable cyber assets.

NRC requires operating nuclear power plant licensee and license applicants to ensure that digital computer and communication systems associated with a nuclear power plant’s safety, security, and emergency preparedness functions are protected from cyberattacks.

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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 DHS’s U.S.

Computer Emergency Response Team, and the Federal Bureau of Investigation.

Furthermore, the NRC has established liaison relationships with the intelligence and law enforcement communities to include the National Counterterrorism Center, the U.S.

Department of Homeland Security’s ( DHS) Computer Emergency Response Team, and the Federal Bureau of Investigation.

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

State —T he 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.

16 unchanged sentences

Commitments and Contingent Liabilities.

Table of Conte n t s

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.

Environmental Justice (EJ) —The New Jersey Department of Environmental Protection (NJDEP) has issued an administrative order requiring an EJ review of certain environmental permit applications pending the promulgation of final EJ regulations that will provide additional guidance.

The impacts of the NJDEP’s actions are being evaluated for both PSE&G and PSEG Power and the outcome cannot be determined at this time.

New Jersey Protecting Against Climate Threats (NJ PACT) —This NJDEP regulatory reform is expected to result in changes to existing air and land use regulations in response to anticipated impacts of climate change.

It has published proposed changes pertaining to inland flood protection which are intended to protect new development from fluvial flooding.

The final regulation is anticipated in 2023.

We continue to assess the potential impact of the NJ PACT, which could have cost implications for business operations, including the construction of new facilities or upgrades to existing utility infrastructure.

Such expenditures could materially affect the continued economic viability and/or cost to construct one or more such facilities.

Water Pollution Control

8 unchanged sentences

Site Remediation —Federal and state environmental laws and regulations require the cleanup of discharged hazardous substances.

They authorize the EPA, the NJDEP and private parties to commence lawsuits to compel clean-ups or seek reimbursement for such remediation.

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.

16 unchanged sentences

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.

Table of Conte n t s

INFORMATION ABOUT OUR EXECUTIVE OFFICERS (PSEG)

Name Age as of

December 31, 2023

Office Effective Date

1 unchanged sentence

Present Position

LaRossa 59 President and Chief Executive Officer (CEO) -PSEG (A) September 2022 to present

Chair of the Board (COB) and CEO - PSEG Power September 2022 to present

LaRossa 60 Chair of the Board (COB), President and Chief Executive Officer (CEO) - PSEG January 2023 to present

President and CEO -PSEG September 2022 to present

Chief Operating Officer (COO) - PSEG January 2020 to August 2022

COB and CEO - PSE&G September 2022 to present

COB and CEO - PSEG Power 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 and President - Services September 2022 to present

COB, CEO and President - Services September 2022 to present

President and COO - PSEG Power October 2017 to August 2022

1 unchanged sentence

COB - PSEG Long Island LLC December 2020 to August 2022

Eric Carr 48 President and COO - PSEG Power September 2022 to present

President and Chief Nuclear Officer - PSEG Nuclear LLC July 2019 to present

Vice President (VP) Hope Creek Generating Station - PSEG Nuclear LLC September 2016 to July 2019

Cregg 60 Executive Vice President (EVP) and Chief Financial Officer (CFO) - PSEG October 2015 to present

5 unchanged sentences

SVP - Delivery, Projects and Construction - PSE&G July 2014 to September 2018

VP - Delivery, Projects and Construction - PSE&G December 2010 to July 2014

Linde 59 EVP and General Counsel - PSEG July 2014 to present

1 unchanged sentence

EVP and General Counsel - PSEG Power July 2014 to present

McFeaters 64 President and Chief Nuclear Officer - PSEG Nuclear LLC May 2023 to present

SVP - Nuclear Operations - PSEG Nuclear LLC November 2020 to May 2023

Vice President (VP) - Salem Generating Station - PSEG Nuclear LLC October 2016 to November 2020

Rostiac 53 SVP - Human Resources, Chief Human Resources and Chief Diversity Officer - Services January 2020 to present

7 unchanged sentences

VP-Finance, Corporate Strategy and Planning - Services November 2017 to March 2019

VP-Finance, Holdings and Corporate Strategy and Planning - Services October 2015 to November 2017

(A) Effective January 1, 2023, in accordance with a management transition plan, Ralph A.

LaRossa became COB of PSEG.

Table of Conte n t s

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business