Item 1. BUSINESS

We were incorporated under the laws of the State of New Jersey in 1985 and our principal executive offices are located at 80 Park Plaza, Newark, New Jersey 07102. We principally conduct our business through two direct wholly owned subsidiaries, PSE&G and PSEG Power LLC (PSEG Power), each of which also has its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102.

We are an energy company with a diversified business mix. Our operations are located primarily in the Northeastern and Mid- Atlantic United States. Our business approach focuses on operational excellence, financial strength and disciplined investment. As a holding company, our profitability depends on our subsidiaries’ operating results. Below are descriptions of our two principal direct operating segments.

• 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 and related programs in New Jersey.

• PSEG Power**—A Delaware limited liability company formed in 1999 as a result of the deregulation and restructuring of the electric power industry in New Jersey. PSEG Power earns revenues from the generation and marketing of power and natural gas to hedge business risks and optimize the value of its portfolio of power plants, other contractual arrangements and oil and gas storage facilities. PSEG Power is no longer an SEC registrant; however, it continues to be consolidated and reported in PSEG’s financial statements as a wholly owned subsidiary and operating segment.

As discussed below, in 2021 PSEG Power sold its solar facilities and entered into two agreements to sell PSEG Power’s 6,750 megawatts (MW) fossil generation asset portfolio. In February 2022, we completed the sale of this fossil generation portfolio which represented an important milestone in our strategy. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information. As a result, disclosures in this Item 1 and otherwise in this document that relate solely to this 6,750 MW fossil generation asset portfolio, except for those related to certain assets and liabilities excluded from the sale transactions, primarily for obligations under environmental regulations, including possible remediation obligations under the New Jersey Industrial Site Recovery Act and the Connecticut Transfer Act, are no longer relevant.

Over the past few years, our investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G, which improves the sustainability and predictability of our earnings and cash flows. The sale of the fossil generating portfolio further alters our business mix, resulting in an even higher percentage of earnings contribution by PSE&G going forward and provides more financial flexibility.

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Our other direct wholly owned subsidiaries are: PSEG Energy Holdings L.L.C. (Energy Holdings), which holds our investments in offshore wind ventures and legacy portfolio of lease investments; 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; 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 6.5 million people, or about 70% 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.

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

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In addition to our current utility products and services, we have implemented a set of programs to encourage conservation and energy efficiency by providing energy and cost-saving measures directly to businesses and families. Our largest program, Clean Energy Future, as described below, encompasses four programs (i) Energy Efficiency; (ii) Electric Vehicle make ready charging infrastructure; (iii) Energy Cloud and (iv) Energy Storage, three of which we began implementing in 2021.

We have also implemented several programs to invest in regulated solar generation within New Jersey, including programs to help finance the installation of solar power systems throughout our electric service area, and programs to develop, own and operate solar power systems.

How PSE&G Operates

We are a transmission owner in PJM Interconnection, L.L.C. (PJM) and we provide distribution service to 2.3 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 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. 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 a Regional Transmission Operator (RTO). See Item 7. MD&A—Executive Overview of 2021 and Future Outlook.

We continue to invest in transmission projects that are included for review in the FERC-approved PJM transmission expansion process. These projects focus on reliability improvements and replacement of aging infrastructure with planned capital spending of $2.3 billion for transmission in 2022-2024 as disclosed in Item 7. MD&A—Capital Requirements.

Distribution

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. The BPU has also approved a series of PSE&G infrastructure, energy efficiency, electric vehicle and renewable energy investment programs with cost recovery through various clause mechanisms. For a discussion of proposed and approved programs, see Clean Energy Future Program below and Item 7. MD&A—Executive Overview of 2021 and Future Outlook. Our load requirements are split among residential, C&I customers, as described in the following table for 2021:

									% of 2021 Sales
			Customer Type						Electric						Gas
			Commercial						56%						37%
			Residential						35%						59%
			Industrial						9%						4%
			Total						100%						100%

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Our customer base has modestly increased since 2017, with electric and gas loads changing as illustrated in the following table:

			Electric and Gas Distribution Statistics
						December 31, 2021
						Number of Customers									Electric Sales and Firm Gas Sales (A)									Historical Annual Load Growth 2017-2021
			Electric			2.3			Million						40,163			Gigawatt hours (GWh)						(0.7)%
			Gas			1.9			Million						2,422			Million Therms						0.5%

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

Electric sales declined due to the economic impact of the ongoing coronavirus pandemic (COVID-19) on commercial usage, greater conservation, more energy efficient appliances and increases in solar net metering installations, partially offset by an increase in residential sales due to a significant number of customers working from home during the pandemic and customer growth. Firm gas sales increased due to higher residential sales due to the pandemic, customer growth and customer response to continued low gas prices. 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 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.

Clean Energy Future (CEF) Program

We have launched three of the four components of our CEF program:

• Energy Efficiency (EE)**—a $1 billion three-year commitment with the majority of the investment occurring over a five-year period, approved by the BPU in September 2020, is designed to achieve energy efficiency 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)— a $707 million four-year investment, approved by the BPU in January 2021, driven by the implementation of “smart meters,” and new software and product solutions to improve our processes and better manage the electric grid.

• Electric Vehicle (EV)—a $166 million six-year investment, approved by the BPU in January 2021, 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. A remaining component of our program related to medium and heavy duty charging infrastructure has been the subject of a stakeholder process at the BPU.

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.

For additional information on the recovery of revenues, capital costs and expenses related to the CEF program, see Item 7. MD&A—Executive Overview of 2021 and Future Outlook.

Solar Generation

We have undertaken two major solar initiatives at PSE&G, the Solar Loan Program and the Solar 4 All® Programs. Our Solar Loan Program provides solar system financing to our residential and commercial customers. The loans are repaid with cash or solar renewable energy certificates (SRECs). We sell the SRECs received through periodic auctions and use the proceeds to offset program costs. Our Solar 4 All® Programs invest in utility-owned solar photovoltaic (PV) grid-connected solar systems installed on PSE&G property and third-party sites, including landfill facilities, and solar panels installed on distribution system poles in our electric service territory. We sell the energy from the systems in the PJM wholesale electricity market. In addition, we sell SRECs generated by the projects through the same periodic auction used in the Solar Loan program, the proceeds of which are used to offset program costs. In both programs, our economics are driven by our net investment in solar, with a contemporaneous return on that rate base.

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Supply

Although commodity revenues make up almost 34% of our revenues, 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 validated by the BPU, electricity prices for BGS service are set. Approximately one-third of PSE&G’s total BGS-RSCP eligible load is auctioned each year for a three-year term. For information on current prices, see Item 8. Note 15. 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.

Markets and Market Pricing

Historically, there has been significant volatility in commodity prices. Such fluctuations can have a considerable impact on us since a rising commodity price environment results in higher delivered electric and gas rates for customers. This 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.

PSEG Power

Through PSEG Power, we have sought to produce low-cost electricity by efficiently operating our nuclear and gas/oil-fired generation assets while balancing generation output, fuel requirements and supply obligations through energy portfolio management. 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 is also subject to certain regulatory requirements imposed by state utility commissions such as those in New York and Connecticut.

In June 2021, we completed the sale of PSEG Power’s solar portfolio. In August 2021, we entered into two agreements to sell PSEG Power’s 6,750 MW of fossil generation located in New Jersey, Connecticut, New York and Maryland to newly formed subsidiaries of ArcLight Energy Partners Fund VII, L.P., a fund controlled by ArcLight Capital Partners, LLC. In February 2022, we completed the sale of this fossil generation portfolio. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for further discussion.

Products and Services

As a merchant generator, our revenue is derived from selling a range of products and services under contract to an array of customers, including utilities, power marketers, such as retail energy providers, or counterparties in the open market. These products and services may be transacted bilaterally or through exchange markets and include but are not limited to:

• Energy**—the electrical output produced by generation plants that is ultimately delivered to customers for use in lighting, heating, air conditioning and operation of other electrical equipment. Energy is our principal product and is priced on a usage basis, typically in cents per kilowatt hour or dollars per megawatt hour (MWh).

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• Capacity**—distinct from energy, capacity is a market commitment that a given generation unit will be available to an Independent System Operator (ISO) for dispatch to produce energy when it is needed to meet system demand. Capacity is typically priced in dollars per MW for a given sale period (e.g. day or month).

• Ancillary Services**—related activities supplied by generation unit owners to the wholesale market that are required by the ISO to ensure the safe and reliable operation of the bulk power system. Owners of generation units may bid units into the ancillary services market in return for compensatory payments. Costs to pay generators for ancillary services are recovered through charges collected from market participants.

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. In 2014, the BPU approved an extension of the long-term BGSS contract to March 31, 2019, 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 others and uses it for its generation fleet.

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

The remainder of this section about PSEG Power covers our nuclear and fossil fleet which comprises the vast majority of PSEG Power’s operations and financial performance. For additional information, see Item 2. Properties.

How PSEG Power’s Generation Operates

Nearly all of our generation capacity is located in the Northeast and Mid-Atlantic regions of the United States in some of the country’s largest and most developed electricity markets.

• Capacity**

As of December 31, 2021, PSEG Power had 10,638 MW of nuclear and fossil generation capacity, including the fossil assets Held for Sale. The sale of our 6,750 MW of fossil generation located in New Jersey, Connecticut, New York and Maryland was completed in February 2022. Effective May 31, 2021, PSEG Power retired its 383 MW coal unit in Bridgeport, Connecticut. PSEG Power has retired or exited all of its coal-fired generation.

• Generation Dispatch**

Our generation units have historically been characterized as serving one or more of three general energy market segments: base load; load following; and peaking, based on their operating capability and performance.

• Base Load Units** run the most and typically are called to operate whenever they are available. These units generally derive revenues from both energy and capacity sales. 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. Our nuclear generation is considered to be base load.

• Load Following Units’** operating costs are generally higher per unit of output than for base load units due to the use of higher-cost fuels such as oil and natural gas or lower overall unit efficiency. These units usually have more flexible operating characteristics than base load units which enable them to more easily follow fluctuations in load. They operate less frequently than base load units and derive revenues from energy, capacity and ancillary services.

• Peaking Units** run the least amount of time. These units typically start very quickly in response to system needs. Costs per unit of output tend to be higher than for base load units given the combination of higher heat rates and fuel costs. The majority of revenues are from capacity and ancillary service sales. The characteristics of these units enable them to capture energy revenues during periods of high energy prices.

In the energy markets in which we operate, owners of power plants specify to the ISO prices at which they are prepared to generate and sell energy based on the marginal cost of generating energy from each individual unit. The ISOs will generally dispatch in merit order, calling on the lowest variable cost units first and dispatching progressively higher-cost units until the point that the entire system demand for power (known as the system “load”) is satisfied reliably. Base load units are dispatched first, with load following units next, followed by peaking units. It should be noted that the sustained lower pricing of natural gas over the past several years has resulted in changes in relative operating costs compared to historical norms, enabling some gas-fired generation to displace some generation by other fuel types. This change, combined with the addition of new, more

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efficient generation capacity, has altered the historical dispatch order of certain plants in the markets where we operate.

Typically, the bid price of the last unit dispatched by an ISO establishes the energy market-clearing price. After considering the market-clearing price and the effect of transmission congestion and other factors, the ISO calculates the Locational Marginal Price (LMP) for every location in the system. The ISO pays all units that are dispatched their respective LMP for each MWh of energy produced, regardless of their specific bid prices. Since bids generally approximate the marginal cost of production, units with lower marginal costs typically generate higher gross margins than units with comparatively higher marginal costs.

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 primary markets in which we operate.

Market wholesale prices may vary by location resulting from congestion or other factors, such as the availability of natural gas from the Marcellus (Leidy) and other shale-gas regions, 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.

Fuel Supply

• 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.

• Gas Supply**—Natural gas is the primary fuel for the bulk of our load following and peaking fleet. We purchase gas directly from natural gas producers and marketers. We have approximately 2.3 billion cubic feet-per-day of firm transportation capacity and firm storage delivery under contract to meet our obligations under the BGSS contract. This volume includes capacity from the Pennsylvania and Ohio shale gas regions where we purchase the majority of our natural gas. On an as-available basis, this firm transportation capacity may also be used to serve the gas supply needs of our New Jersey generation fleet. These supplies are transported to New Jersey by four interstate pipelines with which we have contracted. In addition, we hold year-round firm gas transportation capacity to serve the majority of the requirements of Keys Energy Center in Maryland.

• Oil**—Oil is used as the primary fuel for one load following steam unit and four combustion turbine peaking units and can be used as an alternate fuel by several load following and peaking units that have a dual-fuel capability. Oil for operations is drawn from on-site storage and is generally purchased on the spot market and delivered by truck or barge.

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. For additional information and a discussion of risks, see Item 1A. Risk Factors, Item 7. MD&A—Executive Overview of 2021 and Future Outlook and Item 8. Note 15. Commitments and Contingent Liabilities.

Markets and Market Pricing

All of PSEG Power’s nuclear generation assets are located within the PJM RTO. PJM conducts the largest centrally dispatched energy market in North America. The PJM Interconnection coordinates the movement of electricity through all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. PSEG Power’s fossil generation assets classified as Held for Sale as of December 31, 2021 are primarily located within PJM and also have operations within the New York ISO (NYISO) and New England (ISO-NE).

The Bethlehem Energy Center generating station operates in New York and our Bridgeport Harbor 5 and New Haven stations operate in Connecticut.

The price of electricity varies by location in each of these markets. Depending on our production and our obligations, these price differentials may increase or decrease our profitability.

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Commodity prices, such as electricity, gas, oil and environmental products, as well as the availability of our fleet of generation units to operate, have a considerable effect on our profitability. Over the long-term, the higher the forward prices are, the more attractive an environment exists for us to contract for the sale of our anticipated output. However, higher prices also increase the cost of replacement power; thereby placing us at greater risk should our generating units fail to operate effectively or otherwise become unavailable.

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 the ISO for dispatch at its discretion. Capacity payments reflect the value to the ISO of assurance that there will be sufficient generating capacity available at all times to meet system reliability and energy requirements. See Item 7. MD&A—Executive Overview of 2021 and Future Outlook—Wholesale Power Market Design.

In PJM and ISO-NE, where we operate most of our generation, the market design for capacity payments provides for a structured, forward-looking, capacity pricing mechanism through the Reliability Pricing Model (RPM) in PJM and the Forward Capacity Market (FCM) in ISO-NE. For additional information regarding FERC actions related to the capacity market construct, see Regulatory Issues—Federal Regulation.

The prices to be received by generating units in PJM for capacity have been set through RPM base residual and incremental auctions and depend upon the zone in which the generating unit is located. For each delivery year, the prices differ in the various areas of PJM, depending on the transfer limitations of the transmission system in each area.

Our PJM generating units are located in several zones. The average capacity prices that PSEG Power expects to receive from the base and incremental auctions which have been completed are disclosed in Item 8. Note 3. Revenues. The price that must be paid by an entity serving load in the various capacity zones is also set through these auctions. These prices can be higher or lower than the prices disclosed in Item 8. Note 3. Revenues due to the import and export capability to and from lower-priced areas.

We have obtained price certainty for our PJM capacity through May 2023 through the RPM pricing mechanism and New England capacity through May 2025 for New Haven through the FCM pricing mechanism.

Like PJM and ISO-NE, the NYISO provides capacity payments to its generating units, but unlike the other two markets, the New York market does not provide a forward price signal beyond a six-month auction period.

For additional information on the RPM and FCM markets, as well as on state subsidization through various mechanisms, see Regulatory Issues—Federal Regulation.

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.

Generally, we seek to hedge our output through sales at PJM West or other nodes corresponding to our generation portfolio. Sales in PJM generally reflect block energy sales at the liquid PJM Western Hub or other basis locations when available and other transactions that seek to secure price certainty for our generation related products. 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 2021, is also limited. Therefore, our realized prices in 2021 were significantly lower than market pricing due to forward sales contracts executed in prior years for delivery in 2021. For this same reason, expected realized prices in forward periods will also have limited benefits from the recent rise in forward market prices.

We ceased entering into new full requirements contracts as a hedging strategy due to the sale of the fossil generation assets. In addition, we ceased hedging the fossil generation assets in 2022 due to the sale. As defined in the sales agreements, any positive or negative cash flow from the fossil generating assets based on actual performance starting after December 31, 2021 will result in an adjustment to the purchase price. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for more information.

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 2022 and a significant portion through 2023.

More than 90% of PSEG Power’s expected gross margin in 2022 from the expected remaining generation assets after the sale of the fossil generation portfolio relates to our hedging strategy, our expected revenues from the capacity market mechanisms

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described above, Zero Emission Certificate (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 three years are as follows:

			Base Load Generation						2022						2023						2024
			Generation Sales						95%-100%						85%-90%						45%-50%

Energy Holdings

Energy Holdings maintains our interests in offshore wind as well as a portfolio of domestic lease investments. See Item 8. Note 9. Long-Term Investments and Note 10. Financing Receivables for additional information.

Offshore Wind

In December 2020, PSEG entered into a definitive agreement with Ørsted North America Inc. (Ørsted) to acquire a 25% equity interest in Ørsted’s Ocean Wind project. Ocean Wind was selected by New Jersey to be the first offshore wind farm as part of the State’s intention to add 7,500 MW of offshore wind generating capacity by 2035. The Ocean Wind project is expected to achieve full commercial operation in 2025. On March 31, 2021, the BPU approved PSEG’s investment in Ocean Wind and the acquisition was completed in April 2021. 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 and Ørsted are exploring further opportunities to develop the remaining GSOE lease area. For information on potential additional offshore wind projects, see Item 7. MD&A—Executive Overview of 2021 and Future Outlook.

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. PSEG LI uses its brand in the Long Island T&D service area. 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. An amendment to the OSA was negotiated in 2021 and is pending approval by the New York State Comptroller. See Item 7. MD&A—Executive Overview of 2021 and Future Outlook.

COMPETITIVE ENVIRONMENT

PSE&G

Our T&D business is not affected when customers choose alternate electric or gas suppliers since we earn our return by providing T&D service, not by supplying the commodity. Based on our transmission formula rate and the CIP program for electric and gas distribution, we are also minimally impacted by changes in customers’ usage. Our growth is driven by (i) our investment program to deliver energy more reliably by modernizing our electric transmission and electric and gas distribution system and (ii) investing in programs that help deliver cleaner energy, including our energy efficiency programs to help customers use less energy and investment programs to build EV infrastructure and solar generation. 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, and other factors. While there is not a substantial amount of net metered generation in our territory, a growing amount, and/or other changes in customer usage behavior could lead to a smaller base of customer usage to recover our costs, resulting in higher rates overall. Conversely, an increase in EV adoption and other factors could lead to an increase in system usage, require incremental investments to meet higher peak demands and result in a larger customer usage base. There is also an expected shift toward greater electrification and less gas usage in the coming decades, 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. 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 to our current period revenue as compared to revenue thresholds established in our most

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

Changes in the current policies for building new transmission lines, such as those ordered by FERC and being implemented by PJM and other ISOs to eliminate contractual provisions that previously provided us a “right of first refusal” to construct 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. 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:

• merchant generators,

• domestic and multi-national utility generators,

• energy marketers and retailers,

• private equity firms, banks and other financial entities,

• fuel supply companies, and

• affiliates of other industrial companies.

New additions of lower-cost or more efficient generation capacity, as well as subsidized generation capacity, could make our plants less economic in the future. Such capacity could impact market prices and our competitiveness.

Our business is also under competitive pressure due to demand-side management (DSM) and other efficiency efforts aimed at changing the quantity and patterns of usage by consumers which could result in a reduction in load requirements. A reduction in load requirements can also be caused by economic cycles, weather and climate change, municipal aggregation and other customer migration and other factors. In addition, how resources such as demand response and capacity imports are permitted to bid into the capacity markets also affects the prices paid to generators such as PSEG Power in these markets. It is also possible that advances in technology, such as distributed generation and micro grids, will reduce the cost of alternative methods of producing electricity to a level that is competitive with that of most central station electric production. To the extent that additions to the electric transmission system relieve or reduce limitations and constraints in eastern PJM where most of our plants are located, our revenues could be adversely affected. Changes in the rules governing what types of transmission will be built, who is selected to build transmission and who will pay the costs of future transmission could also impact our generation revenues.

Adverse changes in energy industry law, policies and regulation could have significant economic, environmental and reliability consequences. For example, PJM, NYISO and ISO-NE each have capacity markets that have been approved by FERC. FERC regulates these markets and continues to examine whether the market design for each of these three capacity markets 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 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, such as restrictions on emissions of carbon dioxide (CO2) and other pollutants, may also have a competitive impact on us to the extent that it becomes more expensive for some of our plants to remain compliant, thus affecting our ability to be a lower-cost provider compared to competitors without such restrictions. In addition, most of our plants, which are located in the Northeast where rules are more stringent, can be at an economic disadvantage compared to our competitors in certain Midwest states.

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

At PSEG, our workforce is essential in delivering on our business objectives. Our human capital management strategy is integrated with our overall environmental, social, and governance (ESG) leadership objectives and is designed to attract, develop, and retain a high performing workforce and evolve our culture to sustain our business, both today and in the future. PSEG maintains a consistent focus on a culture of inclusion and operational excellence that supports its employees, customers

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and the many diverse communities we serve. Our workforce is guided by our core commitments of safety, integrity, diversity, equity and inclusion (DEI), customer service and continuous improvement.

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 DEI, workforce development and succession planning.

PSEG has a fundamental commitment to human rights and as a responsible corporate citizen and leader in the energy field, we remain steadfast in our commitment to treating people with dignity and respect at all times. We are determined to maintain the high standards of ethical conduct on which our business and reputation have been built. In every aspect of our operations, we are committed to protecting and advancing human rights.

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

In 2021, of our external hires, 19% were women and 31% were racially and/or ethnically diverse. PSEG’s workforce is stable with a voluntary attrition rate of 6.0%. Retirement comprises the majority of that figure, occurring at a rate of 3.7% with resignation making up the remaining 2.3%. The average employee tenure is 14 years.

Health and Safety

We are committed to protecting the health and safety of our employees, contractors and the communities that we serve. We demonstrate our commitment each day by providing the tools and skill building needed to ensure employees are able to perform their work safely. Every employee is empowered and encouraged to question, stop and correct any unsafe act or condition while communicating openly and honestly on health and safety issues. 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. PSEG’s Occupational Safety and Health Administration (OSHA) Recordable Incident Rate decreased from 0.85 in 2020 to 0.70 in 2021 and the OSHA Days Away from Work Rate also decreased from 12.68 in 2020 to 5.63 in 2021. Both metrics are top decile performance against the industry benchmark.

Culture, Diversity, Equity and Inclusion

We are committed to fostering a culture of belonging and equity, where diversity is celebrated and inclusion is the norm. The four strategic pillars of our DEI program are inclusive leadership, driving change at the site-specific level, equitable policies and practices and union partnership. In 2021, PSEG released its first DEI report providing transparent disclosures on the company’s Inclusion for All strategy and initiatives, including launching Neurodiversity Works, a program to provide access to employment at PSEG for neurodivergent individuals, publishing a formal LGBTQ+ Inclusion Pledge and job creation programs with worker diversity goals and commitments for supplier diversity.

Our 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 continuously solicit feedback from employees through focus groups, listening sessions throughout the year and our annual Your Voice Matters employee experience survey. Employee engagement scores for 2021 averaged 84%, indicating employees are proud to work at PSEG, had meaningful work and intend to stay.

Talent, Attraction, Development and Engagement

From our frontline employees to our leadership roles, PSEG has maintained an unwavering focus on attracting, developing and retaining a robust talent pipeline to remain competitive and to continue to provide our customers with the highest standard of service.

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PSEG’s relationships with minority-serving institutions, trade schools and community partners attract a skilled workforce that reflects the communities we serve and all dimensions of diversity represented in those communities, including race, ethnicity, disability, parental status, LGBTQ+, and those with socioeconomic challenges.

Our employees grow through a variety of training and development opportunities at all career tracks within the organization and 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 identify and develop diverse talent pools for critical technical and leadership positions.

As we accelerate our business to a primarily regulated utility and contracted energy business with carbon-free generation and infrastructure investment, PSEG is committed to a fair, equitable and transparent approach to human capital management, one that is grounded in treating people with dignity and respect. With evolving technologies in energy and digital advancements, we look for training, upskilling and redeployment opportunities for our existing workforce.

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. Our programs include access to therapy, childcare and eldercare resources, voluntary benefits for discounted services, tuition reimbursement and adoption assistance.

Labor Relations

We are proud of the partnership we have with union leadership and the approximately 7,900 employees represented by unions in our workforce. Our strong relationship with our unions allowed for swift and effective implementation of temporary COVID-19 protocols, policies and practices, as well as negotiation of permanent agreements, such as telecommuting that support PSEG’s reimagined vision of more flexible work. In 2021, we launched our Union DEI & Culture Council to focus on issues impacting represented employees and improving the workplace culture at PSEG. In 2021, we also extended additional labor contracts through 2023, providing labor stability during the pendency of key business initiatives.

COVID-19 Response for Our Employees

We continued to anticipate and respond to changing circumstances in year two of the pandemic. In addition to remote work and enhanced benefits enacted in 2020, during 2021 employees were assisted in scheduling vaccination appointments and were provided on-site vaccination at various locations. All employees hired after October 2021 are required to be vaccinated subject to certain accommodation exceptions. We provide COVID-19 related paid time off for employees to take care of themselves and their family members, to get vaccinated, recover from side effects of the COVID-19 vaccine, to navigate school and daycare closures and for bereavement. We also implemented changes to medical and retirement savings plans made available through federal relief packages. PSEG’s Medical and Health and Safety team continues to provide consistent, up-to-date information to educate employees on current conditions.

The pandemic response hotline that was put in place in 2020 continued to provide up-to-date guidance to employees addressing questions about their COVID-19-related health and safety, providing identification and notification of close contact exposure, and offering clinical assessments to determine quarantine needs and appropriate return-to-work procedures.

In September 2021, PSEG opened offices for voluntary re-entry, as part of providing a sustained, reimagined way of working that is supported by a set of practices that enable us to work, live and hire responsibly. As COVID-19 conditions evolve, PSEG continues to monitor Centers for Disease Control and Prevention and OSHA guidance and updates its Job Hazard Analyses and protocols accordingly in order to protect our employees and the communities we serve.

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 15. Commitments and Contingent Liabilities. In addition, information regarding PSE&G’s specific filings pending before the BPU is discussed in Item 8. Note 7. 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 the generation and energy trading 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

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corporate reorganizations.

FERC also regulates RTOs/ISOs, such as PJM, and their energy and capacity markets.

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 with FERC.

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

Over the past few years, PSEG has advocated for enhanced price formation rules in PJM so that generators receive better price signals in the energy market. An example of such an improvement has been in the area of fast-start pricing. Specifically, over the past two years, FERC ordered, and PJM then fully implemented as of September 2021, rules that allow fast-start resources with quick ramping capability to set prices in the energy market.

In May 2020, FERC issued an order approving PJM’s proposal to modify the curves used for pricing reserves with FERC. However, in December 2021, FERC determined that certain aspects of PJM’s reserve reforms, in particular the reserve penalty factors and the two-step operating reserve demand curves were unjust and unreasonable. As a result, generators would not receive higher revenues associated with the mechanisms proposed by PJM. Given FERC’s finding, FERC reinstated the backward-looking energy and ancillary services offset which is an input in capacity offer bids. As a result, FERC directed PJM to propose a new auction schedule for the upcoming base residual auction. In February, FERC approved PJM’s filing requesting that the auction be held in June 2022.

In January 2020, New Jersey rejoined the Regional Greenhouse Gas Initiative (RGGI). As a result, generating plants operating in New Jersey that emit CO2 emissions will have to procure credits for each ton that they emit. Other PJM states in RGGI are Maryland, Delaware and Virginia and Pennsylvania continues to investigate joining. PJM initiated a process in 2019 to investigate the development of a carbon pricing mechanism to mitigate the environmental and financial distortions that could occur when emissions “leak” from non-participating states to the RGGI states. PJM has halted the process. Proposals to consider the incorporation of environmental attributes into the market are now being addressed as part of PJM’s capacity market design reform efforts.

Capacity Market Issues

PJM, NYISO and ISO-NE each have capacity markets that have been approved by FERC. FERC regulates these markets and continues to examine whether the market design for each of these three capacity markets 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 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 designs.

PJM—The RPM is the locational installed capacity market design for the PJM region, including 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 December 2019, FERC issued an order establishing new rules for PJM’s capacity market. In this new order, FERC extended the PJM Minimum Offer Price Rule (MOPR), which currently applies to new natural gas-fired generators, to include both new and existing resources that receive or are entitled to receive certain out-of-market payments, with certain exemptions.

In July 2021, PJM submitted to FERC a proposal to replace the extended MOPR with new provisions that 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 would not be subject to the MOPR. In September 2021, FERC issued a notice that it

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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 will apply to the next base residual auction, which has been delayed until June 2022.

In November 2021, a group of generators challenged the new MOPR rules in the Court of Appeals for the Third Circuit on the grounds that FERC’s inaction was unlawful. PSEG has intervened in the proceeding in support of the new MOPR rules. 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 could result in lower capacity prices for other market participants, including PSEG, and therefore, lower revenues for PSEG since market offers for many resource types will need to be approved by the Independent Market Monitor and PJM.

ISO-NE—ISO-NE’s market for installed capacity in New England provides fixed capacity payments for generators, imports and demand response. The market design consists of a forward-looking auction for installed capacity that is intended to recognize the locational value of resources on the system and contains incentive mechanisms to encourage availability during stressed system conditions. ISO-NE also employs a mechanism, similar to PJM’s Capacity Performance mechanism, that provides incentives for performance and that imposes charges for non-performance during times of system stress. We view this mechanism as generally positive for generating resources as providing more robust income streams. However, it also imposes additional financial risk for non-performance.

NYISO—NYISO operates a short-term capacity market that provides a forward price signal only for six months into the future. Various matters pending before FERC could affect the competitiveness of this market and the outcome of these proceedings could result in artificial price suppression for PSEG and other market participants unless sufficient market protections are adopted.

Transmission Regulation

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

Transmission Rate Proceedings and ROE—From time to time, various matters are pending before FERC relating to, among other things, transmission planning, reliability standards and transmission rates and returns, including incentives. Depending on their outcome, any of these matters could materially impact our results of operations and financial condition.

In October 2021, FERC approved a settlement agreement effective August 1, 2021 between PSE&G, the BPU and the New Jersey Division of Rate Counsel (New Jersey Rate Counsel) related to the level of PSE&G’s base transmission ROE and other formula rate matters. The settlement reduces PSE&G’s base ROE from 11.18% to 9.9% and makes several other changes regarding the recovery of certain costs. The agreement provides that the settling parties will not seek changes to PSE&G’s transmission formula rate for three years. We have implemented the terms of the agreement and PJM issued refunds to customers in January 2022.

In a rulemaking proceeding, 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 could reduce PSE&G’s annual Net Income and annual cash inflows by approximately $30 million-$40 million.

Compliance

**Reliability Standards—**Congress has required FERC to put in place, through the North American Electric Reliability Corporation (NERC), national and regional reliability standards to ensure the reliability of the U.S. electric transmission and generation system (grid) and to prevent major system blackouts. As a result, under NERC’s physical security standard, approved by FERC in 2015, utilities are required to identify critical substations as well as develop threat assessment plans to be reviewed by independent third parties. In our case, the third-party is PJM. As part of these plans, utilities can decide or be required to build additional redundancy into their systems. This standard supplements the Critical Infrastructure Protection standards that are already in place and that establish physical and cybersecurity protections for critical systems. FERC directed NERC to develop a new reliability standard to provide security controls for supply chain management associated with the procurement of industrial control system hardware, software, and services related to grid operations. FERC approved the supply chain management standard in October 2018, with an implementation date of October 1, 2020. We have documented procedures and implemented new processes to comply with these standards.

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The NERC is currently examining revised criteria for low-impact cyber systems, which could result in expanding the Critical Infrastructure Protection standards to a larger set of applicable cyber assets. This examination is expected to be completed in 2022**.**

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 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. We are currently subject to recordkeeping and data reporting requirements applicable to commercial end users. The CFTC finalized new rules establishing federal position limits for trading in certain commodities, such as natural gas. Entities such as PSEG began complying with the rules on January 1, 2022.

Nuclear

Nuclear Regulatory Commission (NRC)

Our operation of nuclear generating facilities is subject to comprehensive regulation by the NRC, a federal agency established to regulate nuclear activities to ensure the protection of public health and safety, as well as the environment. Such regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety 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 nuclear generating unit may operate. The NRC conducts ongoing reviews of nuclear industry operating 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

State Regulation

Our principal state regulator is the BPU, which oversees electric and natural gas distribution companies (GDCs) 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. PSE&G’s participation in solar, EV and energy efficiency 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.

In addition to base rates, we recover certain costs or earn on certain investments pursuant to mechanisms known as adjustment clauses. These clauses permit the flow-through of costs to, or the recovery of investments from, customers related to specific programs, outside the context of base rate proceedings. Recovery of these costs or investments is subject to BPU approval for which we make periodic filings. Delays in the pass-through of costs or recovery of investments under these mechanisms could result in significant changes in PSE&G’s cash flow.

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. The EMP recognizes the goals of New Jersey’s Clean Energy Act of 2018 (the Clean Energy Act) to achieve, by 2026, annual reductions of electric and gas consumption of at least 2% and 0.75%, respectively, of the average of the prior three years of retail sales. The EMP outlines several strategies, including statewide energy efficiency programs; expansion of renewable generation (solar and offshore wind), energy storage and other carbon-free technologies; preservation of existing nuclear generation; electrification of the transportation sector; and reduced reliance on natural gas. 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 and gas generating stations and PSE&G’s electric transmission and gas distribution assets. We also cannot predict what actions federal government

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agencies may take in light of the Environmental Protection Agency’s (EPA) Affordable Clean Energy (ACE) rule and other federal initiatives associated with climate change or the impact of any such actions on our business or results of operations.

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 conducted public hearings. PSE&G and other interested parties answered the BPU’s questions regarding capacity procurement (e.g. timing, price, sufficiency); the sufficiency of New Jersey’s pipeline capacity; cost impacts if GDCs were to be required to secure incremental capacity for their transportation customers; and economic benefits to residential customers. The consultant’s November 2021 report found that through 2030, firm gas capacity can meet firm demand under normal winter weather conditions. In extreme weather, the consultant projected a system shortfall by 2030, unless New Jersey meets half of its building electrification goals and/or has effective voluntary demand reduction with higher energy efficiency program targets. The BPU may hold additional meetings to develop recommendations. The proceeding remains open.

BGS Process—In July 2021, the State’s electric distribution companies (EDCs), including PSE&G, filed their annual proposal for the conduct of the February 2022 BGS auction covering energy years 2023 through 2025. In prior years, the BPU and BGS suppliers had expressed concerns regarding transmission costs incurred by BGS participants that are collected from customers but not paid to the BGS suppliers due to several unresolved proceedings at FERC. To address these concerns, in their July 2020 BGS filings, the EDCs proposed, among other things, to (a) remove transmission from the BGS product in the upcoming 2021 BGS auction, and (b) amend existing BGS contracts to transfer responsibility for transmission-through the transfer of specific PJM billing line items-from the BGS supplier to the EDCs. In both cases, each EDC would continue to collect transmission costs from its BGS customers as a supply cost. In November 2020, the BPU approved both proposals. As a result, beginning with the 2021 BGS auction, (a) the BGS product excluded the obligation for the BGS suppliers to provide transmission and (b) BGS suppliers had the option to amend existing BGS contracts to transfer the supplier’s obligation to provide transmission to the EDCs effective February 1, 2021. In November 2020, the BPU also directed the EDCs to enter into agreements with BGS suppliers pursuant to which the EDCs would pay to BGS suppliers certain funds collected from BGS customers notwithstanding the absence of final FERC Orders in certain cases in which transmission cost allocations have been challenged. Previously, the EDCs had collected these funds from customers but withheld payment of these funds to BGS suppliers until the issuance of a final FERC Order. As security to the EDCs, in the event that the cost allocation challenges are ultimately successful and BGS suppliers must return the funds to the EDCs, the BGS suppliers must post a letter of credit in an amount equal to 50% of the payment due the suppliers. Those BGS suppliers that do not choose to receive such funds are not required to enter into agreements or post letters of credit with the EDCs.

EV Activity—Consistent with the policy set forth in New Jersey’s EMP, the BPU has supported electrification of the transportation sector. EDCs in New Jersey, including PSE&G, are making investments, approved by the BPU for recovery in rates, initially focused on light duty vehicles, such as preparatory work to deliver infrastructure to the EV charging point. In June 2021, the BPU issued a straw proposal for the establishment of an EV infrastructure ecosystem for medium and heavy duty EVs in New Jersey, and conducted a series of stakeholder meetings to discuss that ecosystem. Although we cannot predict the outcome of the stakeholder process, we anticipate that this effort will result in opportunities for EDCs to target infrastructure investments for the medium and heavy duty EV market.

Grid Modernization—In October 2021, the BPU commenced a stakeholder proceeding to develop and implement a systemic Grid Modernization plan in accordance with strategies outlined in the New Jersey EMP. The BPU has retained a consultant that is gathering 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. 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 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 are 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,

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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 Solar Renewable Energy Certificates (SREC-IIs) for each MWh generated by net-metered projects of 5 MW or less, and an annual competitive solicitation 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. The SuSI Program commenced on August 28, 2021.

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 information systems. The Board of Directors, the Audit Committee, Industrial Operations 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:

• Governance

• Cybersecurity Council—which is comprised of members of senior management, meets regularly to discuss emerging cybersecurity issues and maintenance of a corporate 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.

• Internal and external cybersecurity advisors who have expertise in technology security, compliance and controls, or in management practices provide the Chief Operating Officer with periodic cybersecurity assessments of PSEG.

• Training—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. Regular cybersecurity education is also provided to our Board through management reports and presentations by external subject matter experts.

• Technical Safeguards—Deploying measures to protect our network perimeter and internal Information Technology platforms, 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. Notably, in 2020, we implemented additional measures to ensure compliance with new requirements promulgated by the NERC applicable to cyber systems involved in the operation of the Bulk Electric System (BES). These new or enhanced measures require PSEG to identify and assess risks to the BES from vendor products or services.

• Incident Response Plans—Maintaining and updating incident response plans that address 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 testing those plans (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 Operational Technology 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

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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 on physical reliability standards that the NERC has promulgated.

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 of the grid and to prevent major system blackouts. NERC Critical Infrastructure Protection standards establish cybersecurity 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 threats against the nation’s electric grid.

The Transportation Security Administration, an agency of the U.S. Department of Homeland Security (DHS), issued two security directives in 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.

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. It is difficult to project future costs of compliance and their impact on competition. Capital costs of complying with known pollution control requirements are included in our estimate of construction expenditures in Item 7. MD&A—Capital Requirements. The costs of compliance associated with any new requirements that may be imposed by future regulations are not known, but may be material.

For additional information related to environmental matters, including proceedings not discussed below, as well as anticipated expenditures for installation of pollution control equipment, hazardous substance liabilities and fuel and waste disposal costs, see Item 1A. Risk Factors and Item 8. Note 15. Commitments and Contingent Liabilities.

Air Pollution Control

Our facilities are subject to federal regulation under the Clean Air Act (CAA) that requires controls of emissions from sources of air pollution and imposes recordkeeping, reporting and permit requirements. Our facilities are also subject to requirements established under state and local air pollution laws. The CAA requires all major sources, such as our generation facilities, to obtain and keep current an operating permit. The costs of compliance associated with any new requirements that may be imposed and included in these permits in the future could be material and are not included in our estimates of capital expenditures.

Environmental Justice—In September 2020, the New Jersey governor signed legislation that enacted an environmental justice process for applicants seeking environmental permits, including those emission permits regulated under Title V of the CAA, for facilities located in what the law defines as overburdened communities. In September 2021, the New Jersey Department of Environmental Protection (NJDEP) issued an administrative order requiring an environmental justice review of certain permit applications pursuant to the New Jersey Environmental Justice (EJ) Law. The order will remain in effect until implementing regulations under the EJ Law are promulgated, which are expected to be issued as early as Spring 2022. The impacts of the NJDEP’s action are being evaluated for both PSE&G and PSEG Power and the outcome cannot be determined at this time.

Hazardous Air Pollutants (HAPS) Regulation—In February 2012**,** the EPA published Mercury Air Toxics Standards (MATS) for both newly-built and existing electric generating sources under the National Emission Standard for Hazardous Air Pollutants provisions of the CAA. The MATS established allowable levels for mercury as well as other HAPS and went into effect in April 2015. In April 2016, the EPA released the final Supplemental Finding that considers the materiality of costs in

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determining whether to regulate HAPS from power plants in response to a ruling by the U.S. Supreme Court. The 2016 Supplemental Finding determined that HAPS from existing electric generating units should be regulated and that the environmental and health benefits derived from the reduction in emissions of both HAPS and co-benefit pollutants far outweighed the cost of compliance. Industry participants and various state authorities filed petitions with the D.C. Circuit challenging the EPA’s Supplemental Finding.

In May 2020, the EPA finalized a revised Supplemental Finding that reversed the 2016 Supplemental Finding, concluding that it was not “appropriate and necessary” to regulate HAPS from electric generating sources. However, the EPA retained the emission standards and other requirements of MATS. A major coal mining company filed a lawsuit to force the EPA to vacate MATS. We have filed as intervenors to the coal mining company’s suit to challenge the company’s attempt to vacate MATS. In addition, we have joined a challenge against the EPA’s revised Supplemental Finding in the D.C. Circuit Court. In January 2022, the EPA released a proposed rule that would reverse the May 2020 Supplemental Finding. We cannot predict the outcome of this matter.

Climate Change

CO****2 Regulation under the CAA—In June 2019, the EPA issued its final ACE rule as a replacement for the repealed Clean Power Plan, a greenhouse gas (GHG) emission regulation for existing power plants. The ACE rule narrowly defines the “best system of emissions reductions” (BSER) as heat improvements to be applied only to an individual unit, excluding other potential mechanisms to address climate change. In September 2019, a coalition of power companies, including PSEG, filed a Petition for Review of the ACE rule with the D.C. Circuit challenging the EPA’s narrow interpretation of BSER. In January 2021, the D.C. Circuit vacated the ACE rule and remanded the rulemaking to the EPA for further consideration. In April 2021, a 19-state coalition, led by West Virginia, filed a petition with the U.S. Supreme Court to review the D.C. Circuit’s decision to vacate the ACE Rule. In October 2021, the U.S. Supreme Court agreed to review the 2021 D.C. Circuit’s decision vacating the ACE Rule. We cannot predict the outcome of this matter or estimate its impact on our business or results of operations.

RGGI—Certain northeastern states (RGGI States) participate in the RGGI and have state-specific rules in place to enable the RGGI regulatory mandate in each state to cap and reduce CO2 emissions. Generating plants operating in RGGI states that emit CO2 will have to procure credits for each ton that they emit. The post-2020 program cap on regional CO2 emissions for RGGI requires a decline in CO2 emissions in 2021 and each year thereafter, resulting in a 30% reduction in the CO2 emissions cap by 2030.

In June 2019, the NJDEP issued two rules that began New Jersey’s re-entry into RGGI. The first rule established New Jersey’s initial cap on GHG emissions of 18 million tons in 2020. This rule follows the RGGI model rule with a cap that will decline three percent annually through 2030 to a final cap of 11.5 million tons. The second rule established the framework for how credits will be allocated among the New Jersey Economic Development Authority, the BPU and the NJDEP. In April 2020, the State issued a final three-year Strategic Funding Plan that determines how quarterly RGGI credits are to be allocated. New Jersey facilities became subject to RGGI on January 1, 2020. With New Jersey’s re-entry into RGGI, we have generation facilities in four of the RGGI States, specifically New Jersey, New York, Maryland and Connecticut.

New Jersey adopted the Global Warming Response Act in 2007, which calls for stabilizing its GHG emissions to 1990 levels by 2020, followed by a further reduction of greenhouse emissions to 80% below 2006 levels by 2050. To reach this goal, the NJDEP, the BPU, other state agencies and stakeholders are required to evaluate methods to meet and exceed the emission reduction targets, taking into account their economic benefits and costs. Following the close on the sale of the fossil generating assets, PSEG no longer has generation subject to the RGGI compliance requirements.

New Jersey Protecting Against Climate Threats (NJ PACT)—In response to a New Jersey Executive Order, the NJDEP has undertaken a regulatory reform effort that is designed to modernize environmental laws, referred to as NJ PACT. When implemented, NJ PACT is expected to result in changes to existing environmental regulation, modernizing air quality and environmental land use regulations that will enable governments, businesses and residents to effectively respond to current climate threats and reduce future climate damages. In June 2021, the NJDEP took the first step by publishing the Proposed Greenhouse Gas Monitoring and Reporting Rule. The NJDEP proposes to require gas utilities to submit an annual report on replacement of mains and service lines in the State and to quantify maintenance-venting events, referred to as blowdown events. In addition, the NJDEP is proposing registration, recordkeeping, and reporting requirements for facilities with a refrigeration system requiring 50 pounds or more of a refrigerant with high global warming potential. A “refrigeration system” includes industrial process refrigeration utilized at our nuclear facility. 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.

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Water Pollution Control

The Federal Water Pollution Control Act (FWPCA) prohibits the discharge of pollutants to U.S. waters from point sources, except pursuant to a National Pollutant Discharge Elimination System (NPDES) permit issued by the EPA or by a state under a federally authorized state program. The FWPCA authorizes the imposition of technology-based and water quality-based effluent limits to regulate the discharge of pollutants into surface waters and ground waters. The EPA has delegated authority to a number of state agencies, including those in New Jersey, New York and Connecticut, to administer the NPDES program through state action. We also have ownership interests in facilities in other jurisdictions that have their own laws and implement regulations to control discharges to their surface waters and ground waters.

The EPA’s Clean Water Act (CWA) Section 316(b) rule establishes requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. The EPA requires that the NPDES permits be renewed every five years and that each state Permitting Director manage renewal permits for its respective power generation facilities on a case by case basis. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.

Hazardous Substance Liability

The production and delivery of electricity and the distribution and manufacture of gas result in various by-products and substances classified by federal and state regulations as hazardous. These regulations may impose liability for damages to the environment, including obligations to conduct environmental remediation of discharged hazardous substances and monetary payments, regardless of the absence of fault, any contractual agreements between private parties, and the absence of any prohibitions against the activity when it occurred, as well as compensation for injuries to natural resources. Our historic operations and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by federal and state agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex. The EPA is also evaluating the Hackensack River, a tributary to Newark Bay, for inclusion in the Superfund program. We no longer manufacture gas.

Site Remediation—The Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and the New Jersey Spill Compensation and Control Act (Spill Act) require the remediation of discharged hazardous substances and authorize the EPA, the NJDEP and private parties to commence lawsuits to compel clean-ups or 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.

Natural Resource Damages—CERCLA and the Spill Act authorize the assessment of damages against persons who have discharged a hazardous substance, causing an injury to natural resources. Pursuant to the Spill Act, the NJDEP requires persons conducting remediation to address injuries to natural resources through restoration or damages. The NJDEP adopted regulations concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites.

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 United States Department of Energy (DOE) has set the nuclear waste fee rate at 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 formed the Atlantic Compact, which gives New Jersey nuclear generators continued access to the Barnwell waste disposal facility which is owned by South Carolina. We believe that the Atlantic Compact will provide for adequate low-level radioactive waste disposal for Salem and Hope Creek through the end of their current licenses including full decommissioning, although no assurances can be given. Low-Level Radioactive Waste is periodically being shipped to the Barnwell site from Salem and Hope Creek. Additionally, there are on-site storage facilities for Salem, Hope Creek and Peach Bottom, which we believe have the capacity for at least five years of temporary storage for each facility.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS (PSEG)

Name						Age as of December 31, 2021						Office						Effective Date First Elected to Present Position
Ralph Izzo						64						Chairman of the Board (COB), President and Chief Executive Officer (CEO) - PSEG						April 2007 to present
												COB and CEO - PSE&G						April 2007 to present
												COB and CEO - PSEG Power						April 2007 to present
												COB and CEO - Energy Holdings						April 2007 to present
												COB and CEO - Services						January 2010 to present
Daniel J. Cregg						58						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
Ralph A. LaRossa						58						COB - PSEG Long Island LLC						December 2020 to present
												Chief Operating Officer (COO) - PSEG						January 2020 to present
												President and COO - PSEG Power						October 2017 to present
												President and COO - PSE&G						October 2006 to October 2017
												COB - PSEG Long Island LLC						October 2013 to October 2017
Kim C. Hanemann						58						President and COO - PSE&G						June 2021 to present
												Senior Vice President (SVP) and COO - PSE&G						January 2020 to June 2021
												SVP - Electric Transmission and Distribution - PSE&G						September 2018 to January 2020
												SVP - Delivery, Projects and Construction - PSE&G						July 2014 to September 2018
												Vice President (VP) - Delivery, Projects and Construction - PSE&G						December 2010 to July 2014
Tamara L. Linde						57						EVP and General Counsel - PSEG						July 2014 to present
												EVP and General Counsel - PSE&G						July 2014 to present
												EVP and General Counsel - PSEG Power						July 2014 to present
Rose M. Chernick						58						VP and Controller - PSEG						March 2019 to present
												VP and Controller - PSE&G						March 2019 to present
												VP and Controller - PSEG Power						March 2019 to present
												VP-Finance, Corporate Strategy and Planning - Services						November 2017 to March 2019
												VP-Finance, Holdings and Corporate Strategy and Planning - Services						October 2015 to November 2017

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