All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized or even if realized, will have the expected consequences to, or effects on, us or our business, prospects, financial condition, results of operations or cash flows. Readers are cautioned not to place undue reliance on these forward-looking statements in making any investment decision. Forward-looking statements made in this report apply only as of the date of this report. While we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even in light of new information or future events, unless otherwise required by applicable securities laws.

This combined Annual Report on Form 10-K is separately filed by Public Service Enterprise Group Incorporated (PSEG) and Public Service Electric and Gas Company (PSE&G). Information relating to any individual company is filed by such company on its own behalf. PSE&G is only responsible for information about itself and its subsidiaries.

Discussions throughout the document refer to PSEG and its direct operating subsidiaries. Depending on the context of each section, references to “we,” “us,” and “our” relate to PSEG or to the specific company or companies being discussed.

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may obtain our filed documents from commercial document retrieval services, the SEC’s internet website at www.sec.gov or our website at https://investor.pseg.com. Information on our website should not be deemed incorporated into or as a part of this report. Our Common Stock is listed on the New York Stock Exchange under the trading symbol PEG. You can obtain information about us at the offices of the New York Stock Exchange, Inc., 11 Wall Street, New York, New York 10005.

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 withconsisting primarily of a diversifiedregulated electric and gas utility and a nuclear generation business. Over the past few years, our investments resulted in a higher percentage of earnings contribution by PSE&G. The sale of the fossil generating portfolio further simplified our business mix. mix, resulting in an even higher percentage of earnings contribution by PSE&G going forward and provides more financial flexibility.

Our operations are located primarily in the Northeastern and Mid- AtlanticMid-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.subsidiaries.

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;investments and interests in offshore wind ventures; PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under a contractual agreement; and PSEG Services Corporation (Services), which provides us and our operating subsidiaries with certain management, administrative and general services at cost.

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.

Our utility operations primarily earn margins through:

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 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).an RTO. See Item 7. MD&A—Executive Overview of 20212022 and Future Outlook.

We continue to invest in transmission projects that are included for review in theas part of PJM’s FERC-approved PJM transmission expansion planning process. These projects focus on reliability improvements and replacement of aging infrastructure with planned capital spending of $2.3$1.8 billion for transmission in 2022-20242023-2025 as disclosed in Item 7. MD&A—Capital Requirements.    

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 (CEF-EE) filing, we implemented the Conservation Incentive Program (CIP) that trues up PSE&G’s margin to a baseline per customer from our 2018 base rate case for the majority of our customers. As a result, electric gas sales volumes and demands are no longer a driver of our margin and over 90% of our Electric and Gas Distribution margin will only vary based upon the number of customers.

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.

See Item 7. MD&A—Executive Overview of 20212022 and Future Outlook.Outlook for additional information.

Although commodity revenues make up almost 34% of our revenues, weWe 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.

Historically, there has been significant volatility in commodity prices. Such fluctuations can have a considerable impact on us since aA rising commodity price environment results in higher delivered electric and gas rates for customers. Thiscustomers, which could result in decreased demand for electricity and gas, increased regulatory pressures and greater working capital requirements as the collection of higher commodity costs from our customers may be deferred under our regulated rate structure. A declining commodity price, on the other hand, would be expected to have the opposite effect.

Through PSEG Power, we have sought to produce low-cost electricity by efficiently operating our nuclear and gas/oil-fired generation assets while balancing generation output, fuel requirements and natural gas 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.

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

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 2014,2022, the BPU approved an extension of the long-term BGSS contract to March 31, 2019,2027, and thereafter the contract remains in effect unless terminated by either party with a two-year notice.

Approximately 47% of PSE&G’s peak daily gas requirements is provided from PSEG Power’s firm gas transportation capacity. PSEG Power satisfies the remainder of PSE&G’s requirements from storage contracts, contract peaking supply, liquefied natural gas and propane. Based upon the availability of natural gas beyond PSE&G’s daily needs, PSEG Power sells gas to othersother customers and uses it for its generation fleet.shares these proceeds with PSE&G’s customers.

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

Nearly allAs of December 31, 2022, PSEG Power had 3,766 MW of nuclear generation capacity. All of our nuclear generation capacity is located in the Northeast and Mid-Atlantic regionsregion of the United States in someone of the country’s largest and most developed electricity markets.

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

In the energy markets in which we operate,PJM, 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 onTypically, the lowest variable cost units first and dispatching progressively higher-cost units untilbid price of the point thatlast unit dispatched by PJM establishes 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, moreenergy market-clearing price.

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

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 20212022 and Future Outlook and Item 8. Note 15. Commitments and Contingent Liabilities.

All of PSEG Power’s nuclear generation assets are located within the PJM RTO. PJM conductsPrior to the largest centrally dispatched energy market in North America. The PJM Interconnection coordinates the movementsale 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’sits fossil generation assets, classified as Held for Sale as of December 31, 2021 are primarily located within PJM andPSEG Power also have operationshad significant sales within the New York ISO (NYISO) and New England ISO (ISO-NE).

Commodity prices, such as electricity, gas, oil and environmental products, as well as the availability of our fleet of nuclear generation units to operate, have a considerable effect on our profitability. Over the long-term, the higher the forward energy prices are, the more attractive an environment exists for us to contract for the sale of our anticipated output. However, higher pricesa rising price environment, such as what has been experienced in the past year, also increaseincreases 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 ISOPJM for dispatch at its discretion. Capacity payments reflect the value to the ISOPJM 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 20212022 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.

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.energy output. Although we enter into these hedges to provide price certainty for a large portion of our anticipated generation, there is variability in both our actual output as well as in the effectiveness of our hedges. Our hedging practices help to manage some of the volatility of the merchant power business. While this limits our exposure to decreasing prices, our ability to realize benefits from rising market prices, as experienced in 2021,the past two years, is also limited. Therefore, our realized prices in 20212022 were significantly lower than market pricing due to forward sales contracts executed in prior years for delivery in 2021.2022. For this same reason, expected realized prices in forward periods will also havebe limited benefits from the recent rise into when hedges were transacted and not based upon forward market prices.

In August 2022, the Inflation Reduction Act (IRA) was signed into law expanding incentives promoting carbon-free generation. The enacted legislation established the production tax credit (PTC) for electricity generation using nuclear energy set to begin in 2024 through 2032. PSEG Power’s Salem 1, Salem 2, Hope Creek, Peach Bottom 2 and Peach Bottom 3 nuclear plants will each benefit from the PTC. The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts. The PTC rate and the gross receipts cap are subject to annual inflation adjustments. The U.S. Treasury is expected to clarify the definition of gross receipts prior to when the eligibility period begins in 2024. We ceased entering into new full requirements contracts as a hedging strategy dueare continuing to analyze the saleimpact 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 flowIRA on our nuclear units, including additional future guidance from the fossil generating assets basedU.S. Treasury, potential impacts on actual performance starting after December 31, 2021 will result in an adjustment tohedging strategies and the purchase price. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for more information.impact of PTCs on expected ZEC payments.

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 20222024 and a significant portion through 2023.2025.

More than 90% of PSEG Power’s expected gross margin in 20222023 from the expected remainingnuclear generation assets after the sale of the fossil generation portfolio relates to our energy hedging strategy, our expected revenues from the capacity market mechanisms

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

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

In December 2020, PSEG entered into a definitive agreement with Ørsted North America Inc. (Ørsted) to acquireholds a 25% equity interest in Ørsted’sØrsted North America Inc.’s (Ørsted) Ocean Wind project. Ocean Wind was selected by New Jersey1 project which is currently in development. In January 2023, PSEG agreed to be the first offshore wind farm as part of the State’s intentionsell 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 investmentØrsted its 25% equity interest in Ocean Wind 1. The sale is not contingent upon Ørsted electing to proceed to the construction phase of the project. The sale is contingent upon finalization of a purchase and sale agreement with Ørsted and other closing conditions as well as any potential state regulatory approval that may be required to close on the acquisition was completed in April 2021. transaction.

In accordance with a twelve year Operations Services Agreement (OSA) entered into by PSEG LI and LIPA, PSEG LI commenced operating LIPA’s electric T&D system in Long Island, New York on January 1, 2014. Following the effects of Tropical Storm Isaias, LIPA and PSEG LI uses its brandagreed to an amended OSA which became effective in 2022. The OSA contract term continues through 2025, but can be extended for five years subject to a mutual agreement of the Long Island T&D service area.parties. Under the OSA, PSEG LI acts as LIPA’s agent in performing many of its obligations and in return (a) receives reimbursement for pass-through operating expenditures, (b) receives a fixed management fee and (c) is eligible to receive an incentive fee contingent on meeting established performance metrics. Further, since January 2015, PSEG Power provides fuel procurement and power management

services to LIPA under separate agreements. An amendment toIt is uncertain whether 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. separate agreements will be renewed on terms acceptable to us or at all.

Our T&D business is not affected when customers choose alternate electric or gas suppliers since we earn our return by providingon our net investment in rate base to provide T&D service, not by supplying the commodity. Based on our transmission formula rate and the CIP program for electric and gas distribution, we are also minimally impacted by changes in customers’ usage. Our growth is driven by (i) our investment program to deliver energy more reliably by modernizing our electric transmission and electric and gas distribution system and (ii) investing in programs that help deliver cleaner energy, including our energy efficiencyEE programs to help customers use less energy and investment programs to build EV infrastructure and solar generation. There may also be opportunities to expand into related clean energy areas, such as renewable natural gas, hydrogen, energy storage, additional solar and renewables, and broader EE investments, though utility participation in these areas is subject to regulatory approval and market design, which continues to evolve. That growth can be affected by customer cost pressures which could result from higher commodity costs, higher supply costs to support subsidized renewable generation, higher operating costs, higher tax rates, macro-economic conditions including inflation, and other factors. While there is not a substantial amount of net metered generation in our territory, a growing amount, and/or other changes in customer usage behavior could lead to a smaller base of customer usage to recover our costs, resulting in higher rates overall. Conversely, an increase in EV adoption and other factors could lead to an increase in system usage, require incremental investments to meet higher peak demands and result in a larger customer usage base. There is also an expected shift toward greater electrification and less gas usage in the coming decades, 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

Changes in the current policies for building new transmission lines, such as thosepreviously 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 new transmission projects in our service territory, could result in third-party construction of transmission lines in our area in the future and also allow us to seek opportunities to build in other service territories. TheseWhile there has been minimal impact so far, these rules continue to evolve so both the extent of the risk within our service territory and the opportunities for our transmission business elsewhere remain difficult to assess.

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

Adverse changes in energy industry law, policies and regulation could have significant economic, environmental and reliability consequences. For example, PJM NYISO and ISO-NE each havehas a capacity marketsmarket that havehas been approved by FERC. FERC regulates these marketsthis market and continues to examine whether thethis market design for each of these three capacity markets is working optimally. PJM itself often changes capacity market rules, which can cause uncertainty for market participants. Various forums are considering how the competitive market framework can incorporate or be reconciled with state public policies that support particular resources, resource attributes or emerging technologies, whether generators are being sufficiently compensated in the capacity market and whether subsidized resources may be adversely affecting capacity market prices. For information regarding recent actions by FERC relating to capacity market design, see the discussion in Regulatory Issues—Federal Regulation.

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 objectivesgoals and is designed to support our ability to attract, develop, and retain a high performing diverse workforce and evolveto continue building on our culture of inclusion to sustain our business, both today and in the future. PSEG maintainsWe strive for a consistent focus on a culture of inclusionfair, equitable and operational excellence that supports its employees, customers

In 2021,2022, of our external hires, 19%including temporary employees, 23% were women and 31%40% were racially and/or ethnically diverse. PSEG’s workforce is stable with a voluntary attrition rate of 6.0%. Retirement comprisesfor the majority of that figure, occurring at a rate of 3.7% with resignation making up the remaining 2.3%year was 6.5% (3.3% retirements and 3.2% resignations). The average employee tenure is 14 years.

We are committed toemphasize the priority of protecting the health, safety and safetywell-being of our employees, contractors and the communities that we serve. We demonstrate our commitment each daythis by providing the tools and skill building neededsupport to ensure employees are able to perform their work safely. Every employeeso that everyone is empowered and encouraged to question, stop and correct any unsafe act or condition while communicating openly and honestly on health and safety issues.condition. In the event that there is a safety issue, our employees take responsibility for the accurate, honest, and timely reporting of all incidents and injuries. To hold ourselves accountable, we have annual performance goals related to compliance with health and safety policies, practices and procedures. 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.

We are committed to fosteringaspire for a culture of belonging and equity, where diversity is celebrated and inclusion is the norm. The four strategic pillars ofSince publishing 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 disclosuresin 2021, we have continued to build on the company’sour Inclusion for All strategystrategy. Our DEI program combines individual and initiatives, including launching Neurodiversity Works, a program to provide access to employment at PSEG for neurodivergent individuals, publishing a formal LGBTQ+ Inclusion Pledgesite-specific efforts with leadership development and job creation programs with worker diversity goals and commitments for supplier diversity.training activities.

Our 12 Employee Business Resource Groups support key business goals and priorities; help build meaningful connections through community outreach and volunteerism, mentorship and professional development; elevate diverse perspectives; and create spaces for employees to learn from each other.

Our initiatives to advance DEI includes doing business with certified minority, women, veteran & LGBT-owned businesses and maintaining a supplier diversity process that is integrated into our company culture. PSEG achieved its goal to spend 30% with diverse suppliers by 2023 in 2021, averaged 84%, indicating employees are proud to work at PSEG, had meaningful work and intend to stay.two years ahead of schedule.

Our employees grow through a variety of training and development opportunities at all career tracks within the organizationoffered to individual contributors, front line supervisors, managers and weleaders. 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 poolsprepare for critical technical and leadership positions.the future of work.

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.

We are proud of the partnership we have with union leadership across our six unions and the approximately 7,900 employees represented by unionsthey represent in our workforce. OurWe believe 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 employeeswork model and improving the workplace culture at PSEG. In 2021, we also extended additional labor contracts through 2023, providing labor stability during the pendency of keyother mid-term agreements that support strategic objectives and business initiatives.

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.

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 tradingcertain operating subsidiaries of PSEG Power are public utilities as defined by the FPA. FERC has extensive oversight over such public utilities. FERC approval is usually required when a public utility seeks to: sell or acquire an asset that is regulated by FERC (such as a transmission line or a generating station); collect costs from customers associated with a new transmission facility; charge a rate for wholesale sales under a contract or tariff; or engage in certain mergers and internal

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

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.

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 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.

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

The NRC has the ultimate authority to determine whether any U.S. nuclear generating unit may operate. The NRC conducts ongoing reviews of nuclear industry operatingoperations 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:

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. PSE&G’s participation in solar, EV and EE programs is also regulated by the BPU, as the terms and conditions of these programs are approved by the BPU. BPU regulation can also have a direct or indirect impact on our power generation business as it relates to energy supply agreements and energy policy in New Jersey.

agencies may take in lightand expand upon the existing EMP and consider recent state and federal policies and how federal funding can provide additional support for advancement 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.critical clean energy policies.

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 SRECSolar Renewable Energy Certificate (SREC) program to new applications at the earlier of June 1, 2021 or the date at which 5.1% of New Jersey retail electric sales arewere 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,

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)SREC-IIs for each MWh generated by net-metered projects of 5 MW or less, and an annual competitive solicitation, the Competitive Solar Incentive (CSI) program, to establish SREC-II prices applicable to grid-supply projects and net-metered projects in excess of 5 MW. The State’s EDCs have retained an administrator to acquire all of the SREC-IIs received each year by eligible solar generation projects. Each EDC, in turn, may recover from its customers the reasonable and prudent costs for

SREC-II procurement and SREC-II administrator fees, based on its proportionate share of retail electric sales, and other costs reasonably and prudently incurred in the disposition of its SuSI obligations. The SuSI Program commencedPursuant to an order issued by the BPU in December 2022, bids for the CSI program opened on August 28, 2021.February 1, 2023 and close on March 31, 2023.

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 informationtechnology systems. The Board of Directors, the Audit Committee,its Industrial Operations Committee (IOC) and Audit Committee, and senior management receive frequent reports on such topics as personnel and resources to monitor and address cybersecurity threats, technological advances in cybersecurity protection, rapidly evolving cybersecurity threats that may affect us and our industry, cybersecurity incident response and applicable cybersecurity laws, regulations and standards, as well as collaboration mechanisms with intelligence and enforcement agencies and industry groups, to assure timely threat awareness and response coordination.

Our cybersecurity program is focused on the following areas:

PSEG also maintains physical security measures to protect its Operational TechnologyOT 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

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.

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

The Transportation Security Administration (TSA), an agency of the U.S. Department of Homeland Security (DHS), has issued twothree security directives insince May 2021 designed to mitigate cybersecurity threats to natural gas pipelines. The first security directive requires pipeline owners/operators to (i) report actual and potential cybersecurity incidents to the Cybersecurity and Infrastructure Security Agency, a DHS agency; (ii) designate a “Cybersecurity Coordinator;” (iii) review their current cybersecurity practices; and (iv) identify any gaps and related remediation measures to address cyber-related risks. The second security directive requires pipeline owners/operators to (i) implement specific mitigation measures to protect against cyber threats; (ii) implement a cybersecurity contingency and recovery plan; and (iii) conduct a cybersecurity architecture design review. The third security directive requires pipeline owners/operators to (i) establish and implement a TSA-approved Cybersecurity Implementation Plan; (ii) develop and maintain a Cybersecurity Incident Response Plan to reduce the risk of operational disruption; and (iii) establish a Cybersecurity Assessment Program, and submit an annual plan to the TSA that describes how the entity is assessing the effectiveness of its cybersecurity measures.

ENVIRONMENTAL MATTERS

We are subject to federal, state and local laws and regulations with regard to environmental matters. ItOur associated obligations change as legislatures and regulators pass new laws and regulations and amend existing ones. Therefore, it is difficult to project future costs of compliance and their impact on competition. Capital costs of complying with known pollution control requirements are included in our estimate of construction expenditures in Item 7. MD&A—Capital Requirements. The costs of compliance associated with any new requirements that may be imposed by future regulations are not known, but may be material.

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

Our facilities are subject to federal, state and local 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.

The Federal Water Pollution Control Act (FWPCA) prohibits the discharge of pollutants to U.S. waters from point sources to water, except pursuant to a National Pollutant Discharge Elimination System (NPDES) permitduly 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 limitspermit. These permits must generally be renewed every five years. Applicable regulations also impose obligations on facility operators like PSEG Power to regulate the discharge of pollutants into surface waters and ground waters. The EPA has delegated authorityinstall certain technology 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 havetreat their own laws and implement regulations to control discharges to their surface waters and ground waters.ensure discharges meet certain water quality requirements.

The EPA’sEnvironmental Protection Agency’s (EPA) Clean Water Act (CWA) Section 316(b) rule establishes requirements for the regulation of cooling water intakes at existing power plants, 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.such as Salem. 

The productionPSEG’s operations involve substances and delivery of electricity and the distribution and manufacture of gas result in various by-products and substancesbyproducts classified by federal and stateenvironmental regulations as hazardous. These regulations mayimpose handling, storage and disposal requirements for hazardous materials. They also 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.cash penalties.

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.

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

Our business plan calls for extensive investment in capital improvements and additions, including the construction of T&D facilities, modernizing existing infrastructure pursuant to investment programs that provide for current recovery in rates, and our CEF programs, which include providing incentives for customers to install high-efficiency equipment at their premises, constructing EV infrastructure, and implementing our smart meter program. Currently, we have several significant projects underway or being contemplated.

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

In addition, the successful operation of new solar or wind or upgraded generation facilities or transmission or distribution projects is subject to risks relating to supply interruptions; labor availability, work stoppages and labor disputes; weather interferences; unforeseen engineering and environmental problems, including those related to climate change; opposition from local communities, and the other risks described herein. Further, negative public and political views on natural gas could result in diminishing political support for utility investments in gas infrastructure.

Any of these risks could cause our return on these investments to be lower than expected or they could cause these facilities to operate below intended targets, which could adversely impact our financial condition and results of operations through lost revenue and/or increased expenses.

Climate change may increasingly drive change to existing or additional legislation and regulation that may impact our business and shape our customers’ energy preference and sustainability goals. While the CIP protects margin variances against changes in customer usage of gas and electricity, customer demand for ournatural gas could decrease as a result of changing customer preferences favoring electrification and advanced technologies that offer energy efficient options. Electric usage could also be impacted by greater adoption of EVs, installation of distributed energy resources, such as behind the meter solar, installation of

more energy efficient equipment, flexible load and/or energy storage, and other advances in technology. Further, climate change may adversely impact the economy and reduced economic and consumer activity in our service areas could reducelower demand for electricity and gas we deliver. Fluctuations in weather can also affect demand for our services. For example, milder than normal weather can reduce demand for electricity and gas distribution services. AllAny one or all of these factors could impact the need to invest in our electric and gas T&D systems and, therefore, the rate of growth of our company.

Severe weather or acts of nature, including hurricanes, winter storms, earthquakes, floods and other natural disasters can stress systems, disrupt operation of our facilities and cause service outages, production delays and property damage that require incurring additional expenses. These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining generation facilities and T&D systems, resulting in increased maintenance and capital costs (and potential increased financing needs), increased regulatory oversight, and lower customer satisfaction. Where recovery of costs to restore service and repair damaged equipment and facilities is available, any determination by the regulator not to permit timely and full recovery of the costs incurred could have a material adverse effect on our businesses, financial condition, results of operations and prospects.

Climate change-related political pressureaction and state and federal policy goals, including but not limited to those related to energy efficient targets, solar targets, energy storage targets, encouragement of electrification through EV adoption, home heating,policies to restrict the use of natural gas in new or existing homes and businesses, or encourage electrification of end use equipment currently fueled by natural gas, and the associated legislative and regulatory responses, may create financial risk as our operations may be subject to additional regulation at either the state or federal level in the future. Increased regulation of GHG emissions could impose significant additional costs on our electric and natural gas operations, and our suppliers. Developing and implementing plans for compliance with GHG emissions reduction, clean/renewable energy requirements, or for achieving voluntary climate commitments can lead to additional capital, personnel, and Operation and Maintenance (O&M) expenditures and could significantly affect the economic position of existing operations and proposed projects. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply increasingly rigorous regulatory mandates, it could have a material adverse effect on our results of operations, financial condition or cash flows. On the other hand, in the event that the political, policy, regulatory or legislative support for clean energy projects declines, the benefits or feasibility of certain investments we may have made in such projects, including those in the development stage, may be reduced.

We are also exposed to the risk of pandemics, such as the ongoing coronavirus pandemic, which could result in service disruptions and delay or otherwise impair our ability to timely provide service to our customers or complete our investment projects.

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

In addition, the effects of climate change will exacerbatehave increased the physical risks to our facilities and operations resulting from such climate hazards as more severe weather events (extreme wind, rainfall and flooding), such as experienced from Superstorm Sandy and Tropical Storms Isaias and Ida, sea level rise, and extreme heat. Such

Any of the issues described above, if experienced at our facilities, or by others in our industry, could adversely impact our revenues; increase costs to repair and maintain our systems; subject us to potential litigation and/or damage claims, fines or penalties; and increase the level of oversight of our utility and generation operations and infrastructure

Long-lived assets represent approximately 70%74% and 83%82% of the total assets of PSEG and PSE&G, respectively, as of December 31, 2021.2022. Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, including a disallowance of certain costs, business climate or market conditions, including prolonged periods of adverse commodity and capacity prices, could potentially indicate an asset’s or group of assets’ carrying amount may not be recoverable. Significant reductions in our expected revenues or cash flows for an extended period of time resulting from such events could result in future asset impairment charges, which could have a material adverse impact on our financial condition and results of operations.

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

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

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

We and our third-party vendors have been and will continue to be subject to cybersecurity attacks, including but not limited to ransomware, denial of service, business email compromises, and malware attacks. While there has been no material impact on our business or operations from these attacks to date, we may be unable to prevent all such attacks in the future from having such a material impact as such attacks continue to increase in sophistication and frequency. If a significant cybersecurity event or breach occurs within our company or with one of our material vendors, we could be exposed to significant loss of revenue, material repair costs to intellectual and physical property, significant fines and penalties forif determined that we were in non-compliance with existing laws and regulations, significant litigation costs, increased costs to finance our businesses, negative publicity, damage to our reputation and loss of confidence from our customers, regulators, investors, vendors and employees. The misappropriation, corruption or loss of personally identifiable information and other confidential data from us or one of our vendors could lead to significant breach notification expenses, mitigation expenses such as credit monitoring, and legal and regulatory fines and penalties. Moreover, new or updated security laws or regulations or unforeseen threat sources could require changes in current measures taken by us and our business operations, which could result in increased costs and adversely affect our financial statements. Similarly, a significant cybersecurity event or breach experienced by a competitor, regulatory authority, RTO, ISO, or vendor could also materially impact our business and results of operations via enhanced legal and regulatory requirements. The amount and scope of insurance we maintain against losses that result from cybersecurity incidents may not be sufficient to cover losses or adequately compensate for resulting business disruptions. For a discussion of state and federal cybersecurity regulatory requirements and information regarding our cybersecurity program, see Item 1. Business—Regulatory Issues—Cybersecurity.

In response to the ongoing global coronavirus pandemic, we have implemented a comprehensive set of actions to help our customers, communities and employees, and will continue to closely monitor developments and adjust as needed to ensure reliable service while protecting the safety and health of our workforce and the communities we serve.

PSE&G, PSEG Power and PSEG LI are providing essential services during this national emergency related to the coronavirus pandemic. The pandemic’s potential impact will depend on a number of factors outside of our control, including the duration and severity of the outbreak as well as third-party actions, including governmental requirements,requirements. Pursuant to a BPU order, we have deferred a significant amount of costs for future recovery. Any inability to obtain timely recovery of these costs could have a material adverse effect on our business. Further, a number of expanded customer protection measures have been implemented by the State and the BPU, such as an extended moratorium on shut-offs of residential service for non-payment, and more extensive processes to be taken prior to containany shut-off of service. These actions have negatively affected customer payment patterns, leading to an elevated aged accounts receivable balance. Our ability to manage our accounts receivable balance, recover its spreadcarrying costs and mitigate its public health effects.any associated bad debts could have a material impact on our business. We currently cannot estimate the potential impact the ongoing coronavirus pandemic may have on our business, results of operations, financial condition, liquidity and cash flows. However a prolonged outbreakThe impacts of the pandemic and associated government and regulatory responses, including the long-term impact they may have on the economy, which could extend beyond the duration of the pandemic, could affect, among other things:

Certain events such as an aging workforce looking to retire without adequatean opportunity to transfer knowledge to a successor, inadequate workforce plans and replacements, a lack of skill set to complementmeet current and evolving business needs, a culture that does not foster inclusion leading to turnover, a workforce strike resulting from a failure to successfully negotiate new collective bargaining agreements with our labor strike andunions on mutually acceptable terms or at all, unavailability of resources due to health impacts or protocol mandates related to the COVID-19coronavirus pandemic, acts of violence in the workplace and a workforce that is not engaged may lead to operating challenges and increased costs. The challenges include loss of knowledge and a lengthy time period associated with skill development, increased turnover, costs for contractors to replace employees, andpoor productivity, and safety costs.a lack of innovation. Specialized knowledge isand experience are required of the technicalemployees across PSEG and support employees for our carbon-free infrastructure investments and generation and T&D operations.its affiliates. There is competition and a tightening market for these skilled employees. Failure to hire and adequately train and retain employees, including the transfer of significant historical knowledge and expertise to new employees, or future availability and cost of contract labor may adversely affect our results of operations, financial position and cash flows.

Inflation has recently increased across the economy and is impacting portions of our business. Higher costs from suppliers of equipment and materials, fuel, services and labor costs to attract and retain our workforce, could lead to increased costs, which

could reduce our earnings. Also, seeking recovery of higher costs in future rate cases could pressure customer rates, resulting in a potentially adverse outcome of such proceedings, or in other proceedings, including the proposal of certain investment programs or other proceedings that impact customer rates.

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

The performance of the financial markets will affect the value of the assets that are held in trust to satisfy our future obligations under our defined benefit plans and to decommission our nuclear generating plants. A decline in the market value of our NDT Fund could increase PSEG Power’s funding requirements to decommission its nuclear plants. A decline in the market value of the defined benefit plan trust funds could increase our pension plan funding requirements.requirements and result in increased pension costs in future years. The market value of our defined benefit plan trusts could be negatively impacted by decreases inadverse financial market conditions that reduce the rate of return on trust assets, decreased interest rates used to measure the required minimum funding levels, and future government regulation. Additional funding requirements for our defined benefit plans could be caused by changes in required or voluntary contributions, an increase in the number of employees becoming eligible to retire and changes in life expectancy assumptions. IncreasedA decline in the market value of our NDT Fund could increase PSEG Power’s funding requirements to decommission its nuclear plants. An increase in projected costs could also lead to additional funding requirements for our

We obtain substantially all of our physical natural gas and nuclear fuel supply from third parties pursuant to arrangements that vary in term, pricing structure, firmness and delivery flexibility. Our fuel supply arrangements must be coordinated with

We are exposed to increases in the price of natural gas and nuclear fuel, and it is possible that sufficient supplies to operate our generating facilities profitably may not continue to be available to us. Significant changes in the price of natural gas and nuclear fuel could affect our future results and impact our liquidity needs. In addition, we face risks with regard to the delivery to, and the use of natural gas and nuclear fuel by, our power plants including the following:

Our nuclear units have a diversified portfolio of contracts and inventory that provide a substantial portion of our fuel raw material needs over the next several years. However, each of our nuclear units has contracted with a single fuel fabrication services provider, and transitioning to an alternative provider could take an extended period of time. Certain of our other generation facilities also require fuel or other services that may only be available from one or a limited number of suppliers. The availability and price of this fuel may vary due to supplier financial or operational disruptions, transportation disruptions, force majeure and other factors, including market conditions. At times, such fuel may not be available at any price, or we may not be able to transport it to our facilities on a timely basis. In this case, we may not be able to run those facilities even if it would be profitable. If we had sold forward the power from such a facility, we could be required to supply or purchase power from alternate sources, perhaps at a loss. This could have a material adverse impact on our business, the financial results of specific plants and on our results of operations.

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

operations. While our generation runs on a mix of fuels, primarily natural gas and nuclear fuel, an increase in the cost of any particular fuel ultimately used by other generation facilities could impact our results of operations.

The power generation business has seen a substantial change in the technologies used to produce power. Newer generation facilities are often more efficient than aging facilities, which may put some of these older facilities at a competitive disadvantage to the extent newer facilities are able to consume the same or less fuel to achieve a higher level of generation output. Federal and state incentives for the development and production of renewable sources of power have facilitated the penetration of competing technologies, such as wind, solar, and commercial-sized power storage. Additionally, the development of DSM and energy efficiencyEE programs can impact demand requirements for some of our markets at certain times during the year. The continued development of subsidized, competing on-site power generation and storage technologies and significant development of DSM and energy efficiencyEE programs could alter the market and price structure for power generation and could result in a reduction in load requirements, negatively impacting our financial condition, results of operations and cash flows. Technological advances driven by federal laws mandating new levels of energy efficiencyEE in end-use electric devices or other improvements in, or applications of, technology could also lead to declines in per capita energy consumption.

Advances in distributed generation technologies, such as fuel cells, micro turbines, micro grids, windmills and net-metered solar installations, may reduce the cost of alternative methods of producing electricity to a level that is competitive with that of most central station electric production. Large customers, such as universities and hospitals, continue to explore potential micro grid installation. Certain states, such as Massachusetts and California, are also considering mandating the use of power storage resources to replace uneconomic or retiring generation facilities. Such developments could (i) affect the price of energy, (ii) reduce energy deliveries as customer-owned generation becomes more cost-effective, (iii) require further improvements to our distribution systems to address changing load demands, and (iv) make portions of our transmission and/or distribution facilities obsolete prior to the end of their useful lives. These technologies could also result in further declines in commodity prices or demand for delivered energy.

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

We sell generation output and buy fuel through the execution of bilateral contracts. We also seek to contract in advance for a significant proportion of our anticipated output capacity and fuel needs. These contracts are subject to credit risk, which relates to the ability of our counterparties to meet their contractual obligations to us. Any failure of these counterparties to perform could require PSEG Power to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, which could have a material adverse impact on our results of operations, cash flows and financial position. In the spot markets, we are exposed to the risks of the default sharing mechanisms that exist in those markets, some of which

A substantial portion of PSEG Power’s base loadnuclear generation output has been sold forward under fixed price financial power sales contracts and PSEG Power also sells forwardcontracts. Forward financial sales offset physical sales in the output from its intermediate and peaking facilities when it deems it commercially advantageous to do so.PJM RTO spot market. Our forward sales of energy and capacity assume sustained, acceptable levels of operating performance. This is especially important at our lower-cost facilities. Operations at any of our plants could degrade to the point where the plant has to shut down or operate at less than full capacity. Some issues that could impact the operation of our facilities are:

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

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

In addition, as market prices for energy and fuel fluctuate, our forward energy sale and forward fuel purchase contracts could require us to post substantial additional collateral, thus requiring us to obtain additional sources of liquidity during periods when our ability to do so may be limited.

We depend on transmission facilities owned and operated by others to deliver the wholesale power we sell from our generation facilities. If transmission is disrupted or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be adversely impacted. If a region’s power transmission infrastructure is inadequate, our recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in transmission infrastructure. We also cannot predict whether transmission facilities will invest in specific markets to accommodate competitive access to those markets.

In addition, in certain of the markets in which we operate,PJM, energy transmission congestion risk and associated costs exist. We may occurnot be able to accurately predict and we may be deemed responsible forhedge this risk due to insufficient market data and liquidity. An increase in our congestion costs if we schedule delivery of power between congestion zones during times when congestion occurs between the zones. If we were liable for such congestion costs,may adversely affect our financial results could be adversely affected.

PSE&G is subject to regulation by the BPU. Such regulation affects almost every aspect of its businesses, including its retail rates. Failure to comply with these regulations could have a material adverse impact on PSE&G’s ability to operate its business

In September 2020, the BPU ordered the commencement of a comprehensive affiliate and management audit of PSE&G. The BPU also conducts periodic combined management/competitive service audits of New Jersey utilities related to affiliate standard requirements, competitive services, cross-subsidization, cost allocation and other issues. A finding by the BPU of non-compliance with these requirements could potentially impact our business, results of operations and cash flows. For information regarding PSE&G’s current affiliate and management audit, see Item 8. Note 15. Commitments and Contingent Liabilities. In addition, PSE&G procures the supply requirements of its default service BGSS gas customers through a full-requirements contract with PSEG Power. Government officials, legislators and advocacy groups are aware of the affiliation between PSE&G and PSEG Power. In periods of rising utility rates, those officials and advocacy groups may question or challenge costs and transactions incurred by PSE&G with PSEG Power, irrespective of any previous regulatory processes or approvals underlying those transactions. The occurrence of such challenges may subject PSEG Power to a level of scrutiny not faced by other

unaffiliated competitors in those markets and could adversely affect retail rates received by PSE&G in an effort to offset any perceived benefit to PSEG Power from the affiliation.

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

In April 2021, FERC issued a supplemental notice of proposed rulemaking to eliminate the incentive for RTO membership for transmitting utilities that have already received the incentive for three or more years. PSE&G began receiving a 50 basis point adder for RTO membership in 2008. Elimination of the adder for RTO membership couldwould reduce PSE&G’s annual Net Income and annual cash inflows by approximately $30 million-$40 million.

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

In May 2021, the New Jersey Rate Counsel filed an appeal with the New Jersey Appellate Division of the BPU’s April 2021 decision. PSEG cannot predict the outcome of these matters.

If the markets, PTC and/or the ZEC program is overturned or is otherwise materially adversely modified through legal process; or (ii) any of the Salem 1, Salem 2 and Hope Creek plants isdo not sufficiently valued for its environmental, fuel diversity or resilience attributes in future periods and does not otherwise experience a material financial change that would remove the need for such attributes to be sufficiently valued, PSEG Power will take all necessary steps to cease to operate all of these plants. Alternatively, even withprovide sufficient valuation of these attributes, if the financial condition of the plants is materially adversely impacted by changes in commodity prices, FERC’s changes to the capacity market construct (absent sufficient capacity revenues provided under a program approved by the BPU in accordance with a FERC-authorized capacity mechanism),revenue, or, in the case of the Salem nuclear plants, decisions by the EPA and state environmental regulators regarding the implementation of Section 316(b) of the Clean Water Act (CWA)CWA and related state regulations, or other factors, PSEG Power willmay take all necessary steps to cease to operate all of these plants.plants and will incur associated costs and accounting charges in the event that the financial condition of the plants is materially adversely impacted in the future. Ceasing operations of these plants would result in a material adverse impact on PSEG’s results of operations.

The energy industry continues to be regulated and the rules to which our businesses are subject are always at risk of being changed. Our business has been impacted by established rules that create locational capacity markets in each of PJM, ISO-NE

Further, some of the market-based mechanisms in which we participate are at times the subject of review or discussion by some of the participants in the New Jersey and federal arenas. We can provide no assurance that these mechanisms will continue to exist in their current form, nor otherwise be modified.

ToIn July 2021, the extentBPU issued a report on its investigation related to whether New Jersey can achieve its long-term clean energy and environmental objectives under the current resource adequacy procurement paradigm. The report found that additionsparticipating in the regional market is the most efficient way for New Jersey to achieve its clean energy goals and therefore consideration of leaving the regional market is paused while market reforms are being considered at the regional and national level. In

September 2022, the BPU issued a Progress Report expanding on the recommendations contained in the 2021 report. The Progress Report found that it is in New Jersey’s best interest to pursue a voluntary independent clean energy market and Staff sought the BPU’s authorization to evaluate various options that would serve as alternatives to the transmission system relievePJM capacity market or reduce congestionwork in eastern PJM where most of our plants are located, PSEG Power’s capacity and energy revenues could be adversely affected. Moreover, through changes encouraged by FERC to transmission planning processes, or through RTO/ISO initiatives to change their planning processes, more transmission mayconjunction with it. We cannot predict whether the BPU will ultimately be built to facilitate renewable generation or support other public policy initiatives. Any such addition totake any measures in the transmission system couldfuture that will have a material adversean impact on the capacity market or our financial condition and results of operations.generating stations.

Over halfThe vast majority of our total generation output each year is provided by our nuclear fleet. For this reason, we are exposed to risks related to the continued successful operation of our nuclear facilities and issues that may adversely affect the nuclear generation industry. In addition to the risk of retirement discussed below, risks associated with the operation of nuclear facilities include:

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

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

We are subject to extensive federal, state and local environmental laws and regulations regarding air quality, water quality, site remediation, land use, waste disposal, climate change impact, natural resource damages and other matters. These laws and regulations affect how we conduct our operations and make capital expenditures. WithOver the change in administration following the 2020 presidential election,past several years, there have been various recent changes to existing environmental laws and regulations and this trend may continue. Changes in these laws, or violations of laws, could result in significant increases in our compliance costs, capital expenditures to bring facilities into compliance, operating costs for remediation and clean-up actions, civil penalties or damages from actions brought by third parties for alleged health or property damages. Any such increase in our costs could have a material impact on our financial condition, results of operations and cash flows and could require further economic review to determine whether to continue operations or decommission an affected facility. We may also be unable to successfully recover certain of these cost increases through our existing regulatory rate structures, in the case of PSE&G, or our contracts with our customers, in the case of PSEG Power.

Actions by state and federal government agencies could also result in reduced reliance on natural gas and could potentially result in stranding natural gas assets owned and operated by PSEG Power and PSE&G, which could materially adversely affect our business, financial condition and results of operations.

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

In addition, PSEG Power will retainretained ownership of certain assets and liabilities excluded from the sale of its fossil generation business,portfolio. These primarily relatedrelate to obligations under environmental regulations, including possible remediation obligations under the New Jersey Industrial Site Recovery Act and the Connecticut Transfer Act. Fulfilling the requirements under these regulationsIt will spanrequire multiple years and may requirecomprehensive environmental sampling of environmental media to understand the extent of anyand to carry out the required remediation. The amounts for any such environmentalfull remediation costs are not estimable, but maywill likely be material.

Environmental laws and regulations have generally become more stringent over time, and this trend is likely to continue. For further discussion of environmental laws and regulations impacting our business, results of operations and financial condition, including the impact of federal and state laws and regulations relating to GHG emissions and remediation of environmental contamination, see Item 1. Environmental Matters and Item 8. Note 15. Commitments and Contingent Liabilities.

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

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

A prolonged coronavirus pandemic, further economic stimulus,The enactment of additional federal or future federal and state tax legislation and clarification of previously enacted tax laws could have a material impact on our effective tax rate and cash tax position.

All of our owned physical property is held by our subsidiaries. We believe that we and our subsidiaries maintain adequate insurance coverage against loss or damage to plants and properties, subject to certain exceptions and deductibles, to the extent such property is usually insured and insurance is available at a reasonable cost. For a discussion of nuclear insurance, see Item 8. Note 15. Commitments and Contingent Liabilities.

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

As of December 31, 2021,2022, PSE&G’s electric T&D system included approximately 25,000 circuit miles, and 862,000864,000 poles, of which 64% are jointly-owned. In addition, PSE&G owns and operates 5655 switching stations with an aggregate installed capacity of 39,35339,653 megavolt-amperes (MVA) and 235 substations with an aggregate installed capacity of 9,2859,735 MVA. Four of those substations, having an aggregate installed capacity of 109 MVA are operated on leased property. In addition, PSE&G owns four electric distribution headquarters and five electric sub-headquarters.

As of December 31, 2021,2022, PSE&G’s gas system included approximately 18,000 miles of gas mains, 12 gas distribution headquarters, two sub-headquarters, and one meter shop serving all of its gas territory in New Jersey. In addition, PSE&G operates 5856 natural gas metering and regulating stations, of which 2226 are located on land owned by customers or natural gas pipeline suppliers and are operated under lease, easement or other similar arrangement. In some instances, the pipeline companies own portions of the metering and regulating facilities. PSE&G also owns one liquefied natural gas and three liquid petroleum air gas peaking facilities. The daily gas capacity of these peaking facilities (the maximum daily gas delivery available during the three peak winter months) is approximately 2.8 million therms in the aggregate.

As of December 31, 2021,2022, PSE&G owned 158 MW dc of installed PV solar capacity throughout New Jersey.

As of December 31, 2021,2022, PSEG Power’s share of installed fossil and nuclear generating capacity is shown in the following

We are party to various lawsuits and environmental and regulatory matters, including in the ordinary course of business. For information regarding material legal proceedings, see Item 1. Business—Regulatory Issues and Environmental Matters and Item 8. Note 15. Commitments and Contingent Liabilities.

Not applicable.

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed on the New York Stock Exchange, Inc. under the trading symbol “PEG.” As of February 18, 2022,17, 2023, there were 52,14550,146 registered holders.

The following graph shows a comparison of the five-year cumulative return assuming $100 invested on December 31, 20162017 in our common stock and the subsequent reinvestment of quarterly dividends, the S&P Composite Stock Price Index, the Dow Jones Utilities Index and the S&P Electric Utilities Index.