Public Service Enterprise Group Inc: Form 10-K for the period ended Dec 31, 2022

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

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

• **PSE&G—**A New Jersey corporation, incorporated in 1924, which is a franchised public utility in New Jersey. It is also the provider of last resort for gas and electric commodity service for end users in its service territory. PSE&G earns revenues from its regulated rate tariffs under which it provides electric transmission and electric and natural gas distribution to residential, commercial and industrial (C&I) customers in its service territory. It also offers appliance services and repairs to customers throughout its service territory and invests in regulated solar generation projects and regulated energy efficiency (EE) and related programs in New Jersey.
• **PSEG Power—**A Delaware limited liability company formed in 1999 as a result of the deregulation and restructuring of the electric power industry in New Jersey. PSEG Power earns revenues from its nuclear generation and marketing of power and natural gas to hedge business risks and the value of its portfolio of nuclear power plants, other contractual arrangements and gas storage facilities.

In February 2022, we completed the sale of our 6,750 megawatt (MW) fossil generation portfolio which represented an important milestone in our strategy. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information.

Our other direct wholly owned subsidiaries are: PSEG Energy Holdings L.L.C. (Energy Holdings), which holds our legacy portfolio of lease investments and interests in offshore wind ventures; PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under a contractual agreement; and PSEG Services Corporation (Services), which provides us and our operating subsidiaries with certain management, administrative and general services at cost.

OPERATIONS AND STRATEGY

PSE&G

Our regulated T&D public utility, PSE&G, distributes electric energy and natural gas to customers within a designated service territory running diagonally across New Jersey where approximately 6.5 million people, or about 70% of New Jersey’s population resides.

Products and Services

Our utility operations primarily earn margins through:

• **Transmission—**the movement of electricity at high voltage from generating plants to substations and transformers, where it is then reduced to a lower voltage for distribution to homes, businesses and industrial customers. Our revenues for these services are based upon tariffs approved by the Federal Energy Regulatory Commission (FERC).
• **Distribution—**the delivery of electricity and gas to the retail customer’s home, business or industrial facility. Our revenues for these services are based upon tariffs approved by the New Jersey Board of Public Utilities (BPU).

The commodity portion of our utility business’ electric and gas sales is managed by basic generation service (BGS) and basic gas supply service (BGSS) suppliers. Pricing for those services is set by the BPU as a pass-through, resulting in no margin for our utility operations.

In addition, we continue to invest in and pursue opportunities in regulated clean energy, including EE, electric vehicle (EV) make-ready charging infrastructure, solar, energy storage and other potential investments.

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

How PSE&G Operates

We are a transmission owner in PJM Interconnection, L.L.C. (PJM) which is an Independent System Operator (ISO) and Regional Transmission Organization (RTO) that operates the electric transmission system in the Mid-Atlantic Region, including

New Jersey and the surrounding states. We provide distribution service to 2.3 million electric customers and 1.9 million gas customers in a service area that covers approximately 2,600 square miles running diagonally across New Jersey. We serve the most densely populated, commercialized and industrialized territory in New Jersey, including its six largest cities and approximately 300 suburban and rural communities.

Transmission

We use formula rates for our transmission cost of service and investments. Formula rates provide a method of rate recovery where the transmission owner annually determines its revenue requirements through a fixed formula that provides for a recovery of our operating costs and a return of and on our capital investments in the system, net of depreciation expense and deferred taxes (also known as rate base) using an approved return on equity (ROE) in developing the weighted average cost of capital. Under this formula, rates are put into effect in January of each year based upon our internal forecast of annual expenses and capital expenditures. Rates are subsequently trued up to reflect actual annual expenses and capital expenditures. Our current approved rates provide for a base ROE of 9.90% and a 50 basis point adder for our membership in PJM as an RTO. See Item 7. MD&A—Executive Overview of 2022 and Future Outlook.

We continue to invest in transmission projects as part of PJM’s FERC-approved transmission expansion planning process. These projects focus on reliability improvements and replacement of aging infrastructure with planned capital spending of $1.8 billion for transmission in 2023-2025 as disclosed in Item 7. MD&A—Capital Requirements.

Distribution

PSE&G distributes electricity and natural gas to end users in our respective franchised service territories. In October 2018, the BPU issued an Order approving the settlement of our distribution base rate proceeding with new rates effective November 1, 2018. The Order provides for a distribution rate base of $9.5 billion, a 9.60% ROE for our distribution business and a 54% equity component of our capitalization structure. The BPU has also approved a series of PSE&G infrastructure, EE, EV and renewable energy investment programs with cost recovery through various clause mechanisms. For a discussion of proposed and approved programs, see Investment Clause Programs below and Item 7. MD&A—Executive Overview of 2022 and Future Outlook. Our load requirements are split among residential, C&I customers, as described in the following table for 2022:

Our customer base has modestly increased since 2018, with electric and gas loads changing as illustrated in the following table:

Electric and Gas Distribution Statistics

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

Effective June 1 and October 1, 2021 for electric and gas, respectively, as part of the BPU’s approval of the Clean Energy Future-Energy Efficiency (CEF-EE) filing, we implemented the Conservation Incentive Program (CIP) that trues up PSE&G’s margin to a baseline per customer from our 2018 base rate case for the majority of our customers. As a result, electric gas sales volumes and demands are no longer a driver of our margin and over 90% of our Electric and Gas Distribution margin will only vary based upon the number of customers.

Investment Clause Programs

The following table lists our major approved investment clause programs that are in progress:

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

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

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

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

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

• **EE—**designed to achieve EE targets required under New Jersey’s Clean Energy Act through a suite of ten programs for residential, C&I programs, including low-income, multi-family, small business and local government.
• **EC—**driven by the implementation of “smart meters,” and new software and product solutions to improve our processes and better manage the electric grid.
• **EV—**primarily relating to preparatory work to deliver infrastructure to the charging point for three programs: residential smart charging; Level-2 mixed use charging; and direct current (dc) fast charging. A remaining component of our program related to medium and heavy duty charging infrastructure is the subject of a stakeholder process that began in 2021 at the BPU. In December 2022, the BPU issued a revised straw proposal on medium and heavy duty vehicle support for public comment.

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

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

See Item 7. MD&A—Executive Overview of 2022 and Future Outlook for additional information.

Solar Generation

We have also undertaken solar initiatives at PSE&G, which primarily invest in utility-owned solar photovoltaic (PV) grid-connected solar systems installed on PSE&G property and third party sites with our economics driven by our net investment in solar, with a contemporaneous return on that rate base.

Supply

We make no margin on the default supply of electricity and gas since the actual costs are passed through to our customers.

All electric and gas customers in New Jersey have the ability to choose their electric energy and/or gas supplier. Pursuant to BPU requirements, we serve as the supplier of last resort for two types of electric and gas customers within our service territory that are not served by another supplier. The first type provides default supply service for smaller C&I customers and residential customers at seasonally-adjusted fixed prices for a three-year term (BGS-Residential Small Commercial Pricing (RSCP)). These rates change annually on June 1 and are based on the average price obtained at auctions in the current year and two prior years. The second type provides default supply for larger customers, with energy priced at hourly PJM real-time market prices for a contract term of 12 months (BGS-Commercial Industrial Energy Pricing).

We procure the supply to meet our BGS obligations through auctions authorized by the BPU for New Jersey’s total BGS requirement. These auctions take place annually in February. Once validated by the BPU, electricity prices for BGS service are set. Approximately one-third of PSE&G’s total BGS-RSCP eligible load is auctioned each year for a three-year term. For information on current prices, see Item 8. Note 15. Commitments and Contingent Liabilities.

PSE&G procures the supply requirements of its default service BGSS gas customers through a full-requirements contract with PSEG Power. The BPU has approved a mechanism designed to recover all gas commodity costs related to BGSS for residential customers. BGSS filings are made annually by June 1 of each year, with a targeted effective date of provisional rates by October 1. PSE&G’s revenues are matched with its costs using deferral accounting, with the goal of achieving a zero cumulative balance by September 30 of each year. In addition, we have the ability to put in place two self-implementing BGSS increases on December 1 and February 1 of up to 5% and also may reduce the BGSS rate at any time and/or provide bill credits. Any difference between rates charged under the BGSS contract and rates charged to our residential customers is deferred and collected or refunded through adjustments in future rates. C&I customers that do not select third-party suppliers are also supplied under the BGSS arrangement. These customers are charged a market-based price largely determined by prices for commodity futures contracts.

Markets and Market Pricing

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

PSEG Power

Through PSEG Power, we have sought to produce low-cost electricity by efficiently operating our nuclear generation assets while balancing fuel requirements and natural gas supply obligations through energy portfolio management. PSEG Power is a public utility within the meaning of the Federal Power Act (FPA) and the payments it receives and how it operates are subject to FERC regulation.

In June 2021, we completed the sale of PSEG Power’s solar portfolio. In February 2022, we completed the sale of PSEG Power’s 6,750 MW fossil generating portfolio. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for further discussion.

Products and Services

As a merchant generator, our revenue is derived primarily from energy, capacity and ancillary services to counterparties in the open markets. These products and services may be transacted through exchange markets or bilaterally.

PSEG Power also sells wholesale natural gas, primarily through a full-requirements BGSS contract with PSE&G to meet the needs of PSE&G’s customers. In 2022, the BPU approved an extension of the long-term BGSS contract to March 31, 2027, and thereafter the contract remains in effect unless terminated by either party with a two-year notice.

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

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

How PSEG Power’s Nuclear Generation Operates

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

Generation Dispatch

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

In PJM, owners of power plants specify prices at which they are prepared to generate and sell energy based on the marginal cost of generating energy from each individual unit. Typically, the bid price of the last unit dispatched by PJM establishes the energy market-clearing price.

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

Market wholesale prices may vary by location resulting from congestion or other factors and do not necessarily reflect our contract prices. Forward prices are volatile and there can be no assurance that current forward prices will remain in effect or that we will be able to contract output at these forward prices.

Nuclear Fuel Supply

We have long-term contracts for nuclear fuel. These contracts provide for:

• purchase of uranium (concentrates and uranium hexafluoride),
• conversion of uranium concentrates to uranium hexafluoride,
• enrichment of uranium hexafluoride, and
• fabrication of nuclear fuel assemblies.

We expect to be able to meet the 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 2022 and Future Outlook and Item 8. Note 15. Commitments and Contingent Liabilities.

Markets and Market Pricing

All of PSEG Power’s nuclear generation assets are located within the PJM RTO. Prior to the sale of its fossil generation assets, PSEG Power also had significant sales within the New York ISO (NYISO) and New England ISO (ISO-NE). The price of electricity varies by location in the PJM RTO.

Commodity prices, as well as the availability of our fleet of nuclear generation units to operate, have a considerable effect on our profitability. Over the long-term, the higher the forward energy prices are, the more attractive an environment exists for us to contract for the sale of our anticipated output. However, a rising price environment, such as what has been experienced in the past year, also increases the cost of replacement power; thereby placing us at greater risk should our generating units fail to operate effectively or otherwise become unavailable.

PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants have been awarded Zero Emission Certificates (ZECs) by the BPU through May 2025. These nuclear plants are expected to receive ZEC revenue from the electric distribution companies (EDCs) in New Jersey, which is equivalent to approximately $10 per megawatt hour (MWh) in payments to selected nuclear plants.

In addition to energy sales, we earn revenue from capacity payments for our generating assets. These payments are compensation for committing our generating units to PJM for dispatch at its discretion. Capacity payments reflect the value to PJM of assurance that there will be sufficient generating capacity available at all times to meet system reliability and energy requirements. See Item 7. MD&A—Executive Overview of 2022 and Future Outlook—Wholesale Power Market Design.

In PJM the market design for capacity payments provides for a structured, forward-looking, capacity pricing mechanism through the Reliability Pricing Model (RPM). 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. The average capacity prices that PSEG expects to receive from the base residual and incremental auctions which have been completed are disclosed in Item 8. Note 3. Revenues. We have obtained price certainty for our PJM capacity through May 2024 through the RPM pricing mechanism. However, there is currently regulatory and timing uncertainty regarding the June 2024 through May 2025 planning year as discussed in Regulatory Issues—Federal Regulation.

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

Hedging Strategy

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 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 the past two years, is also limited. Therefore, our realized prices in 2022 were significantly lower than market pricing due to forward sales contracts executed in prior years for delivery in 2022. For this same reason, expected realized prices in forward periods will also be limited to when hedges were transacted and not based upon forward market prices.

In August 2022, the Inflation Reduction Act (IRA) was signed into law expanding incentives promoting carbon-free generation. The enacted legislation established the production tax credit (PTC) for electricity generation using nuclear energy set to begin in 2024 through 2032. PSEG Power’s Salem 1, Salem 2, Hope Creek, Peach Bottom 2 and Peach Bottom 3 nuclear plants will each benefit from the PTC. 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 are continuing to analyze the impact of the IRA on our nuclear units, including additional future guidance from the U.S. Treasury, potential impacts on hedging strategies and the impact of PTCs on expected ZEC payments.

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 2024 and a significant portion through 2025.

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

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

Energy Holdings

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

Offshore Wind

PSEG holds a 25% equity interest in Ørsted North America Inc.’s (Ørsted) Ocean Wind 1 project which is currently in development. In January 2023, PSEG agreed to sell to Ørsted its 25% equity interest in Ocean Wind 1. The sale is not contingent upon Ørsted electing to proceed to the construction phase of the project. The sale is contingent upon finalization of a purchase and sale agreement with Ørsted and other closing conditions as well as any potential state regulatory approval that may be required to close on the transaction.

Additionally, PSEG and Ørsted each owns 50% of Garden State Offshore Energy LLC (GSOE) which holds rights to an offshore wind lease area just south of New Jersey. PSEG has decided not to exercise its option to purchase 50% of Ørsted’s Skipjack projects in Maryland (one of which would utilize a portion of the GSOE lease area) or pursue an ownership interest in Ørsted’s Ocean Wind 2 offshore wind project or other offshore wind generation projects. PSEG is evaluating its options for the potential sale of its interest in GSOE. See Item 8. Note 5. Variable Interest Entities for additional information.

LIPA Operations Services Agreement

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

COMPETITIVE ENVIRONMENT

PSE&G

Our T&D business is not affected when customers choose alternate electric or gas suppliers since we earn our return on our net investment in rate base to provide T&D service, not by supplying the commodity. Based on our transmission formula rate and the CIP program for electric and gas distribution, we are also minimally impacted by changes in customers’ usage. Our growth is driven by (i) our investment program to deliver energy more reliably by modernizing our electric transmission and electric and gas distribution system and (ii) investing in programs that help deliver cleaner energy, including our EE programs to help customers use less energy and investment programs to build EV infrastructure and solar generation. There may also be opportunities to expand into related clean energy areas, such as renewable natural gas, hydrogen, energy storage, additional solar and renewables, and broader EE investments, though utility participation in these areas is subject to regulatory approval and market design, which continues to evolve. That growth can be affected by customer cost pressures which could result from higher commodity costs, higher supply costs to support subsidized renewable generation, higher operating costs, higher tax rates, macro-economic conditions including inflation, and other factors. 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 our current period revenue as compared to revenue thresholds established in our most recent distribution base rate proceeding. Recovery under the CIP is subject to certain limitations, including an actual versus allowed ROE test and ceilings on customer rate increases.

Changes previously ordered by FERC and implemented by PJM and other ISOs to eliminate contractual provisions that previously provided us a “right of first refusal” to construct new transmission projects in our service territory, could result in third-party construction of transmission lines in our area in the future and also allow us to seek opportunities to build in other service territories. While there has been minimal impact so far, these rules continue to evolve so both the extent of the risk within our service territory and the opportunities for our transmission business elsewhere remain difficult to assess.

PSEG Power

Various market participants compete with us and one another in transacting in the wholesale energy markets and entering into bilateral contracts. Our competitors include (i) merchant generators, (ii) domestic and multi-national utility generators, (iii) energy marketers and retailers, (iv) private equity firms, banks and other financial entities, (v) fuel supply companies, and (vi) affiliates of other industrial companies, and companies that promote and aggregate demand side management (DSM) and other EE efforts that could reduce load.

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

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

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

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

HUMAN CAPITAL MANAGEMENT

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

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

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

In 2022, of our external hires, including temporary employees, 23% were women and 40% were racially and/or ethnically diverse. PSEG’s voluntary attrition rate for the year was 6.5% (3.3% retirements and 3.2% resignations). The average employee tenure is 14 years.

Health, Safety and Well-Being

We emphasize the priority of protecting the health, safety and well-being of our employees, contractors and the communities that we serve. We demonstrate this by providing support to employees so that everyone is empowered and encouraged to question, stop and correct any unsafe act or condition. In the event that there is a safety issue, our employees take responsibility for the accurate, honest, and timely reporting of all incidents and injuries. To hold ourselves accountable, we have annual performance goals related to compliance with health and safety policies, practices and procedures.

Culture, Diversity, Equity and Inclusion

We aspire for a culture of belonging and equity, where diversity is celebrated and inclusion is the norm. Since publishing our first DEI report in 2021, we have continued to build on our Inclusion for All strategy. Our DEI program combines individual and site-specific efforts with leadership development and training activities.

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

To measure the effectiveness of our DEI and workplace culture efforts, we solicit feedback from employees through focus groups, listening sessions and employee experience surveys. In 2022, we saw improvements in many areas, including comfort speaking up, belonging, and manager relationship, with an overall engagement score of 82%.

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

Talent, Attraction and Development

Our talent acquisition strategy is focused on hiring the workforce necessary to serve our customers and meet our business objectives. As part of these efforts, we work to attract employees who reflect broad dimensions of diversity, including race, gender, disability, generation, education, and other traits and characteristics that make each person who they are.

Our employees grow through a variety of training and development opportunities offered to individual contributors, front line supervisors, managers and leaders. We invest in technical and operational training for our craft and field workers to support safe and reliable operations. We utilize data-driven workforce planning and succession processes to prepare for the future of work.

Total Rewards

In addition to our competitive pay, incentives, and health, welfare and retirement programs, our Total Rewards offerings consider the safety and overall well-being of our employees. We offer an array of programs designed to support physical, emotional, and financial wellness.

Labor Relations

We are proud of the partnership we have with union leadership across our six unions and the employees they represent in our workforce. We believe our strong relationship with our unions allowed for negotiation of permanent agreements that support PSEG’s flexible work model and other mid-term agreements that support strategic objectives and business goals.

REGULATORY ISSUES

In the ordinary course of our business, we are subject to regulation by, and are party to various claims and regulatory proceedings with FERC, the BPU, the Commodity Futures Trading Commission (CFTC) and various state and federal environmental regulators, among others. For information regarding material matters, other than those discussed below, see Item 8. Note 15. Commitments and Contingent Liabilities. In addition, information regarding PSE&G’s specific filings pending before the BPU is discussed in Item 8. Note 7. Regulatory Assets and Liabilities.

Federal Regulation

FERC is an independent federal agency that regulates the transmission of electric energy and natural gas in interstate commerce and the sale of electric energy and natural gas at wholesale pursuant to the FPA and the Natural Gas Act. PSE&G and certain operating subsidiaries of PSEG Power are public utilities as defined by the FPA. FERC has extensive oversight over such public utilities. FERC approval is usually required when a public utility seeks to: sell or acquire an asset that is regulated by FERC (such as a transmission line or a generating station); collect costs from customers associated with a new transmission facility; charge a rate for wholesale sales under a contract or tariff; or engage in certain mergers and internal corporate reorganizations.

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

Transmission Regulation

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

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

In a rulemaking proceeding issued in 2021, FERC has proposed to eliminate the existing 50 basis point adder for RTO membership, which is currently available to PSE&G and other transmission owners in RTOs. Elimination of the RTO adder for RTO membership would reduce PSE&G’s annual Net Income and annual cash inflows by approximately $30 million-$40 million.

***Transmission Planning Proceedings—***During 2022, FERC issued several rulemakings and notices that examine current transmission planning proceedings to determine whether the rules as currently implemented will facilitate the integration of renewable resources onto the grid and whether there is sufficient oversight over transmission costs to protect customers. Among other issues, FERC is considering whether transmission competitive solicitations are working as intended, whether interconnection queue rules for new generation should dramatically change and whether some type of transmission monitor construct to oversee costs should be imposed. FERC’s consideration of many of these issues is still in its early stages.

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

Under FERC regulations, public utilities that wish to sell power at market rates must receive FERC authorization (market-based rate (MBR) authority) to sell power in interstate commerce before making power sales. They can sell power at cost-based rates or apply to FERC for authority to make MBR sales. For a requesting company to receive MBR authority, FERC must first determine that the requesting company lacks market power in the relevant markets and/or that market power in the relevant markets is sufficiently mitigated. Certain PSEG companies are public utilities and currently have MBR authority. These companies, which include PSEG Energy Resources & Trading LLC, PSEG Nuclear LLC and PSE&G must file at FERC every three years to update their market power analyses. At the end of 2022, PSEG filed such a market power update at FERC, which remains pending.

Energy Clearing Prices

Energy clearing prices in the markets in which we operate are generally based on bids submitted by generating units. Under FERC-approved market rules, bids are subject to price caps and mitigation rules applicable to certain generation units. FERC rules also govern the overall design of these markets. At present, all units, including those owned by PSEG, within a delivery zone receive a clearing price based on the bid of the marginal unit (i.e. the last unit that must be dispatched to serve the needs of load) which can vary by location.

Capacity Market Issues

PJM operates a capacity market that has been approved by FERC. FERC regulates the capacity market and continues to examine whether the market design is working optimally. Various forums are considering how the competitive market framework can incorporate or be reconciled with state public policies that support particular resources, resource and environmental attributes or emerging technologies, whether generators are being sufficiently compensated in the capacity market and whether subsidized resources may be adversely affecting capacity market prices. We cannot predict what action, if any, FERC might take with regard to capacity market design.

The RPM is the locational installed capacity market design for the PJM region, including a forward auction for installed capacity. Under the RPM, generators located in constrained areas within PJM are paid more for their capacity as an incentive to ensure adequate supply where generation capacity is most needed. The mechanics of the RPM in PJM continue to evolve and be refined in stakeholder proceedings and FERC proceedings in which we are active.

In July 2021, PJM submitted to FERC a proposal to scale back the PJM Minimum Offer Price Rule (MOPR) to accommodate state public policy programs that do not attempt to set the price of capacity. Under the PJM proposal, PSEG Power’s New Jersey nuclear plants that receive ZEC payments are not subject to the MOPR. In September 2021, FERC issued a notice that it was not able to act on PJM’s proposed changes to the MOPR because of a split among the Commissioners on the lawfulness of PJM’s proposal. Therefore, PJM’s rules became automatically effective as of September 29, 2021 and they were applied to the June 2022 base residual auction.

In November 2021, a group of generators challenged these MOPR rules in the Court of Appeals for the Third Circuit on the grounds that FERC’s inaction was unlawful. PSEG intervened in the proceeding in support of the MOPR rules. Oral argument on the appeal was held in January 2023. We cannot predict the outcome of this proceeding.

In another order related to the auction, FERC found that the current rules related to the Market Seller Offer Cap were unjust and unreasonable and ultimately eliminated the default offer cap. In its place, FERC adopted a unit-specific approach to reviewing certain capacity market offers. These new rules resulted in lower capacity prices for other market participants, including PSEG, and therefore, lower revenues for PSEG in the June 2022 base residual auction since market offers for many resource types need to be approved by the Independent Market Monitor and PJM.

PJM’s most recent base residual auction was held at the beginning of December 2022. However, in mid-December, PJM communicated to all market participants that it is not announcing the results of this auction while it waits for FERC to act on emergent filings it has made at FERC proposing to change how the reliability requirement for a specific capacity market deliverability area will be calculated effective December 24, 2022. PJM’s filings at FERC, and its related decision to postpone the announcement of base residual auction results, creates uncertainty for market participants, including PSEG. We cannot predict the outcome of these developments at this time.

Compliance

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

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

CFTC

In accordance with the Dodd-Frank Wall Street Reform and Consumer Protection Act, the SEC and the CFTC continue to implement a regulatory framework for swaps and security-based swaps. The rules are intended to reduce systemic risk, increase transparency and promote market integrity within the financial system by providing for the registration and comprehensive regulation of swap dealers and by imposing recordkeeping, data reporting, margin and clearing requirements with respect to swaps. We are currently subject to recordkeeping and data reporting requirements applicable to commercial end users. The CFTC finalized new rules establishing federal position limits for trading in certain commodities, such as natural gas. Entities such as PSEG began complying with the rules on January 1, 2022.

Nuclear

Nuclear Regulatory Commission (NRC)

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

The NRC has the ultimate authority to determine whether any U.S. nuclear generating unit may operate. The NRC conducts ongoing reviews of nuclear industry operations experience and may issue or revise regulatory requirements. We are unable to predict the final outcome of these reviews or the cost of any actions we would need to take to comply with any new regulations, including possible modifications to the Salem, Hope Creek and Peach Bottom facilities, but such costs could be material.

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

(A) Depreciation Expense and the Asset Retirement Obligation assume these units will operate through 2053 and 2054, respectively, given our expectation that previously approved operating license expiration dates will be restored by the NRC. See Item 8. Note 13. Asset Retirement Obligations (AROs) for additional information.

State Regulation

Our principal state regulator is the BPU, which oversees electric and natural gas distribution companies in New Jersey. We are also subject to various other states’ regulations due to our operations in those states.

Our New Jersey utility operations are subject to comprehensive regulation by the BPU including, among other matters, regulation of retail electric and gas distribution rates and service, the issuance and sale of certain types of securities and compliance matters.

In addition to base rates, we recover certain costs or earn on certain investments pursuant to mechanisms known as adjustment clauses. These clauses permit the flow-through of costs to, or the recovery of investments from, customers related to specific programs, outside the context of base rate proceedings. Recovery of these costs or investments is subject to BPU approval for which we make periodic filings. Delays in the pass-through of costs or recovery of investments under these mechanisms could result in significant changes in PSE&G’s cash flow. PSE&G’s participation in solar, EV and EE programs is also regulated by the BPU, as the terms and conditions of these programs are approved by the BPU. BPU regulation can also have a direct or indirect impact on our power generation business as it relates to energy supply agreements and energy policy in New Jersey.

***New Jersey Energy Master Plan (EMP)—***In January 2020, the State of New Jersey released its EMP. While the EMP does not have the force of law and does not impose any obligations on utilities, it outlines current expectations regarding the State’s role in the use, management, and development of energy. The EMP recognizes the goals of New Jersey’s Clean Energy Act of 2018 (the Clean Energy Act) to achieve, by 2026, annual reductions of electric and gas consumption of at least 2% and 0.75%, respectively, of the average of the prior three years of retail sales. The annual reductions were subsequently adjusted to 2.15% for electric and 1.10% for gas by 2027 in the BPU’s EE framework approved in June 2020. The EMP outlines several strategies, including statewide EE programs; expansion of renewable generation (solar and offshore wind), energy storage and other carbon-free technologies; preservation of existing nuclear generation; electrification of the transportation sector; and reduced reliance on natural gas. We cannot predict the impact on our business or results of operations from the EMP or any laws, rules or regulations promulgated as a result thereof, particularly as they may relate to PSEG Power’s nuclear generating stations and PSE&G’s electric transmission and gas distribution assets. In January 2023, the New Jersey governor’s office announced the commencement of planning for the development of a new EMP for release in 2024. The 2024 EMP will update and expand upon the existing EMP and consider recent state and federal policies and how federal funding can provide additional support for advancement of critical clean energy policies.

***Gas Capacity Review—***In September 2019, the BPU formally opened a stakeholder proceeding to explore gas capacity procurement service to all New Jersey natural gas customers. The BPU retained a consultant and in June 2022 accepted the consultant’s key finding that, through 2030, New Jersey’s firm gas capacity can meet firm demand under normal design day conditions. The only potential gas supply shortfall was found during extreme weather (i.e. a winter day that could be expected to occur only once in 90 years) and/or a “perfect storm,” which occurs when there is an outage on a transcontinental pipeline during a design day. The BPU noted that its consultant’s analysis supports the argument against the need for additional interstate pipeline capacity and also supports the BPU’s aggressive policy approach to reduce the State’s overall reliance on fossil fuels, and achieve the Governor’s goal of 100% clean energy by 2050.

***BGS Process—***In July 2022, the State’s EDCs, including PSE&G, filed their annual proposal for the conduct of the February 2023 BGS auction covering energy years 2024 through 2026. In November 2022, the BPU issued its decision to approve the joint EDCs’ proposals regarding the BGS auction process. In addition to addressing procedural issues for conducting the annual BGS auction, the BPU’s November 2022 order addressed EV charging supply rate issues and required that the EDCs must (i) continue to collect EV charging data and coordinate with BPU Staff in developing a BGS rate solution for commercial dc fast charging EV stations, and must include chargers and submit a proposal regarding the rate design in the June 1, 2023 joint EDC BGS filing; and (ii) implement by June 1, 2023 a BGS rate solution for residential EV charging customers similar to distribution rate off-peak charging solutions put in place in some of the EDCs’ (including PSE&G’s) light duty EV incentive programs.

***EV Activity—***Consistent with the policy set forth in New Jersey’s EMP, the BPU has supported electrification of the transportation sector. EDCs in New Jersey, including PSE&G, are making investments, approved by the BPU for recovery in rates, initially focused on light duty vehicles, such as preparatory work to deliver infrastructure to the EV charging point. In June 2021, the BPU issued an initial straw proposal for the establishment of an EV infrastructure ecosystem for medium and heavy duty EVs in New Jersey, and conducted a series of stakeholder meetings to discuss that ecosystem. In December 2022, the BPU issued a revised straw proposal for public comment. Although we cannot predict the outcome of the stakeholder process, we anticipate that this effort will result in opportunities for EDCs to target infrastructure investments for the medium and heavy duty EV market.

***Grid Modernization—***In October 2021, the BPU commenced a stakeholder proceeding to develop and implement a systemic Grid Modernization plan in accordance with strategies outlined in the New Jersey EMP. The BPU retained a consultant that gathered detailed and comprehensive information from the State’s EDCs, including PSE&G, regarding resource issues and policy changes needed to interconnect the clean energy capacity required under state policy. In June 2022, the BPU’s consultant issued a draft report with its findings and recommendations to update the BPU’s interconnection regulations and processes. We cannot predict the impact on our business or results of operations from this Grid Modernization plan or any laws, rules or regulations promulgated as a result thereof, particularly as they may relate to PSE&G’s electric distribution assets.

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

In 2019, the BPU established a “Community Solar Energy Pilot Program,” permitting customers to participate in solar energy projects remotely located from their properties, and allowing for bill credits related to that participation. Still pending with the BPU are certain issues, including minor modifications to the community solar pilot program, discussions regarding the potential implementation of consolidated billing for the benefit of project developers and participants, and development of a cost recovery mechanism for the EDCs.

The Clean Energy Act required the BPU to close the then-existing Solar Renewable Energy Certificate (SREC) program to new applications at the earlier of June 1, 2021 or the date at which 5.1% of New Jersey retail electric sales were derived from solar. The 5.1% threshold was attained and the SREC market was closed to new applications on April 30, 2020, with limited exceptions related to the impact of COVID-19 on projects under development. Solar projects that failed to achieve commercial operation before April 30, 2020 may be entitled to receive transition renewable energy certificates (TRECs) for each MWh of solar production. The New Jersey EDCs, including PSE&G, are required to purchase, using the services of a TREC administrator, TRECs from solar projects at rates set by the BPU.

In July 2021, the BPU issued an order formally establishing the Successor Solar Incentive (SuSI) Program, heavily drawing upon the predecessor TREC program, to serve as the permanent program for providing solar incentives to qualified solar electric generation facilities. The program provides for incentive payments at prices established in the BPU’s July 2021 order in the form of SREC-IIs for each MWh generated by net-metered projects of 5 MW or less, and an annual competitive solicitation, the Competitive Solar Incentive (CSI) program, to establish SREC-II prices applicable to grid-supply projects and net-metered projects in excess of 5 MW. The State’s EDCs have retained an administrator to acquire all of the SREC-IIs received each year by eligible solar generation projects. Each EDC, in turn, may recover from its customers the reasonable and prudent costs for

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

Cybersecurity

In an effort to reduce the likelihood and severity of cybersecurity incidents, we have established a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of our technology systems. The Board of Directors, its Industrial Operations Committee (IOC) and Audit Committee, and senior management receive frequent reports on such topics as personnel and resources to monitor and address cybersecurity threats, technological advances in cybersecurity protection, rapidly evolving cybersecurity threats that may affect us and our industry, cybersecurity incident response and applicable cybersecurity laws, regulations and standards, as well as collaboration mechanisms with intelligence and enforcement agencies and industry groups, to assure timely threat awareness and response coordination.

Our cybersecurity program is focused on the following areas:

• Governance
• Board Oversight—The Board’s IOC holds the primary responsibility, as enumerated in its charter, of overseeing PSEG’s cybersecurity program. Cybersecurity is a standing agenda item at each IOC meeting, which includes discussion on operational technology cyber risk, a cybersecurity update from the Chief Information Security Officer (CISO), and review of a corporate cybersecurity scorecard. In addition, the IOC meets with the CISO in executive session at each meeting with no other members of management present.
• Cybersecurity Council—which is comprised of members of senior management, meets regularly to discuss emerging cybersecurity issues and maintenance of the cybersecurity scorecard to measure performance of key risk indicators. The Cybersecurity Council ensures that senior management, and ultimately, the Board, is given the information required to exercise proper oversight over cybersecurity risks and that escalation procedures are followed.
• The Senior Vice President, Chief Information and Digital Officer has the overall responsibility for cybersecurity.
• Documented corporate practice to ensure delineated cybersecurity incidents, or potential incidents, are escalated promptly to senior management.
• Training and Awareness—Providing annual cybersecurity training for all personnel with network access, as well as additional education for personnel with access to industrial control systems or customer information systems; and conducting phishing exercises with progressive consequences for failures. Employees also receive periodic cybersecurity awareness messages and each October are invited to presentations throughout the month from internal and external cyber experts covering diverse cyber topics.
• Technical Safeguards—Managing controls to protect our network perimeter, internal Information Technology (IT) and Operational Technology (OT) environments, such as internal and external firewalls, network intrusion detection and prevention, penetration testing, vulnerability assessments, threat intelligence, anti-malware and access controls.
• Vendor Management—Maintaining a risk-based vendor management program, including the development of robust security contractual provisions.
• Incident Response Plans—Maintaining and updating a cyber incident response plan that addresses the life cycle of a cybersecurity incident from a technical perspective (i.e., detection, response, and recovery), as well as data breach response (with a focus on external communication and legal compliance); and conducting regular table top exercises to test plan effectiveness (both internally and through external exercises).
• Mobile Security—Maintaining controls to prevent loss of data through mobile device channels.

PSEG also maintains physical security measures to protect its OT systems, consistent with a defense in depth and risk-tiered approach. Such physical security measures may include access control systems, video surveillance, around-the-clock command center monitoring, and physical barriers (such as fencing, walls, and bollards). Additional features of PSEG’s physical security program include threat intelligence, insider threat mitigation, background checks, a threat level advisory system, a business interruption management model, and active coordination with federal, state, and local law enforcement officials. See Regulatory Issues—Federal Regulation for a discussion of Critical Infrastructure Protection standards that the NERC has promulgated that mitigate risk associated with both cybersecurity and physical security of PSEG’s critical facilities.

In addition, we are subject to federal and state requirements designed to further protect against cybersecurity threats to critical infrastructure, as discussed below. For a discussion of the risks associated with cybersecurity threats, see Item 1A. Risk Factors.

***Federal—***NERC, at the direction of FERC, has implemented national and regional reliability standards to ensure the reliability and security of the grid and to prevent major system blackouts. NERC Critical Infrastructure Protection standards establish cybersecurity and physical security protections for critical systems and facilities. These standards are also designed to develop coordination, threat sharing and interaction between utilities and various government agencies regarding potential cyber and physical threats against the nation’s electric grid.

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

The NERC Critical Infrastructure Protection standards do not apply to nuclear facilities which are instead governed by the NRC for purposes of physical and cyber security. NRC has a number of risk-informed, performance-based security programs in place to effectively protect U.S. commercial nuclear facilities. The NRC has existing requirements, effective processes, and the expertise to regulate and inspect cybersecurity to ensure the federal requirements are met.

NRC requires operating nuclear power plant licensee and license applicants to ensure that digital computer and communication systems associated with a nuclear power plant’s safety, security, and emergency preparedness functions are protected from cyberattacks. As a result, computer systems at operating power plants that monitor and control safety systems and help the reactor operate are isolated from external communications. Security systems that provide safeguards of the facility are also isolated from external communications, including the Internet.

NRC’s Office of Nuclear Security and Incident Response established the Cyber Security Branch (CSB) to strengthen internal governance of the agency’s regulatory activities. The CSB plans, coordinates, and manages agency activities related to cybersecurity for NRC applicants and licensees, such as security programs’ development and policy enhancements to prevent malevolent cyber acts against NRC-licensed facilities. The CSB’s cybersecurity-related responsibilities include developing rules and guidance, reviewing licensing actions, developing policy enhancements, and overseeing NRC-licensed facilities.

NRC regularly monitors the threats associated with cybersecurity, including potential threats against NRC-licensed facilities. Within the CSB there is a cyber assessment team that assesses real-world cyber events at NRC-licensed facilities. The team evaluates whether an identified threat could impact licensed facilities and makes recommendations for NRC actions and communications to the licensees. Furthermore, the NRC has established liaison relationships with the intelligence and law enforcement communities to include the National Counterterrorism Center, the DHS’s U.S. Computer Emergency Response Team, and the Federal Bureau of Investigation.

***State—***The BPU requires utilities, including PSE&G, to, among other things, implement a cybersecurity program that defines and implements organizational accountabilities and responsibilities for cyber risk management activities, and establishes policies, plans, processes and procedures for identifying and mitigating cyber risk to critical systems. Additional requirements of this order include, but are not limited to (i) annually inventorying critical utility systems; (ii) annually assessing risks to critical utility systems; (iii) implementing controls to mitigate cyber risks to critical utility systems; (iv) monitoring log files of critical utility systems; (v) reporting cyber incidents to the BPU; and (vi) establishing a cybersecurity incident response plan and conducting biennial exercises to test the plan. In addition, New York’s Stop Hacks and Improve Electronic Data Security (SHIELD) Act, which became effective in March 2020, requires businesses that own or license computerized data that includes New York State residents’ private information to implement reasonable safeguards to protect that information.

ENVIRONMENTAL MATTERS

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

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

Air Pollution Control

Our facilities are subject to federal, state and local regulation that requires controls of emissions from sources of air pollution and imposes recordkeeping, reporting and permit requirements.

***Environmental Justice (EJ)—***The New Jersey Department of Environmental Protection (NJDEP) has issued an administrative order requiring an EJ review of certain environmental permit applications pending the promulgation of final EJ regulations that will provide additional guidance. The impacts of the NJDEP’s actions are being evaluated for both PSE&G and PSEG Power and the outcome cannot be determined at this time.

***New Jersey Protecting Against Climate Threats (NJ PACT)—***This NJDEP regulatory reform is expected to result in changes to existing air and land use regulations in response to anticipated impacts of climate change. It has published proposed changes pertaining to inland flood protection which are intended to protect new development from fluvial flooding. The final regulation is anticipated in 2023.

We continue to assess the potential impact of the NJ PACT, which could have cost implications for business operations, including the construction of new facilities or upgrades to existing utility infrastructure. Such expenditures could materially affect the continued economic viability and/or cost to construct one or more such facilities.

Water Pollution Control

The Federal Water Pollution Control Act prohibits the discharge of pollutants from point sources to water, except pursuant to a duly issued permit. These permits must generally be renewed every five years. Applicable regulations also impose obligations on facility operators like PSEG Power to install certain technology to treat their discharges to ensure discharges meet certain water quality requirements.

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

Hazardous Substance Liability

PSEG’s operations involve substances and byproducts classified by environmental regulations as hazardous. These regulations impose handling, storage and disposal requirements for hazardous materials. They also impose liability for damages to the environment, including cash penalties.

***Site Remediation—***Federal and state environmental laws and regulations require the cleanup of discharged hazardous substances. They authorize the EPA, the NJDEP and private parties to commence lawsuits to compel clean-ups or seek reimbursement for such remediation. The clean-ups can be more complicated and costly when the hazardous substances are in or under a body of water. Clean-up obligations may be imposed regardless of the absence of fault, contractual agreements between parties, or the legality of activities at the time of discharge.

***Natural Resource Damages—***Federal and state environmental laws and regulations authorize damage assessments against persons who have caused an injury to natural resources through the discharge of a hazardous substance. The NJDEP requires persons conducting remediation to address such injuries through restoration or damage assessments.

Fuel and Waste Disposal

***Nuclear Fuel Disposal—***The federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of spent nuclear fuel. Under the Nuclear Waste Policy Act of 1982 (NWPA), nuclear plant owners are required to contribute to a Nuclear Waste Fund to pay for this service. Since May 2014, the nuclear waste fee rate has been zero. No assurances can be given that this fee will not be increased in the future. The NWPA allows spent nuclear fuel generated in any reactor to be stored in reactor facility storage pools or in Independent Spent Fuel Storage Installations located at reactors or away from reactor sites.

We have on-site storage facilities that are expected to satisfy the storage needs of Salem 1, Salem 2, Hope Creek, Peach Bottom 2 and Peach Bottom 3 through the end of their operating licenses.

***Low-Level Radioactive Waste—***As a by-product of their operations, nuclear generation units produce low-level radioactive waste. Such waste includes paper, plastics, protective clothing, water purification materials and other materials. These waste materials are accumulated on site and disposed of at licensed permanent disposal facilities. New Jersey, Connecticut and South Carolina have reached an agreement that gives New Jersey nuclear generators continued access to a waste disposal facility which is owned by South Carolina. We believe that this agreement will provide for adequate low-level radioactive waste disposal for Salem and Hope Creek through the end of their current licenses including full decommissioning, although no assurances can be given. Low-Level Radioactive Waste is periodically being shipped to the South Carolina waste disposal facility from Salem and Hope Creek. Additionally, there are on-site storage facilities for Salem, Hope Creek and Peach Bottom, which we believe have the capacity for at least five years of temporary storage for each facility.

INFORMATION ABOUT OUR EXECUTIVE OFFICERS (PSEG)

(A) Effective January 1, 2023, in accordance with a management transition plan, Ralph A. LaRossa became COB of PSEG.

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

GENERAL OPERATIONAL AND FINANCIAL RISKS

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

Our business plan calls for extensive investment in capital improvements and additions, including the construction of T&D facilities, modernizing 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:

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

Any delays, cost escalations or otherwise unsuccessful construction and development could materially affect our financial position, results of operations and cash flows.

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

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

Any of these risks could cause 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.

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

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 natural 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 lower demand for electricity and gas we deliver. Any 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.

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

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

Further, our business is subject to policy, regulatory, technology and economic uncertainties and contingencies, including regulatory approvals required for various of our clean energy initiatives, many of which are beyond our control and may affect our ability to implement our clean energy strategy and initiatives and achieve our goal of net zero GHG emissions by 2030, or other GHG emissions reduction or climate-related goals that we may set from time to time, in a cost-effective manner or at all.

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

The success of our businesses is dependent on our ability to continue providing safe and reliable service to our customers while minimizing service disruptions. We are exposed to the risk of asset and equipment failures, gas explosions, accidents, natural disasters, severe weather events, acts of war or terrorism or other acts of violence, including active shooter situations (such as the shooting incident involving an employee and a former employee which occurred in February 2023 outside of a PSE&G field facility in Somerset County, New Jersey), sabotage, physical attacks or security breaches (as have been experienced recently by certain other utilities), cyberattacks or other incidents, which could result in damage to or destruction of our substations or other facilities or infrastructure, or damage to persons or property and to electric and gas supply interruptions. Further, a major failure of availability or performance of a critical operating technology or business system, and inadequate preparation or execution of business continuity or disaster recovery plans for the loss of one or several critical systems, could result in extended disruption to operations or business processes, damage to systems and/or loss of data. We have historically benefited from access to mutual aid, a voluntary and reciprocal arrangement with other utilities that provides access to a trained and flexible labor force which has helped to reduce outage restoration times during extreme weather events. There is no guarantee that we will have continued access to mutual aid as the utility industry consolidates and the frequency of severe weather events rises.

We are also exposed to the risk of pandemics, such as the 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 have increased the physical risks to our facilities and operations resulting from such climate hazards as more severe weather events (extreme wind, rainfall and flooding), such as experienced from Superstorm Sandy and Tropical Storms Isaias and Ida, sea level rise, and extreme heat.

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 through investigations or through the imposition of additional regulatory or legislative requirements. Such actions could adversely affect our costs, competitiveness and future investments, which could be material to our financial position, results of operations and cash flow. For our T&D business, the cost of storm restoration efforts may not be fully recoverable through the regulatory process. In addition, the inability to restore power to our customers on a timely basis could result in negative publicity and materially damage our reputation.

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

Long-lived assets represent approximately 74% and 82% of the total assets of PSEG and PSE&G, respectively, as of December 31, 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.

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

The supply chain of goods and services is currently being negatively impacted by several factors, including manufacturing labor shortages, domestic and international shipping constraints, increases in demand, and shortages of raw materials and specialty components. As a result, we are seeing price increases in some areas and delivery delays of certain goods. These factors have increased our costs and have the potential to impact our operations. We cannot currently estimate the potential impact of continued supply chain disruptions but they could materially impact our business and results of operations.

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

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

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

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

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

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

Cybersecurity threats to the energy market infrastructure are increasing in sophistication, magnitude and frequency, particularly since the coronavirus pandemic and the resulting shift to virtual operations began. Because of the inherent vulnerability of infrastructure and technology and operational systems to disability or failure due to hacking, viruses, malicious or destructive code, phishing and other social engineering attacks, denial of service attacks, ransomware, acts of war or terrorism, or other cybersecurity incidents, we face increased risk of cyberattack. We rely on information and operational technology systems and network infrastructure to operate our generation and T&D systems. We also store sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, infrastructure, employees, shareholders, customers and vendors on our IT systems and conduct power marketing and hedging activities. In addition, the operation of our business is dependent upon the IT systems of third parties, including our vendors, regulators, RTOs and ISOs, among others. Our and third-party operational and IT systems and products may be vulnerable to cybersecurity attacks involving fraud, malice or oversight on the part of our employees, other insiders or third parties, whether domestic or foreign sources. A successful cybersecurity attack may result in unauthorized use of our systems to cause disruptions at a third party. Cybersecurity risks to our operations include:

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

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 if 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.

A material shift away from natural gas toward increased electrification and a reduction in the use of natural gas as a result of economic decarbonization measures could adversely impact our business.

Technological advancements enabling customer choice and state climate policy supporting decarbonization are driving transformative change in the electric power industry. New Jersey utilities are experiencing increased usage by customers and third parties of distributed energy resources, such as on-site solar generation, energy storage, fuel cells, EE, and demand response technologies. These developments will require modernization of the electric distribution grid to, among other things, accommodate two-way flows of electricity, increase the grid’s capacity, and interconnect distributed energy resources. In order to enable the New Jersey clean energy economy, sustained investments are required in grid modernization, renewable integration projects, EE programs, energy storage options, EV infrastructure and state infrastructure modernization. If these changes progressed in the near-term, our business model and our ability to execute on our strategy could be materially impacted. Various jurisdictions outside of New Jersey have enacted prohibitions or restrictions on the use and consumption of natural gas that will reduce the use of natural gas. If New Jersey were to enact similar prohibitions or restrictions, a reduction in the use of natural gas could lead to a reduction in the gas customer base, higher customer rates for those customers who remain, and a diminished need for gas infrastructure, which could potentially cause substantial investment value of gas assets to be stranded and removed from our rate base, resulting in a reduction in associated rate recovery. Our inability to recover through rates our investments into the natural gas system, while still ensuring gas system safety and reliability, could materially affect our financial condition, results of operations, liquidity, and cash flows. Further, these industry changes, costs associated with complying with new regulatory developments and initiatives and with technological advancements could materially affect our financial condition, results of operations, liquidity, and cash flows.

Our financial condition and results of operations could be adversely affected by the coronavirus pandemic.

In response to the 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.

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. 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 any 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 carrying costs and any associated bad debts could have a material impact on our business. We currently cannot estimate the potential impact the coronavirus pandemic may have on our business, results of operations, financial condition, liquidity and cash flows. The 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:

• PSE&G’s residential and C&I customer payment patterns, in part as residential customer non-safety related service disconnections for non-payment were temporarily suspended for an extended period, resulting in adverse impacts to accounts receivable and bad debt expense;
• the recovery of incremental costs incurred related to the pandemic, including higher bad debts; and
• the availability of materials and supplies due to supply chain interruptions.

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

Certain events such as an aging workforce looking to retire without an opportunity to transfer knowledge to a successor, inadequate workforce plans and replacements, lack of skill set to meet current and evolving business needs, a culture that does not foster inclusion leading to turnover, a workforce strike resulting from a failure to successfully negotiate new collective bargaining agreements with our labor unions on mutually acceptable terms or at all, unavailability of resources due to the coronavirus 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, poor productivity, and a lack of innovation. Specialized knowledge and experience are required of employees across PSEG and its affiliates. There is competition for these skilled employees. Failure to hire and adequately train and retain employees, including the transfer of significant historical knowledge and expertise to new employees, may adversely affect our results of operations, financial position and cash flows.

Increases in the costs of equipment and materials, fuel, services and labor could adversely affect our operating results.

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.

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

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 entity. PSEG’s, PSE&G’s and PSEG Power’s bank credit agreements contain events of default customary for financings of their type, including cross defaults and accelerations and, in the case of PSEG’s and PSEG Power’s bank credit agreements, certain change of control events. PSEG’s PSE&G’s and PSEG Power’s bank credit agreements, contain certain limitations on the incurrence of 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.

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

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

RISKS RELATED TO OUR GENERATION BUSINESS

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

In the competitive markets where we operate, natural gas prices have a major impact on the price that generators receive for their output and participants are not guaranteed any specific rate of return on their capital investments. Recently, the natural gas market and, therefore, energy markets have become more volatile due to higher domestic demand, increased natural gas exports and impacts from the global liquefied natural gas market, among other things. The price of natural gas is the primary driver of energy pricing in PJM. As such, the volatility in the natural gas market and potential lower natural gas prices may impact our results of operations and cash flows. Lower natural gas prices result in lower electricity prices, which reduce our margins where our nuclear generation costs may not have declined similarly.

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

• increases and decreases in generation capacity, including the addition of new supplies of power as a result of the development of new power plants, expansion of existing power plants or additional transmission capacity;
• severe weather conditions;
• power supply disruptions, including power plant outages and transmission disruptions;
• climate change and weather conditions, particularly unusually mild summers or warm winters in our market areas;
• seasonal fluctuations;
• economic and political conditions that could negatively impact the demand for power;
• changes in the supply of, and demand for, energy commodities;
• development of new fuels or new technologies for the production or storage of power;
• incurring penalties due to generation performance failure when called on by PJM during emergency situations;
• federal and state regulations and actions of PJM and changing PJM market rules; and
• federal and state power, market and environmental regulation and legislation, including financial incentives for new renewable energy generation capacity that could lead to oversupply and price suppression.

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

Increases in market prices also affect our ability to hedge generation output and fuel requirements as the obligation to post margin increases with increasing prices.

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

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

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

We are exposed to increases in the price of nuclear fuel, and 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 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 nuclear fuel by, our power plants including the following:

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

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 nuclear fuel, an increase in the cost of any particular fuel ultimately used by other generation facilities could impact our results of operations.

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

Federal and state incentives for the development and 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 EE 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 EE 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 EE 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.

Several states, cities and other stakeholders are also considering bans on new natural gas customers and transitioning away from natural gas in the future. Such actions could have a material adverse effect on our business.

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 are subject to third-party credit risk relating to our sale of nuclear generation output and purchase of nuclear fuel.

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 attempt to spread the risk across all participants. Therefore, a default by a third party could increase our costs, which could negatively impact our results of operations and cash flows.

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

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

• breakdown or failure of equipment, IT, processes or management effectiveness;
• disruptions in the transmission of electricity;
• labor disputes or work stoppages;
• fuel supply interruptions;
• transportation constraints;
• limitations which may be imposed by environmental or other regulatory requirements; and
• operator error, acts of war or terrorist attacks (including cybersecurity breaches) or catastrophic events such as fires,

earthquakes, explosions, floods, severe weather or other similar occurrences.

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

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

Certain of our generation facilities rely on transmission facilities that we do not own or control and that may be subject to transmission constraints. Transmission facility owners’ inability to maintain adequate transmission capacity could restrict our ability to deliver wholesale electric power to our customers and we may either incur additional costs or forgo revenues.

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.

In addition, in PJM, energy transmission congestion risk and associated costs exist. We may not be able to accurately predict and hedge this risk due to insufficient market data and liquidity. An increase in our congestion costs may adversely affect our financial results.

REGULATORY, LEGISLATIVE AND LEGAL RISKS

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

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

PSE&G also is pursuing a number of opportunities to expand its products and services to customers to support clean energy goals. BPU approval is required for any new endeavor, and is not guaranteed. Rejection or delay of such filings could have an adverse impact on our future growth, or our standing with environmentally conscious investors or other stakeholders.

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.

PSE&G’s proposed investment programs may not be fully approved by regulators, which could result in lower than desired service levels to customers, and actual capital investment by PSE&G may be lower than planned, which would cause lower than anticipated rate base.

PSE&G is a regulated public utility that operates and invests in an electric T&D system and a gas distribution system as well as certain regulated clean energy investments, including solar and EE within New Jersey. PSE&G invests in capital projects to maintain and improve its existing T&D system and to address various public policy goals and meet customer expectations. Transmission projects are subject to a FERC-approved transmission expansion planning process while distribution and clean energy projects are subject to approval by the BPU. The costs of PSE&G’s transmission projects are subject to prudency challenge at FERC and PSE&G’s rates themselves may also be challenged at FERC. We cannot be certain that any proposed project will be approved as requested or at all. If the programs that PSE&G may file from time to time are only approved in part, or not at all, or if the approval fails to allow for the timely recovery of all of PSE&G’s costs, including a return of, or on, its investment, PSE&G will have a lower than anticipated rate base, thus causing its future earnings to be lower than anticipated. If these programs are not approved, that could also adversely affect our service levels for customers. Further, the BPU could take positions to exclude or limit utility participation in certain areas, such as renewable generation, EE, EV infrastructure, energy storage, renewable natural gas or hydrogen projects, which would limit our relationship with customers and narrow our future growth prospects.

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

We are subject to regulation by federal authorities. Such regulation affects almost every aspect of our businesses, including management and operations; the terms and rates of transmission services; 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.

***Recovery of wholesale transmission rates—***PSE&G’s wholesale transmission rates are regulated by FERC and are recovered through a FERC-approved formula rate. The revenue requirements are reset each year through this formula.

In 2021, FERC approved a settlement agreement effective August 1, 2021 that we reached with the BPU and the New Jersey Rate Counsel about 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 made changes to recovery of certain costs. The agreement provides that the settling parties will not seek changes to our transmission formula rate for three years. We have implemented the terms of the agreement.

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

***Transmission Planning—***FERC Order 1000 has generally opened transmission development to competition from independent developers, allowing such developers to compete with incumbent utilities for the construction and operation of transmission facilities in its service territory. While Order 1000 retains limited carve-outs for certain projects that will continue to default to incumbents for construction responsibility, including immediately needed reliability projects, upgrades to existing transmission facilities, projects cost-allocated to a single transmission zone, and projects being built on existing rights-of-way, increased competition for transmission projects could decrease the value of new investments that would be subject to recovery by PSE&G under its rate base, which could have a material adverse impact on our financial condition and results of operations. FERC is currently considering whether to modify Order 1000’s competition rules to further limit competition in an effort to encourage collaborative planning of large regional and interregional transmission projects. FERC is also examining whether additional oversight is needed to control transmission costs.

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

***MBR Authority and Other Regulatory Approvals—***Under FERC regulations, public utilities that sell power at market rates must receive MBR authority before making power sales, and the majority of our businesses operate with such authority. Failure to maintain MBR authorization, or the effects of any severe mitigation measures that would be required if market power was evaluated differently in the future, could have a material adverse effect on our business, financial condition and results of operations. In December 2022, all of PSEG’s operating companies with MBR authority filed at FERC for acceptance of the companies’ updated triennial market power analysis. This filing remains pending at FERC.

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

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

The markets, PTC and/or ZEC program may not provide sufficient revenue for our New Jersey nuclear plants or the PTC and/or ZEC program could be materially adversely modified through legal proceedings, either of which could result in the retirement of all of these nuclear plants.

As further described in Item 7. MD&A—Executive Overview of 2022 and Future Outlook, in April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs by the BPU through May 2022. In April 2021, these nuclear plants were awarded ZECs for the three-year period starting June 2022.

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.

In August 2022, the IRA was signed into law expanding incentives promoting carbon-free generation. The enacted legislation established a PTC for electricity generation using nuclear energy set to begin in 2024 through 2032. The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts. The PTC rate and the gross receipts 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. The ZEC payment may be adjusted by the BPU at any time to offset environmental or fuel diversity payments that a selected nuclear plant may receive from another source. We are continuing to analyze the impact of the IRA on our nuclear units including additional future guidance from the U.S. Treasury and the interactions with PTCs on expected ZEC payments.

If the markets, PTC and/or the ZEC program do not provide sufficient 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 CWA and related state regulations, or other factors, PSEG Power may take all necessary steps to cease to operate all of these plants and will incur associated costs and accounting charges in the event that the financial condition of the plants is materially adversely impacted in the future. Ceasing operations of these plants would result in a material adverse impact on PSEG’s results of operations.

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

The energy industry continues to be regulated and the rules to which our businesses are subject are always at risk of being changed. Our business has been impacted by established rules that create locational capacity markets in PJM. Under these rules, generators located in constrained areas are paid more for their capacity so there is an incentive to locate in those areas where generation capacity is most needed. PJM’s capacity market design rules continue to evolve, including in response to efforts to integrate public policy initiatives into the wholesale markets. For a discussion of recent changes in energy regulatory policies that may affect our business and results of operations, see Item 1. Regulatory Issues—Federal Regulation.

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.

In July 2021, the BPU 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 participating 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 PJM capacity market or work in conjunction with it. We cannot predict whether the BPU will ultimately take any measures in the future that will have an impact on the capacity market or our generating stations.

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

The 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:

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

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

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

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

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

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

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

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

We are subject to extensive federal, state and local environmental laws and regulations regarding air quality, water quality, site remediation, land use, waste disposal, climate change impact, natural resource damages and other matters. These laws and regulations affect how we conduct our operations and make capital expenditures. Over the past several years, there have been various changes to 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. Any failure to make future recoveries could materially impact our financial condition.

In addition, PSEG Power retained ownership of certain liabilities excluded from the sale of its fossil generation portfolio. These primarily relate to obligations under environmental regulations, including remediation obligations under the New Jersey Industrial Site Recovery Act and the Connecticut Transfer Act. It will require multiple years and comprehensive environmental sampling to understand the extent of and to carry out the required remediation. The full remediation costs are not estimable, but will 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 remediation of environmental contamination, see Item 8. Note 15. Commitments and Contingent Liabilities.

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

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

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

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

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

The enactment of additional federal or 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.

PSE&G

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

Electric Property and Facilities

As of December 31, 2022, PSE&G’s electric T&D system included approximately 25,000 circuit miles, and 864,000 poles, of which 64% are jointly-owned. In addition, PSE&G owns and operates 55 switching stations with an aggregate installed capacity of 39,653 megavolt-amperes (MVA) and 235 substations with an aggregate installed capacity of 9,735 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.

Gas Property and Facilities

As of December 31, 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 56 natural gas metering and regulating stations, of which 26 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.

Solar

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

PSEG Power

Generation Facilities

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

table:

(A) Operated by Constellation Energy Generation, LLC.

As of December 31, 2022, PSEG Power owned a 50% interest (104 MW) in a generation facility in Hawaii.

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.

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

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

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

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

Our business discussion in Item 1. Business provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Item 1A. Risk Factors provides information about factors that could have a material adverse impact on our businesses. The following discussion provides an overview of the significant events and business developments that have occurred during 2022 and key factors that we expect may drive our future performance. This discussion refers to the Consolidated Financial Statements (Statements) and the related Notes to the Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements and Notes.

EXECUTIVE OVERVIEW OF 2022 AND FUTURE OUTLOOK

We are a public utility holding company that, acting through our wholly owned subsidiaries, is a predominantly regulated electric and gas utility and a nuclear generation business. Our business plan focuses on achieving growth by allocating capital primarily toward regulated investments in an effort to continue to improve the sustainability and predictability of our business. We are focused on investing to modernize our energy infrastructure, improve reliability and resilience, increase EE and deliver cleaner energy to meet customer expectations and be well aligned with public policy objectives. In furtherance of these goals, over the past few years, our investments have simplified our business mix to reflect a higher percentage of earnings contribution by PSE&G. We have further proactively changed our business mix through the sale of our fossil generation portfolio which closed in 2022. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information. In addition, the passage of the Inflation Reduction Act (IRA) established a Production Tax Credit (PTC) for nuclear from 2024 through 2032 which is expected to provide downside price protection for our nuclear generation fleet.

PSE&G

At PSE&G, our focus is on investing capital in T&D infrastructure and clean energy programs to enhance the reliability and resiliency of our T&D system, meet customer expectations and support public policy objectives. For the years 2023-2027, PSE&G’s capital investment program is estimated to be in a range of $15.5 billion to $18 billion, resulting in an expected compound annual growth in rate base of 6% to 7.5% from year-end 2022 to year-end 2027. The low end of this range includes an extension of our Gas System Modernization Program (GSMP) and Clean Energy Future (CEF)-EE program at their average annual investment levels plus inflation, as these programs are expected to continue beyond their currently approved timeframe of 2023. The upper end of our capital investment range includes an extension of our Energy Strong program, which otherwise concludes in 2024, as well as the remaining portion of our CEF proposal (portion of Electric Vehicle (EV) and Energy Storage (ES) programs) and a potentially higher amount of investments for GSMP and CEF-EE beyond current levels. We filed for a $320 million short-term extension of our CEF-EE program in September 2022, which we expect will be resolved in 2023. A remaining component of our CEF-EV program related to medium and heavy duty charging infrastructure has been the subject of a stakeholder process that the BPU began in 2021 and we expect that this effort will result in PSE&G submitting a filing targeting infrastructure investments for the medium and heavy duty EV market in 2023. Our CEF-ES program is being held in abeyance. In September 2022, the BPU released a draft Storage Incentive Program proposal and is currently undertaking a stakeholder process to receive comments. PSE&G is active in the proceeding. Pursuant to our GSMP II and Energy Strong II programs, we are required to file a distribution base rate case no later than December 31, 2023. Among other things, the rate case will recover capital expenditures associated with these programs, as well as the Advanced Metering Infrastructure and EV programs, and other investments that are not recovered through periodic rate roll-ins. We expect to conclude the case in the second half of 2024.

PSEG Power

At PSEG Power, we seek to produce low-cost electricity by efficiently operating our nuclear generation assets, mitigate volatility by contracting in advance for a significant portion of their output and support public policy objectives that preserve these existing nuclear generating plants. During 2022, our nuclear units generated 31.3 terawatt hours and operated at a capacity factor of 92.2%.

We recently closed the sale of our Solar generation and Fossil generation businesses in 2021 and 2022, respectively. These transformative transactions reduced our overall business risk and earnings volatility.

PSEG Power’s hedging practices help to mitigate a significant amount of the earnings volatility of the merchant nuclear power business. More than 90% of PSEG Power’s expected gross margin in 2023 relates to hedging of our energy margin, our expected revenues from the capacity market mechanism, Zero Emission Certificate (ZEC) revenues and, certain gas operations and ancillary service payments such as reactive power. While this limits our exposure to decreasing prices, our ability to realize benefits from rising market prices is also limited. During the second half of 2021 and continuing throughout 2022, forward energy prices have demonstrated considerable price volatility and have increased dramatically. This has led to significantly higher variation in our collateral requirements, which have also increased substantially over that time period for hedge positions that are out-of-the money. PSEG Power’s net cash collateral postings related to these hedge positions increased from $343 million at the end of June 2021 to $1.5 billion at the end of December 2022. Subsequent to December 2022, collateral postings continued to experience significant fluctuations in our daily collateral requirements. Net cash collateral postings were approximately $700 million as of February 17, 2023. While currently off their highs experienced during 2022, collateral postings could remain volatile into 2023. However, as historical lower-priced trades continue to settle through 2024, collateral is expected to be returned as we satisfy our obligations under those contracts. PSEG continues to maintain sufficient liquidity as described in Liquidity and Capital Resources.

Climate Strategy and Sustainability Efforts

For more than a century, our purpose has been to provide safe access to an around-the-clock supply of reliable, affordable energy. Today, our vision is to power a future where people use less energy, and it is cleaner, safer and delivered more reliably than ever. We have established a net zero greenhouse gas (GHG) emissions by 2030 goal that includes direct GHG emissions (Scope 1) and indirect GHG emissions from operations (Scope 2) across our operations, assuming advances in technology, public policy and customer behavior. Scope 1 emissions include power generation, methane leaks, vehicle fleet emissions, and sulfur hexafluoride and refrigerant leaks. Scope 2 emissions include both gas and electric purchased energy for our PSE&G facilities and line losses. We have also committed to the United Nations-backed Race to Zero campaign. We continue to evaluate and are working toward developing and submitting science-based emission reduction targets following the criteria and recommendations of the Science Based Targets initiative (SBTi) by September 2023 which encompass Scopes 1, 2, and 3 (the majority of which are associated with the downstream use of energy products) and seek to be in line with 1.5oC emissions scenarios in order to be validated by the SBTi.

PSE&G has undertaken a number of initiatives that support the reduction of GHG emissions and the implementation of EE initiatives. PSE&G’s approved CEF-EE, CEF-Energy Cloud and CEF-EV programs and the proposed CEF-ES program are intended to support New Jersey’s Energy Master Plan through programs designed to help customers increase their EE, support the expansion of the EV infrastructure in the State, install energy storage capacity to supplement solar generation and enhance grid resiliency, install smart meters and supporting infrastructure to allow for the integration of other clean energy technologies and to more efficiently respond to weather and other outage events.

In addition, PSE&G is committed to the safe and reliable delivery of natural gas to approximately 1.9 million customers throughout New Jersey and we are equally committed to reducing GHG emissions associated with such operations. The first phase of our GSMP replaced approximately 450 miles of cast-iron and unprotected steel gas main infrastructure, and the second phase of this program is expected to replace an additional 875 miles of gas pipes through 2023. The GSMP is designed to significantly reduce natural gas leaks in our distribution system, which would reduce the release of methane, a potent GHG, into the air. Through GSMP II, from 2018 through 2023 we expect to reduce methane leaks by approximately 22% system wide and assuming a continuation of GSMP, we expect to achieve an overall reduction in methane emissions of approximately 60% over the 2011 through 2030 period. We also continue to assess physical risks of climate change and adapt our capital investment program to improve the reliability and resiliency of our system in an environment of increasing frequency and severity of weather events, notably through our investments in our Energy Strong program and Infrastructure Advancement Program. These investments have shown benefits in recent severe weather events, including Tropical Storm Ida in August 2021, which brought significant flooding to our service territory but did not result in the loss of any of our electric distribution substations.

We also continue to focus on providing cleaner energy for our customers. Our priority is to preserve the economic viability of our nuclear units, which provide over 85% of the carbon-free energy in New Jersey, by advocating for state and federal policies, such as the IRA discussed below, that recognize the value of carbon-free generation and reduce market risk.

In February 2023, New Jersey Governor Murphy issued three executive orders that establish targets, or accelerate previously established 2050 targets, for clean-sourced energy, building electrification, and EV adoption goals, with new target dates of 2030 or 2035, as applicable. The executive orders direct the BPU and other state agencies to collaborate with stakeholders to develop plans, including the new 2024 Energy Master Plan, to reach the targets and convene a stakeholder proceeding to develop a new plan for gas distribution utilities to reach the target, previously established in a 2021 executive order, of 50% natural gas emissions reductions over 2006 levels by 2030. Such proceeding is to consider competitive market mechanisms including adoption of a “clean heat” standard, policies to minimize investment in new gas infrastructure, and alternative programs that could provide natural gas utilities with new revenue streams, such as conversion of existing pipeline infrastructure to provide decarbonized heating and cooling (for example, district geothermal). We are unable to predict the outcomes of the various proceedings, but they could have a material impact on our business, results of operations and cash flows.

Offshore Wind

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

In January 2023, PSEG agreed to sell to Ørsted its 25% equity interest in Ocean Wind JV HoldCo, LLC. The sale proceeds approximate PSEG’s carrying value of the investment and no material gain or loss is expected upon disposition. The sale is contingent upon finalization of a purchase and sale agreement with Ørsted and other closing conditions as well as potential state regulatory approval that may be required to close on the transaction. The sale is expected to close in the first half of 2023. PSEG has no further obligation to make any capital contributions to the project prior to closing on the transaction. PSEG will continue to provide construction management and environmental permitting services for the onshore substations and transmission cable installation scope of the project.

Additionally, PSEG and Ørsted each owns 50% of Garden State Offshore Energy LLC (GSOE) which holds rights to an offshore wind lease area just south of New Jersey. PSEG has decided not to exercise its option to purchase 50% of Ørsted’s Skipjack projects in Maryland (one of which would utilize a portion of the GSOE lease area) or pursue an ownership interest in Ørsted’s Ocean Wind 2 offshore wind project or other offshore wind generation projects. PSEG is evaluating its options for the potential sale of its interest in GSOE.

In 2021-2022, PJM Interconnection, L.L.C. (PJM) conducted its first-ever public policy Order 1000 transmission solicitation process utilizing the state agreement approach for transmission projects to support New Jersey’s planned offshore wind generation. The state agreement approach requires customers in the requesting state - in this case New Jersey - to pay for the costs of these public policy transmission projects. PSEG and Ørsted jointly submitted several proposals in response to the solicitation, including multi-spur options and an offshore network proposal. The BPU completed its review of offshore wind transmission in October 2022 and awarded several on-shore, though no offshore, solutions. PSE&G was awarded $40 million for transmission upgrades. The BPU also indicated that it would consider conducting an additional solicitation to address the State’s increased offshore wind generation targets.

Financial Results

The financial results for PSEG, PSE&G and PSEG Power for the years ended December 31, 2022 and 2021 are presented as follows:

Millions, except per share data

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

Regulatory, Legislative and Other Developments

We closely monitor and engage with stakeholders on significant regulatory and legislative developments. Distribution investment needs and scope and transmission planning and rates rules, as well as wholesale power market design, including clarification from the U.S. Treasury on PTCs for electricity generation using nuclear energy, are of particular importance to our results and we continue to advocate for policies and rules that promote fair and efficient electricity markets. For additional information about regulatory, legislative and other developments that may affect us, see Item 1. Business—Regulatory Issues.

Transmission Rate Proceedings and Return on Equity (ROE)

In October 2021, FERC approved a settlement agreement effective August 1, 2021 that we reached with the BPU and the New Jersey Division of Rate Counsel about 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 our transmission formula rate for three years. We have implemented the terms of the agreement.

Under current FERC rules, we continue to earn a 50 basis point adder to that base ROE for our membership in PJM. FERC is considering whether to eliminate this adder and the outcome and timing of any decision is uncertain. If the adder was eliminated it would reduce PSE&G’s annual Net Income and annual cash inflows by approximately $30 million to $40 million.

Wholesale Power Market Design

In December 2022, PJM ran a Base Residual Auction for the Delivery Year 2024-2025 but it has not yet announced the results of the auction. Instead, based on what it observed in the auction, PJM made emergency filings at FERC to change the way in which it calculates the clearing prices for capacity zones under certain circumstances. As a result, PSEG does not yet know the level of capacity payments it may receive in this auction. The filings at FERC are pending and we cannot predict the outcome.

Environmental Regulation

We are subject to liability under environmental laws for the costs and penalties of remediating contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. In particular, the historic operations of PSEG companies and the operations of numerous other companies 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 in violation of various statutes. In addition, PSEG Power has retained ownership of certain liabilities excluded from the sale of its fossil generation portfolio, primarily related to obligations under New Jersey and Connecticut state law to investigate and remediate the sites. We are also currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, and the costs and penalties of any such remediation efforts could be material.

For further information regarding the matters described above, as well as other matters that may impact our financial condition and results of operations, see Item 8. Note 15. Commitments and Contingent Liabilities.

Nuclear

In April 2021, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs for the three-year eligibility period starting June 2022 at the same approximate $10 per megawatt hour (MWh) received during the prior ZEC period through May 2022. Pursuant to a process established by the BPU, ZECs are purchased from selected nuclear plants and recovered through a non-bypassable distribution charge in the amount of $0.004 per kilowatt-hour used (which is equivalent to approximately $10 per MWh generated in payments to selected nuclear plants (ZEC payment)). As previously noted, in August 2022, the IRA was signed into law expanding incentives promoting carbon-free generation. The enacted legislation established the PTC for electricity generation using nuclear energy set to begin in 2024 through 2032. The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts. The PTC rate and the gross receipts 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 are continuing to analyze the impact of the IRA on our nuclear units including additional future guidance from the U.S. Treasury and the impact of PTCs on expected ZEC payments. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information.

Current Inflationary Environment

The current inflationary environment has prompted the Federal Reserve to tighten monetary policy resulting in higher interest rates, which have impacted financial markets, reducing the value of fixed income investments and created uncertainty about the future economic outlook weakening equity markets. These factors have resulted in negative returns on our pension assets during 2022. As our pension costs are set at the beginning of the calendar year, there was no impact on pension costs for 2022 resulting from asset performance during the year. However, pension costs in 2023 will be and future years are expected to be materially impacted from returns on 2022 pension assets. The higher interest rates translate into a higher discount rate for our pension obligations, which lowers our pension liability and positively affects our funded ratio, which remains strong.

In February 2023, PSE&G received an accounting order from the BPU authorizing PSE&G to modify its method for calculating the amortization of the net actuarial gain or loss component of pension expense for ratemaking purposes. This order will mitigate some of the volatility in earnings and customer rates related to our pension trust performance, and is effective for calendar year 2023 and forward. As a result of this order, PSEG’s 2023 pension expense, net of amounts capitalized, will be reduced by $59 million, resulting in a pension credit of $16 million.

Further, higher interest rates on borrowings will contribute to higher interest expense on variable rate debt, which has increased due to cash collateral postings, and to long-term rates on future financing plans. During September and October 2022, PSEG entered into floating-to-fixed interest rate swaps totaling $1.05 billion in order to reduce the volatility in interest expense for PSEG Parent’s $500 million variable rate term loan due May 2023 and a portion of PSEG Power’s $1.25 billion variable rate term loan due March 2025. Inflation will also result in upward pressure on operating costs and capital spending.

Tax Legislation

Future federal and state tax legislation and clarification of existing legislation could have a material impact on our effective tax rate and cash tax position.

The IRA enacted a new 15% corporate alternative minimum tax, effective in 2023, a PTC for existing nuclear generation facilities and allows energy tax credits to be transferable. Many aspects of the IRA remain unclear and in need of further guidance; therefore, we cannot determine the impact the IRA will have on PSEG’s and PSE&G’s results of operations, financial condition and cash flows.

In 2020, the Internal Revenue Service (IRS) issued final and proposed Section 163(j) regulations addressing the limitation on deductible business interest expense, increasing the amount of interest that can be deducted by unregulated businesses in years before 2022. The portion of PSEG’s and PSEG Power’s business interest expense that was disallowed in 2018 and 2019 is now deductible in those respective years.

Additionally, the federal Coronavirus Aid, Relief, and Economic Security Act (CARES Act) allowed us to carry back the 2018 tax net operating loss (NOL) generated by the final Section 163(j) regulations to 2023. In December 2022, the IRS approved our carry back claim, providing a $28 million tax benefit.

Future Outlook

Our future success will depend on our ability to continue to maintain strong operational and financial performance to capitalize on or otherwise address regulatory and legislative developments that impact our business and to respond to the issues and challenges described below. In order to do this, we will continue to:

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

In addition to the risks described elsewhere in this Form 10-K for 2022 and beyond, the key issues and challenges we expect our business to confront include:

• regulatory and political uncertainty, both with regard to transmission planning and rates policy, the role of distribution utilities and decarbonization impacts, future energy policy, design of energy and capacity markets, and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceedings,
• the current inflationary environment and associated volatility in the financial markets, including the impact on our pension fund performance and interest rates on our future financing plans,
• increases in commodity prices and customer rates, which may adversely affect customer collections and future regulatory proceedings,
• the increasing frequency, sophistication and magnitude of cybersecurity attacks against us and our respective vendors and business partners who may have our sensitive information and/or access to our environment, and the increasing frequency and magnitude of physical attacks on electric and gas infrastructure;
• future changes in federal and state tax laws or any other associated tax guidance, and
• the impact of changes in demand, natural gas and electricity prices, and expanded efforts to decarbonize several sectors of the economy.

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

• investments in PSE&G, including T&D facilities to enhance reliability, resiliency and modernize the system to meet the growing needs and increasingly higher expectations of customers, and clean energy investments such as CEF-EE, CEF-EV, CEF-ES and Solar,
• continued operation of our nuclear generation facilities that are supported through the PTC through 2032 and can enable certain enhancements to the units as well as potential license extensions,
• investments in regional offshore wind regulated transmission, should New Jersey pursue the development of an offshore network, with returns that provide revenue predictability and reasonable risk-adjusted returns, and
• acquisitions, dispositions, development and other transactions involving our common stock, assets or businesses that could provide value to customers and shareholders.

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

RESULTS OF OPERATIONS

Millions, except per share data

(A) PSEG Power & Other results in 2022 include after-tax impairments of $92 million related to certain Energy Holdings investments and additional adjustments related to the sale of PSEG Power’s fossil generation assets. PSEG Power & Other results in 2021 include an after-tax impairment loss and other associated charges, including debt extinguishment costs, of $2,158 million related to the sale of PSEG Power’s fossil generation assets. PSEG Power & Other results in 2020 include an after-tax gain of $86 million related to the sale of Power’s ownership interest in the Yards Creek generation facility. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information.

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

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

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

(A) NDT Fund Income (Expense) includes gains and losses on NDT securities which are recorded in Net Gains (Losses) on Trust Investments. See Item 8. Note 11. Trust Investments for additional information. NDT Fund Income (Expense) also includes interest and dividend income and other costs related to the NDT Fund recorded in

Other Income (Deductions), interest accretion expense on PSEG Power’s nuclear Asset Retirement Obligation (ARO) recorded in Operation & Maintenance (O&M) Expense and the depreciation related to the ARO asset recorded in Depreciation and Amortization (D&A) Expense.

(B) Net of tax (expense) benefit of $97 million, $(70) million and $(94) million for the years ended December 31, 2022, 2021 and 2020, respectively.

(C) Net of tax benefit of $178 million, $174 million and $23 million for the years ended December 31, 2022, 2021 and 2020, respectively.

Net Income in 2022 as compared to a Net Loss in 2021 was driven primarily by

• an impairment loss and related charges taken in 2021 as a result of the sale of the fossil generation assets at PSEG Power (see Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information),
• higher earnings due to continued investments in T&D programs at PSE&G, and
• the favorable impact of the Conservation Incentive Program (CIP) in 2022 at PSE&G,
• partially offset by net unrealized losses on equity securities in 2022 in the NDT Fund and net realized losses in 2022 as compared to net realized gains in 2021.

Our results of operations are primarily comprised of the results of operations of our principal operating segments, PSE&G and PSEG Power, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 8. Note 26. Related-Party Transactions.

PSEG

The 2022, 2021 and 2020 amounts in the preceding table for Operating Revenues and O&M costs each include $516 million, $511 million and $520 million, respectively, for PSEG LI’s subsidiary, Long Island Electric Utility Servco, LLC (Servco). These amounts represent the O&M pass-through costs for the Long Island operations, the full reimbursement of which is reflected in Operating Revenues. See Item 8. Note 5. Variable Interest Entities for additional information. The following discussions for PSE&G and PSEG Power provide a detailed explanation of their respective variances.

PSE&G

Year Ended December 31, 2022 as compared to 2021

Operating Revenues increased $813 million due to changes in delivery, clause, commodity and other operating revenues.

Delivery Revenues increased $209 million.

• Gas distribution revenues increased $129 million due primarily to increases of $55 million from collection of the GSMP in base rates, $54 million from higher sales volumes and $18 million in CIP decoupling revenues.
• Electric distribution revenues increased $47 million due primarily to $30 million from CIP decoupling revenue and $20 million from an Energy Strong II rate roll-in.
• Electric distribution and gas distribution revenue requirements were $28 million higher due primarily to a net decrease in the flowback to customers of excess deferred income tax liabilities and tax repair-related accumulated deferred income taxes, which is offset in Income Tax Expense.
• Transmission revenues increased $5 million due to an increase in revenue requirements attributable to higher rate base investment, partially offset by the estimated impact of the ROE settlement.

Clause Revenues increased $4 million due primarily to $35 million in higher Societal Benefits Clause (SBC) collections, partially offset by a $30 million decrease in Tax Adjustment Credits (TAC) and Green Program Recovery Charge (GPRC) deferrals. The changes in SBC collections and TAC and GPRC deferrals were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, D&A and Interest and Tax Expenses. PSE&G does not earn margin on SBC collections or TAC and GPRC deferrals.

Commodity Revenues increased $551 million due to higher Gas revenues and Electric revenues. The changes in Commodity Revenues for both gas and electric are entirely offset by changes in Energy Costs. PSE&G earns no margin on the provision of basic gas supply service (BGSS) and basic generation service (BGS) to retail customers.

• Gas revenues increased $393 million due primarily to $335 million from higher BGSS prices and $60 million from higher BGSS sales volumes.
• Electric revenues increased $158 million due primarily to $140 million from higher BGS sales volumes and $20 million from higher prices.

Other Operating Revenues increased $49 million due primarily to a $25 million increase in appliance service revenues, and an $18 million increase from the Successor Solar Incentive Program (SuSI) and Solar Renewable Energy Credits (SREC) revenues. The changes in SuSI and SREC revenues are entirely offset by changes to Energy Costs.

Operating Expenses

Energy Costs increased $582 million. This is entirely offset by changes in Commodity Revenues and Other Operating Revenues.

Operation and Maintenance increased $146 million due primarily to increases of $82 million in clause and renewable related expenses, $45 million in higher operational costs and $13 million in injuries and damages.

Depreciation and Amortization increased $7 million due primarily to an increase in depreciation due to higher plant placed in service, partially offset by a decrease due to lower transmission depreciation rates effective August 1, 2021 and a decrease in the amortization of Regulatory Assets.

Non-Operating Pension and OPEB Credits (Costs) increased $17 due primarily to a $51 million decrease in amortization of the net actuarial loss, partially offset by a $21 million decrease in the expected return on plan assets and a $13 million increase in interest cost.

Interest Expense increased $25 million due primarily to long-term debt issuances in 2022 and 2021, partially offset by debt maturities in 2021.

Income Tax Expense decreased $57 million due primarily to an increase in flowback of excess deferred income tax benefits, an increase in tax benefits from the CEF program investments, and a decrease in bad debt flow-through tax expense.

Year Ended December 31, 2021 as compared to 2020

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2021 as filed with the SEC on February 24, 2022 for information related to the year ended December 31, 2021 as compared to 2020, which information is incorporated herein by reference.

PSEG Power & Other

Year Ended December 31, 2022 as compared to 2021

Operating Revenues decreased $501 million due to changes in generation, gas supply and other operating revenues.

Generation Revenues decreased $1,300 million due primarily to

• a net decrease of $807 million due primarily to lower volumes sold in the PJM, New England (NE) and New York (NY) regions primarily due to the sale of the fossil generating plants in February 2022, coupled with lower average realized prices in the PJM region, partially offset by higher average realized prices in the NE and NY regions,
• a net decrease of $234 million in capacity revenue due primarily to the sale of the fossil generating plants coupled with lower capacity prices in the PJM region, partially offset by decreases in capacity expenses due to lower load volumes served,
• a net decrease of $216 million due primarily to lower volumes of electricity sold under the BGS contracts, partially offset by less transmission services under the BGS contracts that were transferred from the BGS suppliers to the

Electric Distribution Companies (EDCs) in February 2021,

• a net decrease of $37 million in ancillary revenues due primarily to the sale of the fossil generating plants, and
• a net decrease of $24 million in solar revenues due to the sale of the solar plants in June 2021,
• partially offset by a net increase of $16 million due to lower MTM losses in 2022 as compared to 2021. Of this amount, there was a $368 million increase due to gains on positions reclassified to realized upon settlement in 2022 as compared to losses in 2021, partially offset by a $352 million decrease due to changes in forward prices.

Gas Supply Revenues increased $788 million due primarily to

• a net increase of $481 million in sales under the BGSS contract due primarily to $419 million from higher prices and $62 million from higher sales volumes,
• a net increase of $282 million related to sales to third parties, primarily due to $248 million from higher sales prices and $34 million from higher sales volumes, and
• an increase of $25 million due primarily to changes in forward prices.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet PSEG Power’s obligation under its BGSS contract with PSE&G. Energy Costs increased $171 million due to

Gas costs increased $721 million due primarily to

• a net increase of $478 million related primarily to sales under the BGSS contract, of which $425 million was due to the higher average cost of gas and $53 million due to higher send out volumes, and
• a net increase of $243 million related to sales to third parties, of which $213 million was due to an increase in the average cost of gas and $30 million to higher volumes sold.

Generation costs decreased $550 million due primarily to

• a net decrease of $413 million in fuel costs, due primarily to lower volumes of gas used in the PJM, NY, and NE regions caused by the sale of the fossil generating plants, partially offset by higher gas prices. Additionally, there was a decrease in coal costs in the NE region due to the retirement of the Bridgeport Harbor 3 (BH3) plant in 2021,
• a net decrease of $142 million in energy purchases due primarily to lower renewable energy credit (REC) requirements and lower ancillary charges caused by decreases in load served in the PJM and NE regions,
• a net decrease of $33 million in emission costs due to the sale of the fossil generating plants, and
• a net decrease of $17 million in transmission costs due primarily to the impact from transfer of responsibility for firm transmission services under BGS contracts from BGS suppliers to the EDCs,
• partially offset by a net increase of $56 million due to net MTM losses in 2022 as compared to net MTM gains in 2021. Of this amount, there was a $42 million increase due to positions reclassified to realized upon settlement in 2022 as compared to 2021, coupled with a $15 million increase due to changes in forward prices.

Operation and Maintenance decreased $194 million due primarily to the sale of the fossil generating plants in February 2022 and the sale of our ownership interest in the solar plants in June 2021.

Depreciation and Amortization decreased $123 million due primarily to ceasing depreciation expense on the then pending sales of the solar and fossil generating plants since May and August 2021, respectively, and the retirement of BH3 in 2021, partially offset by higher depreciation related to an increase in the nuclear AROs in 2021.

(Gains) Losses on Asset Dispositions and Impairments The $123 million loss in 2022 reflects an impairment loss of $50 million due to the sale of the fossil generating plants in February 2022, partially offset by a $5 million gain on a land sale at PSEG Power and pre-tax impairments of $78 million at Energy Holdings related to one of its domestic energy generating facilities and its real estate assets. The $2,641 million net loss in 2021 reflects impairment losses due to the sale of the fossil generating plants and other impairments, partially offset by a $63 million gain from the sale of PSEG Solar Source (Solar Source) in 2021. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments.

Net Gains (Losses) on Trust Investments decreased $455 million due primarily to NDT investments with an increase of $224 million of net unrealized losses on equity securities as compared to 2021 and $50 million of net realized losses in 2022 as compared to $166 million of net realized gains in 2021.

Other Income (Deductions) increased $26 million due primarily to lower donations at the parent company.

Non-Operating Pension and OPEB Credits (Costs) increased $31 million due to a $22 million decrease in the amortization of the net actuarial loss and a $29 million increase in the expected return on plan assets, partially offset by an $18 million increase in interest cost and $2 million in co-owner charges.

Loss on Extinguishment of Debt represents a loss incurred in 2021 for a make whole premium that was payable upon early redemption of all outstanding PSEG Power Senior Notes and other non-cash debt extinguishment costs.

Interest Expense increased $32 million due primarily to increases from issuances of term loans at PSEG Power and term loans and commercial paper at the parent company, partially offset by the early redemption of all outstanding PSEG Power debt obligations in 2021.

Income Tax Benefit decreased $469 million due primarily to a lower pre-tax loss in 2022, partially offset by the recapture of investment tax credits (ITCs) related to the sale of Solar Source in 2021, increased tax benefits on losses from the NDT qualified fund in 2022, and the tax benefit of PSEG’s federal 2018 carryback claim in 2022.

Year Ended December 31, 2021 as compared to 2020

Operating Revenues decreased $462 million due to changes in generation, gas supply and other operating revenues.

Generation Revenues decreased $668 million due primarily to

• a net decrease of $606 million due to higher MTM losses in 2021 as compared to 2020. Of this amount, there was a $624 million decrease due to changes in forward prices, partially offset by an $18 million increase due to less losses on positions reclassified to realized upon settlement in 2021,
• a net decrease of $288 million due primarily to $201 million from lower volumes of electricity sold under the BGS contracts, coupled with an $87 million impact from the transfer of responsibility for firm transmission services from BGS suppliers to the EDCs, and
• a net decrease of $29 million in solar revenues due to the sale of the solar plants in June 2021,
• partially offset by a net increase of $188 million due primarily to higher average realized prices and higher volumes sold in the PJM, NE and NY regions, and
• a net increase of $64 million in capacity revenues due primarily to increases in auction prices, coupled with decreases in capacity charges due to lower BGS and other load obligations in the PJM region, partially offset by lower capacity prices and the retirement of the BH3 coal plant in the NE region.

Gas Supply Revenues increased $182 million due primarily to

• a net increase of $106 million in sales under the BGSS contract due primarily to higher prices of $72 million and higher sales volumes of $34 million, and
• a net increase of $74 million related to sales to third parties, of which $90 million was due to higher average sales prices, partially offset by $16 million due to lower volumes sold.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet PSEG Power’s obligation under its BGSS contract with PSE&G. Energy Costs increased $157 million due to

Generation costs decreased $13 million due primarily to

• a net decrease of $147 million in transmission costs due primarily to an $87 million impact from the transfer of responsibility for firm transmission services under BGS contracts from BGS suppliers to the EDCs, coupled with a $60 million decrease in other transmission costs, mainly from lower volumes of electricity sold under the BGS contracts, and
• a net decrease of $66 million due to higher net MTM gains in 2021. Of this amount, there was a $52 million decrease due to changes in forward prices, coupled with a $14 million decrease due to more gains on positions reclassified to realized upon settlement in 2021,
• partially offset by a net increase of $157 million in fuel costs, reflecting higher gas prices and higher volumes in the PJM, NY, and NE regions, and
• a net increase of $42 million in energy purchases due primarily to an increase in purchased volumes in the PJM region to meet physical energy sales. This was partially offset by a decrease in REC requirements caused by decreases in load served in the PJM region.

Gas costs increased $170 million due primarily to

• a net increase of $103 million in costs related to sales under the BGSS contract, of which $74 million was due to the higher average cost of gas and $29 million to higher send out volumes. Included in the 2020 average cost of gas were $18 million of interstate gas pipeline refunds due to a settlement on pipeline rates from prior periods, and
• a net increase of $67 million related to sales to third parties, of which $81 million was due to an increase in the average cost of gas, partially offset by a decrease of $14 million due to lower volumes sold.

Operation and Maintenance increased $33 million due primarily to a refueling outage in 2021 at our 100%-owned Hope Creek nuclear plant as compared to an outage in 2020 at our 57%-owned Salem 2 nuclear plant and severance costs related to the sale of the fossil generating plants, partially offset by lower costs in 2021 due to the sale of our ownership interest in the solar plants in June 2021.

Depreciation and Amortization decreased $110 million due primarily to ceasing depreciation expense on the solar and fossil generating plants since May and August, 2021, respectively, and the retirement of BH3 in 2021.

(Gains) Losses on Asset Dispositions and Impairments The loss in 2021 primarily reflects a $2,691 million impairment due to the sale of the fossil generating plants and other impairments, partially offset by a $63 million gain from the sale of the solar plants. The $122 million gain in 2020 was due to the sale of our ownership interest in the Yards Creek generation facility. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments.

Net Gains (Losses) on Trust Investments decreased $58 million due primarily to a $101 million decrease in net unrealized gains on equity investments in the NDT Fund, partially offset by a $46 million increase in net realized gains on NDT Fund investments.

Other Income (Deductions) increased $3 million due primarily to less purchases of NOL tax benefits under the New Jersey Technology Tax Benefit Transfer Program at the parent company and higher interest and dividend income on NDT Fund investments in 2021, partially offset by higher donations at the parent company.

Non-Operating Pension and OPEB Credits (Costs) increased $20 million due to a $19 million decrease in interest cost and a $9 million increase in the expected return on plan assets, partially offset by a $5 million increase in the amortization of net prior service cost and net actuarial loss and $3 million in co-owner charges.

Loss on Extinguishment of Debt represents a loss incurred in 2021 for a make whole premium that was payable upon early redemption of all remaining outstanding Senior Notes and other non-cash debt extinguishment costs.

Interest Expense decreased $43 million due primarily to the early redemption of all remaining outstanding debt obligations of PSEG Power in October 2021.

Income Tax Expense decreased $921 million due primarily to lower pre-tax income in 2021, partially offset by the recapture of ITCs related to the sale of the solar plants in 2021, the tax benefit in 2020 from changes in uncertain tax positions as a result of the settlement of the 2011-2016 federal income tax audits, and the purchase of less New Jersey NOL tax benefits in 2021.

LIQUIDITY AND CAPITAL RESOURCES

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

Financing Methodology

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

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

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

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

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

PSEG Power’s sources of external liquidity include the Master Credit Facility and PSEG Power’s letter of credit facilities. Credit capacity is primarily used to provide collateral in support of PSEG Power’s forward energy sale and forward fuel purchase contracts as the market prices for energy and fuel fluctuate, and to meet potential collateral postings in the event that PSEG Power is downgraded to below investment grade by Standard & Poor’s (S&P) or Moody’s. PSEG Power’s dividend payments to PSEG are also designed to be consistent with its capital structure objectives which have been established to maintain investment grade credit ratings and provide sufficient financial flexibility.

Operating Cash Flows

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

For the year ended December 31, 2022, our operating cash flow decreased $233 million. The net decrease was primarily due to the sale of the fossil generation plants in February 2022, and a $244 million increase in payments to counterparties at PSEG Power and the net change at PSE&G, as discussed below. In addition, there were tax payments in 2022 as compared to tax refunds in 2021 at the parent company.

PSE&G

PSE&G’s operating cash flow increased $304 million from $1,724 million to $2,028 million for the year ended December 31, 2022, as compared to 2021, due primarily to decreases in vendor and electric energy payments, lower tax payments, higher earnings in 2022, and an increase in cash collateral postings received from BGS suppliers. This was partially offset by an increase in net accounts receivable due to ongoing delayed collections as a result of COVID-19 moratoriums in 2022, increases in materials and supplies to support our electric AMI program as well as an increase in material purchases in 2022 due to easing of prior year supply chain shortages, and a net increase in regulatory deferrals in 2022.

Short-Term Liquidity

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

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

During the second half of 2021 and continuing throughout 2022, forward energy prices have demonstrated considerable price volatility and have increased dramatically. This has led to significantly higher variation in our daily collateral requirements which have also increased substantially over that time period for hedge positions that are out-of-the money. PSEG Power’s net cash collateral postings related to these hedge positions increased from $343 million at the end of June 2021 to $1.5 billion at the end of December. Subsequent to December 2022, collateral postings have decreased but PSEG Power continued to experience significant fluctuations in its daily collateral requirements. Net cash collateral postings were approximately $700 million on February 17, 2023. While currently off their highs experienced during 2022, collateral postings could remain volatile into 2023. However, as historical lower-priced trades continue to settle through 2024, collateral is expected to be returned as we satisfy our obligations under those contracts. Proceeds from the sale of Fossil, the closing of a $1.25 billion term loan in March 2022 at PSEG Power, and short-term borrowings at PSEG have contributed to available liquidity to help support PSEG Power’s collateral requirements in 2022.

In March and May 2021, PSEG entered into two 364-day variable rate term loan agreements for $500 million and $750 million, respectively. In August 2021, PSEG entered into a $1.25 billion, 364-day variable rate term loan agreement. In March 2022, the $500 million term loan matured and PSEG repaid the $750 million term loan due in May 2022. In July 2022, PSEG repaid the $1.25 billion term loan due in August 2022.

In April 2022 and May 2022, PSEG entered into 364-day variable rate term loan agreements for $1.5 billion and $500 million, respectively. In January 2023, PSEG repaid $750 million of the $1.5 billion term loan due in April 2023. These term loans are not included in the credit facility amounts presented in the following table.

Our total committed credit facilities and available liquidity as of December 31, 2022 were as follows:

For additional information, see Item 8. Note 16. Debt and Credit Facilities.

We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements, including to satisfy any additional collateral requirements. As of December 31, 2022, our liquidity position, including our credit facilities and access to external financing, was expected to be sufficient to meet our projected stressed requirements over our 12 month planning horizon. PSEG analyzes its liquidity requirements using stress scenarios that consider different events, including changes in commodity prices and the potential impact of PSEG Power losing its investment grade credit rating from S&P or Moody’s, which would represent a two level downgrade from its current Moody’s and S&P ratings. In the event of a deterioration of PSEG Power’s credit rating, certain of PSEG Power’s agreements allow the counterparty to demand further performance assurance. The potential additional collateral that we would be required to post under these agreements if PSEG Power were to lose its investment grade credit rating was approximately $878 million and $1,151 million as of December 31, 2022 and 2021, respectively. See Item 8. Note 15. Commitments and Contingent Liabilities for additional discussion of PSEG Power’s agreements.

Long-Term Debt Financing

During the next twelve months,

• PSEG has $750 million of 0.841% Senior Notes due November 2023,
• PSE&G has $500 million of 2.38% of Medium-Term Notes Series I, due May 2023, and
• PSE&G has $325 million of 3.25% of Medium-Term Notes, Series M, due September 2023.

For additional information, see Item 8. Note 16. Debt and Credit Facilities.

NDT Fund Obligation

The NRC requires a biennial filing of the NDT fund balances against the decommissioning liability estimate. Any funding shortfalls are required to be cured prior to the next NDT reporting period. The current market downturn associated with inflation and rising interest rates is not currently expected to result in any supplemental required funding of the NDT Fund.

Debt Covenants

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

In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As of December 31, 2022, PSE&G’s Mortgage coverage ratio was 3.4 to 1 and the Mortgage would permit up to approximately $7.8 billion aggregate principal amount of new Mortgage Bonds to be issued against additions and improvements to its property.

Default Provisions

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

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

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

Ratings Triggers

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

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

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

Common Stock Dividends

On February 14, 2023, our Board of Directors approved a $0.57 per share common stock dividend for the first quarter of 2023. This reflects an indicative annual dividend rate of $2.28 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. For additional information related to cash dividends on our common stock, see Item 8. Note 24. Earnings Per Share (EPS) and Dividends.

Credit Ratings

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

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

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

Other Comprehensive Income

For the year ended December 31, 2022, we had Other Comprehensive Loss of $200 million on a consolidated basis. The Other Comprehensive Loss was due primarily to $132 million of net unrealized losses related to Available-for-Sale Debt Securities, and a decrease of $71 million related to pension and other postretirement benefits, partially offset by $3 million of unrealized gains on derivative contracts accounted for as hedges. See Item 8. Note 23. Accumulated Other Comprehensive Income (Loss), Net of Tax for additional information.

CAPITAL REQUIREMENTS

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

PSE&G

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

• Transmission—investments focused on reliability improvements and replacement of aging infrastructure.
• Electric and Gas Distribution—investments for new business, reliability improvements, flood mitigation, and

modernization and replacement of equipment that has reached the end of its useful life.

• Clean Energy—investments associated with customer EE programs, infrastructure supporting EVs and grid-connected solar.

In 2022, PSE&G made $2,590 million of capital expenditures, primarily for T&D system reliability. This does not include expenditures for EE and EV programs of approximately $286 million and cost of removal, net of salvage, of $129 million, which are included in operating cash flows.

Other

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

In 2022, PSEG’s other capital expenditures were $105 million, excluding $193 million for nuclear fuel, primarily related to various nuclear projects at PSEG Power.

Other Material Cash Requirements

The following table reflects our other material cash requirements which include debt maturities and interest payments, operating lease payments and energy related purchase commitments in the respective periods in which they are due. For additional information, see Item 8. Note 16. Debt and Credit Facilities, Note 8. Leases and Note 15. Commitments and Contingent Liabilities.

The table below does not reflect any anticipated cash payments for pension and OPEB or AROs due to uncertain timing of payments. See Item 8. Note 14. Pension and Other Postretirement Benefits (OPEB) and Savings Plans and Note 13. Asset Retirement Obligations (AROs) for additional information.

CRITICAL ACCOUNTING ESTIMATES

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

Accounting for Pensions and Other Postretirement Benefits (OPEB)

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

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

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

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

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

Effect if Different Assumptions Used: As part of the business planning process, we have modeled future costs assuming an 8.10% expected rate of return and a 5.20% discount rate for 2023 pension costs/credits and a 5.16% discount rate for 2023 OPEB costs/credits. The 8.10% expected rate of return on assets for 2023 has increased as compared to 2022, as increasing interest rates during 2022 were a significant contributor to the reduction in pension assets during the year and drove the increase in the expected rate of return. Based upon these assumptions, we have estimated a net periodic pension expense in 2023 of approximately $21 million, or a net periodic pension credit of $16 million, net of amounts capitalized, and a net periodic OPEB credit in 2023 of approximately $43 million, or $44 million, net of amounts capitalized. Our 2023 net periodic pension amounts include the impact of the accounting order approved by the BPU authorizing PSE&G to modify its pension accounting for ratemaking purposes. See a discussion in Item 7. MD&A—Executive Overview of 2022 and Future Outlook for further details. Actual future pension costs/credits and funding levels will depend on future investment performance, changes in discount rates, market conditions, funding levels relative to our projected benefit obligation and accumulated benefit obligation and various other factors related to the populations participating in the pension plans. Actual future OPEB costs/credits will depend on future investment performance, changes in discount rates, market conditions, and various other factors.

The following chart reflects the sensitivities associated with a change in certain assumptions. The effects of the assumption changes shown below solely reflect the impact of that specific assumption.

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

Derivative Instruments

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

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

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

For a small number of contracts where limited observable inputs or pricing information are available, modeling techniques are employed in determination of their fair value using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable.

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

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

For additional information regarding Derivative Financial Instruments, see Item 8. Note 1. Organization, Basis of Presentation and Significant Accounting Policies, Note 18. Financial Risk Management Activities and Note 19. Fair Value Measurements.

Long-Lived Assets

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

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

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

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

Effect if Different Assumptions Used: The above cash flow tests, and fair value estimates and estimated remaining useful lives may be impacted by a change in the assumptions noted above and could significantly impact the outcome, triggering additional impairment tests, write-offs or accelerated depreciation. For additional information on the potential impacts on our future financial statements that may be caused by a change in the assumptions noted above, see Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments.

Asset Retirement Obligations (ARO)

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

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

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

We obtain updated nuclear decommissioning cost studies triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2021. When we revise any assumptions used to calculate fair values of existing AROs, we adjust the ARO balance and corresponding long-lived asset which generally impacts the amount of accretion and depreciation expense recognized in future periods.

Nuclear Decommissioning AROs

AROs related to the future decommissioning of PSEG Power’s nuclear facilities comprised approximately 74% or $1,105 million of PSEG’s total AROs as of December 31, 2022. PSEG Power determines its AROs for its nuclear units by assigning probability weighting to various discounted cash flow outcomes for each of its nuclear units that incorporate the assumptions above as well as:

• financial feasibility and impacts on potential early shutdown,
• license renewals,
• SAFSTOR alternative, which assumes the nuclear facility can be safely stored and subsequently decommissioned in a period within 60 years after operations,
• DECON alternative, which assumes decommissioning activities begin after operations, and
• recovery from the federal government of assumed specific costs incurred for spent nuclear fuel.

Effect if Different Assumptions Used: Changes in the assumptions could result in a material change in the ARO balance sheet obligation and the period over which we accrete to the ultimate liability. Had the following assumptions been applied, our estimates of the approximate impacts on the Nuclear ARO as of December 31, 2022 are as follows:

• A decrease of 1% in the discount rate would result in a $41 million increase in the Nuclear ARO.
• An increase of 1% in the inflation rate would result in a $329 million increase in the Nuclear ARO.
• If the federal government were to discontinue reimbursing us for assumed specific spent fuel costs as prescribed under the Nuclear Waste Policy Act, the Nuclear ARO would increase by $161 million.
• If we would elect or be required to decommission under a DECON alternative at Salem and Hope Creek, the Nuclear ARO would increase by $557 million.
• If PSEG Power were to increase its early shutdown probability to 100% and retire Salem and Hope Creek starting in 2032, which is significantly earlier than the end of their current license periods, the Nuclear ARO would increase by $102 million. For additional information, see Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments.

Accounting for Regulated Businesses

PSE&G prepares its financial statements to comply with GAAP for rate-regulated enterprises, which differs in some respects from accounting for non-regulated businesses. In general, accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (Regulatory Asset) or recognize obligations (Regulatory Liability) if the rates established are designed to recover the costs and if the competitive environment makes it probable that such rates can be charged or collected. This accounting results in the recognition of revenues and expenses in different time periods than that of enterprises that are not regulated.

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

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

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

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

Effect if Different Assumptions Used: A change in the above assumptions may result in a material impact on our results of operations or our cash flows. See Item 8. Note 7. Regulatory Assets and Liabilities for a description of the amounts and nature of regulatory balance sheet amounts.

MARKET RISK

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

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

Commodity Contracts

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

Value-at-Risk (VaR) Models

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

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

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

See Item 8. Note 18. Financial Risk Management Activities for a discussion of credit risk.

Interest Rates

We are subject to the risk of fluctuating interest rates in the normal course of business. We manage interest rate risk by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, we use a mix of fixed and floating rate debt, interest rate swaps and interest rate lock agreements.

As of December 31, 2022, a hypothetical 10% increase in market interest rates would result in an additional $6 million in pre-tax annual interest costs related to either the current or the long-term portion of long-term debt, and term loan agreements.

Debt and Equity Securities

As of December 31, 2022, we had $5.3 billion of net assets in trust for our pension and OPEB plans. Although fluctuations in market prices of securities within this portfolio do not directly affect our earnings in the current period, changes in the value of these investments could affect

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

The NDT Fund is comprised primarily of fixed income and equity securities. As of December 31, 2022, the portfolio included $1.1 billion of equity securities and $1.1 billion in fixed income securities. The fair market value of the assets in the NDT Fund will fluctuate primarily depending upon the performance of equity markets. As of December 31, 2022, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $110 million.

We use duration to measure the interest rate sensitivity of the fixed income portfolio. Duration is a summary statistic of the effective average maturity of the fixed income portfolio. The benchmark for the fixed income component of the NDT Fund currently has a duration of 6.17 years and a yield of 4.68%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2022, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $71 million.

Disclosure Controls and Procedures

PSEG and PSE&G

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

Internal Controls

PSEG and PSE&G

We have conducted assessments of our internal control over financial reporting as of December 31, 2022, as required by Section 404 of the Sarbanes-Oxley Act, using the framework promulgated by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO.” Managements’ reports on PSEG’s and PSE&G’s internal control over financial reporting are included on pages 152 and 153, respectively. The Independent Registered Public Accounting Firm’s report with respect to the effectiveness of PSEG’s internal control over financial reporting is included on page 154. Management has concluded that internal control over financial reporting is effective as of December 31, 2022.

We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of our financial reporting. There have been no changes in internal control over financial reporting that occurred during the fourth quarter of 2022 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.