# Public Service Enterprise Group Inc: Form 10-K for the period ended Dec 31, 2023 - Company: [Public Service Enterprise Group Inc](/companies/peg.md) (CIK 788784) - Form: 10-K - Filed: 2024-02-26 - Accepted by EDGAR: Feb 26, 2024, 16:26 ET - Period: 2023-12-31 - Accession: 0001628280-24-006885 - Inline XBRL: yes - Main document: https://www.sec.gov/Archives/edgar/data/788784/000162828024006885/pseg-20231231.htm - All documents and exhibits: https://www.sec.gov/Archives/edgar/data/788784/000162828024006885/ ## Figures reported in this filing Standardized XBRL line items for the period ended 2023-12-31. | Line item | Period | Value | XBRL concept | | --- | --- | ---: | --- | | Revenue | 12 months, 2023-01-01 to 2023-12-31 | $11.24bn | us-gaap:Revenues | | Operating income | 12 months, 2023-01-01 to 2023-12-31 | $3.69bn | us-gaap:OperatingIncomeLoss | | Interest expense | 12 months, 2023-01-01 to 2023-12-31 | $748.0m | us-gaap:InterestExpense | | Income tax | 12 months, 2023-01-01 to 2023-12-31 | $518.0m | us-gaap:IncomeTaxExpenseBenefit | | Net income | 12 months, 2023-01-01 to 2023-12-31 | $2.56bn | us-gaap:NetIncomeLoss | | Diluted EPS | 12 months, 2023-01-01 to 2023-12-31 | $5.13 | us-gaap:EarningsPerShareDiluted | | Basic EPS | 12 months, 2023-01-01 to 2023-12-31 | $5.15 | us-gaap:EarningsPerShareBasic | | Diluted shares (weighted) | 12 months, 2023-01-01 to 2023-12-31 | 500,000,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding | | Operating cash flow | 12 months, 2023-01-01 to 2023-12-31 | $3.81bn | us-gaap:NetCashProvidedByUsedInOperatingActivities | | Capital expenditure | 12 months, 2023-01-01 to 2023-12-31 | $3.33bn | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment | | Dividends paid | 12 months, 2023-01-01 to 2023-12-31 | $1.14bn | us-gaap:PaymentsOfDividendsCommonStock | | Share repurchases | 12 months, 2023-01-01 to 2023-12-31 | $0 | us-gaap:PaymentsForRepurchaseOfCommonStock | | Cash and equivalents | at 2023-12-31 | $54.0m | us-gaap:CashAndCashEquivalentsAtCarryingValue | | Current assets | at 2023-12-31 | $3.37bn | us-gaap:AssetsCurrent | | Total assets | at 2023-12-31 | $50.74bn | us-gaap:Assets | | Current liabilities | at 2023-12-31 | $5.06bn | us-gaap:LiabilitiesCurrent | | Long-term debt | at 2023-12-31 | $17.78bn | us-gaap:LongTermDebtNoncurrent | | Current portion of debt | at 2023-12-31 | $1.50bn | us-gaap:LongTermDebtCurrent | | Short-term borrowings | at 2023-12-31 | $949.0m | us-gaap:CommercialPaper | | Shareholders' equity | at 2023-12-31 | $15.48bn | us-gaap:StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest | ## Business As filed, 72,289 characters. We were incorporated under the laws of the State of New Jersey in 1985 and our principal executive offices are located at 80 Park Plaza, Newark, New Jersey 07102. We 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 a public utility holding company consisting primarily of a regulated electric and gas utility and a nuclear generation business. Over the past several years, our investments resulted in a higher percentage of earnings contribution by PSE&G. The sale of the fossil generating portfolio in 2022 further simplified our business mix, resulting in an even higher percentage of earnings contribution by PSE&G going forward and provides more financial flexibility. Our business approach focuses on operational excellence, financial strength and disciplined investment. 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 3. Asset Dispositions and Impairments for additional information. Our other direct wholly owned subsidiaries are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under a contractual agreement; PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily holds our legacy lease investments and competitively bid, FERC regulated transmission; and PSEG Services Corporation (Services), which provides us and our operating subsidiaries with certain management, administrative and general services at cost. ### OPERATIONS AND STRATEGY ### PSE&G Our regulated T&D public utility, PSE&G, distributes electric energy and natural gas to customers within a designated service territory running diagonally across New Jersey where approximately 6.8 million people, or about 74% of New Jersey’s population resides. ### Products and Services Our utility operations primarily earn margins through: - **Transmission—**the movement of electricity at high voltage from generating plants to substations and transformers, where it is then reduced to a lower voltage for distribution to homes, businesses and industrial customers. Our revenues for these services are based upon tariffs approved by the Federal Energy Regulatory Commission (FERC). - **Distribution—**the delivery of electricity and gas to the retail customer’s home, business or industrial facility. Our revenues for these services are based upon tariffs approved by the New Jersey Board of Public Utilities (BPU). The commodity portion of our utility business’ electric and gas sales is managed by basic generation service (BGS) and basic gas supply service (BGSS) suppliers. Pricing for those services is set by the BPU as a pass-through, resulting in no margin for our utility operations. In addition, we continue to invest in and pursue opportunities in regulated clean energy, 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 2.4 million electric customers and 1.9 million gas customers in a service area that covers approximately 2,600 square miles running diagonally across New Jersey. We serve the most densely populated, commercialized and industrialized territory in New Jersey, including its six largest cities and approximately 300 suburban and rural communities. ### Transmission We use formula rates for our transmission cost of service and investments. Formula rates provide a method of rate recovery where the transmission owner annually determines its revenue requirements through a fixed formula that provides for a recovery of our operating costs and a return of and on our capital investments in the system, net of accumulated depreciation and deferred tax liabilities (also known as rate base) using an approved return on equity (ROE) in developing the weighted average cost of capital. Under this formula, rates are put into effect in January of each year based upon our internal forecast of annual expenses and capital expenditures. Rates are subsequently trued up to reflect actual annual expenses and capital expenditures. Our transmission revenues are not impacted by sales volumes. Our current approved transmission rates provide for a base ROE of 9.90% and a 50 basis point adder for our membership in PJM as an RTO. See Item 7. MD&A—Executive Overview of 2023 and Future Outlook. ### Distribution PSE&G distributes electricity and natural gas to end users in our respective franchised service territories. Our distribution rates are subject to periodic rate cases approved by the BPU. 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. Our current approved distribution base rates provide for an ROE of 9.6%. In December 2023, we filed a distribution base rate case as required by the BPU. For a discussion of our recent distribution base rate case filing, see Item 7. MD&A—Executive Overview of 2023 and Future Outlook. For a discussion of proposed and approved programs, see Investment Clause Programs as follows and Item 7. MD&A—Executive Overview of 2023 and Future Outlook. Our load requirements are split among residential, C&I customers, as described in the following table for 2023: | Customer Type | % of 2023 Sales Electric | Gas | | --- | ---: | ---: | | Commercial | 58% | 38% | | Residential | 33% | 58% | | Industrial | 9% | 4% | | **Total** | **100%** | **100%** | Our customer base has modestly increased since 2019, with electric and gas loads changing as illustrated in the following table: *Electric and Gas Distribution Statistics* | | Number of Customers as of December 31, 2023 | | Historical Annual Customer Growth 2019-2023 | Electric Sales and Firm Gas Sales as of December 31, 2023 (A) | | Historical Annual Load Decline 2019-2023 | | --- | ---: | --- | ---: | ---: | --- | ---: | | Electric | 2.4 | Million | 0.9% | 39,085 | Gigawatt hours | (1.4)% | | Gas | 1.9 | Million | 0.6% | 2,282 | Million Therms | (2.8)% | (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 distribution base rate case for the majority of our customers. As a result, electric gas sales volumes and demands are no longer a driver of our margin and over 90% of our Electric and Gas Distribution margin will only vary based upon the number of customers. While there has been a recent decrease in load due to a decline in larger industrial customers, greater EE and other factors, PJM’s most recent forecast indicates an increase in load over the next several years due to the increasing adoption of EVs, the expansion of data centers and other large users in our area, ongoing growth in the number of customers, other sources of electrification and other factors, which will collectively drive the need for increased system investment in the future. ### Investment Clause Programs The following table lists our major approved investment clause programs that are in progress: | Program | Investment | Approval Date | Term of Investment | | Year Started | | --- | --- | --- | --- | --- | --- | | Gas System Modernization Program II (GSMP II) Extension | $902 million | 2023 | 2 years | (A) | 2024 | | Energy Strong II Program | $842 million | 2019 | 4 years | (B) | 2019 | | CEF-EE | $1 billion | 2020 | 5 years | (C) | 2020 | | CEF-EE Extension | $280 million | 2023 | 9 months | | 2023 | | CEF-Energy Cloud (EC) | $707 million | 2021 | 4 years | | 2021 | | CEF-EV | $166 million | 2021 | ~6 years | | 2021 | | Infrastructure Advancement Program (IAP) | $511 million | 2022 | 4 years | | 2022 | (A) The program has a small amount of trailing costs expected to be spent in year 3. (B) The program has a small amount of trailing costs expected to be spent in year 5. (C) Rolling three-year program with over 80% of spending within 5 years, with limited spending thereafter. **GSMP II Extension—**designed to replace at least 400 miles of cast iron and unprotected steel mains and services in our gas system. **Energy Strong II Program—**structured to harden, modernize and improve the resiliency of our electric and gas distribution systems. To date, we launched three of the four components of our **CEF:** - **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. Our CEF-Energy Storage (ES) program, which was filed with the BPU in October 2018, is being held in abeyance. Our proposed ES program is for a $109 million investment that encompasses solar smoothing, whereby a battery energy solar system is used to neutralize fluctuations in solar output to facilitate its entry into the grid, distribution investment deferral, outage management, microgrids and peak reduction for municipal facilities. **IAP—**designed to improve the reliability of the “last mile” of our electric distribution system and address aging substations and gas metering and regulation stations. See Item 7. MD&A—Executive Overview of 2023 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 13. Commitments and Contingent Liabilities. PSE&G procures the supply requirements of its default service BGSS gas customers through a full-requirements contract with PSEG Power. The BPU has approved a mechanism designed to recover all gas commodity costs related to BGSS for residential customers. BGSS filings are made annually by June 1 of each year, with a targeted effective date of provisional rates by October 1. PSE&G’s revenues are matched with its costs using deferral accounting, with the goal of achieving a zero cumulative balance by September 30 of each year. In addition, we have the ability to put in place two self-implementing BGSS increases on December 1 and February 1 of up to 5% and also may reduce the BGSS rate at any time and/or provide bill credits. Any difference between rates charged under the BGSS contract and rates charged to our residential customers is deferred and collected or refunded through adjustments in future rates. C&I customers that do not select third-party suppliers are also supplied under the BGSS arrangement. These customers are charged a market-based price largely determined by prices for commodity futures contracts. ### PSEG Power & Other PSEG Power & Other is predominantly comprised of its nuclear generation assets, its natural gas supply operations, the Operating Services Agreement (OSA) of PSEG LI with LIPA, and other legacy investments. PSEG Power is a public utility within the meaning of the Federal Power Act (FPA) and the payments it receives and how it operates are subject to FERC regulation. ### PSEG Power ### Products and Services As a nuclear generation owner and operator, our revenue has been derived primarily from energy, capacity and ancillary services sold to PJM in the spot markets. These products and services may also be transacted through exchange markets or bilaterally. In August 2022, the Inflation Reduction Act (IRA) was signed into law expanding incentives that promote carbon-free generation. The enacted legislation established the production tax credit (PTC) for electricity generation using nuclear energy, which begins January 1, 2024 and is available through 2032. PSEG Power’s Salem 1, Salem 2, Hope Creek, Peach Bottom 2 and Peach Bottom 3 nuclear plants are expected to benefit from the PTC. The expected PTC rate is up to $15 per megawatt hour (MWh) subject to adjustment based upon a facility’s gross receipts and meeting prevailing wage rules. The PTC rate and the gross receipts threshold are subject to annual inflation adjustments. Until additional guidance is issued by the U.S. Treasury, we are unable to fully determine the impacts of the PTC. PSEG Power also sells wholesale natural gas, primarily through a full-requirements BGSS contract with PSE&G to meet the needs of PSE&G’s default service customers. In 2022, the BPU approved an extension of the long-term BGSS contract to March 31, 2027, and thereafter the contract remains in effect unless terminated by either party with a two-year notice. PSEG Power supplies PSE&G’s peak daily gas requirements through its balanced portfolio of firm gas transportation capacity, storage contracts, contract peaking supply, and liquefied natural gas and propane. Based upon the availability of natural gas beyond PSE&G’s actual daily needs, PSEG Power sells gas to other customers and shares these proceeds with PSE&G’s customers. ### How PSEG Power’s Nuclear Generation Operates As of December 31, 2023, PSEG Power had 3,761 MW of nuclear generation capacity. All of our nuclear generation capacity is located in New Jersey and Pennsylvania. ### 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. The PTC is expected to mitigate our exposure to this volatility and provide support for the nuclear units. ### Nuclear Fuel Supply We have long-term contracts for nuclear fuel. These contracts provide for: - purchase of uranium (concentrates and uranium hexafluoride), - conversion of uranium concentrates to uranium hexafluoride, - enrichment of uranium hexafluoride, and - fabrication of nuclear fuel assemblies. We expect to be able to meet the nuclear fuel supply demands of our operations. However, 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, war and hostilities, and other factors. For additional information and a discussion of risks, see Item 1A. Risk Factors, Item 7. MD&A—Executive Overview of 2023 and Future Outlook and Item 8. Note 13. Commitments and Contingent Liabilities. ### Markets and Market Pricing All of PSEG Power’s nuclear generation assets are located within the PJM RTO. Our nuclear generating units’ performance, together with the PTC, have a considerable effect on our profitability. The PTC is designed to increase with inflation, and therefore, future inflation levels will impact the financial support of the nuclear units. In addition, market revenues in excess of the PTC threshold would provide incremental benefit. PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants have also been awarded zero emission certificates (ZECs) by the BPU through May 2025. These nuclear plants are expected to receive ZEC revenue from the electric distribution companies (EDCs) in New Jersey, which is equivalent to approximately $10/MWh. The number of ZECs purchased by each EDC from a selected nuclear power plant for an energy year is expected to be reduced by the number of ZECs equal in value to the dollar amount of PTCs received by the same plants. In addition to energy sales, we earn revenue from capacity payments for our generating assets. These payments are compensation for committing our generating units to PJM for dispatch at its discretion. Capacity payments reflect the value to PJM of assurance that there will be sufficient generating capacity available at all times to meet system reliability and energy requirements. In PJM the market design for capacity payments provides for a 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 2. Revenues. 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 The PTC is intended to provide sufficient and stable support for nuclear units and is effective January 1, 2024. To mitigate volatility in our results, we seek to contract in advance to hedge the price exposure for a significant portion of our anticipated electric output, capacity and fuel needs. We historically have sold a portion of our anticipated generation over a multi-year forward horizon, normally over a period of two to three years. As of the end of 2023, we have hedged approximately 90% to 95% of its expected generation output for 2024. Beginning in 2024, our hedging strategy will incorporate an estimated range of risk reduction impacts from the PTCs on our nuclear generation portfolio. This is expected to result in changes to our current approach given PTC guidance uncertainty, and potential incremental changes upon final U.S. Treasury guidance. 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 nuclear generation business. While this limits our exposure to decreasing prices, our ability to realize benefits from rising market prices is also limited. The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts. The U.S. Treasury is expected to clarify the definition of gross receipts as the eligibility period begins January 1, 2024. We are continuing to analyze the impact of the IRA on our nuclear units, including additional future guidance from the U.S. Treasury, potential impacts on hedging strategies and overall financial support. Our fuel strategy is to maintain certain levels of uranium in inventory and to make periodic purchases to support such levels. Our nuclear fuel commitments cover approximately 100% of our estimated uranium, enrichment and fabrication requirements through 2026 and a significant portion through 2027. ### LIPA Operations Services Agreement In accordance with a 12-year OSA entered into by PSEG LI and LIPA, PSEG LI commenced operating LIPA’s electric T&D system in Long Island, New York on January 1, 2014. The OSA contract term continues through 2025, but can be extended subject to a mutual agreement of the parties. Under the OSA, PSEG LI acts as LIPA’s agent in performing many of its obligations and in return (a) is prefunded for pass-through operating expenditures, (b) receives a fixed management fee and (c) is eligible to receive an incentive fee contingent on meeting established performance metrics. Further, since January 2015, PSEG Power provides fuel procurement and power management services to LIPA under separate agreements that expire at the end of 2025. It is uncertain whether the OSA and the separate agreements will be renewed on terms acceptable to us or at all. ### Energy Holdings Energy Holdings maintains our portfolio of legacy lease investments. See Item 8. Note 8. Long-Term Investments and Note 9. Financing Receivables for additional information. Energy Holdings also owns 50% of Garden State Offshore Energy LLC (GSOE) which holds rights to an offshore wind lease area just south of New Jersey. We are evaluating our options for the potential sale of our interest in GSOE. In December 2023, PJM awarded a subsidiary of Energy Holdings an approximately $424 million project to construct a 500 kV transmission line in Maryland. PSEG’s project was part of a larger set of projects designed to address reliability issues driven by load growth and retirement of fossil generation. Our project is expected to be placed in service in 2027. ### COMPETITIVE ENVIRONMENT ### 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. While current costs and relative emission savings would limit any substantial change in the near term, technological advances for heat pumps, actions by certain jurisdictions in our service territory and other factors could accelerate these potential changes, which could result in a slowing in the growth of our gas distribution and an increase in the growth of our electric T&D business. Our CIP reduces the impact on our distribution revenues from changes in sales volumes and demand for most customers. The CIP, which is calculated annually, provides for a true-up of our current period revenue as compared to revenue thresholds established in our most recent distribution base rate proceeding. 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 but are not limited to merchant generators, utility generators, energy marketers, retailers, private equity firms, and other financial entities. New additions of lower-cost or more efficient generation capacity, as well as subsidized generation capacity, or technological advances could impact forward market prices in the future. PJM has a capacity market that has been approved by FERC. FERC regulates this market and continues to examine whether this market design is working optimally. 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. ### HUMAN CAPITAL MANAGEMENT Our Core Commitments – safety, integrity, continuous improvement, customer service and diversity, equity and inclusion (DEI) – are at the center of our workplace culture. They guide us in important aspects of our Human Capital Management strategy, including recruitment, employee development, retention, performance, safety, and collaboration. We rely on our inclusive culture to support our many stakeholders including employees, customers, and the many diverse communities we serve. We believe in treating people with dignity and respect, protecting each of our fundamental human rights, and we strive to maintain the high standards of ethical conduct on which our business and reputation have been built. Our human capital management strategy is integrated with our overall business strategy. Relying on our core commitments and strong culture of inclusion, our focus is to attract, develop, and retain a high performing diverse workforce - one with the skill sets needed to succeed in a rapidly evolving environment. Over 60% of our workforce is represented by six unions under various collective bargaining agreements that cover wages, benefits and other terms and conditions of employment. In 2023, we negotiated new agreements with all six of our unions in advance of contract expiration. These agreements contain four-year terms, expiring in 2027 and support strategic objectives and business goals. The Organization and Compensation Committee of the PSEG Board of Directors is responsible for oversight of PSEG’s human capital management practices and is updated regularly on matters related to executive leadership succession and development, culture, and DEI. Safety metrics, such as Occupational Safety and Health Administration (OSHA) recordable incidence rate, OSHA days away from work rate, and serious injury incidence rate, are regularly monitored and reported to our Board. The following charts present our total employee population indicating percentages of employees that are represented by a collective bargaining unit, are women, or are racially and/or ethnically diverse: ### Health, Safety and Well-Being We value the health, safety, security and well-being of our employees, contractors and the communities that we serve. We demonstrate this by providing support to employees so that everyone is empowered and encouraged to question, stop and correct any unsafe act or condition. We take measures to provide employees and contractors with proper knowledge, training and protective equipment to maintain their personal health and safety and to mitigate workplace risks. ### Culture, Diversity, Equity and Inclusion We incorporate DEI throughout the employee life cycle and build on our Inclusion for All strategy. Since everyone is responsible for DEI and work-place culture, employees have many opportunities to influence the work environment, let their voices be heard and to step up and lead. Our efforts are led by the PSEG Office of DEI. It is supported by our Employee Business Resource Groups and the Local Inclusion Teams within our business units and field locations. The Office of DEI works to make sure our programs such as community outreach and volunteerism, mentorship, recognition and professional development, are relevant and accessible to all employees. To determine if we are being responsive to the needs of our employees, we routinely assess the impact of our work by soliciting employee feedback through focus groups, listening sessions, pulse surveys and a biennial employee engagement survey. Our initiatives to advance DEI include doing business with certified minority, women, veteran and service-disabled veteran-owned businesses as well as LGBTQ+-owned businesses and continuously improving our supplier diversity process which is integrated into our company culture. ### Talent, Attraction and Workforce Development Our talent acquisition strategy is focused on hiring a diverse, high-performing workforce to meet our business objectives, including the critical skilled trade roles needed to provide energy that is safer and delivered more reliably than ever. As part of these efforts, we work to attract employees who reflect broad dimensions of diversity, including race, gender, disability, generation, education, and other traits and characteristics that make each person who they are. Our employees grow through a variety of training and development opportunities offered to individual contributors, front line supervisors, managers and leaders. Talent reviews and succession planning for senior and critical positions are key components of our workforce planning strategy. We continue to identify and develop internal talent to step into key roles, minimizing any potential disruptions to our operations. We invest in technical and operational training for our craft and field workers to support safe and reliable operations. We continue to focus on hiring ahead of attrition and upskilling our skilled trade roles to adapt to evolving technologies and digital advancements. ### Total Rewards We support the well-being of our employees through a comprehensive total rewards program. We provide compensation to our workforce and a benefit program that is designed to support mental and physical health and emotional and financial wellness. In 2023, we performed a total rewards study, which included a comprehensive evaluation of our performance management process, compensation structure and design as well as pay fairness review. ### REGULATORY ISSUES 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 13. Commitments and Contingent Liabilities. In addition, information regarding PSE&G’s specific filings pending before the BPU is discussed in Item 8. Note 6. 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 proposed to eliminate the existing 50 basis point adder for RTO membership, which is currently available to PSE&G and other transmission owners in RTOs. Elimination of the RTO adder for RTO membership would reduce PSE&G’s annual Net Income and annual cash inflows by approximately $40 million. ***Transmission Planning Proceedings—***Through rulemaking proceedings, FERC continues to determine whether changes are needed to current transmission and interconnection planning rules to facilitate the integration of renewable resources onto the grid. FERC is also examining whether there is sufficient oversight over transmission costs to protect customers. Among other issues, FERC is considering whether transmission competitive solicitations are working as intended, whether interconnection queue rules for new generation should dramatically change and whether some type of transmission monitor construct to oversee costs should be imposed. On the interconnection front, in July 2023, FERC issued a Final Rule, which parties have challenged on rehearing, that will require RTOs to implement rules to speed up the processing of interconnection queue requests. This Rule may also result in penalties being imposed on generators, RTOs and transmission owners that fail to meet certain process deadlines. ### Regulation of Wholesale Sales—Generation/Market Issues/Market Power 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 called the Reliability Pricing Model (RPM), the rules for which are approved by FERC. RPM incorporates a forward auction for installed capacity. Under the RPM, generators located in constrained areas within PJM are paid more for their capacity as an incentive to ensure adequate supply where generation capacity is most needed. The mechanics of the RPM in PJM continue to evolve and be refined in stakeholder proceedings and FERC proceedings in which we are active. In October 2023, PJM submitted two related filings at FERC proposing reforms to its capacity market design, including (i) enhanced risk modeling to better account for winter risk; (ii) changes to supply-side market power mitigation rules; and (iii) more stringent capacity qualification and performance requirements. In January 2024, FERC issued an order approving PJM’s reforms relating to enhanced risk modeling and qualification and performance requirements. However, in February 2024, FERC issued an order rejecting PJM’s second package of reforms, including PJM’s proposed changes to its supply-side market power mitigation rules. At the same time, in this order FERC provided guidance to PJM should PJM choose to develop an alternate proposal in the future. Various parties may seek rehearing of FERC’s rejection order. In February 2024, PJM submitted a request asking FERC to delay the commencement of the base residual auction for the 2025/26 Delivery Year to mid-July 2024. This request is pending before FERC. In late December 2022, PJM called its first ISO-wide Maximum Generation Emergency Action during Winter Storm Elliott, which triggered a Performance Assessment Interval (PAI) event. As a result of this event, PSEG both incurred penalties and received bonuses under PJM’s capacity performance rules, neither of which were material to PSEG’s financial results in 2022 or 2023. Many generators filed complaints at PJM seeking to reduce or eliminate their obligations to pay non-performance penalties incurred during the event. Parties ultimately reached a settlement effectuating a penalty reduction that was not material to PSEG. In December 2023, FERC approved the settlement. ### 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. As a result of physical attacks in 2022 to electric infrastructure, NERC is studying whether the physical security standard should be revised. Moreover, under NERC’s supply chain standard approved by FERC in 2018, PSEG has developed physical and cybersecurity controls for supply chain management associated with the procurement of industrial control system hardware, software, and services related to grid operations. In February 2023, FERC approved additional reliability standards governing extreme cold weather preparedness and operations, which will begin going into effect in 2024. We continue to analyze these new standards. FERC and NERC continue to study potential revisions to reliability standards regarding extreme cold weather. Relatedly, in November 2023, FERC and NERC released a report regarding the operation of the Bulk Power System (BPS) during Winter Storm Elliott that struck in late 2022, causing power outages for millions and significantly straining the BPS in certain regions of the country, and proposed recommendations. These recommendations for extreme cold weather events include: (i) creation of additional reliability standards to strengthen generator operations; (ii) legislation or regulations to ensure the reliability of natural gas infrastructure; (iii) identification of high risk generating units and conducting cold weather verifications of these units; and (iv) improving short-term load forecasts for extreme cold weather events. In June 2023, FERC issued a rule directing NERC to either change existing reliability standards or create a new standard that will require RTOs like PJM to plan for extreme weather events. In October 2023, pursuant to FERC’s rule, PSE&G, along with PJM and other RTOs, jointly submitted an informational report describing their policies and processes for conducting extreme weather vulnerability assessments. ***Investor Ownership of Public Utilities—***In December 2023, FERC proposed new rules that, if finalized, would mean that institutional investors in FERC-regulated public utilities or in holding companies with public utility affiliates will need to obtain approval from FERC before acquiring such an ownership interest that exceeds a defined monetary threshold. Under current rules, investors are able to rely upon blanket authorizations to make such investments and are not required to obtain FERC approval for specific stock acquisitions. FERC is concerned that there is insufficient oversight to protect consumers and is seeking public comment on the proposed rules. We cannot predict the outcome of this rulemaking proceeding. ### CFTC In accordance with the Dodd-Frank Wall Street Reform and Consumer Protection Act, the SEC and the CFTC continue to implement a regulatory framework for swaps and security-based swaps. The rules are intended to reduce risk, increase transparency and promote market integrity within the financial system by providing for the registration and comprehensive regulation of swap dealers and by imposing recordkeeping, data reporting, margin and clearing requirements with respect to swaps. We are currently subject to recordkeeping and data reporting requirements applicable to commercial end users. The CFTC finalized 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: | Unit | Year | | --- | --- | | Salem Unit 1 | 2036 | | Salem Unit 2 | 2040 | | Hope Creek | 2046 | | Peach Bottom Unit 2 (A) | 2033 | | Peach Bottom Unit 3 (A) | 2034 | (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 11. 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) and Future of Gas Stakeholder Proceeding—***In January 2020, the State of New Jersey released its EMP. While the EMP does not have the force of law and does not impose any obligations on utilities, it outlines current expectations regarding the New Jersey’s role in the use, management, and development of energy. The EMP recognizes the goals of New Jersey’s Clean Energy Act of 2018 (the Clean Energy Act) to achieve, by 2026, annual reductions of electric and gas consumption of at least 2% and 0.75%, respectively, of the average of the prior three years of retail sales. 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. In February 2023, the governor of New Jersey issued three Executive Orders (EOs), one of which directs the BPU to immediately convene a stakeholder process on the future of gas to develop a plan to meet the State’s current EMP goal to reduce emissions by 50% versus 2006 levels by 2030. In March 2023, the BPU opened a stakeholder proceeding to implement such EO that commenced in August 2023 with a two-day technical conference. This proceeding will consider the possible development of a “clean heat standard” or other market mechanisms to support New Jersey’s goals, among other things. The BPU Board is seeking to retain a consultant to assist with this proceeding, and is expected to convene additional working groups and/or stakeholder sessions in 2024. Additionally, in April of 2023 the governor’s office Council on the Green Economy initiated a “Clean Buildings Working Group” that is considering pathways for building electrification and meeting gas utility emissions reduction goals, including development of a clean heat standard. PSE&G was invited to participate in this working group focused on strategic planning. We cannot predict the impact on our business or results of operations from these stakeholder proceedings, or any laws, rules, or regulations promulgated as a result thereof, particularly as they may relate to PSEG Power’s nuclear energy generating stations and PSE&G’s electric transmission and gas distribution assets. ***Stakeholder Proceeding on Gas Competition, BGSS—***In February 2023, the BPU announced that it would open a new docket to conduct a stakeholder proceeding regarding gas supply issues previously raised by competitive gas suppliers, including third-party suppliers’ participation in New Jersey gas distribution companies’ annual BGSS filings, and other aspects of the existing BGSS construct. In April-May 2023 the BPU Board conducted an initial stakeholder meeting and received written comments identifying any issues to be examined, presumably in a future portion of this proceeding following BPU Staff recommendation and BPU Board adoption. There has been no public activity in this matter since the submissions in May 2023. ***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 New Jersey’s overall reliance on fossil fuels and achieve the New Jersey governor’s goal of 100% clean energy by 2050. ***Energy Efficiency, Triennial Review—***During 2023, the BPU issued two Energy Efficiency Framework Orders which address, among other things, program administration and design, cost recovery and filing requirements, goals, a performance incentive mechanism, building decarbonization and demand response (DR), and required utilities to submit EE programs aligned with this framework. In September 2023, the BPU directed utilities to apply for a six-month extension of the first triennial programs. PSE&G filed for its six-month extension of the existing program in November 2023, and filed its second triennial EE program proposal in December 2023. Both filings are subject to BPU approval. ***BGS Process—***In June 2023, New Jersey’s EDCs, including PSE&G, filed their annual joint proposal for the conduct of the February 2024 BGS auction covering energy years 2025 through 2027. As was directed by a November 2022 BPU order, PSE&G participated in a working group led by BPU Staff to consider proposals for a commercial dc, fast-charging (DCFC) rate solution. PSE&G’s proposal included in the June 2023 joint EDC BGS filing is for a two-year DCFC BGS rate pilot program to begin June 1, 2024. Also, in accordance with the November 2022 order’s directive that the EDCs implement a rate solution for residential EV charging customers, in May 2023, the BPU approved PSE&G’s proposal for a BGS time-of-use rate solution for residential EV charging, with rates effective June 1, 2023. In November 2023, the BPU issued its decision to approve the joint EDCs’ proposal regarding the BGS auction process, including approving the EDCs’ proposed DCFC BGS rate pilot programs. ***EV Activity—***Consistent with the policy set forth in New Jersey’s EMP, the BPU has supported electrification of the transportation sector. 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 New Jersey’s EDCs, including PSE&G, regarding resource issues and policy changes needed to interconnect the clean energy capacity required under state policy. In June 2022, the BPU’s consultant issued a draft report with its findings and recommendations to update the BPU’s interconnection regulations and processes. The BPU is currently considering revising its interconnection rules to speed up the interconnection of renewable resources to the distribution grid. We cannot predict the impact on our business or results of operations from this Grid Modernization plan or any laws, rules or regulations promulgated as a result thereof, particularly as they may relate to PSE&G’s electric distribution assets. *N****ew Jersey Solar Initiatives—***In July 2021, the BPU issued an order formally establishing the Successor Solar Incentive (SuSI) Program, heavily drawing upon the predecessor Transition Renewable Energy Certificates program, to serve as the permanent program for providing solar incentives to qualified solar electric generation facilities. New Jersey’s EDCs role in the program is to acquire all of the Solar Renewable Energy Certificates-II received each year by eligible solar generation projects and each EDC may recover from its customers the reasonable and prudent costs incurred in the disposition of SuSI obligations. During 2023, the BPU rejected the first round of bids for the SuSI program projects as they exceeded pre-determined, confidential price caps. In September 2023, the BPU issued an Order opening a second round of solicitations which closes in February 2024. In August 2023, the BPU established a permanent Community Solar Energy Program (CSEP) including eligibility requirements, registration processes, the implementation of consolidated billing for the benefit of project developers and participants and allowing for the electric and natural gas utilities to recover costs related to implementing and administering the CSEP program. The program does not include the opportunity for utilities to develop or operate CSEP projects. ### Cybersecurity Regulation ***Federal—***NERC Critical Infrastructure Protection standards establish cybersecurity and physical security protections for critical systems and facilities. These standards are also designed to promote coordination, threat sharing and interaction between utilities and various government agencies regarding potential cyber and physical threats against the nation’s electric grid. The scope of the Critical Infrastructure Protection standards is limited to Bulk Electric System (BES) Cyber Systems that would impact the reliable operation of the BES. PSE&G is obligated to comply with the NERC Critical Infrastructure Protection standards. NERC Critical Infrastructure Protection standards do not apply to nuclear facilities which are instead governed by the NRC for purposes of physical and cyber security. NRC has a number of risk-informed, performance-based security programs in place to effectively protect U.S. commercial nuclear facilities. NRC has existing requirements, effective processes, and the expertise to regulate and inspect cybersecurity to ensure the federal requirements are met. NERC continues to examine revising criteria for low-impact cyber systems, which could result in expanding the Critical Infrastructure Protection standards to a larger set of applicable cyber assets. NRC requires operating nuclear power plant licensee and license applicants to ensure that digital computer and communication systems associated with a nuclear power plant’s safety, security, and emergency preparedness functions are protected from cyberattacks. As a result, computer systems at operating power plants that monitor and control safety systems and help the reactor operate are isolated from external communications. Security systems that provide safeguards of the facility are also isolated from external communications, including the Internet. NRC’s Office of Nuclear Security and Incident Response established the Cyber Security Branch (CSB) to strengthen internal governance of the agency’s regulatory activities. The CSB plans, coordinates, and manages agency activities related to cybersecurity for NRC applicants and licensees, such as security programs’ development and policy enhancements to prevent malevolent cyber acts against NRC-licensed facilities. The CSB’s cybersecurity-related responsibilities include developing rules and guidance, reviewing licensing actions, developing policy enhancements, and overseeing NRC-licensed facilities. NRC regularly monitors the threats associated with cybersecurity, including potential threats against NRC-licensed facilities. Within the CSB there is a cyber assessment team that assesses real-world cyber events at NRC-licensed facilities. The team evaluates whether an identified threat could impact licensed facilities and makes recommendations for NRC actions and communications to the licensees. Furthermore, the NRC has established liaison relationships with the intelligence and law enforcement communities to include the National Counterterrorism Center, the U.S. Department of Homeland Security’s (DHS) Computer Emergency Response Team, and the Federal Bureau of Investigation. The Transportation Security Administration, an agency of the U.S.DHS, has issued multiple security directives since May 2021 designed to mitigate cybersecurity threats to natural gas pipelines. ***State—***The BPU requires utilities, including PSE&G, to, among other things, implement a cybersecurity program that defines and implements organizational accountabilities and responsibilities for cyber risk management activities, and establishes policies, plans, processes and procedures for identifying and mitigating cyber risk to critical systems. Additional requirements of this order include, but are not limited to (i) annually inventorying critical utility systems; (ii) annually assessing risks to critical utility systems; (iii) implementing controls to mitigate cyber risks to critical utility systems; (iv) monitoring log files of critical utility systems; (v) reporting cyber incidents to the BPU; and (vi) establishing a cybersecurity incident response plan and conducting biennial exercises to test the plan. In addition, New York’s Stop Hacks and Improve Electronic Data Security (SHIELD) Act, which became effective in March 2020, requires businesses that own or license computerized data that includes New York State residents’ private information to implement reasonable safeguards to protect that information. ### ENVIRONMENTAL MATTERS We are subject to federal, state and local laws and regulations with regard to environmental matters. Our associated obligations change as legislatures and regulators pass new laws and regulations and amend existing ones. Therefore, it is difficult to project future costs of compliance and their impact on competition. 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 13. Commitments and Contingent Liabilities. ### Air Pollution Control Our facilities are subject to federal, state and local regulation that requires controls of emissions from sources of air pollution and imposes recordkeeping, reporting and permit requirements. ### Water Pollution Control The Federal Water Pollution Control Act prohibits the discharge of pollutants from point sources to water, except pursuant to a duly issued permit. These permits must generally be renewed every five years. Applicable regulations also impose obligations on facility operators like PSEG Power to install certain technology to treat their discharges to ensure discharges meet certain water quality requirements. The Environmental Protection Agency’s (EPA) Clean Water Act (CWA) Section 316(b) rule establishes requirements for the regulation of cooling water intakes at existing power plants, such as Salem. ### Hazardous Substance Liability PSEG’s operations involve substances and byproducts classified by environmental regulations as hazardous. These regulations impose handling, storage and disposal requirements for hazardous materials. They also impose liability for damages to the environment, including cash penalties. ***Site Remediation—***Federal and state environmental laws and regulations require the cleanup of discharged hazardous substances. They authorize the EPA, the New Jersey Department of Environmental Protection (NJDEP) and private parties to commence lawsuits to compel clean-ups or seek reimbursement for such remediation. The clean-ups can be more complicated and costly when the hazardous substances are in or under a body of water. Clean-up obligations may be imposed regardless of the absence of fault, contractual agreements between parties, or the legality of activities at the time of discharge. ***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) | Name | Age as of December 31, 2023 | Office | Effective Date First Elected to Present Position | | --- | ---: | --- | --- | | **Ralph A. LaRossa** | 60 | Chair of the Board (COB), President and Chief Executive Officer (CEO) - PSEG | January 2023 to present | | | | President and CEO -PSEG | September 2022 to present | | | | Chief Operating Officer (COO) - PSEG | January 2020 to August 2022 | | | | COB and CEO - PSE&G | September 2022 to present | | | | COB, President and CEO - PSEG Power | May 2023 to present | | | | COB and CEO - PSEG Power | September 2022 to May 2023 | | | | COB and CEO - Energy Holdings | September 2022 to present | | | | COB, CEO and President - Services | September 2022 to present | | | | President and COO - PSEG Power | October 2017 to August 2022 | | | | President and COO - PSE&G | October 2006 to October 2017 | | | | COB - PSEG Long Island LLC | December 2020 to August 2022 | | **Daniel J. Cregg** | 60 | Executive Vice President (EVP) and Chief Financial Officer (CFO) - PSEG | October 2015 to present | | | | EVP and CFO - PSE&G | October 2015 to present | | | | EVP and CFO - PSEG Power | October 2015 to present | | **Kim C. Hanemann** | 60 | President and COO - PSE&G | June 2021 to present | | | | Senior Vice President (SVP) and COO - PSE&G | January 2020 to June 2021 | | | | SVP - Electric Transmission and Distribution - PSE&G | September 2018 to January 2020 | | | | SVP - Delivery, Projects and Construction - PSE&G | July 2014 to September 2018 | | **Tamara L. Linde** | 59 | EVP and General Counsel - PSEG | July 2014 to present | | | | EVP and General Counsel - PSE&G | July 2014 to present | | | | EVP and General Counsel - PSEG Power | July 2014 to present | | **Charles V. McFeaters** | 64 | President and Chief Nuclear Officer - PSEG Nuclear LLC | May 2023 to present | | | | SVP - Nuclear Operations - PSEG Nuclear LLC | November 2020 to May 2023 | | | | Vice President (VP) - Salem Generating Station - PSEG Nuclear LLC | October 2016 to November 2020 | | **Sheila J. Rostiac** | 53 | SVP - Human Resources, Chief Human Resources and Chief Diversity Officer - Services | January 2020 to present | | | | SVP - Human Resources and Chief Human Resources Officer - Services | September 2019 to January 2020 | | | | VP - Talent, Development and Diversity | October 2012 to September 2019 | | **Richard T. Thigpen** | 63 | SVP - Corporate Citizenship - Services | July 2018 to present | | | | VP - State Government Affairs - Services | March 2007 to July 2018 | | **Rose M. Chernick** | 60 | VP and Controller - PSEG | March 2019 to present | | | | VP and Controller - PSE&G | March 2019 to present | | | | VP and Controller - PSEG Power | March 2019 to present | | | | VP-Finance, Corporate Strategy and Planning - Services | November 2017 to March 2019 | 16 ## Risk factors As filed, 73,716 characters. The following factors should be considered when reviewing our business. These factors could have a material adverse impact on our business, prospects, financial position, results of operations or cash flows and could cause results to differ materially from those expressed elsewhere in this report. ### GENERAL OPERATIONAL AND FINANCIAL RISKS **Inability to successfully develop, obtain regulatory approval for, or construct T&D, and our nuclear generation projects could adversely impact our businesses.** Our business plan calls for extensive investment in capital improvements and additions, including the construction of T&D facilities, modernizing and expanding existing infrastructure pursuant to investment programs that provide for current recovery in rates, 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 information technology (IT), cybersecurity and physical security upgrades; - obtain any necessary debt financing on acceptable terms and/or necessary governmental financial incentives; - ensure that contracting parties, including suppliers, perform under their contracts in a timely and cost-effective manner; and - timely recovery of these investments through rates. Failure to obtain regulatory or other approvals, delays, cost escalations or otherwise unsuccessful construction and development could materially affect our financial position, results of operations and cash flows. Macroeconomic considerations, including inflationary levels, gas and electric supply prices that are passed through to customers and other pressures could factor into our regulators’ assessment in approving the size, duration and timing of cost recovery of certain of these programs. Further, certain negative public and political views 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 the amounts of our investments and/or our return on these investments to be lower than expected, which could adversely impact our financial condition and results of operations through lower investment opportunities and/or lower returns. **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 PSE&G’s 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, wildfires and other natural disasters can stress systems, disrupt operation of our facilities and cause service outages, and property damage that require incurring additional expenses. 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, our suppliers and ultimately, our customers. 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 with 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, penalties, and punitive damages, including but not limited to, for liabilities for damages related to mitigate harm caused by climate change. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates. Further, our business is subject to policy, regulatory, technology and economic uncertainties and contingencies, including regulatory approvals required for 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 for Scopes 1 and 2 emissions, 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, accidents, critical operating technology or business system failures, natural disasters, severe weather events, acts of war or terrorism or other acts of violence, sabotage, physical attacks or security breaches, cyberattacks, or other incidents, including pandemics 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, sabotage, physical attacks or security breaches, cyberattacks or other incidents, which could result in damage to or destruction of our substations or other facilities or infrastructure, or damage to persons or property 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 delays or otherwise impair our ability to timely provide service to our customers or complete our investment projects. In response to the coronavirus pandemic, New Jersey and the BPU implemented a number of expanded customer protection measures, 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 negatively affected customer payment patterns, leading to an elevated aged accounts receivable balance. Our ability to manage our accounts receivable balance, and obtain recovery in rates for our carrying costs and any associated bad debts could have a material impact on our business. These events could result in increased political, economic, financial and insurance market instability, a lack of available insurance 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 otherwise in our business, or by others in our industry, could adversely impact our revenues; increase costs to repair and maintain our systems; subject us to potential litigation and/or damage claims, fines or penalties; and increase the level of oversight of our utility and generation operations and infrastructure through investigations or through the imposition of additional regulatory or legislative requirements. Such actions could adversely affect our costs, competitiveness 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 75% and 82% of the total assets of PSEG and PSE&G, respectively, as of December 31, 2023. Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, including a disallowance of certain costs, a potential sale or disposition of an asset significantly before the end of its useful life, business climate or market conditions, including prolonged periods of adverse commodity and capacity prices, could potentially indicate an asset’s or group of assets’ carrying amount may not be recoverable. Significant reductions in our expected revenues or cash flows for an extended period of time resulting from such events could result in future asset impairment charges, which could have a material adverse impact on our financial condition and results of operations. **Disruptions or cost increases in our supply chain, including labor shortages, could materially impact our business.** The supply chain of goods and services 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 with the regularity of virtual operations. 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. Further, new types of cyberattacks, whether directed at our own infrastructure and technology and operational systems or that of third parties, may be generated or enhanced through the use of Artificial Intelligence (AI). 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. To date, there has been no material impact or reasonably likely material impact on our business strategy, results of operations or financial condition from these attacks or other cybersecurity incidents, including as a result of prior cybersecurity incidents. However, we may be unable to prevent all such attacks in the future from having such a material impact as such attacks continue to increase in sophistication and frequency. If a significant cybersecurity event or breach occurs within our company or with one of our material vendors, we could be exposed to 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, including laws and regulations that respond to evolving application of AI, or unforeseen threat sources could require changes in current measures taken by us and our business operations, which could result in increased costs 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 1C. Cybersecurity. **A material shift away from natural gas toward increased electrification and a reduction in the use of natural gas as a result of decarbonization measures could adversely impact our gas business and ability to execute on our overall PSE&G business strategy.** Various jurisdictions outside of New Jersey have enacted prohibitions or restrictions on the use and consumption of natural gas and the BPU has commenced stakeholder proceedings regarding the Future of Natural Gas as required by the New Jersey governor’s EO issued in 2023. The CIP protects PSE&G’s margin variances against changes in customer usage of gas and electricity, but not against a decrease in the gas customer base (number of customers on the system). 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. If the above changes occurred, that would also require investment in the electric T&D system to accommodate higher loads. In addition, in order to enable the New Jersey clean energy economy, sustained grid modernization will be required to accommodate increased EE, EV infrastructure, increased penetration of distributed energy resources on the electric system, such as on-site solar generation and also anticipated increased deployment of energy storage, fuel cells, and DR technologies. If these changes progress rapidly in the near-term, our business model and our ability to execute on our overall PSE&G business strategy could be materially impacted. **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, acts of violence in the workplace, inadequate training and a workforce that is not engaged may lead to operating challenges, safety concerns and increased costs. The challenges include loss of knowledge and a lengthy time period associated with skill development, increased turnover, costs for contractors to replace employees, poor productivity, and a lack of innovation. Specialized knowledge and experience are required of employees across PSEG and its affiliates. There is competition for these skilled employees. Failure to hire and adequately train and retain employees, including the transfer of significant historical knowledge and expertise to new employees, may adversely affect our results of operations, financial position and cash flows. **Increases in the costs of equipment and materials, fuel, services and labor could adversely affect our operating results.** Higher costs from suppliers of equipment and materials, fuel, 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 distribution base rate cases could pressure customer rates, resulting in a potentially adverse outcome of such proceedings, or in other proceedings, including the proposal of certain investment programs or other proceedings that impact customer rates. **Covenants in our debt instruments and credit agreements may adversely affect our business.** PSEG’s and PSE&G’s debt instruments contain events of default customary for financings of their type, including cross accelerations to other debt of that entity. PSEG’s, PSE&G’s and PSEG Power’s bank credit agreements contain events of default customary for financings of their type, including cross defaults and accelerations and, in the case of PSEG’s and PSEG Power’s bank credit agreements, certain change of control events. PSEG’s, PSE&G’s and PSEG Power’s bank credit agreements, 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. **If we are unable to extend certain significant contracts on terms acceptable to us, this may negatively affect our financial condition and operating results** We are party to several contracts from which we derive significant revenues. PSEG Power sells wholesale natural gas, primarily through a full-requirements BGSS contract with PSE&G to meet the needs of PSE&G’s default gas supply service customers. In 2022, the BPU approved an extension of the long-term BGSS contract to March 31, 2027, and thereafter the contract remains in effect unless terminated by either party with a two-year notice. PSEG LI has an OSA with LIPA to operate LIPA’s electric T&D system in Long Island. The OSA continues through 2025, but can be extended by mutual agreement of the parties. Further, PSEG Power provides fuel procurement and power management services to LIPA under separate agreements that expire at the end of 2025. It is uncertain whether any of these contracts and agreements will be extended on terms acceptable to us or at all, which may negatively affect our financial condition and operating results. For additional information, see Item 1. Business—PSEG Power & Other. **Artificial Intelligence is an emerging area of technology that has the potential to impact various aspects of our business operations and customer interactions.** The development, adoption, and use for generative AI technologies are still in their early stages and ineffective or inadequate AI development or deployment practices by PSEG or third-party vendors could result in unintended consequences. We contract third-party vendors that use AI in products and/or services they provide and we may not have full control or visibility over the quality, performance, security or compliance of the products and services that incorporate AI-related technology. AI algorithms that we or our third-party vendors use may be flawed or may be based on datasets that are biased or insufficient. These limitations or failures could result in reputational damage and legal liabilities. Developing, testing, and deploying resource-intensive AI systems may require additional investment and increase our costs. In addition, the evolving nature of AI may cause new laws and regulations to be enacted which may require significant resources to modify and maintain business practices to comply with the new laws and regulations, the nature of which cannot be determined at this time. Further, inaccurate results generated as a result of our employees’, contractors’ or vendors’ use of generative AI technologies could lead to operational interruptions or reputational harm. ### RISKS RELATED TO OUR GENERATION BUSINESS **Fluctuations in the wholesale power and natural gas markets could negatively affect our financial condition, results of operations and cash flows.** In the competitive markets where we operate, 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 below the PTC threshold 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 or PTCs on our nuclear generation units; - changes in the supply of, and demand for, energy commodities; - development of new fuels or new technologies for the production or storage of power; - incurring penalties due to generation performance failure when called on by PJM during emergency situations; - federal and state regulations and actions of PJM and changing PJM market rules; and - federal and state power, market and environmental regulation and legislation, including financial incentives for new renewable energy generation capacity that could lead to oversupply and price suppression. Our generation business currently involves the establishment of forward sale positions in the wholesale energy markets on long-term and short-term bases. 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, 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 nuclear fuel supply in the future. We obtain substantially all of our nuclear fuel supply from third parties pursuant to arrangements that vary in term, pricing structure, firmness and delivery flexibility. Our fuel supply arrangements must be coordinated with storage services and other contracts to ensure that the nuclear fuel is delivered to our power plants at the times, in the quantities and otherwise in a manner that meets the needs of our generation portfolio and our customers. We must also comply with laws and regulations governing the transportation of such fuels. We are exposed to increases in the price of nuclear fuel, and 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. 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. **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 demand side management (DSM) and EE programs can impact demand requirements for some of our markets. The continued development of 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. Federal or state laws mandating higher levels of efficiency 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, coupled with subsidies, may reduce the cost of alternative methods of delivering electricity to customers 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 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 natural gas connections to new buildings 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 natural gas or of customers, and may cause us to fail to fully realize anticipated benefits from significant capital investments and expenditures, which could have a material adverse effect on our financial position, results of operations and cash flows. These factors could also materially affect our results of operations, cash flows or financial positions through, among other things, reduced operating revenues, increased O&M expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives. **We are subject to third-party credit risk relating to our sale of nuclear generation output 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 may not operate and/or may not be able to meet its commitments under forward sale obligations and PJM rules at a reasonable cost or at all.** A 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; - limitations which may be imposed by environmental or other regulatory requirements; and - operator error, acts of war or terrorist attacks (including physical or cybersecurity breaches) or catastrophic events such as fires, earthquakes, explosions, floods, severe weather or other similar occurrences. Identifying and correcting any of these issues may require significant time and expense. Depending on the materiality of the issue, we may choose to close a plant rather than incur the expense of restarting it or returning it to full capacity. Because the obligations under most of these forward sale agreements are not contingent on a unit being available to generate power, PSEG Power’s results of operations and cash flows are at risk even in the event of a plant outage, or a reduction in the available capacity of the unit. To the extent that PSEG Power does not meet its expected nuclear generation output, PSEG Power would be required to pay the difference between the market price and the contract price on its financial contracts without receiving the physical spot energy revenue or be required to purchase energy at higher prices to cover its shortfall. In addition, as capacity performance resources in PJM, PSEG’s nuclear units have been and will in the future be required to pay penalties if a forced outage at a plant occurs during a declared emergency event within PJM and that plant’s expected performance exceeds its actual performance during such event. The amount of such payments could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, changing capacity performance rules and/or failure to follow existing rules – by PJM or market participants – creates regulatory uncertainty and reliability risk. 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. ### REGULATORY, LEGISLATIVE AND LEGAL RISKS **PSE&G’s revenues, earnings and results of operations are dependent upon state laws and regulations that affect distribution and related activities.** PSE&G is subject to regulation by the BPU. Such regulation affects almost every aspect of its businesses, including its retail rates. Failure to comply with these regulations could have a material adverse impact on PSE&G’s ability to operate its business and could result in fines, penalties or sanctions. The retail rates for electric and gas distribution services are established in a distribution base rate proceeding and remain in effect until a new distribution base rate proceeding is filed and concluded. In December 2023, we filed a distribution base rate case, as required by the BPU. 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 in the periods between distribution base rate proceedings. 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 pursuant to the distribution base rate case and/or these clause recovery mechanisms,, including a return of, or on, our investments in rates, could have a material adverse impact on our results of operations and cash flows. In addition, if legislative and regulatory structures were to evolve in such a way that PSE&G’s exclusive rights to serve its regulated customers were eroded, its future earnings could be negatively impacted. 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 13. 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 projects or programs may not be fully approved by regulators and actual capital investment by PSE&G may be lower than planned, which would cause lower than anticipated rate base.** PSE&G is a regulated public utility that operates and invests in an electric T&D system and a gas distribution system as well as certain regulated clean energy investments, including solar and EE within New Jersey. PSE&G invests in capital projects to maintain and improve its existing T&D system and to address various public policy goals and meet customer expectations. Transmission projects are subject to 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. FERC has also proposed elimination of certain transmission rate incentives, including the incentive that PSE&G receives for being a transmission owner member of PJM and accepting the related risk of RTO membership. We cannot be certain that any proposed project or program will be approved as requested or at all. If the projects or programs that PSE&G may file from time to time are only approved in part, or not at all, or if the approval fails to allow for the timely recovery of all of PSE&G’s costs, including a return of, or on, its investment, PSE&G will have a lower than anticipated rate base, thus causing its future earnings to be lower than anticipated. Further, the BPU could take positions to exclude or limit utility participation in certain areas, such as renewable generation, EE, EV infrastructure, or energy storage programs, renewable natural gas or hydrogen projects, which would limit our relationship with customers and narrow our future growth prospects. **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 reduced PSE&G’s base ROE from 11.18% to 9.9% and made changes to recovery of certain costs. The agreement provided that the settling parties will not seek changes to our transmission formula rate for three years. In April 2021, FERC issued a supplemental notice of proposed rulemaking to eliminate the incentive for RTO membership for transmitting utilities that have already received the incentive for three or more years. PSE&G began receiving a 50 basis point adder for RTO membership in 2008. Elimination of the adder for RTO membership would reduce PSE&G’s annual Net Income and annual cash inflows by approximately $40 million. ***Transmission Planning—***FERC Order 1000 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, and projects cost-allocated to a single transmission zone, 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. A significant input into PJM’s transmission planning process is its regional load forecast, which is adjusted on an annual basis. In 2023, PJM adjusted its load forecast in the PSEG zone to reflect New Jersey’s clean energy policies, including electrification requirements and projected EV penetration. Developing an accurate load forecast that reflects the clean energy targets of the state – and other states in PJM – is critical to ensure that transmission is planned and built where it is needed to maintain reliability. ***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 financial support for our New Jersey nuclear plants which could result in the retirement of all of these nuclear plants.** As further described in Item 7. MD&A—Executive Overview of 2023 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 August 2022, the IRA was signed into law expanding incentives promoting carbon-free generation. The enacted legislation established a PTC for electricity generation using nuclear energy which begins January 1, 2024 and continues through 2032. The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts. The PTC rate and the gross receipts threshold are subject to annual inflation adjustments. The U.S. Treasury is expected to clarify the definition of gross receipts. The ZEC payment may be adjusted by the BPU to offset environmental or fuel diversity payments that a selected nuclear plant may receive from another source. Until additional guidance is issued by the U.S. Treasury, we are unable to fully determine the impacts of the PTC. If the markets, PTC and/or the ZEC program do not provide sufficient financial support, or, in the case of the Salem nuclear plants, decisions by the EPA and state environmental regulators regarding the implementation of Section 316(b) of the CWA and related state regulations, or other factors, PSEG Power may take all necessary steps to cease to operate all of these plants and will incur associated costs and accounting charges in the event that the financial condition of the plants is materially adversely impacted in the future. Ceasing operations of these plants would result in a material adverse impact on PSEG’s results of operations. **We may be adversely affected by changes in energy regulatory policies, including energy and capacity market design rules and developments affecting transmission.** The energy industry continues to be regulated and the rules to which our businesses are subject are always at risk of being changed. 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, and recent extreme weather events in PJM. 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 the BPU 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. The BPU is currently examining whether and how to implement a forward clean energy attributes market that could involve several states in PJM and work in tandem with PJM’s capacity and energy markets. 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.** 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. ***Third-Party Operation of Peach Bottom Plants—***While we have a 50% ownership interest in the Peach Bottom nuclear generation plants, these plants are operated by a third party and, therefore, we have limited control over the operational and other risks associated with these plants. **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 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. At this stage of the remediation process, the full remediation costs are not estimable, but given the number and operating history of the facilities in the portfolio, the full remediation costs will likely be material in the aggregate. The costs could potentially include costs for, among other things, excavating soil, implementation of institutional controls, and the construction, operation and maintenance of engineering controls. Environmental laws and regulations have generally become more stringent over time, and this trend is likely to continue. For further discussion of environmental laws and regulations impacting our business, results of operations and financial condition, including the impact of federal and state laws and regulations relating to remediation of environmental contamination, see Item 8. Note 13. Commitments and Contingent Liabilities. **We may not receive necessary licenses, permits and siting approvals in a timely manner or at all, which could adversely impact our business and results of operations.** We must periodically apply for licenses and permits from various regulatory authorities, including environmental regulatory authorities, and siting/permitting approvals for our transmission investments, and abide by their respective orders. Delay in obtaining, or failure to obtain and maintain, any permits or approvals, including environmental permits or approvals, or delay in or failure to satisfy any applicable regulatory requirements, could: - prevent construction of new facilities, - limit or prevent continued operation of existing facilities, - limit or prevent the sale of energy from these facilities, or - result in significant additional costs, each of which could materially affect our business, financial condition, results of operations and cash flows. In addition, the process of obtaining licenses and permits from regulatory authorities may be delayed or defeated by concerted community opposition and such delay or defeat could have a material effect on our business. **Changes in tax laws and regulations may adversely affect our financial condition, results of operations and cash flows.** The enactment of additional federal or state tax legislation and clarification of previously enacted tax laws, including anticipated U.S. Treasury guidance relating to the 15% corporate alternative minimum tax and energy tax credit provisions, could have a material impact on our effective tax rate and cash tax position. ## Cybersecurity As filed, 14,839 characters. 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 and our business operations more broadly. For a discussion of the risks associated with cybersecurity threats, see Item 1A. Risk Factors. ### Risk Management and Strategy Our processes for assessing, identifying, and managing material risks from cybersecurity threats include the following: - ***Ongoing Assessment—***The Cybersecurity Risk and Compliance department, led by the Managing Director, Chief Information Security Officer (CISO), and reporting to the SVP, Chief Information and Digital Officer (CIDO) is staffed with cyber professionals tasked with the day-to-day responsibility of assessing material risks from cybersecurity threats. In addition, the Cyber Security Council, comprised of senior management, is kept apprised of the state of PSEG’s cybersecurity program, including any emerging risks, and provides guidance on the strategic directions of the program. - ***Engagement of Third Parties—***We engage third parties, such as security service providers, risk management firms and external legal counsels to assess material risks from cybersecurity threats and report on our internal incident response preparedness and cyber posture, support incident response, conduct tabletop exercises, and comply with applicable laws and regulations. We also carry cybersecurity insurance that provides certain protection against losses from a cybersecurity incident. Regulatory agencies, including but not limited to the NRC and Transportation Security Administration, as well as NERC, inspect applicable components of our cybersecurity program. - ***Third-Party Service Provider Management—***We maintain processes to oversee and identify risks from cybersecurity threats associated with our use of third-party service providers. This includes a risk-based vendor management program, which incorporates robust security contractual provisions, vendor security assessments and, if appropriate, periodic audits. - ***Technical Safeguards—***We manage controls to protect our network perimeter, internal IT and Operational Technology (OT) environments, such as internal and external firewalls, network intrusion detection and prevention, penetration testing, vulnerability assessments, threat intelligence, anti-malware and access controls. - ***Training and Awareness—***We provide mandatory 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 conduct phishing exercises with progressive consequences for failures. Employees also receive periodic cybersecurity awareness messages and each October, in recognition of Cybersecurity Awareness Month, are invited to presentations throughout the month from internal and external cyber experts covering diverse cyber topics. These efforts better enable all employees to identify potential cybersecurity risks and escalate them appropriately. - ***Incident Response Plans—***We maintain and periodically update 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 a data breach response plan (with a focus on external communication/disclosure and legal compliance); and conduct regular tabletop exercises to test plan effectiveness (both internally and through external exercises). - ***Mobile Security—***We maintain controls to prevent loss of data through mobile device channels. - ***Physical Security—***We also maintain physical security measures to protect our 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 Item 1. Business. 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. These processes are integral to our overall risk management system or processes and inform the identification and assessment of risks and mitigations through our Enterprise Risk Management (ERM) program. The ERM team, led by the SVP – Audit, Enterprise, Risk and Compliance (AERC) considers cybersecurity risks alongside other PSEG risks, and facilitates discussion with PSEG subject matter experts to identify cybersecurity risks, evaluate their potential severity and likelihood, identify mitigations, including those identified above, and assess the impact of those mitigations on residual risk. In addition, PSEG maintains a Risk Management Committee (RMC), responsible for assessing exposure to and determining PSEG's overall risk management strategy, including with respect to cybersecurity. The RMC, supported by the ERM function, is chaired by the SVP – AERC and consists of members of senior management including the CIDO and six other of the CEO’s direct reports. In discharging its responsibilities related to cybersecurity threats, the RMC has received presentations from the CISO. To date, there has been no material impact or reasonably likely material impact on our business strategy, results of operations or financial condition from these attacks or other cybersecurity incidents, including as a result of prior cybersecurity incidents. ### Governance - PSEG Board of Directors (Board) Oversight of Risks from Cybersecurity Threats: - ***PSEG Board —***The PSEG Board has ultimate responsibility for the oversight of risk management at PSEG, overseeing PSEG’s risk management program and reviewing the most significant risks facing PSEG, including cybersecurity risks. The Governance, Nominating and Sustainability Committee of the PSEG Board reviews key enterprise risks, including cybersecurity risks, and recommends to the Board the mapping of each risk to an appropriate committee or the full Board, in accordance with the allocation of risk categories reflected in the charter of each committee. Through this process, cybersecurity risk is mapped primarily to the Board’s Industrial Operations Committee (IOC), and also the Audit Committee. In providing oversight of risks from cybersecurity threats, the Board is informed of cybersecurity incidents as appropriate, by way of updates from Senior Management, pursuant to PSEG’s Cybersecurity Event Escalation and Incident Response Practice, as administered by the CISO. - ***IOC—***At the PSEG Board level, the IOC holds the primary responsibility, as enumerated in its charter, of overseeing PSEG’s cybersecurity program and assessing overall compliance through active, independent and critical oversight. The IOC is informed about cybersecurity risks by the CIDO and/or the CISO, during the IOC’s four regularly scheduled meetings a year, which each include cybersecurity as a standing agenda item. Cybersecurity updates to the IOC include discussions on OT and IT cyber risk, a cybersecurity update from the CISO and/or CIDO, and review of a corporate cybersecurity scorecard and other performance indicators. The CIDO and CISO are regular attendees at IOC meetings. In addition, the IOC meets with the CISO in executive session at each meeting with no other members of management present, and has also met with the CIDO, to whom the CISO directly reports, in executive session with no other members of management present. To ensure the full Board is kept informed about the cybersecurity risks discussed at the IOC meetings, the cybersecurity materials provided to the IOC are available for full viewing by all members of the Board, members of the Board who are not IOC members have a courtesy invitation to each IOC meeting, and the Chair of the IOC provides a summary of IOC meetings to the full Board, typically the day after the meeting takes place. - ***Audit Committee—***The Audit Committee has the charter responsibility of overseeing cybersecurity risks related to financial reporting and internal controls. The Audit Committee receives a cybersecurity update twice a year from the CIDO, either with the full Board or the IOC in attendance. Audit Committee members have a courtesy invitation to all IOC meetings, have full access to IOC meeting materials, and receive the summary of IOC meetings from the IOC Chair noted above. - ***Governance, Nominating and Sustainability Committee and Audit Committee—***These committees are briefed at least annually on enterprise-level risks and emerging risks, including those related to cybersecurity, and receive regular updates on PSEG RMC activities, including those related to cybersecurity. - ***Board of Directors, IOC, and Audit Committee—***In providing oversight of risks from cybersecurity threats, the Board, IOC and Audit Committee are informed of cybersecurity risks by way of frequent reports on such topics as personnel and resources to monitor and address cybersecurity threats, technological advances in cybersecurity protection, rapidly evolving cybersecurity threats that may affect us and our industry, cybersecurity incident response and applicable cybersecurity laws, regulations and standards, as well as collaboration mechanisms with intelligence and enforcement agencies and industry groups to assure timely threat awareness and response coordination. In addition, risks associated with cybersecurity incidents, or potential incidents, are escalated by senior management promptly to the Board outside of regularly scheduled meetings, if appropriate. - Management’s Role in Assessing and Managing Material Cybersecurity Risks: The assessment and management of material risks from cyber threats is managed by the CIDO, CISO and Cybersecurity Council, as further described below. - ***CIDO—***The CIDO has had the overall responsibility for PSEG’s cybersecurity since September 2022, including the assessment and management of materials risks to PSEG from cybersecurity threats. The CIDO has served in that position since August 2020 and is a direct report of the CEO. The CIDO has over 25 years of energy experience inclusive of leading technology compliance with cybersecurity regulations for nuclear, transmission, gas and corporate assets. Our CIDO’s experience includes leading the secure technology design, development, and deployment strategy for grid modernization efforts, including digital customer engagement platforms, advanced metering, enterprise asset management and distribution automation functionality. As noted above, the CIDO provides cybersecurity updates to the Board or its Committees twice per year, regularly attends and provides updates with the CISO to the IOC, and has met with the IOC, without other members of management present, during the IOC executive sessions. The CIDO remains informed about the monitoring, prevention, detection, mitigation, and remediation of cybersecurity incidents through the CISO and other members of the cybersecurity, risk and compliance team, as appropriate, who are tasked with these responsibilities on a day-to-day basis. - ***CISO—***The CISO has day-to-day responsibility for PSEG’s cybersecurity, including the assessment and management of material risks to PSEG from cybersecurity threats, and leads the cybersecurity, risk and compliance team. The CISO has served in this role since September 2018. Our CISO has over 20 years of experience in IT security management and served as the director of information security and chief security architect in the insurance sector prior to joining PSEG. Our CISO has a bachelor’s degree in electrical engineering and holds multiple security certifications, including Certificate of Cloud Security Knowledge, Certified Information Systems Security Professional, Certified Information Systems Auditor, Information Systems Security Architecture Professional, and National Institute of Standards and Technology Cyber Security Professional Practitioner. As noted above, the CISO provides cybersecurity updates during the four regularly scheduled IOC meetings and meets with the IOC, without other members of management present, during each meeting’s executive session. The CISO remains informed about the monitoring, prevention, detection, mitigation, and remediation of cybersecurity incidents through the members of the CISO’s cybersecurity, risk and compliance team, who are tasked with these responsibilities on a day-to-day basis. - ***Cybersecurity Council—***The Cybersecurity Council, chaired by the CISO, ensures that senior management, and ultimately, the Board, are given the information required to exercise proper oversight over cybersecurity risks and that escalation procedures are followed. The Cybersecurity Council meets at least six times annually to receive reports on the state of PSEG’s cybersecurity program, provide guidance on the strategic direction of the program, discuss emerging cybersecurity issues, and review the cybersecurity scorecard to measure performance of key risk indicators. The Cybersecurity Council receives presentations from the CISO, members of the Cybersecurity Risk and Compliance Team cybersecurity managing counsel, and external cybersecurity experts, and participates in tabletop exercises led by external consultants. In addition to the CISO, the Cybersecurity Council members include the: (i) CIDO; (ii) EVP and General Counsel; (iii) EVP and CFO; (iv) President and COO of PSE&G; (v) President of PSEG Nuclear and Chief Nuclear Officer; (vi) SVP – Corporate Citizenship; (vii) SVP – Chief Human Resources and Diversity Officer; (viii) VP of Corporate Security and Properties; (ix) SVP – AERC; (x) Project Executive Advisor; and (xi) Vice President and Controller. PSEG’s Managing Counsel – Cybersecurity serves as counsel to the Cybersecurity Council. In providing oversight of risks from cybersecurity threats, Senior Management is informed of cybersecurity risks by way of updates shared during Cybersecurity Council meetings, as well as through notifications or updates by the CISO, pursuant to PSEG’s Cybersecurity Event Escalation and Incident Response Practice. For a discussion of regulatory requirements relating to cybersecurity matters, see Item 1. Business—Regulatory Issues. ## Properties As filed, 3,094 characters. All of our owned physical property is held by our subsidiaries. We believe that we and our subsidiaries maintain adequate insurance coverage against loss or damage to plants and properties, subject to certain exceptions and deductibles, to the extent such property is usually insured and insurance is available at a reasonable cost. For a discussion of nuclear insurance, see Item 8. Note 13. 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, 2023, PSE&G’s electric T&D system included approximately 25,000 circuit miles, and 866,000 poles, of which 64% are jointly-owned. In addition, PSE&G owns and operates 56 switching stations with an aggregate installed capacity of 39,953 megavolt-amperes (MVA) and 235 substations with an aggregate installed capacity of 10,382 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, 2023, 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 2.9 million therms in the aggregate. ### Solar As of December 31, 2023, PSE&G owned 158 MW dc of installed PV solar capacity throughout New Jersey. ### PSEG Power ### Generation Facilities As of December 31, 2023, PSEG Power’s share of installed nuclear generating capacity is shown in the following table: | Name Nuclear: | Location | Total Capacity (MW) | % Owned | Owned Capacity (MW) | | --- | --- | ---: | ---: | ---: | | Hope Creek | NJ | 1,174 | 100% | 1,174 | | Salem 1 & 2 | NJ | 2,287 | 57% | 1,312 | | Peach Bottom 2 & 3 (A) | PA | 2,549 | 50% | 1,275 | | **Total Nuclear** | | **6,010** | | **3,761** | (A) Operated by Constellation Energy Generation, LLC. ## Legal proceedings As filed, 300 characters. We are party to various lawsuits and environmental and regulatory matters, including in the ordinary course of business. For information regarding material legal proceedings, see Item 1. Business—Regulatory Issues and Environmental Matters and Item 8. Note 13. Commitments and Contingent Liabilities. ## Management's discussion and analysis As filed, 82,754 characters. This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG) and Public Service Electric and Gas Company (PSE&G). Information contained herein relating to any individual company is filed by such company on its own behalf. PSEG’s business consists of two reportable segments, PSE&G and PSEG Power LLC (PSEG Power) & Other, primarily comprised of our principal direct wholly owned subsidiaries, which are: - **PSE&G—**which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU), the Federal Energy Regulatory Commission (FERC), and other federal and New Jersey state regulators. PSE&G also invests in regulated solar generation projects and 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) and other federal regulators and state regulators in the states in which they operate. The PSEG Power & Other reportable segment also includes amounts related to the parent company as well as PSEG’s other direct wholly owned subsidiaries, which are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) transmission and distribution (T&D) system under an Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily holds legacy lease investments and competitively bid, FERC regulated transmission; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost. Our business discussion in Item 1. Business provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Item 1A. Risk Factors provides information about factors that could have a material adverse impact on our businesses. The following discussion provides an overview of the significant events and business developments that have occurred during 2023 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 2023 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, our investments in PSE&G have adjusted our business mix to reflect a higher percentage of earnings contribution by PSE&G. In addition, the passage of the Inflation Reduction Act of 2022 (IRA) established a production tax credit (PTC) for existing nuclear facilities from 2024 through 2032. The PTC is expected to provide downside price protection for our nuclear generation fleet as the tax credit value is directly linked to a nuclear facility’s gross receipts. For the years 2024-2028, our regulated capital investment program is estimated to be in a range of $18 billion to $21 billion. We expect these capital investments to result in a compound annual growth rate in our regulated rate base in a range of 6% to 7.5% from year-end 2023 to year-end 2028. The regulated capital investments represent the majority of PSEG’s total capital investment program of $19 billion to $22.5 billion. The low end of the range includes an extension of our Gas System Modernization Program (GSMP) and Clean Energy Future (CEF)-EE program at their current average annual investment levels plus inflation, as these programs are expected to continue beyond their currently approved timeframes. The upper end of our capital investment range includes incremental investments, particularly for an expansion of our current EE programs as well as other clean energy and infrastructure investments. ### 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. During 2023, the BPU approved a $280 million nine-month extension of our CEF-EE program through June 2024 and a two-year extension of our current GSMP program to replace at least 400 miles of cast iron and unprotected steel mains and services in our gas system. The GSMP program extension provides for main replacement through December 2025 plus trailing services replacement and paving costs into 2026 and totals approximately $900 million of investment. Of the $900 million, $750 million is recovered through three periodic rate updates with the balance recovered through a future distribution base rate case. Our broader GSMP III, which also included projects to introduce renewable natural gas and hydrogen blending into our existing distribution system is being held in abeyance, with negotiations reinitiated by January 2025 with the intent of beginning the work in January 2026. A remaining component of our CEF-Electric Vehicle (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 2024. In September 2022, the BPU released a draft Storage Incentive Program proposal and is currently undertaking a stakeholder process to determine the details of the program. In the meantime, our CEF-Energy Storage (ES) program is being held in abeyance. In November 2023, we filed for a second extension of our CEF-EE program, which would cover a commitment period of six months from July 2024 through December 2024 for approximately $300 million. In December 2023, we filed for our CEF-EE II program, which proposed a $3.1 billion investment for a second program cycle covering commitments from January 2025 through June 2027, with investments being made over a six-year period. This EE filing is a significant increase from our prior filings, driven by an increase in the savings targets required under the BPU Energy Efficiency Framework and higher costs to achieve those targeted savings. The filing also includes demand response programs and building decarbonization programs. The CEF-EE extension filing is expected to be resolved in the first half of 2024 and the EE II filing is expected to be resolved in the second half of 2024. Pursuant to our GSMP II and Energy Strong II programs, we filed a distribution base rate case as required by the BPU in December 2023. Among other things, the distribution base rate case will seek to recover capital expenditures associated with our infrastructure investment programs that are not already in rates, as well as the Advanced Metering Infrastructure (AMI) and EV programs, other investments that are not recovered through periodic rate roll-ins, and several other cost and return factors. The filing proposes an overall revenue increase of 9% with a 12% increase for the combined typical residential electric and gas customer. We expect to conclude the distribution base rate case later in 2024. ### PSEG Power At PSEG Power, we seek to produce low-cost, reliable and resilient electricity by efficiently operating our nuclear generation assets, mitigate earnings volatility through the PTC mechanism and hedging, and support public policies that preserve these existing carbon-free base load nuclear generating plants. During 2023, our nuclear units generated approximately 32 terawatt hours and operated at a capacity factor of approximately 93%. As of the end of 2023, PSEG Power has hedged approximately 90% to 95% of its expected generation output for 2024. Beginning in 2024, our hedging strategy will incorporate an estimated range of risk reduction impacts from the PTCs on our nuclear generation portfolio. This is expected to result in changes to our current approach given PTC guidance uncertainty, and potential incremental changes upon final U.S. Treasury guidance. ### 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 business operations, assuming advances in technology, public policy and customer behavior. Scope 1 emissions include power generation, fuel combustion at PSEG facilities, methane leaks, vehicle fleet emissions, sulfur hexafluoride emissions, and refrigerant leaks. Scope 2 emissions include purchased electric and steam energy for our PSEG facilities and emissions associated with line losses. Consistent with our commitment to the United Nations-backed Race to Zero campaign, we had submitted proposed targets encompassing Scopes 1, 2 and 3 emissions to the Science-Based Targets initiative (SBTi). SBTi recently informed us that they have rejected our submittal because, while our Scope 1 and 2 and Scope 3 electric targets meet requirements to proceed to the validation process, our Scope 3 natural gas target aligns with a Well Below 2C temperature scenario, rather than a more ambitious 1.5C scenario. 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 and CEF-EE II programs are intended to support New Jersey’s Energy Master Plan and recent Gubernatorial Executive Orders through programs designed to help customers use energy more efficiently, reduce GHG emissions, support the expansion of the EV infrastructure in New Jersey, install energy storage capacity to supplement solar generation and enhance grid resiliency, install smart meters and supporting infrastructure to allow for the integration of other clean energy technologies and to more efficiently respond to weather and other outage events. 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 replaced an additional 1,090 miles of gas pipes and was completed in the first quarter of 2023. As mentioned above, the BPU approved a two-year extension of GSMP in October 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 reduced methane leaks by approximately 22% system wide and assuming continuation of GSMP, we expect to achieve an overall reduction in methane emissions of at least 60% over the 2011 baseline 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 and our investments in transmission infrastructure upgrades. These investments have shown benefits in recent severe weather events, including Tropical Storm Ida in 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 by working to preserve the economic viability of our nuclear units, which provide over 85% of the carbon-free energy in New Jersey. These efforts include reducing market risk by advocating for state and federal policies, such as the PTC established by the IRA, and capacity market reform at PJM that recognize the value of our nuclear fleet’s carbon-free generation and its contribution to grid reliability. ### Offshore Wind In May 2023, PSEG sold to Ørsted North America Inc. (Ørsted) its 25% equity interest in Ocean Wind JV HoldCo, LLC. The sale proceeds approximated PSEG’s carrying value of the investment; therefore, no material gain or loss was recognized upon disposition. 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 is evaluating its options for the potential sale of its interest in GSOE. ### Competitively Bid, FERC Regulated Transmission Projects PSEG continues to evaluate investment opportunities in regulated transmission beyond PSE&G. In December 2023, PJM awarded a subsidiary of Energy Holdings an approximately $424 million project to address increasing load and reliability issues in Maryland as part of its 2022 Window 3 competitive solicitation. The project has an expected in-service date of 2027. We also continue to evaluate regulated transmission opportunities to support offshore wind development in the New Jersey area. In April 2023,the BPU issued an order requesting that PJM conduct a second public policy transmission solicitation process utilizing the State Agreement Approach for transmission projects to support New Jersey’s expanded offshore wind goal. The solicitation will seek to procure both onshore and offshore transmission solutions. PJM stated that the solicitation process is tentatively expected to commence in 2024. In November 2023, the BPU issued an order directing its staff to conduct a solicitation for “pre-build infrastructure” to support landing and routing of underground transmission cables of future offshore wind projects. PSEG is evaluating this opportunity and may submit a bid or bids into the solicitation. ### Financial Results The financial results for PSEG, PSE&G and PSEG Power & Other for the years ended December 31, 2023 and 2022 are presented as follows: *Millions, except per share data* | | Years Ended December 31, 2023 | 2022 | | --- | ---: | ---: | | PSE&G | $1,515 | $1,565 | | PSEG Power & Other | 1,048 | (534) | | **PSEG Net Income** | **$2,563** | **$1,031** | | **PSEG Net Income Per Share (Diluted)** | **$5.13** | **$2.06** | For a detailed discussion of our financial results, see Results of Operations. ### Regulatory, Legislative and Other Developments We closely monitor and engage with stakeholders on significant regulatory and legislative developments. ### Transmission Rate Proceedings and Return on Equity (ROE) Under current FERC rules, PSE&G continues to earn a 50 basis point adder to its base ROE for its membership in PJM as a transmission owner. In April 2021, FERC proposed eliminating this ROE adder for Regional Transmission Owner participation. FERC has not acted on the proposal. If the adder was eliminated, it would reduce PSE&G’s annual Net Income and annual cash inflows by approximately $40 million. ### New Jersey Stakeholder Proceedings In February 2023, the governor of New Jersey issued executive orders (EOs) that establish or accelerate previously established 2050 targets for clean-sourced energy, building decarbonization, and EV adoption goals, with new target dates of 2030 or 2035, as applicable. The EOs direct the BPU and other state agencies to collaborate with stakeholders to develop plans to reach the targets and the BPU has convened a stakeholder proceeding to develop a plan for gas distribution utilities to reach the target of 50% natural gas emissions reductions over 2006 levels by 2030. We are unable to predict the outcomes of this proceeding, but it could have a material impact on our business, results of operations and cash flows. ### 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 13. Commitments and Contingent Liabilities. ### Nuclear In April 2021, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded zero emission certificates (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 existing nuclear energy set to begin January 1, 2024 and continue through 2032. The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts. The PTC rate and the gross receipts threshold are subject to annual inflation adjustments. The establishment of the PTC impacted PSEG Power’s decision not to apply for the next ZEC three-year eligibility period starting June 2025. We continue to analyze the impact of the IRA on our nuclear units, and will analyze any future guidance from the U.S. Treasury to assess any impact of PTCs on expected ZEC payments and/or any future ZEC application periods. ### Pension and Interest Rate Matters 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 mitigates some of the volatility in earnings and customer rates related to our pension trust performance and became effective for calendar year 2023 and forward. In July 2023, PSEG and Fiduciary Counselors Inc., as independent fiduciary of the Pension Plan I and Pension Plan II (Plans), entered into a commitment agreement ( for a “lift-out”) with The Prudential Insurance Company of America (the Insurer) under which the Plans agreed to purchase a group annuity contract that would transfer to the Insurer approximately $1 billion of the Plans’ defined benefit pension obligations and associated Plan assets related to certain pension benefits covering approximately 2,000 retirees from PSEG Power & Other. In August 2023, assets were transferred to the Insurer and the transaction was closed, which reduces future volatility due to lowering our pension assets and liabilities. See Item 8. Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans for additional information. Federal Reserve policy to reduce inflation has resulted in a higher interest rate environment which may persist as the Federal Reserve continues to assess the economic outlook. If it persists, higher interest rates on borrowings will contribute to higher interest expense on variable-rate debt and long-term rates on future financing plans. As of December 31, 2023, PSEG had entered into floating-to-fixed interest rate swaps totaling $1.4 billion in order to reduce the volatility in interest expense related to $900 million of a $1.25 billion variable rate term loan at PSEG Power due March 2025 and PSEG’s $500 million variable rate term loan due April 2024. PSE&G’s interest rate risk is moderated due to annual transmission rate filings and distribution recoveries through base rate filings and clause-based investment programs. ### Tax Legislation Future federal and state tax legislation and clarification of enacted legislation could have a material impact on our effective tax rate and cash tax position. In April 2023, the U.S. Treasury issued Revenue Procedure 2023-15 that provides a safe harbor method of accounting to determine the annual repair tax deduction for gas T&D property. The impact, if any, this may have on PSEG and PSE&G’s financial statements has not yet been determined. The IRA enacted a new 15% corporate alternative minimum tax (CAMT), effective in 2023, a PTC for existing nuclear generation facilities and allows energy tax credits to be transferable. The U.S. Treasury has issued proposed regulations and several Notices pertaining to the CAMT and the prevailing wage and transferability rules of energy tax credits. Many aspects of the IRA remain unclear and in need of further guidance; therefore, we continue to analyze the impact the IRA will have on PSEG’s and PSE&G’s results of operations, financial condition and cash flows, which could be material. ### Future Outlook Our future success will depend on our ability to continue to maintain strong operational and financial performance, address regulatory and legislative developments that impact our business and respond to the issues and challenges described below. In order to do this, we will continue to: - seek 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, - 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 2023 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, tax regulations, design of energy and capacity markets, and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceedings, - performance of the financial markets, including the impact on our pension and interest rates on our future financing plans, - continuing to manage costs and maintain affordable customer rates in an inflationary environment, which could impact 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 expected to be supported through the PTC through 2032 and can enable certain investments to increase the capacity of the units as well as potential license extensions, - investments in competitive, regulated transmission investments through PJM processes and BPU solicitations that provide revenue predictability and reasonable risk-adjusted returns, and - acquisitions, dispositions, development and other transactions involving our common stock, assets or businesses that could provide value to customers and shareholders. There can be no assurance, however, that we will successfully develop and execute any of the strategic options noted above, or any additional options we may consider in the future. The execution of any such strategic plan may not have the expected benefits or may have unexpected adverse consequences. ### RESULTS OF OPERATIONS *Millions, except per share data* | Earnings (Losses) | Years Ended December 31, 2023 | 2022 | 2021 | | --- | ---: | ---: | ---: | | PSE&G | $1,515 | $1,565 | $1,446 | | PSEG Power & Other (A)(B) | 1,048 | (534) | (2,094) | | **PSEG Net Income (Loss)** | **$2,563** | **$1,031** | **$(648)** | | **PSEG Net Income (Loss) Per Share (Diluted)** | **$5.13** | **$2.06** | **$(1.29)** | (A) PSEG Power & Other results in 2023 include a $239 million after-tax pension charge due to the settlement of a portion of the qualified pension plans. 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. See Item 8. Note 3. 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 (Loss) attributable to changes related to the NDT Fund and MTM are shown in the following table: | | Years Ended December 31, 2023 Millions, after tax | 2022 | 2021 | | --- | ---: | ---: | ---: | | NDT Fund and Related Activity (A) (B) | $109 | $(174) | $108 | | Non-Trading MTM Gains (Losses) (C) | $959 | $(457) | $(446) | (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 10. 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 Net Other Income (Deductions), interest accretion expense on PSEG Power’s nuclear Asset Retirement Obligation (ARO) recorded in Operation & Maintenance (O&M) Expense and the depreciation related to the ARO asset recorded in Depreciation and Amortization (D&A) Expense. (B) Net of tax (expense) benefit of $(74) million, $97 million and $(70) million for the years ended December 31, 2023, 2022 and 2021, respectively. (C) Net of tax (expense)benefit of $(376) million, $178 million and $174 million for the years ended December 31, 2023, 2022 and 2021, respectively. Our increase in Net Income for 2023 as compared to 2022 was driven primarily by - changes in the MTM and NDT Fund as shown in the table above, and - higher earnings due to continued investments in T&D clause programs at PSE&G, - partially offset by a pension settlement charge in 2023 See Item 8. Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans, and - lower pension and other postretirement benefit (OPEB) credits in 2023. 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 24. Related-Party Transactions. ### PSEG | | Years Ended December 31, 2023 Millions | 2022 | 2021 | Increase / (Decrease) 2023 vs. 2022 Millions% | | Increase / (Decrease) 2022 vs. 2021 Millions% | | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Operating Revenues | $11,237 | $9,800 | $9,722 | $1,437 | 15 | $78 | 1 | | Energy Costs | 3,260 | 4,018 | 3,499 | (758) | (19) | 519 | 15 | | Operation and Maintenance | 3,150 | 3,178 | 3,226 | (28) | (1) | (48) | (1) | | Depreciation and Amortization | 1,135 | 1,100 | 1,216 | 35 | 3 | (116) | (10) | | Losses on Asset Dispositions and Impairments | 7 | 123 | 2,637 | (116) | (94) | (2,514) | (95) | | Income from Equity Method Investments | 1 | 14 | 16 | (13) | (93) | (2) | (13) | | Net Gains (Losses) on Trust Investments | 189 | (265) | 194 | 454 | N/A | (459) | N/A | | Net Other Income (Deductions) | 172 | 124 | 98 | 48 | 39 | 26 | 27 | | Net Non-Operating Pension and OPEB (Costs) Credits | (218) | 376 | 328 | (594) | N/A | 48 | 15 | | Loss on Extinguishment of Debt | — | — | (298) | — | N/A | 298 | N/A | | Interest Expense | 748 | 628 | 571 | 120 | 19 | 57 | 10 | | Income Tax Expense (Benefit) | 518 | (29) | (441) | 547 | N/A | 412 | (93) | The 2023, 2022 and 2021 amounts in the preceding table for Operating Revenues and O&M costs each include $533 million, $516 million and $511 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 4. Variable Interest Entity for additional information. The following discussions for PSE&G and PSEG Power provide a detailed explanation of their respective variances. ### PSE&G | | Years Ended December 31, 2023 Millions | 2022 | 2021 | Increase / (Decrease) 2023 vs. 2022 Millions% | | Increase / (Decrease) 2022 vs. 2021 Millions% | | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Operating Revenues | $7,807 | $7,935 | $7,122 | $(128) | (2) | $813 | 11 | | Energy Costs | 3,010 | 3,270 | 2,688 | (260) | (8) | 582 | 22 | | Operation and Maintenance (A) | 1,843 | 1,838 | 1,692 | 5 | — | 146 | 9 | | Depreciation and Amortization | 980 | 935 | 928 | 45 | 5 | 7 | 1 | | Gain on Asset Dispositions | — | — | (4) | — | — | 4 | N/A | | Net Gains (Losses) on Trust Investments | — | (2) | 2 | 2 | N/A | (4) | N/A | | Net Other Income (Deductions) | 80 | 88 | 88 | (8) | (9) | — | — | | Net Non-Operating Pension and OPEB Credits | 114 | 281 | 264 | (167) | (59) | 17 | 6 | | Interest Expense | 493 | 427 | 402 | 66 | 15 | 25 | 6 | | Income Tax Expense | 160 | 267 | 324 | (107) | (40) | (57) | (18) | (A) Includes amortization of EE programs regulatory investment expenditures of $82 million, $48 million and $31 million for the years ended December 31, 2023, 2022 and 2021, respectively. ### Year Ended December 31, 2023 as compared to 2022 **Operating Revenues** decreased $128 million due to changes in delivery, clause, commodity and other operating revenues. ***Delivery Revenues*** increased $184 million. - Transmission revenues increased $112 million in revenue requirements attributable to higher rate base investment. - Electric distribution and gas distribution revenues were $36 million higher due primarily to a 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. - Electric distribution revenues increased $22 million due primarily to $38 million from Conservation Incentive Program (CIP) decoupling revenues and $16 million from an Energy Strong II rate roll-in, partially offset by a $34 million decrease in sales volumes. - Gas distribution revenues increased $14 million due primarily to increases of $39 million from additional GSMP revenues in base rates and $24 million in CIP decoupling revenues, partially offset by $50 million from lower sales volumes. ***Clause Revenues*** decreased $80 million due primarily to a $48 million net decrease in Tax Adjustment Credits (TAC) and Green Program Recovery Charge (GPRC) deferrals and $33 million in lower Societal Benefits Clause (SBC) collections. The changes in TAC and GPRC deferrals and SBC collections were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, D&A and Interest and Income Tax Expenses. PSE&G does not earn margin on TAC and GPRC deferrals or on SBC collections. ***Commodity Revenues*** decreased $289 million due to lower 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 decreased $254 million due to $133 million from lower BGSS sales volumes and $121 million from lower BGSS prices. - Electric revenues decreased $35 million due primarily to $64 million from lower BGS sales volumes, partially offset by $29 million from higher prices. ***Other Operating Revenues*** increased $57 million due primarily to a $45 million increase in Transition Renewable Energy Certificates (TREC) revenues, a $13 million increase in appliance service revenues, and a $9 million increase from the Successor Solar Incentive Program (SuSI), partially offset by an $18 million reduction in Solar Renewable Energy Credits (SREC) and ZEC revenues. The changes in TREC, SuSI, SREC and ZEC revenues are entirely offset by changes to Energy Costs. ### Operating Expenses **Energy Costs** decreased $260 million. This is offset by changes in Commodity Revenues and Other Operating Revenues. **Operation and Maintenance** increased $5 million due primarily to increased amortization of EE programs regulatory investment expenditures and higher T&D expenditures, partially offset by decreases in other clause related and various other operational expenses. **Depreciation and Amortization** increased $45 million due primarily to an increase in depreciation due to higher plant placed in service, partially offset by a net decrease in the amortization of Regulatory Assets and Liabilities. **Net Other Income (Deductions)** decreased $8 million due primarily to lower Allowance for Funds Used During Construction and a reduction in solar loan interest income. **Net Non-Operating Pension and OPEB Credits** decreased $167 million due primarily to an $86 million increase in interest cost, a $63 million decrease in the expected return on plan assets and a $62 million decrease in the amortization of service credits, partially offset by a $47 million decrease in amortization of the net actuarial loss. **Interest Expense** increased $66 million due primarily to long-term debt net issuances at higher rates in 2023 and incremental issuances in 2022. **Income Tax Expense** decreased $107 million due primarily to lower pre-tax income, an increase in the flowback of excess deferred income tax benefits, an increase in tax benefits from the CEF program investments, and an increase in bad debt write-offs. ### Year Ended December 31, 2022 as compared to 2021 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, 2022 as filed with the SEC on February 22, 2023 for information related to the year ended December 31, 2022 as compared to 2021, which information is incorporated herein by reference. ### PSEG Power & Other | | Years Ended December 31, 2023 Millions | 2022 | 2021 | Increase / (Decrease) 2023 vs. 2022 Millions% | | Increase / (Decrease) 2022 vs. 2021 Millions% | | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Operating Revenues | $4,533 | $3,266 | $3,767 | $1,267 | 39 | $(501) | (13) | | Energy Costs | 1,353 | 2,149 | 1,978 | (796) | (37) | 171 | 9 | | Operation and Maintenance | 1,307 | 1,340 | 1,534 | (33) | (2) | (194) | (13) | | Depreciation and Amortization | 155 | 165 | 288 | (10) | (6) | (123) | (43) | | Losses on Asset Dispositions and Impairments | 7 | 123 | 2,641 | (116) | (94) | (2,518) | (95) | | Income from Equity Method Investments | 1 | 14 | 16 | (13) | (93) | (2) | (13) | | Net Gains (Losses) on Trust Investments | 189 | (263) | 192 | 452 | N/A | (455) | N/A | | Net Other Income (Deductions) | 96 | 36 | 10 | 60 | N/A | 26 | N/A | | Net Non-Operating Pension and OPEB (Costs) Credits | (332) | 95 | 64 | (427) | N/A | 31 | 48 | | Loss on Extinguishment of Debt | — | — | (298) | — | N/A | 298 | N/A | | Interest Expense | 259 | 201 | 169 | 58 | 29 | 32 | 19 | | Income Tax Expense (Benefit) | 358 | (296) | (765) | 654 | N/A | 469 | (61) | ### Year Ended December 31, 2023 as compared to 2022 **Operating Revenues** increased $1,267 million due primarily to changes in generation and gas supply and other operating revenues. ***Generation Revenues*** increased $1,868 million due primarily to - a net increase of $2,023 million due to MTM gains in 2023 as compared to MTM losses in 2022. Of this amount, there was a $1,539 million increase due to changes in forward prices in 2023 as compared to 2022 coupled with a $484 million increase due to positions reclassified to realized upon settlement, and - a net increase of $99 million due primarily to higher average realized prices and volumes sold in 2023 in the PJM region, partially offset by volumes sold in the New England and New York regions in 2022 related to the fossil generating plants sold in February 2022 and lower ZEC revenue, - partially offset by a net decrease of $190 million due primarily to electricity sold under the BGS contracts, which ended in May 2023, and lower volumes of other load contracts, and - a net decrease of $57 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. ***Gas Supply Revenues*** decreased $619 million due primarily to - a net decrease of $288 million related to sales to third parties, due primarily to $384 million from lower sales prices, partially offset by $96 million from higher sales volumes, - a net decrease of $275 million in sales under the BGSS contract due to $148 million from lower sales volumes and $127 million due to lower prices, and - a net decrease of $56 million due primarily to MTM losses in 2023 as compared to MTM gains in 2022. Of this amount, there was a $29 million decrease due to positions reclassified to realized upon settlement, coupled with a $27 million decrease due 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 decreased $796 million due to ***Gas costs*** decreased $536 million due primarily to - a net decrease of $273 million related to sales under the BGSS contract, of which $143 million was due to the lower average cost of gas and $130 million due to lower send out volumes, and - a net decrease of $261 million related to sales to third parties, due primarily to $332 million from the lower average cost of gas, partially offset by $71 million due to higher volumes sold. ***Generation costs*** decreased $260 million due primarily to - a net decrease of $185 million in fuel and emission costs due primarily to the sale of the fossil generating plants, and - a net decrease of $65 million in energy purchases due primarily to lower renewable energy credit requirements caused by decreases in load served in the PJM region. **Operation and Maintenance** decreased $33 million due primarily to the sale of the fossil generating plants in February 2022. **Losses on Asset Dispositions and Impairments** The $7 million loss in 2023 reflects an impairment at Energy Holdings related to one of its real estate assets. The $123 million loss in 2022 reflects an impairment loss of $78 million at Energy Holdings related to one of its domestic energy generating facilities and its real estate assets, and a $50 million impairment loss 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. See Item 8. Note 3. Asset Dispositions and Impairments. **Income from Equity Method Investments** decreased $13 million due primarily to the sale of our ownership interest in Kalaeloa completed in July 2023. **Net Gains (Losses) on Trust Investments** increased $452 million due primarily to NDT investments with $146 million of net unrealized gains on equity securities in 2023 as compared to $205 million of net unrealized losses in 2022 and $42 million of net realized gains in 2023 as compared to $50 million in net realized losses in 2022. **Net Other Income (Deductions)** increased $60 million due primarily to purchases of net operating loss (NOL) tax benefits under the New Jersey Technology Tax Benefit Transfer Program in 2022 and higher interest income in 2023. **Net Non-Operating Pension and OPEB (Costs) Credits** increased $427 million due primarily to the pension lift-out settlement charge, a decrease in the expected return on plan assets, an increase in interest cost, and a decrease in the amortization of the net prior service credit. **Interest Expense** increased $58 million due primarily to the replacement of maturing debt at the parent company at higher rates, the issuance of a PSEG Power term loan in March 2022, as well as higher rates on PSEG Power and parent company variable rate term loans in 2023. **Income Tax Expense** increased $654 million due primarily to higher pre-tax income in 2023. ### Year Ended December 31, 2022 as compared to 2021 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, 2022 as filed with the SEC on February 22, 2023 for information related to the year ended December 31, 2022 as compared to 2021, which information is incorporated herein by reference. ### LIQUIDITY AND CAPITAL RESOURCES The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our two direct major operating subsidiaries. ### Financing Methodology We expect our capital requirements to be met through internally generated cash flows and external financings, consisting of short-term debt for working capital needs and long-term debt for capital investments. PSE&G’s sources of external liquidity include a $1 billion multi-year revolving credit facility. PSE&G uses internally generated cash flow and its commercial paper program to meet seasonal, intra-month and temporary working capital needs. PSE&G does not engage in any intercompany borrowing or lending arrangements. PSE&G maintains 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. 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, 2023, our operating cash flow increased $2,303 million. The net increase was primarily due to an inflow of $1,408 million in net cash collateral postings in 2023 as compared to a $677 million outflow in 2022 at PSEG Power and lower tax payments in 2023, partially offset by a net change at PSE&G, as discussed below. ### PSE&G PSE&G’s operating cash flow decreased $488 million from $2,028 million to $1,540 million for the year ended December 31, 2023, as compared to 2022, due primarily to lower cash collateral postings received from BGS suppliers, increases in materials and supplies to support our electric AMI and other infrastructure programs, an increase in vendor and electric energy payments, and a net increase in regulatory deferrals. This was partially offset by a decrease in net accounts receivable due to improved collections following the delays from COVID-19 moratoriums. ### Short-Term Liquidity PSEG meets its short-term liquidity requirements, as well as those of PSEG Power, primarily through the issuance of commercial paper and, from time to time, short-term loans. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facility. Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. In January 2023, PSEG repaid $750 million of the $1.5 billion 364-day variable rate term loan that was issued in April 2022 and in April 2023 the remaining $750 million matured. In April 2023, PSEG entered into a new 364-day variable rate term loan agreement for $750 million. In May 2023, PSEG’s $500 million 364-day variable rate term loan matured. In August 2023, PSEG repaid $250 million of the $750 million 364-day variable rate term loan that was issued in April 2023.These term loans are not included in the credit facility amounts presented in the following table. In December 2023, PSEG Power converted a $100 million letter of credit facility from committed to uncommitted. PSEG Power also decreased a letter of credit facility, from $100 million to $75 million. Our total committed credit facilities and available liquidity as of December 31, 2023 were as follows: | Company/Facility Total Facility | As of December 31, 2023 Usage Millions | Available Liquidity | | | --- | ---: | ---: | ---: | | PSEG | $1,500 | $27 | $1,473 | | PSE&G | 1,000 | 445 | 555 | | PSEG Power | 1,525 | 188 | 1,337 | | **Total** | **$4,025** | **$660** | **$3,365** | For additional information, see Item 8. Note 14. 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, 2023, 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 $751 million and $878 million as of December 31, 2023 and 2022, respectively. See Item 8. Note 13. 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 2.88% of Senior Notes maturing in June 2024, - PSE&G has $250 million of 3.75% of Medium-Term Notes Series I, due March 2024, - PSE&G has $250 million of 3.15% of Medium-Term Notes, Series J, due August 2024, and - PSE&G has $250 million of 3.05% of Medium-Term Notes, Series J, due November 2024. For additional information, see Item 8. Note 14. 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. We do not currently expect to be required to provide supplemental 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, 2023, PSE&G’s Mortgage coverage ratio was 3.8 to 1 and the Mortgage would permit up to approximately $9.3 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 | Dividend Payments on Common Stock | Years Ended December 31, 2023 | 2022 | 2021 | | --- | ---: | ---: | ---: | | Per Share | $2.28 | $2.16 | $2.04 | | in Millions | $1,137 | $1,079 | $1,031 | On February 13, 2024, our Board of Directors approved a $0.60 per share common stock dividend for the first quarter of 2024. This reflects an indicative annual dividend rate of $2.40 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 22. Earnings Per Share (EPS) and Dividends. ### Credit Ratings If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Credit Ratings shown are for securities that we typically issue. Outlooks are shown for the credit ratings at each entity and can be Stable, Negative, or Positive. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security. | | Moody’s (A) | S&P (B) | | --- | --- | --- | | **PSEG** | | | | Outlook | **Stable** | **Stable** | | Senior Notes | Baa2 | BBB | | Commercial Paper | P2 | A2 | | **PSE&G** | | | | Outlook | **Stable** | **Stable** | | Mortgage Bonds | A1 | A | | Commercial Paper | P2 | A2 | | **PSEG Power** | | | | Outlook | **Positive** | **Stable** | | Issuer Rating | Baa2 | BBB | (A) Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities. (B) S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities. ### Other Comprehensive Income For the year ended December 31, 2023, we had Other Comprehensive Income of $371 million on a consolidated basis. The Other Comprehensive Income was due primarily to $324 million related to pension and other postretirement benefits, $41 million of net unrealized gains related to available-for-sale debt securities, and $6 million of unrealized gains on derivative contracts accounted for as hedges. See Item 8. Note 21. 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: | 2024 | 2025 Millions | 2026 | | --- | ---: | ---: | ---: | | Transmission | $610 | $785 | $725 | | Electric Distribution | 1,155 | 1,160 | 1,255 | | Gas Distribution | 1,145 | 1,090 | 1,095 | | Clean Energy | 440 | 605 | 585 | | **Total PSE&G** | **$3,350** | **$3,640** | **$3,660** | | Competitively Bid, FERC Regulated Transmission | 15 | 70 | 240 | | PSEG Power & Other | 265 | 205 | 170 | | **Total PSEG** | **$3,630** | **$3,915** | **$4,070** | ### 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 2023, PSE&G made $2,998 million of capital expenditures, primarily for T&D system reliability. In addition, PSE&G had cost of removal, net of salvage, of $166 million associated with capital replacements, and expenditures for EE programs of approximately $466 million, which are included in operating cash flows. ### Competitively Bid, FERC Regulated Transmission In December 2023, PJM awarded a subsidiary of Energy Holdings a project to address increasing load and reliability issues in Maryland as part of its 2022 Window 3 competitive solicitation. ### PSEG Power & Other PSEG’s other projected expenditures are primarily comprised of investments to maintain and enhance current nuclear operations and opportunities to increase nuclear generation at PSEG Power and to purchase software and office equipment at Services. In 2023, PSEG Power & Other made capital expenditures of $140 million, excluding $187 million for nuclear fuel, primarily related to various nuclear projects at PSEG Power and to purchase hardware, software and office equipment at Services. ### Other Material Cash Requirements The following table reflects our other material cash requirements which include debt maturities and interest payments, operating lease payments and energy related purchase commitments in the respective periods in which they are due. For additional information, see Item 8. Note 14. Debt and Credit Facilities, Note 7. Leases and Note 13. 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 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans and Note 11. Asset Retirement Obligations (AROs) for additional information. | Long-Term Recourse Debt Maturities | Total Amount Committed Millions | Less Than 1 Year | 2 - 3 Years | 4 - 5 Years | Over 5 Years | | --- | ---: | ---: | ---: | ---: | ---: | | PSEG | $4,396 | $750 | $550 | $1,300 | $1,796 | | PSE&G | 13,765 | 750 | 1,225 | 1,125 | 10,665 | | PSEG Power | 1,250 | — | 1,250 | — | — | | **Interest on Recourse Debt** | | | | | | | PSEG | 877 | 153 | 277 | 231 | 216 | | PSE&G | 7,997 | 506 | 955 | 898 | 5,638 | | PSEG Power (A) | 79 | 66 | 13 | — | — | | **Operating Leases** | | | | | | | PSE&G | 125 | 18 | 28 | 22 | 57 | | Other | 111 | 17 | 33 | 33 | 28 | | **Energy-Related Purchase Commitments** | | | | | | | PSEG Power | 2,486 | 745 | 981 | 524 | 236 | | **Total** | **$31,086** | **$3,005** | **$5,312** | **$4,133** | **$18,636** | (A) Based on a blended rate including effects of floating to fixed rate hedging transacted at the Parent level. ### CRITICAL ACCOUNTING ESTIMATES Under accounting guidance generally accepted in the United States (GAAP), many accounting standards require the use of estimates, variable inputs and assumptions (collectively referred to as estimates) that are subjective in nature. Because of this, differences between the actual measure realized versus the estimate can have a material impact on results of operations, financial position and cash flows. We have determined that the following estimates are considered critical to the application of rules that relate to the respective businesses. ### Accounting for Pensions and Other Postretirement Benefits (OPEB) The market-related value of plan assets held for PSEG’s qualified pension and OPEB plans is equal to the fair value of these assets as of year-end. The plan assets are comprised of investments in both debt and equity securities which are valued using quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Plan assets also include investments in unlisted real estate which is valued via third-party appraisals. We calculate pension and OPEB costs using various economic and demographic assumptions. ***Assumptions and Approach Used:*** Economic assumptions include the discount rate and the expected rate of return on plan assets. Demographic pension and OPEB assumptions include projections of future mortality rates, pay increases and retirement patterns, as well as projected health care costs for OPEB. | Assumption Pension | 2023 | 2022 | 2021 | | --- | ---: | ---: | ---: | | Discount Rate | 5.02% | 5.20% | 2.94% | | Expected Rate of Return on Plan Assets | 8.10% | 7.20% | 7.70% | | **OPEB** | | | | | Discount Rate | 4.96% | 5.16% | 2.82% | | Expected Rate of Return on Plan Assets | 8.10% | 7.20% | 7.69% | The discount rate used to calculate PSEG’s pension and OPEB obligations is determined as of December 31 each year, our measurement date. The discount rate is determined by developing a spot rate curve based on the yield to maturity of a universe of high quality corporate bonds with similar maturities to the plan obligations. The spot rates are used to discount the estimated plan distributions. The discount rate is the single equivalent rate that produces the same result as the full spot rate curve. Our expected rate of return on plan assets reflects current asset allocations, historical long-term investment performance and an estimate of future long-term returns by asset class, long-term inflation assumptions and a premium for active management. We utilize a corridor approach that reduces the volatility of reported costs/credits. The corridor requires differences between actuarial assumptions and plan results be deferred and amortized as part of the costs/credits. 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 fifteen 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 5.02% discount rate for 2024 pension costs/credits and a 4.96% discount rate for 2024 OPEB costs/credits. Based upon these assumptions, we have estimated a net periodic pension expense in 2024 of approximately $21 million, or a net periodic pension credit of $19 million, net of amounts capitalized, and a net periodic OPEB expense in 2024 of approximately $6 million, or $5 million, net of amounts capitalized. Beginning in 2023, our net periodic pension amounts include the impact of the accounting order approved by the BPU authorizing PSE&G to modify its pension accounting for ratemaking purposes. See a discussion in Item 7. MD&A—Executive Overview of 2023 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 in the chart solely reflect the impact of that specific assumption and therefore does not reflect the impact of the 2023 BPU accounting order. | Assumption Pension | % Change | Impact on Benefit Obligation as of December 31, 2023 Millions | Increase to Costs in 2024 | Increase to Costs, net of Amounts Capitalized in 2024 | | --- | ---: | ---: | ---: | ---: | | Discount Rate | (1)% | $536 | $23 | $16 | | Expected Rate of Return on Plan Assets | (1)% | N/A | $40 | $40 | | **OPEB** | | | | | | Discount Rate | (1)% | $72 | $(2) | $(3) | | Expected Rate of Return on Plan Assets | (1)% | N/A | $4 | $4 | See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information. ### Derivative Instruments The operations of PSEG, PSEG Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through executing derivative transactions. Derivative instruments are used to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments. Current accounting guidance requires us to recognize all derivatives on the balance sheet at their fair value, except for derivatives that qualify for and are designated as normal purchases and normal sales contracts. ***Assumptions and Approach Used:*** In general, the fair value of our derivative instruments is determined primarily by end of day clearing market prices from an exchange, such as the New York Mercantile Exchange, Intercontinental Exchange and Nodal Exchange, or auction prices. For our wholesale energy business, many of the forward sale, forward purchase, option and other contracts are derivative instruments that hedge commodity price risk, but do not meet the requirements for, or are not designated as, either cash flow or fair value hedge accounting. The changes in value of such derivative contracts are marked to market through earnings as the related commodity prices fluctuate. As a result, our earnings may experience significant fluctuations depending on the volatility of commodity prices. ***Effect if Different Assumptions Used:*** Any significant changes to the fair market values of our derivatives instruments could result in a material change in the value of the assets or liabilities recorded on our Consolidated Balance Sheets and could result in a material change to the unrealized gains or losses recorded in our Consolidated Statements of Operations. For additional information regarding Derivative Financial Instruments, see Item 8. Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies, Note 16. Financial Risk Management Activities and Note 17. 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, expectation of PTCs, 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, make a number of decisions that impact the operation of our generation assets beyond the current year. These decisions may have a direct impact on the estimated remaining useful lives of our assets and will be influenced by the financial outlook of the assets, including future market conditions such as forward energy 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 3. 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 72% or $1,057 million of PSEG’s total AROs as of December 31, 2023. 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: - 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, - recovery from the federal government of assumed specific costs incurred for spent nuclear fuel, and - financial feasibility and impacts on potential early shutdown. ***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, 2023 are as follows: - A decrease of 1% in the discount rate would result in a $43 million increase in the Nuclear ARO. - An increase of 1% in the inflation rate would result in a $303 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 $139 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 $497 million. ### Accounting for Regulated Businesses PSE&G prepares its financial statements to comply with GAAP for rate-regulated enterprises, which differs in some respects from accounting for non-regulated businesses. In general, accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (Regulatory Asset) or recognize obligations (Regulatory Liability) if the rates established are designed to recover the costs and if the competitive environment makes it probable that such rates can be charged or collected. This accounting results in the recognition of revenues and expenses in different time periods than that of enterprises that are not regulated. ***Assumptions and Approach Used:*** PSE&G recognizes Regulatory Assets where it is probable that such costs will be recoverable in future rates from customers and Regulatory Liabilities where it is probable that refunds will be made to customers in future billings. The highest degree of probability is an order from the BPU either approving recovery of the deferred costs over a future period or requiring the refund of a liability over a future period. Virtually all of PSE&G’s Regulatory Assets and Regulatory Liabilities are supported by BPU orders. In the absence of an order, PSE&G will consider the following when determining whether to record a Regulatory Asset or Liability: - past experience regarding similar items with the BPU, - treatment of a similar item in an order by the BPU for another utility, - passage of new legislation, and - recent discussions with the BPU. All deferred costs are subject to prudence reviews by the BPU. When the recovery of a Regulatory Asset or payment of a Regulatory Liability is no longer probable, PSE&G charges or credits earnings, as appropriate. ***Effect if Different Assumptions Used:*** A change in the above assumptions may result in a material impact on our results of operations or our cash flows. See Item 8. Note 6. Regulatory Assets and Liabilities for a description of the amounts and nature of regulatory balance sheet amounts. ## Market risk As filed, 5,290 characters. ### 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, treasury locks, and options with approved counterparties. These contracts, in conjunction with physical sales and other services, help reduce risk and optimize the value of owned electric generation capacity. ### Value-at-Risk (VaR) Models VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses. MTM VaR consists of MTM derivatives that are economic hedges. The calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some load-serving activities. The VaR models used are variance/covariance models adjusted for the change of positions with 95% and 99.5% confidence levels and a one-day holding period for the MTM activities. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio. | 95% Confidence Level, Loss could exceed VaR one day in 20 days | MTM VaR Years Ended December 31, 2023 Millions | 2022 | | --- | ---: | ---: | | Period End | $48 | $122 | | Average for the Period | $56 | $152 | | High | $127 | $365 | | Low | $24 | $70 | | **99.5% Confidence Level, Loss could exceed VaR one day in 200 days** | | | | Period End | $75 | $191 | | Average for the Period | $87 | $239 | | High | $198 | $572 | | Low | $38 | $110 | See Item 8. Note 16. 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, 2023, a hypothetical 10% increase in market interest rates would result in an additional $2 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, 2023, we had $4.6 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, 2023, the portfolio included $1.3 billion of equity securities inclusive of $0.3 billion of investments in listed real assets, and $1.2 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, 2023, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $131 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 6.24 years and a yield of 4.53%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2023, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $76 million. ## Controls and procedures As filed, 2,444 characters. ### 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, 2023, 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 147 and 148, 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 149. Management has concluded that internal control over financial reporting is effective as of December 31, 2023. 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 2023 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting. Filed Feb 26, 2024. Source: SEC EDGAR, the filing index for accession 0001628280-24-006885. Last ingested by Listed: Nov 2, 2026, 09:01 ET. No prices; not investment advice.