What changed in this filing

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Item 7. Management’s Discussion and Analysis

2024-02-26 compared with 2023-02-22 · 253 added, 300 removed, 411 unchanged (57% of the section changed)

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• PSE&G —which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey.

PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC).

PSE&G 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), the Environmental Protection Agency and the states in which they operate.

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 Energy Holdings L.L.C.

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

PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) transmission and distribution (T&D) system under an Operations Services Agreement (OSA);

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.

Table of Conte n t s

Our business discussion in Item 1.

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We are focused on investing to modernize our energy infrastructure, improve reliability and resilience, increase EE and deliver cleaner energy to meet customer expectations and be well aligned with public policy objectives.

In furtherance of these goals, over the past few years, our investments have simplified our business mix to reflect a higher percentage of earnings contribution by PSE&G.

We have further proactively changed our business mix through the sale of our fossil generation portfolio which closed in 2022.

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

In addition, the passage of the Inflation Reduction Act (IRA) established a Production Tax Credit (PTC) for nuclear from 2024 through 2032 which is expected to provide downside price protection for our nuclear generation fleet.

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.

At PSE&G, our focus is on investing capital in T&D infrastructure and clean energy programs to enhance the reliability and resiliency of our T&D system, meet customer expectations and support public policy objectives.

For the years 2023-2027, PSE&G’s capital investment program is estimated to be in a range of $15.5 billion to $18 billion, resulting in an expected compound annual growth in rate base of 6% to 7.5% from year-end 2022 to year-end 2027.

The low end of this range includes an extension of our Gas System Modernization Program (GSMP) and Clean Energy Future (CEF)-EE program at their average annual investment levels plus inflation, as these programs are expected to continue beyond their currently approved timeframe of 2023.

The upper end of our capital investment range includes an extension of our Energy Strong program, which otherwise concludes in 2024, as well as the remaining portion of our CEF proposal (portion of Electric Vehicle (EV) and Energy Storage (ES) programs) and a potentially higher amount of investments for GSMP and CEF-EE beyond current levels.

We filed for a $320 million short-term extension of our CEF-EE program in September 2022, which we expect will be resolved in 2023.

A remaining component of our CEF-EV program related to medium and heavy duty charging infrastructure has been the subject of a stakeholder process that the BPU began in 2021 and we expect that this effort will result in PSE&G submitting a filing targeting infrastructure investments for the medium and heavy duty EV market in 2023.

Our CEF-ES program is being held in abeyance.

In September 2022, the BPU released a draft Storage Incentive Program proposal and is currently undertaking a stakeholder process to receive comments.

PSE&G is active in the proceeding.

Pursuant to our GSMP II and Energy Strong II programs, we are required to file a distribution base rate case no later than December 31, 2023.

Among other things, the rate case will recover capital expenditures associated with these programs, as well as the Advanced Metering Infrastructure and EV programs, and other investments that are not recovered through periodic rate roll-ins.

We expect to conclude the case in the second half of 2024.

At PSEG Power, we seek to produce low-cost electricity by efficiently operating our nuclear generation assets, mitigate volatility by contracting in advance for a significant portion of their output and support public policy objectives that preserve these existing nuclear generating plants.

During 2022, our nuclear units generated 31.3 terawatt hours and operated at a capacity factor of 92.2%.

We recently closed the sale of our Solar generation and Fossil generation businesses in 2021 and 2022, respectively.

These transformative transactions reduced our overall business risk and earnings volatility.

PSEG Power’s hedging practices help to mitigate a significant amount of the earnings volatility of the merchant nuclear power business.

More than 90% of PSEG Power’s expected gross margin in 2023 relates to hedging of our energy margin, our expected revenues from the capacity market mechanism, Zero Emission Certificate (ZEC) revenues and, certain gas operations

and ancillary service payments such as reactive power.

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

During the second half of 2021 and continuing throughout 2022, forward energy prices have demonstrated considerable price volatility and have increased dramatically.

This has led to significantly higher variation in our collateral requirements, which have also increased substantially over that time period for hedge positions that are out-of-the money.

PSEG Power’s net cash collateral postings related to these hedge positions increased from $343 million at the end of June 2021 to $1.5 billion at the end of December 2022.

Subsequent to December 2022, collateral postings continued to experience significant fluctuations in our daily collateral requirements.

Net cash collateral postings were approximately $700 million as of February 17, 2023.

While currently off their highs experienced during 2022, collateral postings could remain volatile into 2023.

However, as historical lower-priced trades continue to settle through 2024, collateral is expected to be returned as we satisfy our obligations under those contracts.

PSEG continues to maintain sufficient liquidity as described in Liquidity and Capital Resources.

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.

Table of Conte n t s

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.

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

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Today, our vision is to power a future where people use less energy, and it is cleaner, safer and delivered more reliably than ever.

We have established a net zero greenhouse gas (GHG) emissions by 2030 goal that includes direct GHG emissions (Scope 1) and indirect GHG emissions from operations (Scope 2) across our operations, assuming advances in technology, public policy and customer behavior.

Scope 1 emissions include power generation, methane leaks, vehicle fleet emissions, and sulfur hexafluoride and refrigerant leaks.

Scope 2 emissions include both gas and electric purchased energy for our PSE&G facilities and line losses.

We have also committed to the United Nations-backed Race to Zero campaign.

We continue to evaluate and are working toward developing and submitting science-based emission reduction targets following the criteria and recommendations of the Science Based Targets initiative (SBTi) by September 2023 which encompass Scopes 1, 2, and 3 (the majority of which are associated with the downstream use of energy products) and seek to be in line with 1.5 o C emissions scenarios in order to be validated by the SBTi.

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 program are intended to support New Jersey’s Energy Master Plan through programs designed to help customers increase their EE, support the expansion of the EV infrastructure in the State, install energy storage capacity to supplement solar generation and enhance grid resiliency, install smart meters and supporting infrastructure to allow for the integration of other clean energy technologies and to more efficiently respond to weather and other outage events.

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 is expected to replace an additional 875 miles of gas pipes through 2023.

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 expect to reduce methane leaks by approximately 22% system wide and assuming a continuation of GSMP, we expect to achieve an overall reduction in methane emissions of approximately 60% over the 2011 through 2030 period.

We also continue to assess physical risks of climate change and adapt our capital investment program to improve the reliability and resiliency of our system in an environment of increasing frequency and severity of weather events, notably through our investments in our Energy Strong program and Infrastructure Advancement Program.

These investments have shown benefits in recent severe weather events, including Tropical Storm Ida in August 2021, which brought significant flooding to our service territory but did not result in the loss of any of our electric distribution substations.

We also continue to focus on providing cleaner energy for our customers.

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

In February 2023, New Jersey Governor Murphy issued three executive orders that establish targets, or accelerate previously established 2050 targets, for clean-sourced energy, building electrification, and EV adoption goals, with new target dates of 2030 or 2035, as applicable.

The executive orders direct the BPU and other state agencies to collaborate with stakeholders to develop plans, including the new 2024 Energy Master Plan, to reach the targets and convene a stakeholder proceeding to develop a new plan for gas distribution utilities to reach the target, previously established in a 2021 executive order, of 50% natural gas emissions reductions over 2006 levels by 2030.

Such proceeding is to consider competitive market mechanisms including adoption of a “clean heat” standard, policies to minimize investment in new gas infrastructure, and alternative programs that could provide natural gas utilities with new revenue streams, such as conversion of existing pipeline infrastructure to provide decarbonized heating and cooling (for example, district geothermal).

We are unable to predict the

outcomes of the various proceedings, but they could have a material impact on our business, results of operations and cash flows.

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.

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

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

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

The sale proceeds approximate PSEG’s carrying value of the investment and no material gain or loss is expected upon disposition.

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

The sale is expected to close in the first half of 2023.

PSEG has no further obligation to make any capital contributions to the project prior to closing on the transaction.

PSEG will continue to provide construction management and environmental permitting services for the onshore substations and transmission cable installation scope of the project.

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

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

In 2021-2022, PJM Interconnection, L.L.C.

(PJM) conducted its first-ever public policy Order 1000 transmission solicitation process utilizing the state agreement approach for transmission projects to support New Jersey’s planned offshore wind generation.

The state agreement approach requires customers in the requesting state - in this case New Jersey - to pay for the costs of these public policy transmission projects.

PSEG and Ørsted jointly submitted several proposals in response to the solicitation, including multi-spur options and an offshore network proposal.

The BPU completed its review of offshore wind transmission in October 2022 and awarded several on-shore, though no offshore, solutions.

PSE&G was awarded $40 million for transmission upgrades.

The BPU also indicated that it would consider conducting an additional solicitation to address the State’s increased offshore wind generation targets.

Table of Conte n t s

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 for the years ended December 31, 2022 and 2021 are presented as follows:

The financial results for PSEG, PSE&G and PSEG Power & Other for the years ended December 31, 2023 and 2022 are presented as follows:

Years Ended December 31,

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PSEG Power & Other 1,048 (534)

PSEG Net Income (Loss) $ 1,031 $ (648)

PSEG Net Income (Loss) Per Share (Diluted) $ 2.06 $ (1.29)

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.

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We closely monitor and engage with stakeholders on significant regulatory and legislative developments.

Distribution investment needs and scope and transmission planning and rates rules, as well as wholesale power market design, including clarification from the U.S.

Treasury on PTCs for electricity generation using nuclear energy, are of particular importance to our results and we continue to advocate for policies and rules that promote fair and efficient electricity markets.

For additional information about regulatory, legislative and other developments that may affect us, see Item 1.

Business—Regulatory Issues.

Transmission Rate Proceedings and Return on Equity (ROE)

In October 2021, FERC approved a settlement agreement effective August 1, 2021 that we reached with the BPU and the New Jersey Division of Rate Counsel about the level of PSE&G’s base transmission ROE and other formula rate matters.

The settlement reduces PSE&G’s base ROE from 11.18% to 9.9% and makes several other changes regarding the recovery of certain costs.

The agreement provides that the settling parties will not seek changes to our transmission formula rate for three years.

We have implemented the terms of the agreement.

Under current FERC rules, we continue to earn a 50 basis point adder to that base ROE for our membership in PJM.

FERC is considering whether to eliminate this adder and the outcome and timing of any decision is uncertain.

If the adder was eliminated it would reduce PSE&G’s annual Net Income and annual cash inflows by approximately $30 million to $40 million.

Wholesale Power Market Design

In December 2022, PJM ran a Base Residual Auction for the Delivery Year 2024-2025 but it has not yet announced the results of the auction.

Instead, based on what it observed in the auction, PJM made emergency filings at FERC to change the way in which it calculates the clearing prices for capacity zones under certain circumstances.

As a result, PSEG does not yet know the level of capacity payments it may receive in this auction.

The filings at FERC are pending and we cannot predict the outcome.

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

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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.

Table of Conte n t s

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.

Commitments and Contingent Liabilities.

In April 2021, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs for the three-year eligibility period starting June 2022 at the same approximate $10 per megawatt hour (MWh) received during the prior ZEC period through May 2022.

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 nuclear energy set to begin in 2024 through 2032.

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 cap are subject to annual inflation adjustments.

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

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

Treasury and the impact of PTCs on expected ZEC payments.

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

Current Inflationary Environment

The current inflationary environment has prompted the Federal Reserve to tighten monetary policy resulting in higher interest rates, which have impacted financial markets, reducing the value of fixed income investments and created uncertainty about the future economic outlook weakening equity markets.

These factors have resulted in negative returns on our pension assets during 2022.

As our pension costs are set at the beginning of the calendar year, there was no impact on pension costs for 2022 resulting from asset performance during the year.

However, pension costs in 2023 will be and future years are expected to be materially impacted from returns on 2022 pension assets.

The higher interest rates translate into a higher discount rate for our pension obligations, which lowers our pension liability and positively affects our funded ratio, which remains strong.

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 will mitigate some of the volatility in earnings and customer rates related to our pension trust performance, and is effective for calendar year 2023 and forward.

As a result of this order, PSEG’s 2023 pension expense, net of amounts capitalized, will be reduced by $59 million, resulting in a pension credit of $16 million.

Further, higher interest rates on borrowings will contribute to higher interest expense on variable rate debt, which has increased due to cash collateral postings, and to long-term rates on future financing plans.

During September and October 2022, PSEG entered into floating-to-fixed interest rate swaps totaling $1.05 billion in order to reduce the volatility in interest expense for PSEG Parent’s $500 million variable rate term loan due May 2023 and a portion of PSEG Power’s $1.25 billion variable rate term loan due March 2025.

Inflation will also result in upward pressure on operating costs and capital spending.

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.

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 existing legislation could have a material impact on our effective tax rate and cash tax position.

The IRA enacted a new 15% corporate alternative minimum tax, effective in 2023, a PTC for existing nuclear generation facilities and allows energy tax credits to be transferable.

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.

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 cannot determine the impact the IRA will have on PSEG’s and PSE&G’s results of operations, financial condition and cash flows.

In 2020, the Internal Revenue Service (IRS) issued final and proposed Section 163(j) regulations addressing the limitation on deductible business interest expense, increasing the amount of interest that can be deducted by unregulated businesses in years before 2022.

The portion of PSEG’s and PSEG Power’s business interest expense that was disallowed in 2018 and 2019 is now deductible in those respective years.

Additionally, the federal Coronavirus Aid, Relief, and Economic Security Act (CARES Act) allowed us to carry back the 2018 tax net operating loss (NOL) generated by the final Section 163(j) regulations to 2023.

In December 2022, the IRS approved our carry back claim, providing a $28 million tax benefit.

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 to capitalize on or otherwise address regulatory and legislative developments that impact our business and to respond to the issues and challenges described below.

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:

• obtain approval of and execute on our utility capital investment program to modernize our infrastructure, improve the reliability and resilience of the service we provide to our customers, and align our sustainability and climate goals with New Jersey’s energy policy,

• seek 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,

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• seek a fair return for our T&D investments through our transmission formula rate, existing rate incentives, distribution infrastructure and clean energy investment programs and periodic distribution base rate case proceedings,

• focus on controlling costs while maintaining safety, reliability and customer satisfaction and complying with applicable standards and requirements,

• manage the risks and opportunities in federal and state clean energy policies, which is an integral part of our long-term strategy,

• successfully manage our obligations and re-contract our open positions in response to changes in prices and demand,

• 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,

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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, design of energy and capacity markets, and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceedings,

• the current inflationary environment and associated volatility in the financial markets, including the impact on our pension fund performance and interest rates on our future financing plans,

• increases in commodity prices and customer rates, which may adversely affect customer collections and future regulatory proceedings,

• 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,

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• investments in PSE&G, including T&D facilities to enhance reliability, resiliency and modernize the system to meet the growing needs and increasingly higher expectations of customers, and clean energy investments such as CEF-EE, CEF-EV, CEF-ES and solar,

• continued operation of our nuclear generation facilities that are supported through the PTC through 2032 and can enable certain enhancements to the units as well as potential license extensions,

• investments in regional offshore wind regulated transmission, should New Jersey pursue the development of an offshore network, with returns that provide revenue predictability and reasonable risk-adjusted returns, and

• 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.

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The execution of any such strategic plan may not have the expected benefits or may have unexpected adverse consequences.

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RESULTS OF OPERATIONS

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PSEG Net Income (Loss) Per Share (Diluted) $ 5.13 $ 2.06 $ (1.29)

(A) PSEG Power & Other results in 2022 include after-tax impairments of $92 million related to certain Energy Holdings investments and additional adjustments related to the sale of PSEG Power’s fossil generation assets.

(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.

PSEG Power & Other results in 2020 include an after-tax gain of $86 million related to the sale of Power’s ownership interest in the Yards Creek generation facility.

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

Asset Dispositions and Impairments for additional information.

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

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

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

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,

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Trust Investments for additional information.

NDT Fund Income (Expense) also includes interest and dividend income and other costs related to the NDT Fund recorded in

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

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

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

• an impairment loss and related charges taken in 2021 as a result of the sale of the fossil generation assets at PSEG Power (see Item 8.

Early Plant Retirements/Asset Dispositions and Impairments for additional information),

• higher earnings due to continued investments in T&D programs at PSE&G, and

• the favorable impact of the Conservation Incentive Program (CIP) in 2022 at PSE&G,

• partially offset by net unrealized losses on equity securities in 2022 in the NDT Fund and net realized losses in 2022 as compared to net realized gains in 2021.

(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.

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.

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Related-Party Transactions.

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(Decrease) Increase /

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Depreciation and Amortization 1,135 1,100 1,216 35 3 (116) (10)

(Gains) Losses on Asset Dispositions and Impairments 123 2,637 (123) (2,514) (95) 2,760 N/A

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 (265) 194 253 (459) N/A (59) (23)

Other Income (Deductions) 124 98 115 26 27 (17) (15)

Non-Operating Pension and OPEB Credits (Costs) 376 328 249 48 15 79 32

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 (Benefit) Expense (29) (441) 396 412 (93) (837) N/A

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.

Variable Interest Entities for additional information.

Variable Interest Entity for additional information.

The following discussions for PSE&G and PSEG Power provide a detailed explanation of their respective variances.

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Energy Costs 3,010 3,270 2,688 (260) (8) 582 22

Operation and Maintenance 1,838 1,692 1,614 146 9 78 5

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) (1) 4 N/A (3) N/A

Net Gains (Losses) on Trust Investments (2) 2 3 (4) N/A (1) (33)

Other Income (Deductions) 88 88 108 — — (20) (19)

Non-Operating Pension and OPEB Credits (Costs) 281 264 205 17 6 59 29

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

Operating Revenues decreased $128 million due to changes in delivery, clause, commodity and other operating revenues.

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Delivery Revenues increased $184 million.

• Gas distribution revenues increased $129 million due primarily to increases of $55 million from collection of the GSMP in base rates, $54 million from higher sales volumes and $18 million in CIP decoupling revenues.

• Electric distribution revenues increased $47 million due primarily to $30 million from CIP decoupling revenue and $20 million from an Energy Strong II rate roll-in.

• Electric distribution and gas distribution revenue requirements were $28 million higher due primarily to a net decrease in the flowback to customers of excess deferred income tax liabilities and tax repair-related accumulated deferred income taxes, which is offset in Income Tax Expense.

• Transmission revenues increased $5 million due to an increase in revenue requirements attributable to higher rate base investment, partially offset by the estimated impact of the ROE settlement.

Clause Revenues increased $4 million due primarily to $35 million in higher Societal Benefits Clause (SBC) collections, partially offset by a $30 million decrease in Tax Adjustment Credits (TAC) and Green Program Recovery Charge (GPRC) deferrals.

The changes in SBC collections and TAC and GPRC deferrals were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, D&A and Interest and Tax Expenses.

PSE&G does not earn margin on SBC collections or TAC and GPRC deferrals.

Commodity Revenues increased $551 million due to higher Gas revenues and Electric revenues.

• 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 increased $393 million due primarily to $335 million from higher BGSS prices and $60 million from higher BGSS sales volumes.

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

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

The changes in SuSI and SREC revenues are entirely offset by changes to Energy Costs.

• 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 increased $582 million.

This is entirely offset by changes in Commodity Revenues and Other Operating Revenues.

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

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

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

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

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

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

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.

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PSEG Power & Other

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Depreciation and Amortization 155 165 288 (10) (6) (123) (43)

(Gains) Losses on Asset Dispositions and Impairments 123 2,641 (122) (2,518) (95) 2,763 N/A

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 (263) 192 250 (455) N/A (58) (23)

Other Income (Deductions) 36 10 7 26 N/A 3 43

Non-Operating Pension and OPEB Credits (Costs) 95 64 44 31 48 20 45

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

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Year Ended December 31, 2023 as compared to 2022

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

Generation Revenues decreased $1,300 million due primarily to

• a net decrease of $807 million due primarily to lower volumes sold in the PJM, New England (NE) and New York (NY) regions primarily due to the sale of the fossil generating plants in February 2022, coupled with lower average realized prices in the PJM region, partially offset by higher average realized prices in the NE and NY regions,

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.

• a net decrease of $216 million due primarily to lower volumes of electricity sold under the BGS contracts, partially offset by less transmission services under the BGS contracts that were transferred from the BGS suppliers to the

Electric Distribution Companies (EDCs) in February 2021,

• a net decrease of $37 million in ancillary revenues due primarily to the sale of the fossil generating plants, and

• a net decrease of $24 million in solar revenues due to the sale of the solar plants in June 2021,

• partially offset by a net increase of $16 million due to lower MTM losses in 2022 as compared to 2021.

Of this amount, there was a $368 million increase due to gains on positions reclassified to realized upon settlement in 2022 as compared to losses in 2021, partially offset by a $352 million decrease due to changes in forward prices.

Gas Supply Revenues increased $788 million due primarily to

• a net increase of $481 million in sales under the BGSS contract due primarily to $419 million from higher prices and $62 million from higher sales volumes,

• a net increase of $282 million related to sales to third parties, primarily due to $248 million from higher sales prices and $34 million from higher sales volumes, and

• an increase of $25 million due primarily to changes in forward prices.

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 increased $171 million due to

Gas costs increased $721 million due primarily to

• a net increase of $478 million related primarily to sales under the BGSS contract, of which $425 million was due to the higher average cost of gas and $53 million due to higher send out volumes, and

• a net increase of $243 million related to sales to third parties, of which $213 million was due to an increase in the average cost of gas and $30 million to higher volumes sold.

Energy Costs decreased

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$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 $413 million in fuel costs, due primarily to lower volumes of gas used in the PJM, NY, and NE regions caused by the sale of the fossil generating plants, partially offset by higher gas prices.

Additionally, there was a decrease in coal costs in the NE region due to the retirement of the Bridgeport Harbor 3 (BH3) plant in 2021,

• a net decrease of $142 million in energy purchases due primarily to lower renewable energy credit (REC) requirements and lower ancillary charges caused by decreases in load served in the PJM and NE regions,

• a net decrease of $33 million in emission costs due to the sale of the fossil generating plants, and

• a net decrease of $17 million in transmission costs due primarily to the impact from transfer of responsibility for firm transmission services under BGS contracts from BGS suppliers to the EDCs,

• partially offset by a net increase of $56 million due to net MTM losses in 2022 as compared to net MTM gains in 2021.

Of this amount, there was a $42 million increase due to positions reclassified to realized upon settlement in 2022 as compared to 2021, coupled with a $15 million increase due to changes in forward prices.

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

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

(Gains) Losses on Asset Dispositions and Impairments The $123 million loss in 2022 reflects an impairment loss of $50 million due to the sale of the fossil generating plants in February 2022, partially offset by a $5 million gain on a land sale at PSEG Power and pre-tax impairments of $78 million at Energy Holdings related to one of its domestic energy generating facilities and its real estate assets.

The $2,641 million net loss in 2021 reflects impairment losses due to the sale of the fossil generating plants and other impairments, partially offset by a $63 million gain from the sale of PSEG Solar Source (Solar Source) in 2021.

Early Plant Retirements/Asset Dispositions and Impairments.

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

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

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

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

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

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

• 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.

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

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

Generation Revenues decreased $668 million due primarily to

• a net decrease of $606 million due to higher MTM losses in 2021 as compared to 2020.

Of this amount, there was a $624 million decrease due to changes in forward prices, partially offset by an $18 million increase due to less losses on positions reclassified to realized upon settlement in 2021,

• a net decrease of $288 million due primarily to $201 million from lower volumes of electricity sold under the BGS contracts, coupled with an $87 million impact from the transfer of responsibility for firm transmission services from BGS suppliers to the EDCs, and

• a net decrease of $29 million in solar revenues due to the sale of the solar plants in June 2021,

• partially offset by a net increase of $188 million due primarily to higher average realized prices and higher volumes sold in the PJM, NE and NY regions, and

• a net increase of $64 million in capacity revenues due primarily to increases in auction prices, coupled with decreases in capacity charges due to lower BGS and other load obligations in the PJM region, partially offset by lower capacity prices and the retirement of the BH3 coal plant in the NE region.

Gas Supply Revenues increased $182 million due primarily to

• a net increase of $106 million in sales under the BGSS contract due primarily to higher prices of $72 million and higher sales volumes of $34 million, and

• a net increase of $74 million related to sales to third parties, of which $90 million was due to higher average sales prices, partially offset by $16 million due to lower volumes sold.

Operating Expenses

Energy Costs increased $157 million due to

Generation costs decreased $13 million due primarily to

• a net decrease of $147 million in transmission costs due primarily to an $87 million impact from the transfer of responsibility for firm transmission services under BGS contracts from BGS suppliers to the EDCs, coupled with a $60 million decrease in other transmission costs, mainly from lower volumes of electricity sold under the BGS contracts, and

• a net decrease of $66 million due to higher net MTM gains in 2021.

Of this amount, there was a $52 million decrease due to changes in forward prices, coupled with a $14 million decrease due to more gains on positions reclassified to realized upon settlement in 2021,

• partially offset by a net increase of $157 million in fuel costs, reflecting higher gas prices and higher volumes in the PJM, NY, and NE regions, and

• a net increase of $42 million in energy purchases due primarily to an increase in purchased volumes in the PJM region to meet physical energy sales.

This was partially offset by a decrease in REC requirements caused by decreases in load served in the PJM region.

Gas costs increased $170 million due primarily to

• a net increase of $103 million in costs related to sales under the BGSS contract, of which $74 million was due to the higher average cost of gas and $29 million to higher send out volumes.

Included in the 2020 average cost of gas were $18 million of interstate gas pipeline refunds due to a settlement on pipeline rates from prior periods, and

• a net increase of $67 million related to sales to third parties, of which $81 million was due to an increase in the average cost of gas, partially offset by a decrease of $14 million due to lower volumes sold.

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

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

(Gains) Losses on Asset Dispositions and Impairments The loss in 2021 primarily reflects a $2,691 million impairment due to the sale of the fossil generating plants and other impairments, partially offset by a $63 million gain from the sale of the solar plants.

The $122 million gain in 2020 was due to the sale of our ownership interest in the Yards Creek generation facility.

Early Plant Retirements/Asset Dispositions and Impairments.

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

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

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

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

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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.

PSE&G’s long-term financing plan is designed to replace maturities, fund a portion of its capital program

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and manage short-term debt balances.

Generally, PSE&G uses either secured medium-term notes or first mortgage bonds to raise long-term capital.

PSEG, PSEG Power, Energy Holdings, PSEG LI and Services participate in a corporate money pool, an aggregation of daily cash balances designed to efficiently manage their respective short-term liquidity needs, which are accounted for as intercompany loans.

Long Island Electric Utility Servco, LLC (Servco) does not participate in the corporate money pool.

Servco does not participate in the corporate money pool.

Servco’s short-term liquidity needs are met through an account funded and owned by LIPA.

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

For the year ended December 31, 2022, our operating cash flow decreased $233 million.

The net decrease was primarily due to the sale of the fossil generation plants in February 2022, and a $244 million increase in payments to counterparties at PSEG Power and the net change at PSE&G, as discussed below.

In addition, there were tax payments in 2022 as compared to tax refunds in 2021 at the parent company.

PSE&G’s operating cash flow increased $304 million from $1,724 million to $2,028 million for the year ended December 31, 2022, as compared to 2021, due primarily to decreases in vendor and electric energy payments, lower tax payments, higher earnings in 2022, and an increase in cash collateral postings received from BGS suppliers.

This was partially offset by an increase in net accounts receivable due to ongoing delayed collections as a result of COVID-19 moratoriums in 2022, increases in materials and supplies to support our electric AMI program as well as an increase in material purchases in 2022 due to easing of prior year supply chain shortages, and a net increase in regulatory deferrals in 2022.

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’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

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however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs.

During the second half of 2021 and continuing throughout 2022, forward energy prices have demonstrated considerable price volatility and have increased dramatically.

This has led to significantly higher variation in our daily collateral requirements which have also increased substantially over that time period for hedge positions that are out-of-the money.

PSEG Power’s net cash collateral postings related to these hedge positions increased from $343 million at the end of June 2021 to $1.5 billion at the end of December.

Subsequent to December 2022, collateral postings have decreased but PSEG Power continued to experience significant fluctuations in its daily collateral requirements.

Net cash collateral postings were approximately $700 million on February 17, 2023.

While currently off their highs experienced during 2022, collateral postings could remain volatile into 2023.

However, as historical lower-priced trades continue to settle through 2024, collateral is expected to be returned as we satisfy our obligations under those contracts.

Proceeds from the sale of Fossil, the closing of a $1.25 billion term loan in March 2022 at PSEG Power, and short-term borrowings at PSEG have contributed to available liquidity to help support PSEG Power’s collateral requirements in 2022.

In March and May 2021, PSEG entered into two 364-day variable rate term loan agreements for $500 million and $750 million, respectively.

In August 2021, PSEG entered into a $1.25 billion, 364-day variable rate term loan agreement.

In March 2022, the $500 million term loan matured and PSEG repaid the $750 million term loan due in May 2022.

In July 2022, PSEG repaid the $1.25 billion term loan due in August 2022.

In April 2022 and May 2022, PSEG entered into 364-day variable rate term loan agreements for $1.5 billion and $500 million, respectively.

In January 2023, PSEG repaid $750 million of the $1.5 billion term loan due in April 2023.

These term loans are not included in the credit facility amounts presented in the following table.

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.

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Our total committed credit facilities and available liquidity as of December 31, 2023 were as follows:

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During the next twelve months,

• PSEG has $750 million of 0.841% Senior Notes due November 2023,

• PSE&G has $500 million of 2.38% of Medium-Term Notes Series I, due May 2023, and

• PSE&G has $325 million of 3.25% of Medium-Term Notes, Series M, due September 2023.

• 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.

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Any funding shortfalls are required to be cured prior to the next NDT reporting period.

The current market downturn associated with inflation and rising interest rates is not currently expected to result in any supplemental required funding of the NDT Fund.

We do not currently expect to be required to provide supplemental funding of the NDT Fund.

Debt Covenants

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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.

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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.

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The ratings should not be construed as an indication to buy, hold or sell any security.

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Moody’s (A) S&P (B)

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Commercial Paper P2 A2

Outlook Stable Stable

Outlook Positive Stable

Issuer Rating Baa2 BBB

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Other Comprehensive Income

For the year ended December 31, 2022, we had Other Comprehensive Loss of $200 million on a consolidated basis.

The Other Comprehensive Loss was due primarily to $132 million of net unrealized losses related to Available-for-Sale Debt Securities, and a decrease of $71 million related to pension and other postretirement benefits, partially offset by $3 million of unrealized gains on derivative contracts accounted for as hedges.

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.

Accumulated Other Comprehensive Income (Loss), Net of Tax for additional information.

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Total PSE&G $ 3,350 $ 3,640 $ 3,660

Other 165 165 170

Competitively Bid, FERC Regulated Transmission 15 70 240

PSEG Power & Other 265 205 170

Total PSEG $ 3,630 $ 3,915 $ 4,070

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• 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.

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• 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.

This does not include expenditures for EE and EV programs of approximately $286 million and cost of removal, net of salvage, of $129 million, which are included in operating cash flows.

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

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

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The table below does not reflect any anticipated cash payments for pension and OPEB or AROs due to uncertain timing of payments.

Pension and Other Postretirement Benefits (OPEB) and Savings Plans and Note 13.

Pension, Other Postretirement Benefits (OPEB) and Savings Plans and Note 11.

Asset Retirement Obligations (AROs) for additional information.

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PSE&G 7,997 506 955 898 5,638

PSEG Power 131 60 71 — —

PSEG Power (A) 79 66 13 — —

Operating Leases

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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.

Because of this, differences between the actual measure realized versus the estimate can have a material impact on results of operations,

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financial position and cash flows.

We have determined that the following estimates are considered critical to the application of rules that relate to the respective businesses.

Accounting for Pensions and Other Postretirement Benefits (OPEB)

The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of these assets as of year-end.

The 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.

assets also include investments in unlisted real estate which is valued via third-party appraisals.

Plan assets also include investments in unlisted real estate which is valued via third-party appraisals.

We calculate pension and OPEB costs using various economic and demographic assumptions.

Assumptions and Approach Used :

Economic assumptions include the discount rate and the long-term rate of return on trust assets.

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.

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Expected Rate of Return on Plan Assets 8.10 % 7.20 % 7.69 %

The discount rate used to calculate pension and OPEB obligations is determined as of December 31 each year, our measurement date.

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.

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For one of PSEG’s qualified pension plans, the excess would be amortized over the average remaining expected life of inactive participants, which is approximately eighteen years.

For PSEG’s other qualified pension plan, the excess would be amortized over the average remaining service period of active employees, which is approximately fourteen years.

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.

The 8.10% expected rate of return on assets for 2023 has increased as compared to 2022, as increasing interest rates during 2022 were a significant contributor to the reduction in pension assets during the year and drove the increase in the expected rate of return.

Based upon these assumptions, we have estimated a net periodic pension expense in 2023 of approximately $21 million, or a net periodic pension credit of $16 million, net of amounts capitalized, and a net periodic OPEB credit in 2023 of approximately $43 million, or $44 million, net of amounts capitalized.

Our 2023 net periodic pension amounts include the impact of the accounting order approved by the BPU authorizing PSE&G to modify its pension accounting for ratemaking purposes.

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.

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The following chart reflects the sensitivities associated with a change in certain assumptions.

The effects of the assumption changes shown below solely reflect the impact of that specific assumption.

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.

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% Change Impact on Benefit Obligation as of December 31, 2023 Increase to Costs in 2024 Increase to Costs, net of Amounts Capitalized in 2024

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

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

For our wholesale energy business, many of the forward sale, forward purchase, option and other contracts are derivative instruments that hedge commodity price risk, but do not meet the requirements for, or are not designated as, either cash flow or fair value hedge accounting.

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For additional information regarding Derivative Financial Instruments, see Item 8.

Organization, Basis of Presentation and Significant Accounting Policies, Note 18.

Organization, Basis of Presentation and Summary of Significant Accounting Policies, Note 16.

Financial Risk Management Activities and Note 17.

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These tests require significant estimates and judgment when developing expected future cash flows.

Significant inputs may include, but are not limited to, forward power prices, expected PTC payments, ZEC payments for the New Jersey nuclear assets, fuel costs, other operating and capital expenditures, the cost of borrowing and asset sale prices and probabilities associated with any potential sale prior to the end of the estimated useful life or the early retirement of assets .

The assumptions used by management incorporate inherent uncertainties that are at times difficult to predict and could result in impairment charges or accelerated depreciation in future periods if actual results materially differ from the estimated assumptions utilized in our forecasts.

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

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result in impairment charges or accelerated depreciation in future periods if actual results materially differ from the estimated assumptions utilized in our forecasts.

In addition, long-lived assets are depreciated under the straight-line method based on estimated useful lives.

An asset’s operating useful life is generally based upon operational experience with similar asset types and other non-operational factors.

In the ordinary course, management, together with an asset’s co-owners in the case of certain of our jointly-owned assets, makes a number of decisions that impact the operation of our generation assets beyond the current year.

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.

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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.

Early Plant Retirements/Asset Dispositions and Impairments.

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.

Asset Dispositions and Impairments.

Asset Retirement Obligations (ARO)

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PSEG Power determines its AROs for its nuclear units by assigning probability weighting to various discounted cash flow outcomes for each of its nuclear units that incorporate the assumptions above as well as:

• financial feasibility and impacts on potential early shutdown,

• license renewals,

• SAFSTOR alternative, which assumes the nuclear facility can be safely stored and subsequently decommissioned in a period within 60 years after operations,

• DECON alternative, which assumes decommissioning activities begin after operations, and

• recovery from the federal government of assumed specific costs incurred for spent nuclear fuel.

• 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 :

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• A decrease of 1% in the discount rate would result in a $43 million increase in the Nuclear ARO.

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• An increase of 1% in the inflation rate would result in a $303 million increase in the Nuclear ARO.

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• 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.

• If PSEG Power were to increase its early shutdown probability to 100% and retire Salem and Hope Creek starting in 2032, which is significantly earlier than the end of their current license periods, the Nuclear ARO would increase by $102 million.

For additional information, see Item 8.

Early Plant Retirements/Asset Dispositions and Impairments.

Accounting for Regulated Businesses

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

What changed 10-K

Item 7. Management’s Discussion and Analysis