This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG) and Public Service Electric and Gas Company (PSE&G). Information contained herein relating to any individual company is filed by such company on its own behalf. PSEG’s business consists of two reportable segments, PSE&G and PSEG Power LLC (PSEG Power) & Other, primarily comprised of our principal direct wholly owned subsidiaries, which are: •PSE&G—which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU), the Federal Energy Regulatory Commission (FERC), and other federal and New Jersey state regulators. PSE&G also invests in regulated solar generation projects and regulated 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 consists of the operations of merchant nuclear generating assets and fuel supply functions engaged in competitive energy sales via its principal direct wholly owned subsidiaries. PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC) and other federal regulators and state regulators in the states in which they operate. The PSEG Power & Other reportable segment also includes amounts related to the parent company as well as PSEG’s other direct wholly owned subsidiaries, which are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) transmission and distribution (T&D) system under an Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily holds legacy lease investments and competitively bid, FERC regulated transmission; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost. Our business discussion in Item 1. Business of our 2025 Annual Report on 10-K (Form 10-K) provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Item 1A. Risk Factors of Form 10-K provides information about factors that could have a material adverse impact on our businesses. The following supplements that discussion and the discussion included in the Executive Overview of 2025 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2026 and changes to the key factors that we expect may drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements, Notes and the Form 10-K. EXECUTIVE OVERVIEW OF 2026 AND FUTURE OUTLOOK We are a public utility holding company that, acting through our wholly owned subsidiaries, is a predominantly regulated electric and gas utility and a nuclear generation business. Our business plan focuses on achieving growth by allocating capital primarily toward regulated investments in an effort to continue to improve the sustainability and predictability of our business and realizing the value of the consistent and reliable carbon-free generation from our nuclear units. We are focused on investing to meet growing energy demand, modernize our energy infrastructure, improve reliability and resilience, and increase EE to meet customer expectations and be well aligned with public policy objectives. With these investments and higher working capital recovery approved in the distribution rate case, our regulated rate base increased from approximately $34 billion as of December 31, 2024 to approximately $36 billion as of December 31, 2025. In addition, our nuclear facilities retain the downside price protection of a production tax credit (PTC) from 2024 through 2032. For the years 2026-2030, our regulated capital investment program is estimated to be in a range of $22.5 billion to $25.5 billion. We expect these capital investments to result in a compound annual growth rate in our regulated rate base in a range of 6.0% to 7.5% from year-end 2025 to year-end 2030. The regulated capital investments represent the majority of PSEG’s total capital investment program of $24 billion to $28 billion. The low end of the range includes an extension of our Gas System 56 Table of Contents Modernization Program (GSMP) and Clean Energy Future (CEF)-EE program, as these programs are expected to continue beyond their currently approved time frames. The upper end of our capital investment range includes potential incremental investments to address continued demand growth and other investments to meet infrastructure needs and support New Jersey's clean energy goals. PSE&G At PSE&G, our focus is on investing capital in T&D infrastructure and clean energy programs to meet growing demand, enhance the reliability and resiliency of our T&D system, meet customer expectations and support public policy objectives. In 2024, the BPU approved our CEF-EE II filing authorizing approximately $2.9 billion for energy efficiency projects committed between January 1, 2025 through June 30, 2027, to be completed over an expected six-year period. The Order approved a program investment budget of approximately $1.9 billion, net of administrative expenses, and approximately $1 billion to continue our customer on-bill repayment program. In November 2025, the BPU issued an Order approving PSE&G’s GSMP III program, authorizing $1.05 billion of capital investment to replace 525 miles of high pressure cast iron gas mains and unprotected steel mains, with cost recovery through three periodic rate adjustments as portions of the investment are put into service. In that Order, the BPU also authorized $360 million of investment to replace an additional 75 miles of gas main, with cost recovery to be requested in a future base rate case. Investment under the GSMP III program began in 2026 and will continue through December 2028, plus trailing services replacement and paving costs into 2029. PSE&G currently anticipates filing by year end 2026 to update base rates. PSEG Power At PSEG Power, we seek to produce low-cost electricity by efficiently operating our nuclear generation assets, mitigate earnings volatility through hedging and the PTC mechanism, and support public policies that preserve these existing carbon-free base load nuclear generating plants. During the first six months of 2026, our nuclear units generated approximately 15.8 terawatt hours and operated at a capacity factor of 93.7%. Effective April 2025, PSEG Power revised the estimated useful lives for the Salem 1, Salem 2 and Hope Creek nuclear plants due to our expectation that a 20-year license extension will be approved for these facilities. In 2025, we also completed work to extend the refueling cycle at our Hope Creek facility from 18 months to 24 months. In addition, we are planning power uprates at Salem Units 1 and 2 that will increase generation capacity and reliability and support long-term operation of these units, including through a potential subsequent license renewal. Our hedging strategy continues to incorporate an estimated range of risk reduction impacts from the PTCs on our nuclear generation portfolio while retaining the ability to benefit when market pricing exceeds the level at which we would receive PTCs. As of June 30, 2026, we expect that our current portfolio position for 2026 will result in the realized value of our nuclear generation output being above the level at which we would receive PTCs. Our strategy will continue to evolve taking into account energy market conditions, PTC guidance uncertainty, and potential incremental changes upon receiving U.S. Treasury guidance. In addition, we continue to explore opportunities for the potential sale of power, capacity and/or emission credits from our nuclear facilities pursuant to long-term agreements. Climate Strategy and Sustainability Efforts We remain guided by our vision to power a future where people use energy more efficiently, and it’s safer and delivered more reliably than ever. Our investments remain focused on infrastructure modernization, energy efficiency, and supporting growing customer demand, as well as New Jersey's long-term energy goals. PSE&G has undertaken a number of initiatives that support the reduction of GHG emissions, including our implementation of New Jersey's EE and related programs that are intended to support New Jersey’s Energy Master Plan (EMP) and 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. 57 Table of Contents We 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. 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 GSMP is designed to improve safety and reliability and significantly reduce natural gas leaks in our distribution system, which would reduce the release of methane, a potent GHG, into the air. From 2018 through 2025 we reduced reported methane emissions by over 34% system wide. We also continue to focus on working to preserve the economic viability of our nuclear units, which provide over 80% 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 and related generator interconnection policies at PJM Interconnection, L.L.C. (PJM) that recognize the value of our nuclear fleet’s carbon-free generation and its contribution to grid reliability and resource adequacy, and potential long-term contracts that recognize the value of its consistent and reliable carbon-free energy. Competitively Bid, FERC Regulated Transmission Projects PSEG continues to evaluate additional investment opportunities in regulated transmission. In December 2023, PJM awarded us an approximately $424 million project to address increasing load and reliability issues in Maryland and northern Virginia as part of its 2022 Window 3 competitive solicitation. PJM has directed that the project be placed in service in 2027. However, based on the procedural timeline established by order of the Maryland Public Service Commission, we do not currently believe a 2027 in-service date for the project is reasonably achievable. We are continuing to take all available steps to obtain approvals for timely project execution. We cannot predict the outcome. PSEG will continue to evaluate opportunities to participate in transmission solicitation processes and may decide to submit bids for these opportunities, some of which could be material investments. PSEG LI PSEG LI has been operating LIPA’s electric T&D system in Long Island, New York since 2014 under a 12-year OSA with LIPA that expired on December 31, 2025. In 2025, a five year extension of the contract was approved. A competitor in the contract bidding process filed litigation against LIPA challenging the process. LIPA filed a motion to dismiss the competitor’s claim as untimely, which was granted by the New York Supreme Court in December 2025. The competitor filed an appeal in January 2026. Financial Results The results for PSEG, PSE&G and PSEG Power & Other for the three and six months ended June 30, 2026 and 2025 are presented as follows: Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 Millions, except per share data PSE&G $ 342 $ 332 $ 919 $ 878 PSEG Power & Other (A) (8 ) 253 156 296 PSEG Net Income $ 334 $ 585 $ 1,075 $ 1,174 PSEG Net Income Per Share (Diluted) $ 0.67 $ 1.17 $ 2.15 $ 2.35 (A)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. 58 Table of Contents The variances in our Net Income attributable to changes related to the NDT Fund and MTM are shown in the following table: Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 Millions, after tax NDT Fund and Related Activity (A) (B) $ 94 $ 65 $ 87 $ 71 Non-Trading MTM Gains (Losses) (C) $ (185 ) $ 136 $ (215 ) $ 1 (A)NDT Fund activity includes gains and losses on NDT securities which are recorded in Net Gains (Losses) on Trust Investments. See Item 1. Note 6. Trust Investments for additional information. NDT Fund activity 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 and Maintenance (O&M) Expense and the depreciation related to the ARO asset recorded in Depreciation and Amortization (D&A) Expense. (B)Net of tax benefit (expense) of $(59) million and $(43) million for the three months and $(60) million and $(49) million for the six months ended June 30, 2026 and 2025, respectively. (C)Net of tax benefit (expense) of $73 million and $(54) million for the three months and $84 million and $(1) million for the six months ended June 30, 2026 and 2025, respectively. The decreases in Net Income for the three and six months ended June 30, 2026 versus the comparable periods in 2025 was driven primarily by MTM losses in 2026 compared to gains in the prior year, as shown in the table above. These impacts were partially offset by increases from continued investment in T&D clause programs at PSE&G and higher capacity revenues and gas sales at PSEG Power. Regulatory, Legislative and Other Developments We closely monitor and engage with stakeholders on significant regulatory and legislative developments. Transmission Rate Proceedings and Return on Equity (ROE) Under current FERC rules, PSE&G continues to earn a 50 basis point adder to its base ROE for its voluntary membership in PJM as a transmission owner. In June 2026, legislation was passed in New Jersey that requires transmission owners that own and operate transmission facilities in New Jersey to be members of a Regional Transmission Organization (RTO) approved by FERC. The legislation will require that, effective January 1, 2027, transmission owners be members in an RTO. While we are continuing to assess the potential impact of this legislation, this mandatory RTO membership requirement could result in the future loss of PSE&G’s 50 basis-point ROE adder for participating in an RTO. This would prospectively reduce PSE&G’s annual Net Income and annual cash inflows by approximately $40 million. We cannot predict the outcome of this matter. New Jersey Clean Energy Matters In February 2023, the previous 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. In November 2025 the BPU released the updated Energy Master Plan (EMP) that presents potential pathways toward meeting New Jersey’s clean energy and decarbonization goals. Given the new administration took office in January 2026, it is not clear how the EMP might influence New Jersey’s energy policy and we cannot predict the impact on our business that might result. In July 2026, the BPU issued the final framework for the extension of its second triennium of energy efficiency programs. The final framework includes elements that adjust the overall budget for the extension, requiring budgets to be based on gross, not net, energy savings, adjusts return on equity that the utilities can earn for achieving performance goals, and replaces the existing method to collect foregone revenue. The framework also allows for utilities to file for alternative proposals, including but not limited to ROE and savings targets. Petitions by utilities for the extension are due on September 30, 2026. It is 59 Table of Contents anticipated that the BPU will issue the framework for the third program cycle of energy efficiency programs later in 2026. We cannot predict the outcome of this matter. Environmental Regulation We are subject to liability under environmental laws for the costs and penalties of remediating contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. In particular, the historic operations of PSEG companies and the operations of numerous other companies within the Newark Bay Complex are alleged by federal and state agencies to have discharged substantial contamination into the Newark Bay Complex in violation of various statutes. The Newark Bay Complex is a tidal estuary in northern New Jersey that includes Newark Bay, as well as portions of the Passaic River, the Hackensack River and other surrounding waterways. The U.S. Environmental Protection Agency (EPA) has designated various portions of the Newark Bay Complex as federal Superfund sites that must be investigated and remediated under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. In addition, PSEG Power has retained ownership of certain liabilities excluded from the sale of its fossil generation portfolio, primarily related to obligations under New Jersey and Connecticut state laws to investigate and remediate the sites. We are also currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, and the costs and penalties of any such remediation efforts could be material. For further information regarding the matters described above, as well as other matters that may impact our financial condition and results of operations, see Item 1. Note 8. Commitments and Contingent Liabilities. Nuclear In May 2025, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants zero emission certificate (ZEC) sales concluded. Pursuant to a process established by the BPU, ZECs were purchased from these nuclear plants by the electric distribution companies (EDCs) in New Jersey. As previously noted, the Federal government established a PTC for electricity generated using existing nuclear energy, which began January 2024 and continues through 2032 and impacted PSEG Power's decision not to apply for the ZEC three-year eligibility period which began June 2025. The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts. The PTC rate and the gross receipts threshold are subject to annual inflation adjustments. ZEC revenue recorded has been reduced by the estimated PTCs generated from these nuclear plants. The PTC amounts recorded to date are subject to change based on several factors, including but not limited to, adjustments to estimated market prices and generation and the issuance of authoritative guidance by the U.S. Treasury/the Internal Revenue Service, including clarification of the definition of “gross receipts” used to determine the phase out. Any adjustments to amounts previously recorded could be material. We continue to analyze the impact of the PTC, including 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. For additional information, see Item 1. Note 2. Revenues. Demand, Supply and Energy Costs An increasing demand for power and a lack of sufficient new generation resources in PJM and in New Jersey, has raised resource adequacy concerns and resulted in higher electricity costs for our customers in 2025. Prices from the July 2024 PJM annual capacity market auction, which were approximately 10 times higher than prices from the 2023 auction and which impacted customer bills, provoked concern from state regulators and legislators and have created regulatory uncertainty. Prices from the July 2025 capacity market auction were higher than those produced by the July 2024 auction and PJM indicated that the prices would have been even higher if not for the existence of a FERC-approved ceiling, which remained in effect for the December 2025 auction. In February 2026, PJM filed with FERC a proposal to extend the price cap for another two delivery years (2028/29 and 2029/30) and, in April 2026, FERC issued an order accepting PJM’s proposal. In January 2026, the White House’s National Energy Dominance Council signed an agreement with the governors of all 13 states in the PJM region that memorializes a “statement of principles” intended to prompt PJM to make major changes to its capacity market, including running a “reliability backstop auction” to procure new generation capacity to provide up to 15-year “price certainty”. PJM has committed to run this backstop auction and is targeting a September 2026 date following FERC approval of all needed rule changes. In July 2026, PJM submitted proposed tariff revisions with FERC to establish a one-time capacity procurement 60 Table of Contents mechanism to address resource adequacy challenges in the PJM region. Under the “Reliability Backstop Procurement” framework, PJM intends to secure 15-year commitments from new eligible generation resources to match the reliability shortfall observed in the base residual auction for the 2028/2029 delivery year. To commence the procurement window on September 30, 2026, PJM asked FERC to approve the filing with an effective date of September 29, 2026. We cannot predict the outcome of this proceeding. In addition, in 2025, FERC both issued an order that will encourage optionality for “large load” customers by facilitating co-location with generation, and initiated a rulemaking proceeding to establish definitive rules for future large customer connections intended to ensure reliability and address resource adequacy concerns. FERC has recently issued an order in the rulemaking proceeding directing all of the RTOs/ISOs, including PJM, to establish rules for future large load connections, including how the RTOs/ISOs will study these requests and how transmission costs will be paid. We cannot predict the outcome of these proceedings and their impact on our business. Federal and State Executive Orders and State Legislative and Other Activity There have been a number of federal executive orders during the past year, including but not limited to orders requiring retiring generating units to stay on-line beyond their retirement date to mitigate system reliability risk and orders imposing widespread and substantial tariffs on imports. There has been increased New Jersey state legislative activity and executive orders regarding energy affordability, resource adequacy and regulatory topics. In 2025, per direction to EDCs from the BPU, PSE&G took steps to mitigate the impacts of increasing electricity costs resulting from capacity market price increases, including the implementation of extended deferred payment arrangements. Further, the New Jersey legislature enacted a law prohibiting disconnection for non-payment during the period June 15 through August 31, beginning in 2026, and for such period annually thereafter, for certain qualified electric and gas customers. Both of these actions increased our bad debt expense in 2025, with potential additional increases in the future. In January 2026, the New Jersey Governor issued executive orders directing the BPU within its legal authority to mitigate electric rate increases through state funding during 2026 as well as other actions, and to advance resource adequacy solutions, in New Jersey. Executive Order No. 1 directed the BPU to complete and issue a study regarding modernization of the traditional electric distribution utility business model and the BPU retained a consultant to prepare the study. In July 2026, the BPU issued its consultant’s study, which discusses potential options for electric distribution utility ratemaking, including a review of other jurisdictions. The consultant will now undertake a quantitative analysis of the modernization options presented in its report. We cannot predict the outcome of this initiative or its potential impact on our business. It is not clear how these orders might influence New Jersey’s energy policy. We cannot predict the impacts on our supply chain, business, cash flow, results of operations and financial condition from the federal and state legislative activity and executive orders, certain of which may require regulatory actions to implement. Interest Rate Matters PSEG’s long-term financing plan is designed to replace maturities and support funding its capital program. Given our financing needs, the prevailing interest rate environment will be a key factor in determining interest expense on variable-rate debt and long-term rates on future financing plans. In order to increase the predictability of interest expense, we may use interest rate hedges to help limit our exposure to fluctuating interest rates and fix a portion of our interest rate exposure for anticipated long-term financing plans at PSEG and PSEG Power. PSE&G’s interest rate risk is moderated due to annual transmission rate filings and distribution recoveries through periodic rate filings. Tax Legislation The enactment, amendment or repeal of federal or state tax legislation and/or the clarification of previously enacted tax laws could have a material impact on our effective tax rate and cash tax position. In August 2022, the IRA enacted a 15% corporate alternative minimum tax (CAMT), which is based on adjusted financial statement income, and established a PTC for existing qualified nuclear facilities. However, aspects of the IRA provisions for CAMT and PTCs remain unclear; therefore, the issuance of future authoritative guidance could materially impact PSEG’s and PSE&G’s results of operations, financial condition and cash flows. 61 Table of Contents Future Outlook Our future success will be influenced by 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 seek to: •obtain approval of and execute on our utility capital investment program to meet increasing customer demand, 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; •obtain 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 policies related to energy; •advocate for appropriate regulatory guidance on the PTC to ensure long-term support for New Jersey’s largest carbon-free generation resource, and adapt our hedging program accordingly, and realize the value of our consistent and reliable, carbon-free nuclear output; •engage constructively with our multiple stakeholders, including regulators, government officials, customers, employees, investors, suppliers and the communities in which we do business or are seeking to do business; and •deliver on our human capital management strategy to attract, develop and retain a high-performing diverse workforce. In addition to the risks described elsewhere in this Form 10-Q for 2026 and beyond, the key issues and challenges we expect our business to confront include: •regulatory and political uncertainty with regard to federal and state energy and related policies, including transmission planning and rates policy, the role of distribution utilities and decarbonization impacts, design of energy and capacity markets, resource adequacy and affordability, tax regulation 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 funding requirements and interest rates on our future financing plans; •continuing to manage costs and maintain affordable customer rates, which could impact customer collections, investment programs and have other impacts; •the increasing frequency, sophistication and magnitude of cybersecurity attacks against us and our respective vendors and business partners who may have our sensitive information and/or access to our environment, and the increasing frequency and magnitude of physical attacks on electric and gas infrastructure; •future changes in federal and state tax laws or any other associated tax guidance; and •the impact of changes in energy demand, natural gas and electricity prices and PJM’s challenge to ensure resource adequacy to meet demand growth amidst efforts to decarbonize several sectors of the economy. 62 Table of Contents We continually assess a broad range of strategic options to maximize long-term shareholder value and address the interests of our multiple stakeholders. We consider a wide variety of factors when determining how and when to efficiently deploy capital, including the performance and prospects of our businesses; returns and the sustainability and predictability of future earnings streams; the views of investors, regulators, public policy initiatives, rating agencies, customers and employees; our existing indebtedness and restrictions it imposes; and tax considerations, among other things. Strategic options available to us include: •investments in PSE&G, including T&D facilities to enhance reliability, resiliency and modernize the system to meet the growing needs and increasingly higher expectations of customers, and clean energy investments, including our EE programs; •continued operation of our nuclear generation facilities that are expected to be supported by the PTC through 2032, nuclear capacity uprates, such as our planned Salem power uprate supported by a clean energy PTC, as well as obtaining license extensions and energy, capacity and/or emission credit sales with potential customers seeking consistent and reliable carbon-free power; •opportunities that may arise from our enabling of or involvement in new nuclear projects; •investments in generation and battery storage through BPU, RTO or other similar solicitations or bilateral agreements; •investments in competitive, regulated transmission through PJM and other RTO/ISO processes; and •acquisitions, dispositions, development and other transactions involving our common stock, assets or businesses that could provide value to customers and shareholders. There can be no assurance, however, that we will successfully develop and execute any of the strategic options noted above, or any additional options we may consider in the future. The execution of any such strategic plan may not have the expected benefits or may have unexpected adverse consequences. 63 Table of Contents RESULTS OF OPERATIONS PSEG Our results of operations are comprised of the results of operations of our reportable segments, PSE&G and PSEG Power & Other, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 1. Note 17. Related-Party Transactions. Three Months Ended Increase/ Six Months Ended Increase/ June 30, (Decrease) June 30, (Decrease) 2026 2025 2026 vs. 2025 2026 2025 2026 vs. 2025 Millions Millions % Millions Millions % Operating Revenues $ 2,554 $ 2,805 $ (251 ) (9 ) $ 6,402 $ 6,027 $ 375 6 Energy Costs 866 826 40 5 2,373 2,012 361 18 Operation and Maintenance (A) 906 854 52 6 1,843 1,773 70 4 Depreciation and Amortization 321 308 13 4 650 628 22 4 Net Gains (Losses) on Trust Investments 144 95 49 52 127 103 24 23 Net Other Income (Deductions) 41 46 (5 ) (11 ) 84 83 1 1 Net Non-Operating Pension and OPEB Credits (Costs) 21 16 5 31 40 32 8 25 Interest Expense 269 248 21 8 541 489 52 11 Income Tax Expense 64 141 (77 ) (55 ) 171 169 2 1 (A)Includes amortization of Energy Efficiency (EE) programs regulatory expenditures of $53 million, $41 million, $103 million and $79 million for the three months and six months ended June 30, 2026 and 2025, respectively. The following discussions for PSE&G and PSEG Power & Other provide a detailed explanation of their respective variances. PSE&G Three Months Ended Increase/ Six Months Ended Increase/ June 30, (Decrease) June 30, (Decrease) 2026 2025 2026 vs. 2025 2026 2025 2026 vs. 2025 Millions Millions % Millions Millions % Operating Revenues $ 2,137 $ 2,031 $ 106 5 $ 5,222 $ 4,695 $ 527 11 Energy Costs 776 760 16 2 2,134 1,854 280 15 Operation and Maintenance (A) 545 504 41 8 1,182 1,080 102 9 Depreciation and Amortization 286 275 11 4 581 555 26 5 Net Other Income (Deductions) 17 16 1 6 36 32 4 13 Net Non-Operating Pension and OPEB Credits (Costs) 20 18 2 11 37 35 2 6 Interest Expense 174 161 13 8 349 318 31 10 Income Tax Expense 51 33 18 55 130 77 53 69 (A)Includes amortization of EE programs regulatory expenditures of $53 million, $41 million, $103 million and $79 million for the three months and six months ended June 30, 2026 and 2025, respectively. 64 Table of Contents Three Months Ended June 30, 2026 as Compared to Three Months Ended June 30, 2025 Operating Revenues increased $106 million due to changes in delivery, commodity, clause and other operating revenues. Delivery Revenues are primarily derived from revenues recovered on our regulated investments in rate base and costs through periodic filings of distribution rate cases, approved distribution investment recovery programs and the annual filing of transmission formula rates. Due to PSE&G’s electric and gas distribution CIP decoupling mechanism, there is minimal impact from sales volumes on most distribution delivery revenues. Also included in delivery revenues are revenue credits to customers to flowback tax benefits realized by PSE&G. These revenue credits are offset in Income Tax Expense. Delivery revenues increased $40 million due primarily to a $17 million increase in delivery volumes, $13 million from increased GPRC revenues and a $10 million increase in transmission revenues due primarily to higher rate base investments. Clause Revenues are revenues from various pass-through regulatory programs for which PSE&G earns no margin. These revenues are entirely offset by the amortization of related costs in O&M, D&A and Interest and Income Tax Expense, which were originally recognized as regulatory assets. Clause Revenues increased $50 million due primarily to a $35 million increase in TAC and GPRC deferrals and a $15 million increase in Societal Benefits Clause (SBC) collections. Commodity Revenues are revenues from customers choosing default electric (basic generation service or BGS) and gas supply (basic gas supply service or BGSS) from PSE&G. PSE&G procures the BGS and BGSS on behalf of these retail customers and earns no margin on this service as all costs are passed back to the BGS and BGSS customers. The changes in Commodity Revenues for both electric and gas are entirely offset by changes in Energy Costs. Commodity Revenues increased $64 million primarily due to higher electric BGS revenues of $66 million, primarily from higher prices, partially offset by lower gas BGSS revenues of $2 million, primarily from lower volume. Other Operating Revenues are primarily comprised of revenues derived from various GPRC programs including Transition Renewable Energy Certificates (TREC) revenues, Community Solar collections and the Successor Solar Incentive Program (SuSI). The revenues from these programs offset costs included in Energy Costs. In addition, other operating revenues include revenues from our Appliance Service Business (ASB) which offers various appliance protection and repair plans to customers. Other Operating revenues decreased $48 million due primarily to a decrease in ZECs as a result of the ZEC collection ending effective May 31, 2025. Operating Expenses Energy Costs increased $16 million. This is entirely offset by changes in Commodity Revenues and Other Operating Revenues. Operation and Maintenance increased $41 million due primarily to $28 million in higher clause and renewable expenditures and $13 million in higher other operating and Services expenses. Depreciation and Amortization increased $11 million due primarily to an increase in depreciation due to higher plant placed in service and increased amortization of Regulatory Assets. Interest Expense increased $13 million due primarily to incremental debt and the replacement of maturing debt at higher rates. Income Tax Expense increased $18 million due primarily to a decrease in the flowback of historic mixed service cost deductions as an effect of utility ratemaking and higher pre-tax income. Six Months Ended June 30, 2026 as Compared to Six Months Ended June 30, 2025 Operating Revenues increased $527 million due to changes in delivery, commodity, clause and other operating revenues. Delivery Revenues are primarily derived from revenues recovered on our regulated investments in rate base and costs through periodic filings of distribution rate cases, approved distribution investment recovery programs and the annual filing of transmission formula rates. Due to PSE&G’s electric and gas distribution CIP decoupling mechanism, there is minimal impact 65 Table of Contents from sales volumes on most distribution delivery revenues. Also included in delivery revenues are revenue credits to customers to flowback tax benefits realized by PSE&G. These revenue credits are offset in Income Tax Expense. Delivery revenues increased $130 million due primarily to a $67 million increase in delivery volumes, $42 million from increased GPRC revenues and a $28 million increase in transmission revenues due primarily to higher rate base investments. These delivery revenue increases were offset by a $7 million decrease due to an increase in credits flowed back to customers as part of our TAC mechanism. Clause Revenues are revenues from various pass-through regulatory programs for which PSE&G earns no margin. These revenues are entirely offset by the amortization of related costs in O&M, D&A and Interest and Income Tax Expense, which were originally recognized as regulatory assets. Clause Revenues increased $114 million due primarily to an $82 million increase in TAC and GPRC deferrals and a $36 million increase in SBC collections. Commodity Revenues are revenues from customers choosing default electric (basic generation service or BGS) and gas supply (basic gas supply service or BGSS) from PSE&G. PSE&G procures the BGS and BGSS on behalf of these retail customers and earns no margin on this service as all costs are passed back to the BGS and BGSS customers. The changes in Commodity Revenues for both electric and gas are entirely offset by changes in Energy Costs. Commodity Revenues increased $371 million primarily due to higher electric BGS revenues of $267 million and higher gas BGSS revenues of $104 million, primarily from higher prices. Other Operating Revenues are primarily comprised of revenues derived from various GPRC programs including TREC revenues, Community Solar collections and SuSI. The revenues from these programs offset costs included in Energy Costs. In addition, other operating revenues include revenues from our ASB which offers various appliance protection and repair plans to customers. Other Operating revenues decreased $88 million due primarily to a decrease in ZECs as a result of the ZEC collection ending effective May 31, 2025. Operating Expenses Energy Costs increased $280 million. This is entirely offset by changes in Commodity Revenues and Other Operating Revenues. Operation and Maintenance increased $102 million due primarily to $80 million in higher clause and renewable expenditures, $4 million in higher distribution and transmission operational expenditures and $18 million in higher other operating and Services expenses. Depreciation and Amortization increased $26 million due primarily to an increase in depreciation due to higher plant placed in service and increased amortization of software and Regulatory Assets. Interest Expense increased $31 million due primarily to incremental debt and the replacement of maturing debt at higher rates. Income Tax Expense increased $53 million due primarily to a decrease in the flowback of historic mixed service cost deductions as an effect of utility ratemaking and higher pre-tax income. 66 Table of Contents PSEG Power & Other Three Months Ended Increase/ Six Months Ended Increase/ June 30, (Decrease) June 30, (Decrease) 2026 2025 2026 vs. 2025 2026 2025 2026 vs. 2025 Millions Millions % Millions Millions % Operating Revenues $ 534 $ 920 $ (386 ) (42 ) $ 1,950 $ 2,012 $ (62 ) (3 ) Energy Costs 207 212 (5 ) (2 ) 1,009 838 171 20 Operation and Maintenance 361 350 11 3 661 693 (32 ) (5 ) Depreciation and Amortization 35 33 2 6 69 73 (4 ) (5 ) Net Gains (Losses) on Trust Investments 144 95 49 52 127 103 24 23 Net Other Income (Deductions) 24 31 (7 ) (23 ) 48 53 (5 ) (9 ) Net Non-Operating Pension and OPEB Credits (Costs) 1 (2 ) 3 N/A 3 (3 ) 6 N/A Interest Expense 95 88 7 8 192 173 19 11 Income Tax Expense 13 108 (95 ) (88 ) 41 92 (51 ) (55 ) Three Months Ended June 30, 2026 as Compared to Three Months Ended June 30, 2025 Operating Revenues decreased $386 million due primarily to changes in generation and gas supply and other operating revenues. Generation Revenues decreased $387 million due primarily to •a net decrease of $450 million due to MTM losses in 2026 as compared to MTM gains in 2025. Of this amount, there was a $370 million decrease due to changes in forward prices in 2026 as compared to 2025, coupled with a $80 million decrease due to positions reclassified to realized upon settlement, and •a net decrease of $25 million primarily due to the conclusion of ZEC sales in May 2025, •partially offset by a net increase of $51 million in capacity revenue due primarily to higher capacity prices, and •a net increase of $37 million due primarily to higher average realized prices and higher volumes sold in 2026. Gas Supply Revenues decreased $3 million due primarily to •a net decrease of $12 million in sales under the BGSS contract due primarily to $6 million from lower sales volume and $6 million from lower sales prices, •partly offset by a net increase of $9 million related to sales to third parties due primarily to $14 million from higher sales volumes, partially offset by $5 million from lower sales prices. Operating Expenses Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet PSEG Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $5 million due to Gas costs decreased $11 million due primarily to •a net decrease of $17 million related to sales under the BGSS contract, of which $11 million was due to lower average cost of gas coupled with interstate gas pipeline refunds due to a settlement on pipeline rates from prior periods, and $6 million was due to lower send out volumes, and •a net increase of $7 million related to sales to third parties due primarily to $11 million from higher sales volumes, partially offset by $4 million from lower sales prices. 67 Table of Contents Generation costs increased $6 million due primarily to increased nuclear fuel costs. Operation and Maintenance increased $11 million due primarily to a net increase in various operational expenses. Net Gains (Losses) on Trust Investments increased $49 million due primarily to NDT investments with a $157 million increase in net realized gains in 2026, partially offset by $30 million in net unrealized losses in 2026 as compared to $79 million in net unrealized gains in 2025 on equity securities. Other Income (Deductions) decreased $7 million due primarily to interest income. Interest Expense increased $7 million due primarily to incremental debt and the replacement of maturing long-term debt at higher rates. Income Tax Expense decreased $95 million due primarily to lower pre-tax income. Six Months Ended June 30, 2026 as Compared to Six Months Ended June 30, 2025 Operating Revenues decreased $62 million due primarily to changes in generation and gas supply and other operating revenues. Generation Revenues decreased $241 million due primarily to •a net decrease of $300 million due to MTM losses in 2026 as compared to MTM gains in 2025. Of this amount, there was a $276 million decrease due to changes in forward prices in 2026 as compared to 2025, coupled with a $24 million decrease due to positions reclassified to realized upon settlement, and •a net decrease of $81 million primarily due to the conclusion of ZEC sales in May 2025, •partially offset by a net increase of $115 million in capacity revenue due primarily to higher capacity prices, and •a net increase of $24 million due primarily to higher average realized prices, partially offset by lower volumes sold in 2026. Gas Supply Revenues increased $180 million due primarily to •a net increase of $160 million in sales under the BGSS contract due primarily to $136 million from higher sales prices and $24 million from higher sales volumes, and •a net increase of $24 million related to sales to third parties due primarily to $16 million from higher sales prices, and $8 million from higher sales volumes. 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 $166 million due primarily to •a net increase of $155 million related to sales under the BGSS contract, of which $131 million was due to higher average cost of gas, which includes a $9 million reduction in cost from interstate gas pipeline refunds due to a settlement on pipeline rates from prior periods, and $24 million was due to higher send out volumes, and •a net increase of $14 million related to sales to third parties due primarily to higher sales volumes. Generation costs increased $5 million due primarily to increased nuclear fuel costs. Operation and Maintenance decreased $32 million due primarily to an adjustment to indirect taxes in 2026 and a net decrease in nuclear and various operational expenses. Net Gains (Losses) on Trust Investments increased $24 million due primarily to NDT investments with a $170 million increase in net realized gains in 2026, partially offset by $78 million in net unrealized losses in 2026 as compared to $69 million in net unrealized gains in 2025 on equity securities. 68 Table of Contents Other Income (Deductions) decreased $5 million due primarily to interest income. Net Non-Operating Pension and OPEB Credits (Costs) increased $6 million due primarily to a decrease in interest cost and an increase in the long-term expected return on assets. Interest Expense increased $19 million due primarily to incremental debt and the replacement of maturing long-term debt at higher rates. Income Tax Expense decreased $51 million due primarily to lower pre-tax income. LIQUIDITY AND CAPITAL RESOURCES The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our two direct major operating subsidiaries. Operating Cash Flows We continue to expect our operating cash flows combined with cash on hand and financing activities to be sufficient to fund planned capital expenditures and shareholder dividends. For the six months ended June 30, 2026, our operating cash flow increased $294 million, as compared to the same period in 2025. The net increase was primarily due to higher tax refunds and a net change at PSE&G, as discussed below, partially offset by $179 million of higher net cash collateral postings in 2026 as compared to the same period in 2025 at PSEG Power. PSE&G PSE&G’s operating cash flow increased $212 million from $954 million to $1,166 million for the six months ended June 30, 2026, as compared to the same period in 2025. The increase was primarily due to a decrease in net regulatory deferrals, a decrease in accounts receivable and unbilled revenues, and higher earnings, partially offset by taxes paid in 2026 as compared to tax refunds received in 2025 and the timing of vendor payments. Short-Term Liquidity PSEG meets its short-term liquidity requirements, as well as those of PSEG Power, primarily through the issuance of commercial paper and, from time to time, short-term loans. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facility. Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. In March 2026, PSEG, PSEG Power and PSE&G executed a two-year extension to their existing $3.75 billion revolving credit facilities, extending the maturity through March 2031, and removed the sustainability linked pricing mechanism associated with the PSEG sublimit of the Master Credit Facility. The $75 million PSEG Power letter of credit facility was also extended through March 2028. In February 2026, PSEG entered into a 364-day variable rate term loan agreement for $500 million. In June 2026, PSEG prepaid the $500 million term loan. In December 2025, PSEG Power amended its existing $400 million 364-day variable rate term loan, which increased the balance to $500 million and extended the maturity to December 2026. 69 Table of Contents Our total committed credit facilities and available liquidity as of June 30, 2026 were as follows: As of June 30, 2026 Company/Facility Total Facility Usage Available Liquidity Millions PSEG $ 1,500 $ 470 $ 1,030 PSE&G 1,000 27 973 PSEG Power 1,325 118 1,207 Total $ 3,825 $ 615 $ 3,210 PSEG Power has uncommitted credit facilities totaling $425 million, which can be utilized for letters of credit. As of June 30, 2026, PSEG Power had $305 million in letters of credit outstanding under these uncommitted credit facilities. PSE&G has an uncommitted credit facility totaling $30 million, which can be utilized for letters of credit. As of June 30, 2026, PSE&G’s letters of credit outstanding were immaterial under this uncommitted credit facility. We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements, including to satisfy any additional collateral requirements. As of June 30, 2026, PSEG’s liquidity position, including credit facilities and access to external financing, was expected to be sufficient to meet its projected stressed requirements over a 12-month planning horizon. PSEG analyzes its liquidity requirements using stress scenarios that consider different events, including changes in commodity prices and the potential impact of PSEG Power losing its investment grade credit rating from S&P or Moody’s, which would represent a two-level downgrade from its current Moody’s and S&P ratings. In the event of a deterioration of PSEG Power’s credit rating, certain of PSEG Power’s agreements allow the counterparty to demand further performance assurance. The potential additional collateral that we would be required to post under these agreements if PSEG Power were to lose its investment grade credit rating was approximately $705 million and $703 million as of June 30, 2026 and December 31, 2025, respectively. For additional information, see Item 1. Note 9. Debt and Credit Facilities. Long-Term Debt Financing During the next twelve months, •PSE&G has $425 million of 2.25% Secured Medium-Term Notes Series L, due September 2026, and •PSE&G has $425 million of 3.00% Secured Medium-Term Notes Series L, due May 2027. PSEG, PSEG Power, Energy Holdings, PSEG LI and Services participate in a corporate money pool, an aggregation of daily cash balances designed to efficiently manage their respective short-term liquidity needs, which are accounted for as intercompany loans. Servco does not participate in the corporate money pool. Servco’s short-term liquidity needs are met through an account funded and owned by LIPA. For additional information see Item 1. Note 9. Debt and Credit Facilities. Common Stock Dividends On July 20, 2026, our Board of Directors approved a $0.67 per share common stock dividend for the third quarter of 2026. This reflects an indicative annual dividend rate of $2.68 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. For additional information related to cash dividends on our common stock, see Item 1. Note 15. Earnings Per Share (EPS) and Dividends. 70 Table of Contents Credit Ratings If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Credit ratings shown are for securities that we typically issue. Outlooks are shown for the credit ratings at each entity and can be Stable, Negative, or Positive. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security. Moody’s (A) S&P (B) PSEG Outlook Stable Stable Senior Notes Baa2 BBB Commercial Paper P2 A2 PSE&G Outlook Stable Stable Mortgage Bonds A1 A Commercial Paper P2 A2 PSEG Power Outlook Stable Stable Senior Notes Baa2 BBB (A)Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities. (B)S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities. CAPITAL REQUIREMENTS We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. There were no material changes to our projected capital expenditures as compared to amounts disclosed in our 2025 Form 10-K. PSE&G During the six months ended June 30, 2026, PSE&G made capital expenditures of $1,252 million, primarily for T&D system reliability. In addition, PSE&G had $86 million associated with the CEF-EE II on-bill repayment program included in investing cash flows, as well as cost of removal, net of salvage, of $74 million associated with capital replacements, and expenditures for EE programs of $263 million, which are included in operating cash flows. PSEG Power & Other During the six months ended June 30, 2026, PSEG Power & Other made capital expenditures of $134 million, excluding $73 million for nuclear fuel, primarily related to various nuclear projects at PSEG Power and various information technology projects at Services. 71 Table of Contents