Annual report
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UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWASHINGTON, D.C. 20549 FORM10-K ☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934 For the fiscal year endedDecember 31, 2025 or ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ____________ to ____________ Registrant; State of Incorporation; Address; Telephone Number; Commission File Number; and I.R.S. Employer Identification No. EVERSOURCE ENERGY (a Massachusetts voluntary association) 300 Cadwell Drive, Springfield, Massachusetts 01104 Telephone: (800) 286-5000 Commission File Number: 001-05324 I.R.S. Employer Identification No. 04-2147929 THE CONNECTICUT LIGHT AND POWER COMPANY (a Connecticut corporation) 107 Selden Street, Berlin, Connecticut 06037-1616 Telephone: (800) 286-5000 Commission File Number: 000-00404 I.R.S. Employer Identification No. 06-0303850 NSTAR ELECTRIC COMPANY (a Massachusetts corporation) 800 Boylston Street, Boston, Massachusetts 02199 Telephone: (800) 286-5000 Commission File Number: 001-02301 I.R.S. Employer Identification No. 04-1278810 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE (a New Hampshire corporation) Energy Park 780 North Commercial Street, Manchester, New Hampshire 03101-1134 Telephone: (800) 286-5000 Commission File Number: 001-06392 I.R.S. Employer Identification No. 02-0181050 Securities registered pursuant to Section 12(b) of the Act: Title of each class Trading Symbol(s) Name of each exchange on which registered Common Shares, $5.00 par value per share ES New York Stock Exchange
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Indicate by check mark if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act. Yes No ☒ ☐ Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No ☐ ☒ Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes No ☒ ☐ Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files). Yes No ☒ ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Eversource Energy Large acceleratedfiler ☒ Acceleratedfiler ☐ Non-acceleratedfiler ☐ Smaller reportingcompany ☐ Emerging growthcompany ☐ The Connecticut Light andPower Company Large acceleratedfiler ☐ Acceleratedfiler ☐ Non-acceleratedfiler ☒ Smaller reportingcompany ☐ Emerging growthcompany ☐ NSTAR Electric CompanyLarge acceleratedfiler ☐ Acceleratedfiler ☐ Non-acceleratedfiler ☒ Smaller reportingcompany ☐ Emerging growthcompany ☐ Public Service Company ofNew Hampshire Large acceleratedfiler ☐ Acceleratedfiler ☐ Non-acceleratedfiler ☒ Smaller reportingcompany ☐ Emerging growthcompany ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨ Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act): Yes No Eversource Energy ☐ ☒ The Connecticut Light and Power Company ☐ ☒ NSTAR Electric Company ☐ ☒ Public Service Company of New Hampshire ☐ ☒ The aggregate market value of Eversource Energy's Common Shares, $5.00 par value, held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of Eversource Energy's most recently completed second fiscal quarter (June 30, 2025) was $23,590,442,517 based on a closing market price of $63.62 per share for the 370,802,303 common shares outstanding held by non-affiliates on June 30, 2025. Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date:
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Company - Class of Stock Outstanding as of January 31, 2026 Eversource EnergyCommon Shares, $5.00 par value 375,496,611 shares The Connecticut Light and Power CompanyCommon Stock, $10.00 par value 6,035,205 shares NSTAR Electric CompanyCommon Stock, $1.00 par value 200 shares Public Service Company of New HampshireCommon Stock, $1.00 par value 301 shares Eversource Energy holds all of the 6,035,205 shares, 200 shares, and 301 shares of the outstanding common stock of The Connecticut Light and Power Company, NSTAR Electric Company, and Public Service Company of New Hampshire, respectively. The Connecticut Light and Power Company, NSTAR Electric Company, and Public Service Company of New Hampshire each meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K, and each is therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) of Form 10 ‑ K. Eversource Energy, The Connecticut Light and Power Company, NSTAR Electric Company, and Public Service Company of New Hampshire each separately file this combined Form 10-K. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants. Documents Incorporated by Reference Portions of the Eversource Energy and Subsidiaries 2024 combined Annual Report on Form 10-K and portions of the Proxy Statement relating to the Annual Meeting of Shareholders to be held on May 6, 2026, are incorporated by reference into Parts II and III of this Report.
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GLOSSARY OF TERMS The following is a glossary of abbreviations and acronyms that are found in this report: Current or former Eversource Energy companies, segments or investments: Eversource, ES or the CompanyEversource Energy and subsidiaries Eversource parent or ES parentEversource Energy, a public utility holding company ES parent and other companiesES parent and other companies are comprised of Eversource parent, Eversource Service, and other subsidiaries,which primarily includes our unregulated businesses, The Rocky River Realty Company (a real estatesubsidiary), the consolidated operations of CYAPC and YAEC, and Eversource parent's equity ownershipinterests that are not consolidated CL&P The Connecticut Light and Power Company NSTAR Electric NSTAR Electric Company PSNH Public Service Company of New Hampshire PSNH Funding PSNH Funding LLC 3, a bankruptcy remote, special purpose, wholly-owned subsidiary of PSNH NSTAR Gas NSTAR Gas Company EGMA Eversource Gas Company of Massachusetts Yankee Gas Yankee Gas Services Company Aquarion Aquarion Company and its subsidiaries HEEC Harbor Electric Energy Company, a wholly-owned subsidiary of NSTAR Electric Eversource Service Eversource Energy Service Company CYAPC Connecticut Yankee Atomic Power Company MYAPC Maine Yankee Atomic Power Company YAEC Yankee Atomic Electric Company Yankee Companies CYAPC, YAEC and MYAPC Regulated companies The Eversource regulated companies are comprised of the electric distribution and transmission businesses ofCL&P, NSTAR Electric and PSNH, the natural gas distribution businesses of Yankee Gas, NSTAR Gas andEGMA, Aquarion’s water distribution businesses, and the solar power facilities of NSTAR Electric Regulators and Government Agencies: DEEP Connecticut Department of Energy and Environmental Protection DOE U.S. Department of Energy DOER Massachusetts Department of Energy Resources DPU Massachusetts Department of Public Utilities EPA U.S. Environmental Protection Agency FERC Federal Energy Regulatory Commission ISO-NE ISO New England, Inc., the New England Independent System Operator MA DEP Massachusetts Department of Environmental Protection NHPUC New Hampshire Public Utilities Commission PURA Connecticut Public Utilities Regulatory Authority SEC U.S. Securities and Exchange Commission Other Terms and Abbreviations: ADIT Accumulated Deferred Income Taxes AFUDC Allowance For Funds Used During Construction AOCI Accumulated Other Comprehensive Income ARO Asset Retirement Obligation Bcf Billion cubic feet CfD Contract for Differences CWIP Construction Work in Progress EDC Electric distribution company EDIT Excess Deferred Income Taxes EPS Earnings Per Share ERISA Employee Retirement Income Security Act of 1974 ESOP Employee Stock Ownership Plan Eversource 2024 Form 10-KThe Eversource Energy and Subsidiaries 2024 combined Annual Report on Form 10-K as filed with the SEC Fitch Fitch Ratings, Inc. FMCC Federally Mandated Congestion Charge GAAP Accounting principles generally accepted in the United States of America GSEP Gas System Enhancement Program i
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GWh Gigawatt-Hours IPP Independent Power Producers ISO-NE Tariff ISO-NE FERC Transmission, Markets and Services Tariff kV Kilovolt kVa Kilovolt-ampere kW Kilowatt (equal to one thousand watts) kWh Kilowatt-Hours LNG Liquefied natural gas LPG Liquefied petroleum gas LRS Supplier of last resort service MG Million gallons MGP Manufactured Gas Plant MMBtu Million British thermal units MMcf Million cubic feet Moody's Moody's Investors Service, Inc. MW Megawatt MWh Megawatt-Hours NETOs New England Transmission Owners (including Eversource, National Grid and Avangrid) OCI Other Comprehensive Income/(Loss) PAM Pension and PBOP Rate Adjustment Mechanism PBOP Postretirement Benefits Other Than Pension PBOP Plan Postretirement Benefits Other Than Pension Plan Pension Plan Single uniform noncontributory defined benefit retirement plan PPA Power purchase agreement RECs Renewable Energy Certificates Regulatory ROE The average cost of capital method for calculating the return on equity related to the distribution businesssegment excluding the wholesale transmission segment ROE Return on Equity RRBs Rate Reduction Bonds or Rate Reduction Certificates RSUs Restricted share units S&P Standard & Poor's Financial Services LLC SERP Supplemental Executive Retirement Plans and non-qualified defined benefit retirement plans SS Standard service UI The United Illuminating Company VIE Variable Interest Entity ii
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EVERSOURCE ENERGY AND SUBSIDIARIES THE CONNECTICUT LIGHT AND POWER COMPANY NSTAR ELECTRIC COMPANY AND SUBSIDIARY PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES 2025 FORM 10-K ANNUAL REPORT TABLE OF CONTENTS Page PART I Item 1. Business 2 Item 1A. Risk Factors 16 Item 1B. Unresolved Staff Comments 22 Item 1C. Cybersecurity 22 Item 2. Properties 23 Item 3. Legal Proceedings 26 Item 4. Mine Safety Disclosures 26 Information About Our Executive Officers 26 PART II Item 5. Market for the Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities27 Item 6. Removed and Reserved 28 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 29 Item 7A. Quantitative and Qualitative Disclosures about Market Risk 60 Item 8. Financial Statements and Supplementary Data 61 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 149 Item 9A. Controls and Procedures 149 Item 9B. Other Information 149 PART III Item 10. Directors, Executive Officers and Corporate Governance 150 Item 11. Executive Compensation 150 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters150 Item 13. Certain Relationships and Related Transactions, and Director Independence 151 Item 14. Principal Accountant Fees and Services 151 PART IV Item 15. Exhibits and Financial Statement Schedules 153 Item 16. Form 10-K Summary 153 Signatures E-10 iii
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EVERSOURCE ENERGY AND SUBSIDIARIES THE CONNECTICUT LIGHT AND POWER COMPANY NSTAR ELECTRIC COMPANY AND SUBSIDIARY PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 References in this Annual Report on Form 10-K to "Eversource," the "Company," "we," "us," and "our" refer to Eversource Energy and its consolidated subsidiaries. CL&P, NSTAR Electric, and PSNH are each doing business as Eversource Energy. We make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, future financial performance or growth and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the U.S. federal securities laws. You can generally identify our forward-looking statements through the use of words or phrases such as "estimate," "expect," "pending," "anticipate," "intend," "plan," "project," "believe," "forecast," "would," "should," "could," and other similar expressions. Forward-looking statements involve risks and uncertainties that may cause actual results or outcomes to differ materially from those included in our forward-looking statements. Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance. These expectations, estimates, assumptions or projections may vary materially from actual results. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that may cause our actual results or outcomes to differ materially from those contained in our forward-looking statements, including, but not limited to: • cyber events or breaches, including acts of war or terrorism, affecting our systems or the systems of third parties on which we rely, • unauthorized access to, and the misappropriation of, confidential and proprietary Company, customer, employee, financial or system operating information, • actions or inaction of local, state and federal regulatory, public policy and taxing bodies, • changes in laws, regulations, Presidential executive orders or regulatory policy, including compliance with laws and regulations, which may impact the cost of compliance and strategic initiatives of the Company, • adverse publicity, which can harm our reputation, influence legislative and regulatory bodies, and result in unfavorable outcomes, • variability in the costs and final investment returns of the Revolution Wind and South Fork Wind offshore wind projects as it relates to the purchase price post-closing adjustment under the terms of the sale agreement for these projects, • the ability to qualify for investment tax credits, • extreme weather, including severe storms, due to the impacts of climate change, and fluctuations in weather patterns, • adequacy, contamination of, or disruption in, our water supplies, • physical attacks or grid disturbances that may damage and disrupt our electric transmission and electric, natural gas, and water distribution systems, • ability or inability to commence and complete our major strategic development projects and opportunities, • breakdown, failure of, or damage to operating equipment, information technology systems, or processes of our transmission and distribution systems, • changes in levels or timing of capital expenditures, including unplanned expenditures and increased capital expenditure requirements, • changes in business conditions, which could include disruptive technology or development of alternative energy sources related to our current or future business model, • substandard performance of third-party suppliers and service providers, or counterparties not meeting their obligations, • limits on our access to, or increases in, the cost of capital, including disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly, • changes in economic conditions, including impact on interest rates, tax policies, tariffs and customer demand and payment ability, • changes in accounting standards and financial reporting regulations, • actions of rating agencies, and • other presently unknown or unforeseen factors. Other risk factors are detailed in our reports filed with the SEC and are updated as necessary and available on our Investor Relations website at investors.eversource.com and on the SEC’s website at www.sec.gov, and we encourage you to consult such disclosures. All such factors are difficult to predict and contain uncertainties that may materially affect our actual results, many of which are beyond our control. You should not place undue reliance on the forward-looking statements, as each speaks only as of the date on which such statement is made, and, except as required by federal securities laws, we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for us to predict all of such factors, nor can we assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see Item 1A, Risk Factors, included in this combined Annual Report on Form 10-K. This Annual Report on Form 10-K also describes material contingencies and critical accounting policies in the accompanying Management's Discussion and Analysis of Financial Condition and Results of Operations and Combined Notes to Financial Statements. We encourage you to review these items. 1
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EVERSOURCE ENERGY AND SUBSIDIARIES THE CONNECTICUT LIGHT AND POWER COMPANY NSTAR ELECTRIC COMPANY AND SUBSIDIARY PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES PART I Item 1. Business Please refer to the Glossary of Terms for definitions of defined terms and abbreviations used in this combined Annual Report on Form 10-K. Eversource Energy (Eversource), headquartered in Boston, Massachusetts and Hartford, Connecticut, is a public utility holding company subject to regulation by the Federal Energy Regulatory Commission (FERC) under the Public Utility Holding Company Act of 2005. We are engaged primarily in the energy delivery business through the following wholly-owned utility subsidiaries: • The Connecticut Light and Power Company (CL&P), a regulated electric utility that serves residential, commercial and industrial customers in parts of Connecticut; • NSTAR Electric Company (NSTAR Electric), a regulated electric utility that serves residential, commercial and industrial customers in parts of eastern and western Massachusetts and owns solar power facilities, and its wholly-owned subsidiary Harbor Electric Energy Company (HEEC), also a regulated electric utility that distributes electric energy to its sole customer; • Public Service Company of New Hampshire (PSNH), a regulated electric utility that serves residential, commercial and industrial customers in parts of New Hampshire; • NSTAR Gas Company (NSTAR Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Massachusetts; • Eversource Gas Company of Massachusetts (EGMA), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Massachusetts; • Yankee Gas Services Company (Yankee Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Connecticut; and • Aquarion Company (Aquarion), a utility holding company that owns five separate regulated water utility subsidiaries and collectively serves residential, commercial, industrial, and municipal and fire protection customers in parts of Connecticut, Massachusetts and New Hampshire. For information regarding the sale status of Aquarion, regulatory denial and subsequent appeal, see "Business Development and Capital Expenditures – Aquarion Sale Status and Regulatory Denial" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. CL&P, NSTAR Electric and PSNH also serve New England customers through Eversource's electric transmission business. Along with NSTAR Gas, EGMA and Yankee Gas, each is doing business as Eversource Energy in its respective service territory. Eversource, CL&P, NSTAR Electric and PSNH each report their financial results separately. We also include information in this report on a segment basis for Eversource. Eversource has four reportable segments: electric distribution, electric transmission, natural gas distribution and water distribution. These segments represent substantially all of Eversource's total consolidated revenues. CL&P, NSTAR Electric and PSNH do not report separate business segments. Eversource’s previous offshore wind business included 50 percent ownership interests in each of North East Offshore and South Fork Class B Member, LLC. In the third quarter of 2024, Eversource sold its interest in these entities, and in doing so, sold its interests in the Revolution Wind project, the South Fork Wind project, and the Sunrise Wind project. Eversource’s current offshore wind business is now comprised only of a noncontrolling tax equity investment in South Fork Wind. For more information, see Note 13G, "Commitments and Contingencies – Offshore Wind Sale and Contingent Liability," in the accompanying Item 8, Financial Statements and Supplementary Data. ELECTRIC DISTRIBUTION SEGMENT Eversource's electric distribution segment consists of the distribution businesses of CL&P, NSTAR Electric and PSNH, which are engaged in the distribution of electricity to retail customers in Connecticut, Massachusetts and New Hampshire, respectively, and the solar power facilities of NSTAR Electric. 2
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ELECTRIC DISTRIBUTION – CONNECTICUT – THE CONNECTICUT LIGHT AND POWER COMPANY CL&P's distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2025, CL&P furnished retail franchise electric service to approximately 1.32 million customers in 157 cities and towns in Connecticut. CL&P does not own any electric generation facilities. Rates CL&P is subject to regulation by the Connecticut Public Utilities Regulatory Authority (PURA), which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service and construction and operation of facilities. CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services. Under Connecticut law, all of CL&P's customers are entitled to choose their energy suppliers, while CL&P remains their electric distribution company. For those customers who do not choose a competitive energy supplier, CL&P purchases power on behalf of, and passes the related cost, without mark-up, through to those customers under standard service (SS) rates for customers with less than 500 kilowatts of demand (residential customers and small and medium commercial and industrial customers), and supplier of last resort service (LRS) rates for customers with 500 kilowatts or more of demand (larger commercial and industrial customers). CL&P charges customers only the amount that it pays generators for producing electricity and does not earn a return on the cost of electricity. CL&P's retail rates include an energy supply component and a delivery service component, which includes distribution, transmission, conservation, renewable energy programs and other public benefit charges that are assessed on all customers. The rates established by PURA for CL&P, which are grouped by the customer bill components, are comprised of the following: Supply: Cost of electricity from suppliers based on competitive procurements. • An electric generation service charge, which recovers energy-related costs incurred as a result of providing electric generation service supply to all customers who have not migrated to competitive energy suppliers. The generation service charge is adjusted periodically and reconciled annually in accordance with the policies and procedures of PURA, with any differences refunded to, or recovered from, customers. Local Delivery: Cost to build, maintain, repair and operate the distribution grid, including the poles, lines, and meters that deliver power from the substation. It also includes the cost of resiliency and reliability improvements. • A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the infrastructure to deliver electricity to customers, as well as ongoing operating costs to maintain the infrastructure. • A revenue decoupling adjustment that reconciles annual base distribution rate recovery amounts recovered from customers to the pre- established level of baseline distribution delivery service revenue requirement approved by PURA. • An Electric System Improvements (ESI) charge, which collects the costs of building and expanding the infrastructure to deliver electricity to customers above the level recovered through the distribution charge. The ESI also recovers costs associated with CL&P’s system resiliency program. The ESI is adjusted periodically and reconciled annually in accordance with the policies and procedures of PURA, with any differences refunded to, or recovered from, customers. In 2023, the state of Connecticut enacted a law that prohibits CL&P’s ESI capital tracking mechanism from being reauthorized in the next general distribution proceeding. The ESI will therefore remain in place until base distribution rates are adjusted in CL&P’s next general distribution rate proceeding. • A Competitive Transition Assessment (CTA) charge, assessed to recover stranded costs associated with electric industry restructuring such as various IPP contracts. The CTA is reconciled annually to actual costs incurred and reviewed by PURA, with any difference refunded to, or recovered from, customers. Public Benefits: Cost to support energy programs mandated by the state and federal government for financial assistance and energy efficiency programs, purchasing renewable and carbon-free electricity, and funding solar and electric vehicle incentives. • A Federally Mandated Congestion Charge (FMCC), which recovers any costs imposed by the FERC as part of the New England Standard Market Design, including locational marginal pricing, locational installed capacity payments, any costs approved by PURA to reduce these charges, as well as other costs approved by PURA. These costs include costs associated with ISO-NE, costs to avoid congestion on the transmission system, purchase contracts with zero-carbon energy generators (including the Millstone and Seabrook nuclear contracts) and with renewable energy generators, costs for capacity and gas peaker plants, renewable energy credits, and other initiatives required by state law. The non-bypassable component of the FMCC is adjusted periodically and reconciled annually in accordance with the policies and procedures of the PURA, with any differences refunded to, or recovered from, customers. 3
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CL&P is required by both state legislation and regulation to purchase electric generation from Millstone and Seabrook under PURA- approved PPAs entered in 2019. CL&P does not have legislative authority to use this purchased output to serve its customer load and therefore sells the energy into the wholesale market and uses the proceeds from the energy sales to offset the contract costs. The net cost or net sales amount is recovered from, or refunded to, customers in the non-bypassable component of the FMCC rate. CL&P does not earn any return from these PPAs. • A Systems Benefits Charge (SBC), established to fund expenses associated with various hardship and low-income programs. The SBC is reconciled annually to actual costs incurred, and reviewed by PURA, with any difference refunded to, or recovered from, customers. • A Renewable Energy Investment Charge, which is used to promote investment in renewable energy sources. Amounts collected by this charge are deposited into the Connecticut Clean Energy Fund and administered by the Connecticut Green Bank. • A Conservation Adjustment Mechanism (CAM) charge established to implement cost-effective energy conservation programs and market transformation initiatives. The CAM charge is reconciled annually to actual costs incurred, and reviewed by PURA, with any difference refunded to, or recovered from, customers through an approved adjustment to the following year’s energy conservation spending plan budget. Transmission: Cost to maintain high voltage towers and lines, including building, maintaining and operating the regional transmission system that brings electricity from power generators to the local distribution system. • A transmission charge that recovers the cost of transporting electricity over high-voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market. The transmission charge is adjusted periodically and reconciled annually to actual costs incurred, and reviewed by PURA, with any difference refunded to, or recovered from, customers. A summary of CL&P's retail revenues, grouped by customer bill rate components described above, are as follows: For the Years Ended December 31, CL&P(Millions of Dollars) 2025 2024 Increase/ (Decrease) Return Included in Customer Rates Retail Tariff Sales Revenues Amount % Amount % Supply $ 1,050.0 25 % $ 1,094.1 29 % $ (44.1) pass through costs; no return Local Delivery 1,425.1 34 % 1,354.5 35 % 70.6 includes return on investments Public Benefits 959.3 23 % 709.5 19 % 249.8 pass through costs;required by legislation and regulation Transmission 721.0 17 % 664.6 17 % 56.4 includes return on investments Total Retail Tariff Sales Revenues $ 4,155.4 $ 3,822.7 $ 332.7 Distribution Rate Case and Settlement Agreement: CL&P's distribution rates were established in an April 2018 PURA-approved rate case settlement agreement with rates effective May 1, 2018, and incremental step adjustments effective May 1, 2019 and May 1, 2020. In accordance with a 2021 settlement agreement, CL&P agreed that its current base distribution rates would be frozen, subject to certain customer credits, until no earlier than January 1, 2024. The rate freeze applied only to base distribution rates (including storm costs) and not to other rate mechanisms such as the retail rate components, rate reconciling mechanisms, formula rates and any other adjustment mechanisms. The rate freeze also did not apply to any cost recovery mechanism outside of the base distribution rates with regard to grid-modernization initiatives or any other proceedings that were either pending or that could be initiated during the rate freeze period, that could have placed additional obligations on CL&P. The approval of the settlement agreement satisfied the Connecticut statute of rate review requirements that requires electric utilities to file a distribution rate case within four years of the last rate case. CL&P Performance Based Rate Making: PURA currently has an open proceeding to evaluate and eventually implement performance based regulation (PBR) for electric distribution companies. For further information, see "Regulatory Developments and Rate Matters - Connecticut" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. Sources and Availability of Electric Power Supply As noted above, CL&P does not own any generation assets and purchases energy supply to serve its SS and LRS loads from a variety of competitive sources through requests for proposals. During 2025, CL&P supplied approximately 50 percent of its customer load at SS or LRS rates while the other 50 percent of its customer load had migrated to competitive energy suppliers. In terms of the total number of CL&P customers, this equates to 19 percent being on competitive supply, while 81 percent remain with SS or LRS. Because customer migration is limited to energy supply service, it has no impact on CL&P's electric distribution business or its operating income. As approved by PURA, CL&P periodically enters into full requirements supply contracts for SS loads for periods of up to one year. CL&P typically enters into full requirements supply contracts for LRS loads every three months. If CL&P does not obtain full requirements supply contracts for 100 percent of the customer load for any period, it is authorized by PURA to meet the remaining load obligations directly through the ISO-NE wholesale markets. Currently, CL&P has full requirements supply contracts in place for 100 percent of its SS load for the first half of 2026. For the second half of 2026, CL&P has 60 percent of its SS load under full requirements supply contracts and intends to purchase an additional 40 percent of full requirements. None of the SS load for 2027 has been procured. CL&P obtained a full requirements supply contract 4
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for its LRS load through March 2026 and intends to purchase 100 percent of full requirements for LRS for the remainder of 2026. CL&P is prepared to self-manage the LRS load if unable to obtain full requirements supply contracts for LRS. ELECTRIC DISTRIBUTION – MASSACHUSETTS – NSTAR ELECTRIC COMPANY NSTAR Electric's distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2025, NSTAR Electric furnished retail franchise electric service to approximately 1.62 million customers in 159 cities and towns in eastern and western Massachusetts, including Boston, Cape Cod, Martha's Vineyard and the greater Springfield metropolitan area. NSTAR Electric does not own any generating facilities that are used to supply customers, and purchases its energy requirements from competitive energy suppliers. NSTAR Electric owns, operates and maintains a total of 70 MW of solar power facilities on twenty-two sites in Massachusetts. NSTAR Electric sells energy from these facilities into the ISO-NE market, with proceeds credited to customers. Rates NSTAR Electric is subject to regulation by the Massachusetts Department of Public Utilities (DPU), which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, acquisition of securities, standards of service and construction and operation of facilities. The present general rate structure for NSTAR Electric consists of various rate and service classifications covering residential, commercial and industrial services. Under Massachusetts law, all customers of NSTAR Electric are entitled to choose their energy suppliers, while NSTAR Electric remains their electric distribution company. For those customers who do not choose a competitive energy supplier, NSTAR Electric purchases power from competitive suppliers on behalf of, and passes the related cost without mark-up through to, those customers (basic service). Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through basic service for those who choose not to buy energy from a competitive energy supplier. NSTAR Electric charges customers only the amount that it pays generators for producing electricity and does not earn a return on the cost of electricity. NSTAR Electric's retail rates include a supply component and a delivery component, which include distribution, transmission, renewable energy programs and other public policy charges that are assessed on all customers. The rates established by the DPU for NSTAR Electric, which are grouped by the customer bill components, are comprised of the following: Supply: Cost of electricity from suppliers based on competitive procurements. • A basic service charge that represents the collection of energy costs incurred as a result of providing electric generation service supply to all customers who have not migrated to competitive energy suppliers, including costs related to charge-offs of uncollectible energy costs from customers. Basic service rates are reset every six months (every three months for large commercial and industrial customers). Additionally, the DPU has authorized NSTAR Electric to recover the cost of its NSTAR Green wind contracts through the basic service charge. Basic service costs are reconciled annually, with any differences refunded to, or recovered from, customers. Delivery: Cost of grid maintenance and other critical customer services and also includes government-mandated charges. • A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the distribution infrastructure to deliver electricity to its destination, as well as ongoing operating costs. • A revenue decoupling adjustment that reconciles annual base distribution rate recovery amounts recovered from customers to the pre- established level of baseline distribution delivery service revenue requirement approved by the DPU. Annual base distribution amounts are adjusted for inflation and certain other items and filed for approval by the DPU on an annual basis, until the next rate case. • A transmission charge that recovers the cost of transporting electricity over high-voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market. The transmission charge is reconciled annually to actual costs incurred, and reviewed by the DPU, with any difference refunded to, or recovered from, customers. • A transition charge that represents costs to be collected primarily from previously held investments in generating plants, costs related to existing above-market power contracts, and contract costs related to long-term power contract buy-outs. The transition charge is reconciled annually to actual costs incurred, and reviewed by the DPU, with any difference refunded to, or recovered from, customers. • A renewable energy charge that represents a legislatively-mandated charge to support the Massachusetts Renewable Energy Trust Fund. • An energy efficiency charge that represents a legislatively-mandated charge to collect costs for energy efficiency programs. The energy efficiency charge is reconciled annually to actual costs incurred, and reviewed by the DPU, with any difference refunded to, or recovered from, customers. 5
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• Reconciling adjustment charges that recover certain DPU-approved costs, including pension and PBOP benefits, low income customer discounts, credits issued to net metering facilities installed by customers, payments to solar facilities qualified under the state solar renewable energy target program, attorney general consultant expenses, long-term renewable contracts, company-owned solar facilities, vegetation management costs, storm restoration, credits related to the Tax Cuts and Jobs Act of 2017, grid modernization costs, advanced metering infrastructure costs, electric vehicle make-ready infrastructure costs, and provisional system planning charges. These charges are reconciled annually to actual costs incurred, and reviewed by the DPU, with any difference refunded to, or recovered from, customers. Distribution Rate Case: NSTAR Electric distribution rates were established in a November 2022 DPU-approved rate case, with rates effective January 1, 2023. The DPU approved a renewal of the PBR plan originally authorized in its last rate case for a five-year term, with a corresponding stay out provision. The PBR plan term has the possibility of a five-year extension. The PBR mechanism allows for an annual adjustment to base distribution rates for inflation, exogenous events and future capital additions based on a historical five-year average of total capital additions. For further information, see "Regulatory Developments and Rate Matters - Massachusetts" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. Service Quality Metrics: NSTAR Electric is subject to service quality (SQ) metrics that measure safety, reliability and customer service, and could be required to pay to customers a SQ charge of up to 2.5 percent of annual transmission and distribution revenues for failing to meet such metrics. NSTAR Electric will not be required to pay a SQ charge for its 2025 performance as the company achieved results at or above target for all of its SQ metrics in 2025. Sources and Availability of Electric Power Supply As noted above, NSTAR Electric does not own generation assets (other than 70 MW of solar power facilities that produce energy that is sold into the ISO- NE market) and purchases its energy supply requirements from a variety of competitive sources through requests for proposals issued periodically, consistent with DPU regulations. As approved by the DPU, NSTAR Electric enters into supply contracts for basic service for approximately 20 percent of its residential and 15 percent of its small commercial and industrial (C&I) customers twice per year for twelve-month terms. NSTAR Electric enters into supply contracts for basic service for two percent of its large C&I customers every three months. During 2025, NSTAR Electric supplied approximately 12 percent of its overall customer load at basic service rates. The remaining 88 percent of its overall customer load was served either by municipal aggregation or competitive supply. Because customer migration is limited to energy supply service, it has no impact on NSTAR Electric’s electric distribution business or its operating income. ELECTRIC DISTRIBUTION – NEW HAMPSHIRE – PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE PSNH's distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2025, PSNH furnished retail franchise electric service to approximately 549,000 retail customers in 206 cities and towns in New Hampshire. PSNH does not own any electric generation facilities. Rates PSNH is subject to regulation by the New Hampshire Public Utilities Commission (NHPUC), which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service and construction and operation of facilities. Under New Hampshire law, all of PSNH's customers are entitled to choose competitive energy suppliers. For those customers who do not choose a competitive energy supplier, PSNH purchases power on behalf of, and passes the related cost without mark-up through to, those customers (default energy service). PSNH charges customers only the amount that it pays generators for producing electricity and does not earn a return on the cost of electricity. PSNH's retail rates include a supply component and a delivery component, which include distribution, transmission, renewable energy programs and other public policy charges that are assessed on all customers. The rates established by the NHPUC for PSNH, which are grouped by the customer bill components, are comprised of the following: Supply: Cost of electricity from suppliers based on competitive procurements. • A default energy service charge recovers energy-related costs incurred as a result of providing electric generation service supply to all customers who have not migrated to competitive energy suppliers. The default energy service charge changes semi-annually, and is reconciled annually in accordance with the policies and procedures of the NHPUC, with any differences refunded to, or recovered from, customers. Delivery: Cost of building, maintaining and operating distribution and transmission systems, as well as state and federally mandated charges that fund financial assistance, energy efficiency and renewable energy programs. • A distribution charge, which includes kilowatt-hour and/or demand-based charges to recover costs related to the maintenance and operation of PSNH's infrastructure to deliver power to its destination, as well as power restoration and service costs. It also includes a 6
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customer charge to collect the cost of providing service to a customer; such as the installation, maintenance, reading and replacement of meters and maintaining accounts and records. • A Transmission Charge Adjustment Mechanism (TCAM) that recovers the cost of transporting electricity over high-voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market. The transmission charge is reconciled annually to actual costs incurred, and reviewed by the NHPUC, with any difference refunded to, or recovered from, customers. • A Stranded Cost Recovery Charge (SCRC), which allows PSNH to recover its stranded costs, including above-market expenses incurred under mandated power purchase obligations, recovery of costs of the net metering credit program, a credit for revenues generated by the RGGI program, other long-term investments and obligations, and the remaining costs associated with the 2018 sales of its generation facilities. The SCRC rate changes annually with the option to change semi-annually, and is reconciled annually in accordance with the policies and procedures of the NHPUC, with any differences refunded to, or recovered from, customers. • A Systems Benefits Charge (SBC), which funds energy efficiency programs for all customers, as well as assistance programs for residential customers within certain income guidelines. The SBC rate changes annually and is reconciled annually in accordance with the policies and procedures of the NHPUC, with any differences refunded to, or recovered from, customers. • A Regulatory Reconciliation Adjustment (RRA) that reconciles the difference between certain estimated and actual costs included in base distribution rates, including costs related to regulatory assessments, property tax expenses, the New Start Arrearage Forgiveness Program, and unrecovered storm costs in excess of the Major Storm Cost Reserve, once approved. Additionally, the RRA recovers approved rate case expense, as well as historical amounts for New Start and Fee Free program costs. Distribution Rate Case: PSNH's distribution rates were established in a July 2025 NHPUC-approved rate case, with rates effective August 1, 2025. As part of the NHPUC’s alternative regulatory framework, PSNH is authorized three formulaic annual revenue adjustments on August 1, 2026, 2027 and 2028. PSNH is required to file its next base distribution rate case for effect in June 2029. The alternative regulatory framework also contains an exogenous events recovery mechanism for certain unforeseen events out of PSNH’s control and exceeding a specified threshold, a performance metric, and an earnings sharing mechanism where PSNH would return 75 percent of all revenue back to customers that exceeds 25 basis points more than the authorized ROE of 9.5 percent. For further information, see "Regulatory Developments and Rate Matters - New Hampshire" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. Sources and Availability of Electric Power Supply PSNH does not own any generation assets and as approved by the NHPUC, purchases energy supply from a variety of competitive suppliers for its energy service customers through requests for proposals issued twice per year, for six-month terms, for approximately 56 percent of its residential and small C&I customers and for 18 percent of its large C&I customers. As required by the NHPUC, PSNH purchased 50 percent of its residential and small C&I customer load and 100 percent of its medium C&I and large C&I customer load through direct wholesale market participation for the second half of 2025. During 2025, PSNH supplied approximately 56 percent of its customer load at default energy service rates while the other 44 percent of its customer load had migrated to competitive energy suppliers. Because customer migration is limited to energy supply service, it has no impact on PSNH’s electric distribution business or its operating income. ELECTRIC TRANSMISSION SEGMENT CL&P, NSTAR Electric and PSNH each own and maintain transmission facilities that are part of an interstate power transmission grid over which electricity is transmitted throughout New England. Each of CL&P, NSTAR Electric and PSNH, and most other New England utilities, are parties to a series of agreements that provide for coordinated planning and operation of the region's transmission facilities and the rules by which they acquire transmission services. Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent of all market participants, serves as the regional transmission organization of the New England transmission system. Wholesale Transmission Rates and Transmission Proceedings CL&P, NSTAR Electric and PSNH wholesale transmission rates are calculated in accordance with a FERC-approved formula ratemaking framework and each utility is required to file an annual update on or before July 31st with resulting rates effective January 1st the following year. The formula rate framework provides for an annual reconciliation of the prior calendar year actual costs incurred related to our transmission facilities, including an allowed ROE, plus forecasted information through the next rate period. The financial impacts of differences between actual and estimated costs are deferred for future recovery from, or refund to, transmission wholesale customers. The annual update process also includes formula rate protocols that provide disclosure of cost inputs, an opportunity for informal discovery procedures and a challenge process, which provides transparency to stakeholders. The transmission rates are collected from New England wholesale customers, including distribution customers of CL&P, NSTAR Electric and PSNH. 7
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From time to time, various matters are pending before FERC relating to transmission rates, incentives, interconnections and transmission planning. Depending on the outcome, any of these matters could materially impact our results of operations and financial condition. At this time, Eversource cannot predict the ultimate outcome of the matters currently pending before FERC, and the resulting impact on its transmission incentives or planning. Transmission Rate Base Transmission rate base under our FERC-approved tariff primarily consists of our investment in transmission net utility plant less accumulated deferred income taxes. Under our FERC-approved tariff, investments in net utility plant generally enter rate base after they are placed in commercial operation. At the end of 2025, our estimated transmission rate base was approximately $11.3 billion, including approximately $4.6 billion at CL&P, $4.4 billion at NSTAR Electric, and $2.3 billion at PSNH. FERC ROE Complaints Four separate complaints were filed at the FERC by combinations of New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (collectively, the Complainants). In each of the first three complaints, filed on October 1, 2011, December 27, 2012, and July 31, 2014, respectively, the Complainants challenged the NETOs' base ROE of 11.14 percent that had been utilized since 2005 and sought an order to reduce it prospectively from the date of the final FERC order and for the separate 15-month complaint periods. In the fourth complaint, filed April 29, 2016, the Complainants challenged the NETOs' base ROE billed of 10.57 percent and the maximum ROE for transmission incentive (incentive cap) of 11.74 percent, asserting that these ROEs were unjust and unreasonable. In response to appeals of the FERC decision in the first complaint filed by the NETOs and the Complainants, the U.S. Court of Appeals for the D.C. Circuit (the Court) issued a decision on April 14, 2017 vacating and remanding the FERC's decision. On October 16, 2018, FERC issued an order on all four complaints describing how it intends to address the issues that were remanded by the Court. FERC proposed a new framework to determine (1) whether an existing ROE is unjust and unreasonable and, if so, (2) how to calculate a replacement ROE. During 2019 and 2020, FERC also issued multiple decisions in two pending transmission ROE complaints against the Midcontinent ISO (MISO) transmission owners, in which FERC adopted new methodologies for determining base ROEs. On August 9, 2022, the Court issued a decision vacating these MISO ROE FERC decisions and remanded to FERC to reopen the proceedings. On October 17, 2024, FERC issued an order on the remand of the MISO ROE proceedings. On February 4, 2025, the MISO transmission owners submitted a petition for review with the Court requesting review of the October 17, 2024 MISO ROE order on remand and a December 19, 2024 notice of denial of rehearing. On November 13, 2024, the NETOs filed a supplemental brief in their four pending ROE proceedings to explain to FERC that it cannot apply the reasoning and methodologies of the MISO ROE case to the NETOs’ cases due to the entirely different set of facts in the MISO and NETOs ROE proceedings. Doing so would violate the substance of the Court’s April 14, 2017 order and would violate the legal standard required by the Federal Power Act. Given the significant uncertainty regarding the applicability of the FERC order in the MISO transmission owners’ two complaint cases to the NETOs’ pending four complaint cases due to the complex differences between the cases, Eversource concluded that there is no reasonable basis for a change to the reserve or recognized ROEs for any of the complaints or subsequent periods at this time and Eversource cannot reasonably estimate any potential range of loss for any of the four complaint proceedings at this time. The resolution of these proceedings could have a material impact on the financial condition, results of operations, and cash flows. For further information, see "FERC Regulatory Matters - FERC ROE Complaints" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. NATURAL GAS DISTRIBUTION SEGMENT Our natural gas businesses are engaged in the distribution and sale of natural gas to customers. NSTAR Gas distributes natural gas to approximately 306,000 customers in 59 communities in central and eastern Massachusetts. EGMA distributes natural gas to approximately 335,000 customers in 66 communities throughout Massachusetts. Yankee Gas distributes natural gas to approximately 256,000 customers in 85 cities and towns in Connecticut. Total throughput (sales and transportation) in 2025 was approximately 69.9 Bcf for NSTAR Gas, 56.6 Bcf for EGMA, and 61.6 Bcf for Yankee Gas. NSTAR Gas, EGMA and Yankee Gas generate revenues primarily through the sale and/or transportation of natural gas. Our natural gas businesses provide uninterruptible (or firm) natural gas sales and transportation service to eligible retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on natural gas for heating, hot water and cooking needs, as well as commercial and industrial customers who rely on natural gas for space heating, hot water, cooking and commercial and industrial applications and who choose to purchase natural gas from our natural gas businesses. Firm transportation service is offered to customers who purchase natural gas from sources other than NSTAR Gas, EGMA or Yankee Gas. All NSTAR Gas and EGMA retail customers have the ability to choose to purchase gas from third-party marketers under the Massachusetts Retail Choice program. In the past year in Massachusetts, Retail Choice represented only approximately one percent of the total residential load, while Retail Choice represented approximately 40 percent of the total commercial and industrial load. Retail natural gas service in Connecticut is partially unbundled: residential customers in Yankee Gas' service territory buy natural gas supply and delivery only from Yankee Gas while commercial and industrial customers may choose their natural gas suppliers. For customers who purchase natural gas from NSTAR Gas, EGMA and Yankee Gas, the purchased natural gas commodity cost is passed through to those customers without mark-up. NSTAR Gas, EGMA and Yankee Gas do not earn a return on the cost of purchased gas. 8
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Interruptible transportation and interruptible natural gas sales service is offered to certain customers. NSTAR Gas and EGMA offer interruptible transportation and natural gas sales service to high volume commercial and industrial customers. Yankee Gas offers interruptible transportation and natural gas sales service to commercial and industrial customers who have the ability to switch from natural gas to an alternate fuel on short notice. NSTAR Gas, EGMA and Yankee Gas can interrupt service to these customers during peak demand periods or at any other time to maintain distribution system integrity. A portion of the storage of natural gas supply for NSTAR Gas and EGMA during the winter heating season is provided by Hopkinton LNG Corp., an indirect, wholly-owned subsidiary of Eversource. NSTAR Gas has access to facilities consisting of an LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3.0 Bcf of liquefied natural gas and facilities that include additional storage capacity of 0.5 Bcf. Total vaporization capacity of these facilities is 0.21 Bcf per day. EGMA has access to approximately 1.7 Bcf of LNG and 0.1 Bcf of LPG storage, with a total vaporization capacity of 0.14 Bcf per day. Yankee Gas owns a 1.2 Bcf LNG facility, which also has the ability to liquefy and vaporize up to 0.1 Bcf per day. This facility is used primarily to assist Yankee Gas in meeting its supplier-of-last-resort obligations and also enables it to provide economic supply and make economic refill of natural gas, typically during periods of low demand. Rates NSTAR Gas and EGMA are subject to regulation by the DPU and Yankee Gas is subject to regulation by the PURA, both of which, among other things, have jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service and construction and operation of facilities. Retail natural gas supply and delivery rates are established by the DPU and the PURA and are comprised of: • A seasonal cost of gas adjustment clause (CGAC) at NSTAR Gas and EGMA that collects natural gas supply costs, pipeline and storage capacity costs, costs related to charge-offs of uncollected energy costs and working capital related costs. The CGAC is reset semi-annually with any difference being recovered from, or refunded to, customers during the following corresponding season. In addition, NSTAR Gas and EGMA file interim changes to the CGAC factor when the actual costs of natural gas supply vary from projections by more than five percent. • A Purchased Gas Adjustment (PGA) clause at Yankee Gas that collects the costs of the procurement of natural gas for its firm and seasonal customers. The PGA is evaluated monthly. Differences between actual natural gas costs and collection amounts from September 1st through August 31st of each PGA year are deferred and then recovered from, or refunded to, customers during the following PGA year. Carrying charges on outstanding balances are calculated using Yankee Gas' weighted average cost of capital in accordance with the directives of the PURA. • A distribution charge consisting of a fixed customer charge and a demand and/or energy charge that collects the costs of building, maintaining, and expanding the natural gas infrastructure to deliver natural gas supply to its customers. This also includes collection of ongoing operating costs. • A local distribution adjustment clause (LDAC) at NSTAR Gas and EGMA that collects all energy efficiency and related program costs, environmental costs, pension and PBOP related costs, attorney general consultant costs, credits related to the Tax Cuts and Jobs Act of 2017, costs of the gas system enhancement program designed to accelerate the replacement of certain natural gas distribution facilities (GSEP), costs associated with low income customers, and costs associated with a geothermal pilot program. The LDAC is reset annually with any difference being recovered from, or refunded to, customers during the following period and provides for the recovery of certain costs applicable to both sales and transportation customers. • A Conservation Adjustment Mechanism (CAM) at Yankee Gas, which allows 100 percent recovery of conservation costs through this mechanism including program incentives to promote energy efficiency. A reconciliation of CAM revenues to expenses is performed annually with any difference being recovered from, or refunded to, customers with carrying charges during the following year. • A Gas System Improvement (GSI) reconciliation mechanism at Yankee Gas, which collects the cost of core capital plant in service above and beyond the level that is recovered through the distribution charge. The GSI is adjusted and reconciled annually, with any differences refunded to, or recovered from, customers. A Distribution Integrity Management Program (DIMP) reconciliation mechanism at Yankee Gas, which collects the cost of capital to replace aging infrastructure. The DIMP is adjusted and reconciled annually, with any differences refunded to, or recovered from, customers. • A System Expansion Rate (SER) reconciliation mechanism at Yankee Gas, which compares distribution system expansion investment costs and revenues from system expansion customers with the level projected in current distribution customer rates. This reconciliation is performed annually and customer rates are adjusted accordingly. • A Revenue Decoupling Mechanism (RDM) at NSTAR Gas and EGMA that reconciles annual base distribution rate recovery amounts recovered from customers to the pre-established level of baseline distribution delivery service revenue requirement approved by the DPU. The pre-established level of baseline distribution delivery service revenue requirement is also subject to adjustment in accordance with provisions of the November 2020 NSTAR Gas distribution rate case and the October 2020 EGMA rate settlement agreement. 9
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• A RDM at Yankee Gas that reconciles annual base distribution rate recovery amounts recovered from customers to the pre-established level of baseline distribution delivery service revenue requirement approved by the PURA. The pre-established level of baseline distribution delivery service revenue requirement is also subject to adjustment in accordance with provisions of the November 2025 Yankee Gas distribution rate case. Distribution Rate Cases and Settlement Agreements: NSTAR Gas: NSTAR Gas distribution rates were established in an October 2020 DPU-approved rate case, with rates effective November 1, 2020. The DPU also approved a 10-year PBR plan through November 1, 2030, which includes inflation-based adjustments to annual base distribution amounts effective annually beginning November 1, 2021. On December 30, 2025, NSTAR Gas and the Massachusetts Office of the Attorney General reached a joint settlement agreement that allowed for the reinstatement of a rate base reset in base distribution rates effective January 1, 2026, for NSTAR Gas to not petition for a rate case with new rates effective December 1, 2026, and for continuation of NSTAR Gas’ PBR program through November 1, 2030. The settlement agreement was approved by the DPU on January 16, 2026. For further information, see "Regulatory Developments and Rate Matters - Massachusetts" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. EGMA: EGMA’s distribution rates were established in a DPU-approved October 7, 2020 rate settlement agreement, with rate increases on November 1, 2021 and November 1, 2022, and two rate base resets during an eight-year rate plan. The first rate base reset occurred on November 1, 2024 and the second will occur November 1, 2027. Notwithstanding the two distribution rate increases, the two rate base reset provisions, and potential adjustments for qualifying exogenous events, EGMA agreed not to file for an increase or redesign of distribution base rates effective prior to November 1, 2028. For further information, see "Regulatory Developments and Rate Matters - Massachusetts" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. Yankee Gas: Yankee Gas distribution rates were established in a November 5, 2025 PURA-approved rate case, which included a distribution rate increase effective November 1, 2025. For further information, see "Regulatory Developments and Rate Matters - Connecticut" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. Massachusetts Future of Gas: In October 2020, the DPU opened Docket "DPU 20-80 The Future of Gas" to examine the role of Massachusetts natural gas local distribution companies (LDCs) in helping to meet the state’s 2050 climate goals. In December 2023, the DPU ordered that it would consider and, in some cases, require new processes and analysis for traditional natural gas investments, which may require significant changes to the LDC planning process and business models. On April 2, 2024, the DPU ordered the LDCs to implement the inclusion of a Non-Gas Pipeline Alternatives (NPA) analysis on all project authorizations and that each LDC submit climate compliance plans every five years beginning April 1, 2025 that include performance metrics to promote the achievement of climate targets. The climate compliance plan filings include the NPA frameworks, along with energy transitions plans including details on the management of embedded infrastructure investments and cost recovery. Eversource along with the LDCs, have also contracted a consultant to model and investigate statewide cost recovery scenarios including under accelerated depreciation rates. Eversource does not believe there is any indication of an inability to recover costs or risk of impairment of NSTAR Gas’ and EGMA’s natural gas assets at this time. Service Quality Metrics: NSTAR Gas and EGMA are subject to SQ metrics that measure safety, reliability and customer service and each could be required to pay to customers a SQ charge of up to 2.5 percent of annual distribution revenues for failing to meet such metrics. NSTAR Gas is required to pay approximately $1.6 million to customers in SQ charges as a result of not meeting certain customer service-related performance metrics in 2025, which was recorded as a regulatory liability as of December 31, 2025. EGMA will not be required to pay any SQ charges relating to its 2025 performance. Sources and Availability of Natural Gas Supply NSTAR Gas and EGMA maintain flexible resource portfolios consisting of natural gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services. NSTAR Gas and EGMA purchase transportation, storage, and balancing services from Tennessee Gas Pipeline Company and Algonquin Gas Transmission Company, as well as other upstream pipelines that transport natural gas from major natural gas producing regions in the U.S., including the Gulf Coast, Mid-continent region, and Appalachian Shale (as well as Ontario, Canada specific to EGMA), which supply to the final delivery points in the NSTAR Gas and EGMA service areas. NSTAR Gas purchases all of its natural gas supply under a firm, competitively bid annual portfolio management contract. EGMA purchases the majority of its natural gas supply under a number of firm, competitively bid annual portfolio management contracts, and manages a portion of its own portfolio. In addition to the firm transportation and natural gas storage supplies discussed above, NSTAR Gas and EGMA utilize on-system LNG facilities (and also LPG facilities for EGMA) to meet winter peaking demands. These LNG facilities are located within NSTAR Gas' and EGMA’s distribution systems and are used to liquefy pipeline natural gas and/or receive liquefied natural gas or liquefied petroleum gas to be stored during the warmer months for vaporization and use during the heating season. During the summer injection season, excess pipeline capacity and supplies are used to deliver and store natural gas in market area underground storage facilities located in Maryland and Pennsylvania. Stored natural gas is withdrawn during the winter season to supplement flowing pipeline supplies in order to meet firm heating demand. NSTAR Gas has firm underground storage contracts and total storage capacity entitlements of approximately 6.6 Bcf, and 3.5 Bcf LNG storage is provided by Hopkinton LNG Corp. in facilities located in two different locations in Massachusetts. EGMA has firm underground storage contracts and total storage capacity entitlements of approximately 8.8 Bcf, and 1.8 Bcf LNG and LPG storage is provided by Hopkinton LNG Corp. in facilities located at seven different locations in Massachusetts. PURA requires Yankee Gas to meet the needs of its firm customers under all weather conditions. Specifically, Yankee Gas must structure its supply portfolio to meet firm customer needs under a design day scenario (defined as the coldest day in 30 years) and under a design year scenario 10
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(defined as the average of the four coldest years in the last 30 years). Yankee Gas also maintains a flexible resource portfolio consisting of natural gas supply contracts, transportation contracts on interstate pipelines, off-system storage and its on-system 1.2 Bcf LNG storage facility in Connecticut to meet consumption needs during the coldest days of winter. Yankee Gas obtains its interstate capacity from the three interstate pipelines that directly serve Connecticut: the Algonquin, Tennessee and Iroquois Pipelines, which connect to other upstream pipelines that transport natural gas from major natural gas producing regions, including the Gulf Coast, Mid-continent, Canadian regions and Appalachian Shale supplies. Based on information currently available regarding projected growth in demand and estimates of availability of future supplies of pipeline natural gas, each of NSTAR Gas, EGMA and Yankee Gas believes that in order to meet the long-term firm customer requirements in a reliable manner, a combination of pipeline, storage, and non-pipeline solutions will be necessary. WATER DISTRIBUTION SEGMENT Aquarion Company (Aquarion) operates five separate regulated water utilities in Connecticut (Aquarion Water Company of Connecticut, or AWC-CT, and The Torrington Water Company), Massachusetts (Aquarion Water Company of Massachusetts, or AWC-MA), and New Hampshire (Aquarion Water Company of New Hampshire, or AWC-NH, and Abenaki Water Company). These regulated companies provide water services to approximately 249,000 residential, commercial, industrial, municipal and fire protection and other customers, in 73 towns and cities in Connecticut, Massachusetts and New Hampshire. As of December 31, 2025, approximately 91 percent of Aquarion’s customers were based in Connecticut. Rates Aquarion's water utilities are subject to regulation by the PURA, the DPU and the NHPUC in Connecticut, Massachusetts and New Hampshire, respectively. These regulatory agencies have jurisdiction over, among other things, rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service and construction and operation of facilities. Aquarion’s general rate structure consists of various rate and service classifications covering residential, commercial, industrial, and municipal and fire protection services. The rates established by the PURA, DPU and NHPUC are comprised of the following: • A base rate, which is comprised of fixed charges based on meter/fire connection sizes, as well as volumetric charges based on the amount of water sold. Together these charges are designed to recover the full cost of service resulting from a general rate proceeding. • In Connecticut, a revenue adjustment mechanism (RAM) that reconciles earned revenues, with certain allowed adjustments, on an annual basis, to the revenue requirement approved by PURA. • In Connecticut and New Hampshire, a water infrastructure conservation adjustment (WICA) charge, and in Massachusetts, an annual main replacement adjustment mechanism (MRAM) charge, which is applied between rate case proceedings and seeks recovery of allowed costs associated with eligible infrastructure improvement projects placed in-service. The WICA is updated semi-annually in Connecticut and annually in New Hampshire. In Connecticut, an annual WICA reconciliation mechanism reconciles earned WICA revenue to the approved WICA revenue with any differences refunded to, or recovered from, customers. Distribution Rate Cases: Aquarion's Connecticut base distribution rates were established in a 2023 PURA-approved rate case, with updated decisions in 2024 and 2025. For further information, see "Regulatory Developments and Rate Matters - Connecticut" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. Aquarion’s Massachusetts base distribution rates were established in a 2018 DPU-approved rate case. Aquarion's New Hampshire base distribution rates were established in a July 2022 NHPUC-approved rate case settlement agreement, with a single step adjustment approved on January 19, 2023. Rates were effective March 1, 2023. Sources and Availability of Water Supply Our water utilities obtain their water supplies from owned surface water sources (reservoirs) and groundwater supplies (wells) with a total supply yield of approximately 135 million gallons per day, as well as water purchased from other water suppliers. Approximately 98 percent of our annual production is self-supplied and processed at ten surface water treatment plants and numerous well stations, which are all located in Connecticut, Massachusetts, and New Hampshire. The capacities of Aquarion’s sources of supply, and water treatment, pumping and distribution facilities, are considered sufficient to meet the present requirements of Aquarion’s customers under normal conditions. On occasion, drought declarations are issued for portions of Aquarion’s service territories in response to extended periods of dry weather conditions. CAPITAL EXPENDITURES For information on capital expenditures and projects during 2025, as well as projected capital expenditures by business, see "Business Development and Capital Expenditures" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. 11
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FINANCING For information regarding short-term and long-term debt agreements, see "Liquidity" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, Note 8, "Short-Term Debt," and Note 9, "Long-Term Debt," of the Combined Notes to Financial Statements. NUCLEAR FUEL STORAGE CL&P, NSTAR Electric, PSNH, and several other New England electric utilities are stockholders in three inactive regional nuclear generation companies, CYAPC, MYAPC and YAEC (collectively, the Yankee Companies). The Yankee Companies have completed the physical decommissioning of their respective nuclear power facilities and are now engaged in the long-term storage of their spent nuclear fuel. The Yankee Companies fund these costs through litigation proceeds received from the DOE and, to the extent necessary, through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P, NSTAR Electric and PSNH. CL&P, NSTAR Electric and PSNH, in turn recover these costs from their customers through state regulatory commission-approved retail rates. The Yankee Companies collect amounts that we believe are adequate to recover the remaining plant closure and fuel storage cost estimates for the respective plants. We believe CL&P and NSTAR Electric will recover their shares of these obligations from their customers. PSNH has recovered its total share of these costs from its customers. We consolidate the assets and obligations of CYAPC and YAEC on our consolidated balance sheet because our ownership and voting interests are greater than 50 percent of each of these companies. OTHER REGULATORY AND ENVIRONMENTAL MATTERS General We are regulated by various federal and state agencies, including FERC, the SEC, and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each of our companies operates, including the PURA, which has jurisdiction over CL&P, Yankee Gas, and Aquarion, the DPU, which has jurisdiction over NSTAR Electric, NSTAR Gas, EGMA and Aquarion, and the NHPUC, which has jurisdiction over PSNH and Aquarion. Renewable Portfolio Standards Each of the states in which we do business has Renewable Portfolio Standards (RPS) requirements, which generally require fixed percentages of our energy supply to come from renewable energy sources such as solar, wind, hydropower, landfill gas, fuel cells and other similar sources. Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2025, the total RPS obligation was 39.0 percent and will be 37.0 percent in 2030. CL&P is permitted to recover any costs incurred in complying with RPS from its customers through its generation service charge rate. Massachusetts' RPS program requires electricity suppliers to meet renewable energy standards. For 2025, the RPS and Clean Energy Standard (CES) requirements were 63.1 percent, and will ultimately reach 69.3 percent in 2026. Massachusetts electric suppliers were also required to meet Alternative Energy Portfolio Standards (APS) of 6.25 percent and Clean Peak Energy Standards (CPS) of 5.5 percent in 2025. Those requirements will reach 6.5 and 7.0 percent in 2026, respectively. NSTAR Electric is permitted to recover any costs incurred in complying with these requirements from its customers through rates. NSTAR Electric also owns renewable solar power facilities. The RECs generated from NSTAR Electric's solar power facilities are sold to other energy suppliers, and the proceeds from these sales are credited back to customers. New Hampshire's RPS provision requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2025, the total RPS obligation was 22.2 percent and it will ultimately reach 25.2 percent in 2026. The costs of the RECs are recovered by PSNH through rates charged to customers. Environmental Regulation and Matters We are subject to various federal, state and local environmental legislation and regulation with respect to water quality, air quality, natural/working lands (wetlands, water resource areas that include land that borders a body of water, plant/animal habitat), hazardous materials and other environmental matters. Our environmental policy includes formal procedures and a task-scheduling system in place to help address ongoing environmental compliance obligations. The Governance, Environmental and Social Responsibility Committee of Eversource’s Board of Trustees also provides oversight of climate issues, environmental matters and compliance. We also identify and address potential environmental risks through our Enterprise Risk Management (ERM) program in addition to rigorous audits of our facilities, vendors, and processes. Additionally, projects may not be constructed or significantly modified without a review of the environmental impact of the proposed construction or modification by the applicable federal or state agencies. Many of our construction projects require the submission of comprehensive permitting applications to various local, state and federal agencies. The permits we receive outline various best management practices and restoration requirements to address construction period-impacts. 12
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We have recorded a liability for what we believe, based upon currently available information, is our reasonably estimable environmental investigation, remediation, and/or natural resource damages costs for waste disposal sites for which we have probable liability. Under federal and state law, government agencies and private parties can attempt to impose liability on us for recovery of investigation and remediation costs at contaminated sites. As of December 31, 2025, the liability recorded for our reasonably estimable and probable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was $154.3 million, representing 66 sites. These costs could be significantly higher if additional remediation becomes necessary or when additional information as to the extent of contamination becomes available. The most significant liabilities currently relate to future clean-up costs at former MGP facilities. These facilities were owned and operated by our predecessor companies from the mid-1800's to mid-1900's. By-products from the manufacture of natural gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose a potential risk to human health and the environment. We currently have partial or full ownership responsibilities at former MGP sites that have a reserve balance of $140.9 million of the total $154.3 million as of December 31, 2025. MGP costs are recoverable through rates charged to our customers. When planning environmental investigations and remediation of impacted properties, we work closely with the municipalities and environmental regulators to ensure that our remediation plans adhere to applicable regulations while protecting human health and the environment. In many cases, these remediation projects are designed to address opportunities for beneficial reuse of the property. Global Climate Change and Greenhouse Gas Emissions Issues Eversource assesses the regulatory, physical and transitional impacts related to climate change to develop mitigation strategies to reduce emissions in our operations and for the region through clean energy and emerging technologies investments and also to develop adaptation strategies, including evaluating the impacts of more severe and frequent weather events, financial risks, and changing customer behaviors. Regulatory Impacts of Climate Change: Global climate change has received focus from the federal and state governments. Some of the states in which we operate have aggressive climate goals and implementation plans. In Connecticut, legislation includes a target to achieve zero-carbon electricity by 2040 and economy-wide net-zero greenhouse gas (GHG) emissions by 2050. In response to the 2021 Massachusetts climate legislation calling for increased electrification of the transportation and building sectors, in 2023, Eversource developed an Electric Sector Modernization Plan (ESMP) detailing steps the Company will take over the next five and ten years to help ensure reliability and resiliency while supporting a clean energy future. Approved by the DPU in 2024, the ESMP includes incremental spending for interconnections of clean energy and resiliency initiatives, and corresponding cost recovery was established in 2025. Similarly, the Massachusetts “Future of Gas” docket (DPU 20-80) specified measures for natural gas LDCs to support the state’s net zero by 2050 climate goal. In response, the LDCs submitted a Climate Compliance Plan in 2025 which is under review. These state regulations and related policies may introduce risks and opportunities to our businesses if demands for energy change. The prior Federal Administration had communicated a strong focus on addressing climate change by setting a U.S. target of reducing GHG emissions by 50 percent by 2030, compared to 2005 levels, and achieving net-zero emissions by 2050 economy-wide. The plan called for aggressive measures focused on clean transportation, clean energy and climate investments targeted at environmental justice communities. In support of this plan, federal funding and incentive programs for clean transportation and energy have offered opportunities for Eversource to invest in projects that have the ability to reduce emissions in the region while benefiting our communities and shareholders. Eversource continually evaluates the evolving regulatory landscape concerning climate change and emissions reductions, which could potentially lead to additional requirements, rules and regulations that could impact how we operate our businesses. Potential future environmental statutes, regulations, policies and reporting metrics for rate cases that address climate change could impose significant additional costs and there can be no assurance that regulators will approve the recovery of those costs. Physical and Transitional Impacts of Climate Change: Eversource assesses the physical impacts of climate change that are presented in the form of weather and natural events or longer-term shifts in climate patterns, as well as transitional impacts related to a shift to a lower-carbon economy and mitigation and adaptation requirements. To address physical and transitional impacts related to climate change, maintain resiliency across our system, and enable potential opportunities for our business, we are pursuing the following actions, while keeping the focus on customer affordability: • Improving our system resiliency in response to climate change through vegetation management, pole and wire strengthening, flood proofing, and other system hardening measures; • Implementing a grid modernization plan that will enhance our electric distribution infrastructure to improve resiliency and reliability and increase opportunities to facilitate integration of distributed energy resources, electric vehicle infrastructure, and electrification of building heat; • Focusing on improving the efficiency of our electric and natural gas distribution systems, preparing for increased opportunities that clean energy advancements create, and providing customers with ways to optimize their energy efficiency; • Pursuing new technologies and incentives for decarbonization of energy in the sectors that both we and our customers operate in; • Evaluating opportunities for our natural gas system and exploring alternative, less carbon-intensive technologies like networked geothermal for heating and cooling; and • Investigating emerging technologies such as energy storage and automation programs that improve reliability. 13
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Physical risks from climate change may be acute due to increased severity of extreme weather events, such as extreme heat, severe storms, droughts, wildfires, and floods. Acute risks are often exacerbated by chronic risks due to changes in precipitation patterns, extreme variability in weather patterns, rising mean temperatures, and/or rising sea levels. These risks may result in customers’ energy and water usage increasing or decreasing depending on the duration and magnitude of the changes, degradation of water quality, and our ability to reliably deliver our services to customers. Severe weather may cause outages, potential disruption of operations, and property damage to our assets. Our actions to improve system reliability and resiliency allow our business to operate under changing conditions and meet customer expectations. System improvements are designed to withstand severe weather impacts and include installing new and stronger infrastructure like poles, wires and related system equipment, as well as enhanced year-round tree trimming. We are reinforcing existing critical facilities to withstand storm surges and future substations are being “flood hardened” to better protect our system against storm surges associated with the increasing risk of severe weather in the states that support this work. We created our comprehensive emergency preparedness and response plans in partnership with state and community leaders so that when a storm occurs, we can provide customers and municipalities with timely and accurate information, while safely and promptly restoring power. Additionally, we collaborate with other utility providers and industry partners across the country to better understand storm hazards and develop solutions to improve our system reliability. In 2025, Eversource replaced its carbon neutrality goal with an expanded set of GHG reduction targets aiming to achieve a 45 percent reduction in both Scope 1 and 2 emissions by 2035 and to achieve net zero emissions by 2050 for both Scope 1 and 2 as well as Scope 3 emissions associated with customer energy use. These targets rely on absolute emissions reductions as opposed to carbon offsets and put greater emphasis on the indirect emissions from our customers’ energy usage, thereby better aligning with, and supporting, the climate policies and regulations of the states where we operate. Our Scope 1 and 2 emissions from our operations include line loss (emissions associated with the energy lost when power is transmitted and distributed across the electric system), methane leaks from our natural gas distribution system, fuel consumption from our facilities and vehicle fleet, electricity use at our facilities, and sulfur hexafluoride (SF6) leaks from electric equipment. Initiatives to reduce GHG emissions have resulted in a nearly 30 percent reduction in both Scope 1 and 2 emissions from 2018 through 2024 from initiatives including improved energy efficiency at our buildings, utilizing alternative fuels and introducing more hybrid and electric vehicles into the company fleet, reducing emissions of methane by replacing leak-prone natural gas pipes, improving maintenance of SF6 gas-insulated electrical equipment and piloting innovative SF6-free technologies thereby reducing SF6 emissions, and supporting the overall interconnection of clean energy to the region thereby helping reduce the carbon intensity of line losses across the electric grid. Our Scope 3 emissions are our largest portion of our inventory as it includes emissions associated with customer energy use and are included in our net zero target. While we have limited influence over this emissions source, the investments we make to the grid infrastructure that enables more clean energy to be interconnected overtime, will help reduce the carbon footprint of our service territory and our customers, while supporting regional goals addressing climate change. We also influence Scope 3 emissions through our industry-leading energy efficiency programs and interconnection of customer-owned renewable generation sources (such as solar panels). Progress towards our targets is reported at least annually through a third-party-verified GHG emissions inventory. Our business is also exposed to climate-related transitional impacts, such as policy, legal and reputational impacts and technology and market changes as we enable broad decarbonization of the electrical and building sectors in support of regional policies and targets. We actively support local, state and federal emissions reduction goals to address climate change and pursue climate-related opportunities that enable continued business success while serving the needs of our customers. Our investments help reduce regional emissions while improving shareholder value. Meanwhile, our energy efficiency solutions, building electrification and electric vehicle infrastructure investments allow our customers to make choices that minimize climate-related impacts. As our business transitions to support a more energy diverse economy, human capital needs will also change with the potential to impact our workforce. As new technologies are implemented, we will need to recruit, develop and possibly retrain employees to meet the need for new skill sets. Electric and Magnetic Fields For more than forty years, published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF) associated with electric transmission and distribution facilities, including appliances, and wiring in buildings and homes. Some epidemiology studies have reported a possible statistical association between adverse health effects and exposure with EMF. The association identified in some of these studies remain unexplained and inconclusive. Numerous scientific review panels, considering all significant EMF epidemiology and laboratory studies, have concluded that the available body of scientific information does not support a conclusion that EMF affects human health at levels expected in the vicinity. In accordance with recommendations of various regulatory bodies and public health organizations, we use design principles that help reduce potential EMF exposures associated with new transmission lines. HUMAN CAPITAL Eversource Energy is committed to delivering reliable energy and exceptional customer service, expanding energy solutions for our region, promoting environmental stewardship, ensuring a safe and fairly compensated workforce, and demonstrating leadership through community engagement. Our employees are essential to achieving these objectives, and we prioritize attracting, retaining, and developing top talent while upholding fairness and equal employment opportunity for all. 14
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Leaders at every level foster a workplace where employees are engaged, empowered, and collaborative by advocating for customers, sharing ideas for improvement, and focusing on delivering superior experiences. We strengthen engagement through ongoing communication, robust talent development programs, and a culture of teamwork. To drive accountability, we maintain corporate scorecard metrics and annual goals in areas such as safety performance and talent management ensuring measurable progress across the entire Eversource Energy organization. As of December 31, 2025, Eversource Energy employed a total of 10,731 employees, excluding temporary employees, of which 1,554 were employed by CL&P, 2,164 were employed by NSTAR Electric, and 802 were employed by PSNH. Of Eversource Energy’s employees, 4,495 were employed by Eversource Service, Eversource's service company, that provides support services to all Eversource operating companies. Approximately 49 percent of our employees are members of the International Brotherhood of Electrical Workers, the Utility Workers Union of America or The United Steelworkers, and are covered by various collective bargaining agreements. Safety. At Eversource, our commitment to “Safety First and Always” is a principle and a mindset present in every job and every task, whether in the field, office or at home. A priority at Eversource is continuous improvement and safety is at the forefront as we continue to build a strong safety culture, embrace new technologies, and learn with our industry and community partners to improve safety performance. We provide safety training and perform field safety job observations of both internal and contractor crews with a focus on high-energy hazards. We use a series of both industry specific and state and federal metrics to monitor safety performance. A key metric is the OSHA-designed Days Away Restricted Time (DART), which measures the amount of time employees are out of work or on restricted duty as a result of a safety incident. We continue to perform substantially better than the performance goal range and within the top half of the industry, albeit slightly below our DART metric from the prior year, from 0.76 in 2024 to 0.87 in 2025. Workforce Engagement. At Eversource, we are committed to fostering an empowered, engaged workforce that delivers superior service safely to our customers. We believe that a culture of respect and collaboration drives innovation and strengthens trusted relationships with employees, customers, suppliers, and community partners. Our approach includes partnering with programs and agencies that address the unique challenges facing the communities we serve. Employee engagement remains a priority because we know that engaged employees deliver outstanding service. We regularly gather feedback through pulse surveys for individual groups and Business Resource Groups (BRGs), listening sessions, employee meetings, and our online employee community. These insights inform actions that support productivity, customer focus, and evolving work expectations. Throughout the year, we delivered programs, events and discussions aimed at strengthening employee engagement and reinforcing our collaborative culture. We also enhanced our Employee Value Proposition, underscoring Eversource’s commitment to safety, our customers, and sustainability. This proposition serves as a clear message to employees, customers, investors, and prospective candidates, demonstrating how our values guide the employee experience and contribute to long-term organizational success. Leadership and Talent Development. Our executive leadership team actively promotes a culture of engagement by building and leading dynamic, high- performing teams. Leaders are committed to growing a pipeline of exceptional talent, leveraging diverse perspectives to enhance customer service, and engaging with the communities we serve. Recognizing that employees are our most valuable component to the success of our business, we integrate workforce strategies into our annual business and workforce planning process to address immediate and long-term resource needs. In 2025, we launched the Eversource Leadership Development Cohort for high-potential employees, offering senior management interaction, targeted coaching, and learning experiences that promote independent thinking, collaboration and inclusion of different perspectives. We provided targeted training and educational opportunities to all employees to ensure continued growth in the utility industry. Interactive tools and resources supported learning effectiveness and the development of business, leadership, and technical skills. Development initiatives were aligned with strategic workforce plans to support succession planning across all levels of the organization. Additionally, we offered professional development for recent college graduates through our Engineering and Transmission Development Cohorts program. To attract and retain talent in critical technical roles, we partnered with trade organizations and educational institutions within our communities. These partnerships, along with proactive sourcing strategies, help us recruit experienced professionals in engineering, electric and gas operations, and energy efficiency. Employees benefit from competitive pay, comprehensive benefits, and robust training programs, including tuition assistance, internships, co- ops, and leadership development initiatives, all reinforcing equal opportunity, non-discrimination, and advancement based on merit and performance. Strategic Workforce Planning. As the demand for skilled talent grows. Eversource continues to adapt its recruiting strategies for trade and technical roles. Each year, we develop strategic workforce plans to identify short-term and long-range resource needs, ensuring we acquire, develop, and retain top talent. We remain focused on innovative approaches to build and strengthen the workforce, expanding programs to meet business needs, and building a pipeline of technically qualified individuals while maintaining fairness and equal opportunity for all candidates. Compensation, Health and Wellness Benefits. Eversource is committed to fostering a safe, healthy, and supportive work environment. We offer competitive compensation and comprehensive benefits, including healthcare, life insurance, disability coverage, retirement, an Employee Stock Purchase Plan, paid time off, and tuition assistance. Additional programs include health savings and flexible spending accounts, employee assistance services, and wellness initiatives designed to promote healthy lifestyles for employees and their families. To support work-life balance, Eversource has established flexible work guidelines and provides hybrid work arrangements for eligible positions. 15
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Community & Social Impact. Eversource is committed to strengthening the communities where we live and work. Through the Eversource Foundation, we provide grants to nonprofit organizations that drive meaningful, sustainable change and address critical community needs. In addition to financial support, our employees actively volunteer their time and expertise to charitable programs focused on high-priority local concerns. These efforts reflect our ongoing commitment to making a positive difference for our customers and the communities we serve. See our 2024 Sustainability Report located on our website, for more detailed information regarding our human capital programs and initiatives. Nothing on our website, including our Sustainability Report, or sections thereof, shall be deemed incorporated by reference into this Annual Report. INTERNET INFORMATION Our Investor Relations website address is investors.eversource.com. We make available through our website a link to the SEC's EDGAR website (http://www.sec.gov/edgar/searchedgar/companysearch.html), at which site Eversource's, CL&P's, NSTAR Electric's and PSNH's combined Annual Reports on Form 10-K, combined Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed. Information contained on the Company's website or that can be accessed through the website is not incorporated into and does not constitute a part of this Annual Report on Form 10-K. Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Eversource Energy, 247 Station Drive, Westwood, MA 02090. Item 1A. Risk Factors In addition to the matters set forth under "Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995" included immediately prior to Item 1, Business, above, we are subject to a variety of material risks. Our susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks. These risk factors should be considered carefully in evaluating our risk profile. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect our financial position, results of operations, and cash flows. Cybersecurity Risks: Cyber events, including acts of war or terrorism, targeted directly on or indirectly affecting our systems or the systems of third parties on which we rely, could severely impair operations, negatively impact our business, lead to the disclosure of confidential information and adversely affect our reputation. Cyberattacks that seek to exploit potential vulnerabilities in the utility industry and seek to disrupt electric, natural gas and water transmission and distribution systems are increasing in sophistication including artificial intelligence, magnitude and frequency. Various geo-political conflicts and acts of war around the world continue to result in increased cyberattacks against critical infrastructure. In addition to intentional attacks, we also face risks from other cybersecurity events, such as software defects, misconfigurations, system integration failures and problematic third-party software or firmware updates that can cause widespread outages or disruptions even in the absence of a deliberate attack. A successful cyberattack or other significant cyber event affecting technology systems that control our transmission, distribution, natural gas and water systems or other assets could impair or prevent us from managing these systems and facilities, operating our systems effectively, or properly managing our data, networks and programs. The breach or failure of certain information or operational technology systems could adversely affect our ability to correctly record, process and report financial information. A major cyber event could result in significant expenses to investigate and to repair system damage or security breaches and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to our reputation. We have instituted safeguards to protect our technology systems and assets; however, we cannot guarantee that our security efforts will prevent or deter cyberattacks. We deploy substantial technologies to system and application security, encryption and other measures to protect our computer systems and infrastructure from unauthorized access or misuse and to detect and respond to cyber events. Specifically, regarding vulnerabilities, we patch systems timely where patches are available to deploy and have technologies that detect exploits of vulnerabilities and proactively block the exploit when it happens. We also interface with numerous external entities to improve our cybersecurity situational awareness. The FERC, through the North American Electric Reliability Corporation (NERC), requires certain safeguards to be implemented to deter cyberattacks. These safeguards may not always be effective due to the evolving nature of cyberattacks. We maintain cyber insurance to cover damages, potential ransom and defense costs related to breaches of network or operational technology, but it may be insufficient in limits and coverage exclusions to cover all losses. For further information, see Item 1C, Cybersecurity included in this Annual Report on Form 10-K. The unauthorized access to, and the misappropriation of, confidential and proprietary Company, customer, employee, financial or system operating information could adversely affect our business operations and adversely impact our reputation. In the regular course of business, we, and our third-party suppliers, rely on information technology to maintain sensitive Company, customer, employee, financial and system operating information. We are required by various federal and state laws to safeguard this information. Cyber intrusions, security breaches, theft or loss of this information by cybercrime or otherwise could lead to the release of critical operating information or confidential Company, customer or employee information, which could adversely affect our business operations or adversely impact our reputation and could result in significant costs, fines and litigation. We employ system controls to prevent the dissemination of certain confidential information and train employees on phishing risks. We maintain cyber insurance to cover damages, costs related to a system disruption, potential ransom and defense costs arising from unauthorized disclosure of, or failure to protect, private information, as well as costs for notification to, or 16
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for credit monitoring of, customers, employees and other persons in the event of a breach of private information. This insurance covers amounts paid to address a network attack or the disclosure of personal information and costs of a qualified forensics firm to determine the cause, source and extent of a network attack or to investigate, examine and analyze our network to find the cause, source and extent of a data breach, but it may be insufficient to cover all losses. While we have implemented measures designed to prevent network attacks and mitigate their effects should they occur, these measures may not be effective due to the continually evolving nature of efforts to access confidential information. We are increasingly integrating artificial intelligence (AI) into our operations, and while these technologies offer operational benefits, they also introduce significant risks that could adversely impact our business and results of operations. We deploy AI tools and models in areas such as weather forecasting, grid planning, asset management, customer service and internal support functions. This deployment is overseen by an internal governance and oversight committee, which has established policies and procedures and reviews and approves the use of AI throughout the organization. AI systems may produce inaccurate, biased or otherwise unreliable forecasts or recommendations due to flawed algorithms, limited training data or unforeseen conditions which could result in service disruptions, regulatory penalties and reputational harm. Evolving AI regulations may impose new compliance and reporting obligations or restrict usage and stakeholders may raise concerns about transparency, bias, and accountability. Despite implementing a governance framework and policies and controls in place related to AI use, including human oversight of critical decisions and outputs, these risks could negatively affect operations, expose us to litigation or regulatory penalties or fines, increase costs and impair our ability to meet customer expectations, which could have a material adverse impact on our financial position, results of operations, and cash flows. Regulatory, Legislative and Compliance Risks: The actions of regulators and legislators could result in outcomes that may adversely affect our earnings and liquidity. Rate Regulation, Cost Recovery and Affordability Our electric, natural gas, and water utility companies are subject to regulation by federal and state agencies and each is required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for service. Our regulated companies are entitled to charge rates that are sufficient to recover prudently incurred costs and a reasonable return on investment on invested capital. Regulatory decisions may require us to cancel, delay, or reduce planned investments or incur costs we cannot recover. Rates are subject to prudency reviews, refunds or disallowances and may not align with the timing of costs incurred. Adverse outcomes, including reductions in allowed rate of return, disallowance of costs or delays in rate adjustment, could adversely affect our financial position, results of operations and cash flows. Customer affordability concerns, driven by volatility in energy supply costs, evolving public policy mandates and inflationary pressures, may limit our ability to recover costs or fund infrastructure upgrades. Regulators may respond by imposing stricter cost recovery standards, delaying or denying rate increases or cost recovery or requiring alternative funding mechanisms increasing financial uncertainty. Heightened political and public scrutiny of rate- setting processes may also lead to additional compliance obligations or reputational risk. These factors could adversely affect our financial position, results of operations and cash flows. State-Level Risks State commissions regulate rates, operations, accounting and certain financing activities. Rates are set in comprehensive base rate proceedings based on an analysis of invested capital, expenses and other factors, subject to periodic review and adjustments. Regulatory proceedings typically involve multiple parties who have differing concerns and can challenge our current or future rates, and these proceedings can be contentious, lengthy, and subject to appeal. This may lead to uncertainty as to the ultimate result of those proceedings. Regulatory commissions may challenge the reasonableness or prudency of operating expenses (including storm restoration costs) incurred or capital investments made by our regulated operating companies and deny the full recovery of cost of service in rates. Established rates are subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed, including cost recovery mechanisms. The ultimate outcome and timing of regulatory rate proceedings or challenges to certain provisions in our distribution tariffs could have a significant effect on our ability to recover costs timely, or at all, or earn an adequate return. We have incurred significant storm restoration costs that are not yet approved by the regulatory commissions, and though we believe those costs were prudently incurred, it is possible that some amount may be disallowed. Regulators may also impose penalties or reduce allowed returns, which would adversely affect our financial condition. Additionally, catastrophic events at other utilities could lead to new requirements that increase costs. We continue to monitor the evolving regulatory environment in Connecticut, including changes in the composition of PURA, which may affect our electric, natural gas and water businesses in that state. Adverse decisions in our proceedings could adversely affect our credit ratings, financial position, results of operations, and cash flows. Regulatory approval is also required for certain dispositions of property and plant, mergers and consolidations and issuances of long-term securities, and construction and operation of facilities. Failure to obtain required approvals on a timely basis, or at all, could result in increased costs, the postponement or cancellation of planned transactions or projects, changes in financing strategies, and an adverse effect on our financial condition, results of operations, and ability to implement our business strategy. Federal-Level Risks The FERC has jurisdiction over our transmission cost recovery and our allowed ROEs on transmission investments. If FERC changes its methodology on developing ROEs or eliminates certain transmission incentives, it could negatively impact our financial position, results of operations and cash flows. From time to time, various matters are pending before FERC relating to transmission rates, incentives, interconnections and transmission planning. Depending on the outcome, any of these matters could materially impact our results of operations and financial 17
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condition. Additionally, outside parties have filed four complaints against transmission-owning electric companies within ISO-NE, alleging that our allowed ROEs are unjust and unreasonable. An adverse decision in any of these four complaints could adversely affect our financial position, results of operations and cash flows. Further, FERC's policy has encouraged competition for transmission projects as it looks to expand the transmission system to accommodate state and federal policy as well as to enhance reliability and resilience for extreme weather events while lowering costs. Implementation of FERC's goals may expose us to competition for construction of transmission projects, which could result in being exposed to cost caps or a reduced ROE in order to win a project bid, additional regulatory considerations and potential delay with respect to future transmission projects, which may adversely affect our results of operations and lower rate base growth. New processes and planning frameworks, including ISO-NE’s Longer-Term Transmission Planning (LTTP) competitive solicitation process and advisory role as asset condition reviewer, introduce uncertainty around project timing, scope and cost recovery. Competitive solicitations for certain transmission projects may require us to compete against non-incumbent developers, rather than relying on traditional cost-of-service recovery. Failure to secure projects through these processes could reduce transmission investment opportunities and associated incentives, adversely affecting our financial position, results of operations and cash flows. Changes in tax laws, as well as the potential tax effects of business decisions or other actions by the federal government such as Presidential executive orders could negatively impact our business, financial position, results of operations and cash flows. We are exposed to significant reputational risks, which make us vulnerable to increased regulatory oversight or other sanctions. Our electric, natural gas and water utility subsidiaries serve large customer bases and are subject to adverse publicity regarding service safety, reliability and response times to outages, leaks or other interruptions, including those related to storms or climate change. Negative publicity can harm our reputation, influence legislative and regulatory bodies, and result in unfavorable outcomes, such as stricter operational standards, vegetation management requirements, fines, penalties or other sanctions. We also depend on third-party suppliers for power and natural gas. Factors such as inflation, tariffs, geopolitical conflicts, rising energy demand, supply costs, and public policy charges contribute to high customer bills in New England. In extreme cases, ISO-NE may require load shed if regional power capacity is insufficient. High customer bills or failure to meet energy needs could reduce customer satisfaction adversely affecting our business, reputation, financial position, results of operations, and cash flows. Addressing adverse publicity, regulatory actions or legal proceedings is costly and time-consuming and can negatively impact employee morale and relationships with regulators, customers and counterparties. Future legislative or regulatory changes are unpredictable, and we cannot ensure we are able to respond adequately. The direct and indirect effects of negative publicity may materially affect our financial position, results of operations, and cash flows. Costs of compliance with environmental laws and regulations, including those related to climate change, may increase and have an adverse effect on our business and results of operations. The costs of compliance with existing legal requirements may increase in the future. Although we have recorded liabilities for known environmental obligations, these costs can be difficult to estimate due to uncertainties such as the extent of contamination, remediation alternatives, the remediation levels required by state and federal agencies, change in environmental regulations, and the financial ability of other potentially responsible parties. An increase in such costs, unless promptly recovered, could have an adverse impact on our business and our financial position, results of operations and cash flows. Our subsidiaries’ operations are also subject to extensive and increasing federal, state and local environmental statutes, rules and regulations that govern, among other things, water quality (including treatment of PFAS (Per- and Polyfluoroalkyl Substances) and lead), water discharges, the management of hazardous material and solid waste, and air emissions including greenhouse gases. Compliance with these requirements requires us to incur significant costs relating to environmental permitting, monitoring, maintenance and upgrading of facilities, remediation, and reporting. For our water business, compliance with water quality regulations, including those for PFAS and lead, could require the construction of facilities and replacement of customer lead service lines, respectively. In each of the states that we operate, there are requirements for purchases of renewable energy credits from the generation of renewable energy. As the requirement for credits increases and outpace the renewable energy coming online, we may be required to pay higher prices and make alternative compliance payments to the states. Unless renewable energy availability is increased to meet these credit requirements, we will face the risk of increasing costs. For further information, see Item 1, Business – Other Regulatory and Environmental Matters, included in this Annual Report on Form 10-K. Offshore Wind Contingent Liability and Tax Risk: Variability in the costs and final investment returns of the Revolution Wind and South Fork Wind offshore wind projects no longer owned by Eversource and the inability to monetize investment tax credits could have an adverse impact on our financial position, results of operations, and cash flows.
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Following the sale of our 50 percent ownership share in the South Fork Wind and Revolution Wind projects, we have continuing financial exposure as it relates to the purchase price post-closing adjustment payments under the terms of the sale agreement with Global Infrastructure Partners (GIP) for these projects. Our future obligations under the sale terms primarily include a capital expenditure overrun sharing obligation, an obligation to maintain GIP’s internal rate of return through the construction period for each project, and obligation for other future costs prior to commercial operation. Post-closing purchase price adjustment payments are owed following the commercial operation of Revolution Wind. Factors that could increase the post-closing adjustment payments owed to GIP include the ultimate cost of construction and timing and extent of cost overruns for Revolution Wind, delays in construction such as from federal governmental stop work orders, damage to equipment, and weather conditions, which would also impact the economics associated with the purchase price adjustment, and Revolution Wind’s eligibility for federal investment tax credits (ITCs) at a value lower than assumed and included in the purchase price. New information that becomes available or future developments that arise as the construction of Revolution Wind progresses could result in increased costs of the project that would ultimately be owed to GIP. Adverse changes in facts and circumstances, regulations or Presidential executive orders could increase the obligation under the sale agreement above the amount accrued and result in additional losses, which could have a material adverse effect on our financial position, results of operations, and cash flows. The purchase price included the sales value related to a 40 percent level of federal ITCs, 10 percent of which is the energy community ITC adder included in the Inflation Reduction Act related to Revolution Wind. If the project does not meet the qualifications under federal tax law for the full value of the ITC or there are changes to tax law, it could have a material adverse effect on our financial position, results of operations, and cash flows. Additionally, we hold a tax equity investment in South Fork Wind that is expected to result in cash flow benefits from ITCs at a 30 percent level. The tax treatment of the ITCs could be challenged and is subject to audit by the IRS. If the project does not meet the qualifications under federal tax law, we may be unable to monetize the ITCs that support this investment, which could have a material adverse effect on our financial position, results of operations, and cash flows. Risks Related to the Environment and Catastrophic Events: The effects of climate change, including severe storms, could cause significant damage to any of our facilities or assets requiring extensive expenditures, the recovery for which is subject to approval by regulators. Climate change creates physical and financial risks to our operations. Physical risks from climate change may include an increase in sea levels and changes in weather conditions, such as changes in precipitation, extreme heat and weather events, including the effects of significantly stronger wind- related events. To the extent weather conditions are affected by climate change, customers’ energy and water usage could increase or decrease depending on the duration and magnitude of the changes. Severe weather induced by climate change, such as extreme and frequent ice and snowstorms, tornadoes, micro-bursts, hurricanes, floods, droughts, wildfires, landslides, excess humidity and other natural or weather-related phenomenon, may cause outages and property damage, which may require us to incur additional costs that may not be recoverable from customers. The cost of repairing damages to our operating subsidiaries' facilities and the potential disruption of their operations due to the increase in frequency and severity of storms, natural disasters or other catastrophic events could be substantial, particularly as regulators and customers demand better and quicker response times to outages. If, upon review, any of our state regulatory authorities finds that our actions were imprudent, some of those restoration costs may not be recoverable from customers and could result in penalties or fines. The inability to recover a significant amount of such costs could have an adverse effect on our financial position, results of operations and cash flows. We maintain property insurance, but it may be insufficient in limits and coverage exclusions to cover all losses. Additionally, these types of weather events risk interruption of the supply chain and could disrupt the delivery of goods and services required for our operations. Transitional impacts related to climate change may have an adverse effect on our business and results of operations due to costs associated with new technologies, evolving customer expectations and changing workforce needs. Initiatives to mitigate the impacts of climate change, support a transition to cleaner energy, and reduce emissions, may have a material adverse financial impact on our business. These impacts include the costs associated with the development and implementation of new technologies to maintain system reliability and resiliency and lower emissions, including grid modernization and energy storage. An increase in such costs, unless promptly recovered, could have an adverse impact on our financial position, results of operations, and cash flows. There may also be financial and reputational risks if we fail to meet evolving customer expectations, including enabling the integration of residential renewables and providing low carbon solutions, such as electric vehicle infrastructure and energy efficiency services. Additionally, actions to mitigate climate change may result in a transition in our workforce that must adapt to meet the need for new job skills. Associated costs include training programs for existing employees and workforce development as we transition to new technologies and clean energy solutions. Further, the view of natural gas as an attractive fuel source for heating and power generation may be at risk. Certain environmental activist groups, investors and governmental entities continue to oppose natural gas delivery and infrastructure investments because of perceived environmental impacts associated with the natural gas supply chain and end use. 19
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Adequacy of water supplies and contamination of our water supplies, the failure of dams on reservoirs providing water to our customers, or requirements to repair, upgrade or dismantle any of these dams, may disrupt our ability to distribute water to our customers and result in substantial additional costs, which could adversely affect our financial position, results of operations, and cash flows. Our water business faces an inherent strategic risk related to adequacy of supply (i.e., water scarcity). We expect that climate change will cause both an increase in demand due to increasing temperatures and a potential for a decrease in available supply due to shifting rainfall and recharge patterns. Regulatory constraints also present challenges to permit new sources of supply in the region. In Connecticut, where most of our dams are located, impounded waterways are required to release minimum downstream flow. New regulations are being phased into effect over the next one to five years that will increase the volume of downstream releases required across our Connecticut service territory, depleting the volume of supply in storage that is used to meet customer demands. This combination of factors may cause an increased likelihood of drought emergencies and water use restrictions that could adversely affect our ability to provide water to our customers, and reputational/brand damage that could negatively impact our water business. Our water supplies, including water provided to our customers, are also subject to possible contamination from naturally occurring compounds and elements or non-organic substances, including PFAS. Although we believe our water supply facilities, dams, reservoirs, and groundwater sources are structurally sound and well-maintained, significant damage to these facilities, or a significant decrease in the water supplies (reservoirs and groundwater), could adversely affect our ability to provide water to our customers until the facilities and enough water can be restored. A failure of a dam could result in personal injuries and downstream property damage for which we may be liable. The failure of a dam would also adversely affect our ability to supply water in sufficient quantities for our customers. Any losses or liabilities incurred due to a failure of one of our dams may not be recoverable in rates and may have a material adverse effect on our financial position, results of operations, and cash flows. We maintain liability insurance, but it may be insufficient in limits and coverage exclusions to cover all losses. Physical attacks, including acts of war or terrorism, both threatened and actual, could adversely affect our ability to operate our systems and could adversely affect our financial results and liquidity. Physical attacks, including acts of war or terrorism, both threatened and actual, that damage our transmission and distribution systems or other assets could negatively impact our ability to transmit or distribute energy, water, natural gas, or operate our systems efficiently or at all. Because our electric transmission systems are part of an interconnected regional grid, we face the risk of widespread blackouts due to grid disturbances or disruptions on a neighboring interconnected system. Similarly, our natural gas distribution system is connected to transmission pipelines not owned by Eversource. If there was an attack on the transmission pipelines, it could impact our ability to deliver natural gas. If our assets were physically damaged and were not recovered in a timely manner, it could result in a loss of service to customers, a significant decrease in revenues, significant expense to repair system damage, costs associated with governmental actions in response to such attacks and liability claims, all of which could have a material adverse impact on our financial position, results of operations and cash flows. We maintain property and liability insurance, but it may be insufficient in limits and coverage exclusions to cover all losses. In addition, physical attacks against third-party providers could have a similar effect on the operation of our systems. Business and Operational Risks: Strategic development or investment opportunities in electric transmission, distributed generation, or clean-energy technologies may not be successful, which could have a material adverse effect on our business prospects. We are pursuing investment opportunities in electric transmission facilities, distributed generation and other clean-energy infrastructure, including interconnection facilities. The development of these projects involves numerous significant risks including federal, state and local permitting and regulatory approval processes, scheduling or permitting delays, increased costs, tax strategies and changes to federal tax laws, new legislation impacting the industry, including clean energy programs, economic events or factors, environmental, community, and customer affordability concerns, design and siting issues and difficulties in obtaining required rights of way. Also, supply constraints in New England have led to significant increases in commodity costs which may impact our ability to accomplish our strategic objectives. Further, regional clean energy goals may not be achieved if local, state and federal policy is not aligned with integrated planning of our infrastructure investments or if goals result in a significant increase to customer rates. Our transmission and distribution systems may not operate as expected, and could require unplanned expenditures, which could adversely affect our financial position, results of operations, and cash flows. Our ability to safely and properly operate our transmission and distribution systems is critical to the financial performance of our business. Our transmission and distribution businesses face several operational risks, including the breakdown, failure of, or damage to operating equipment, information technology systems, or processes, especially due to age; labor disputes; disruptions in the delivery of electricity, natural gas and water; increased capital expenditure requirements, including those due to environmental regulation; catastrophic events resulting from equipment failures such as wildfires and explosions, or external events such as a solar event, an electromagnetic event, or other similar occurrences; increasingly severe weather conditions due to climate change beyond equipment and plant design capacity; human error; global supply chain disruptions; and potential claims for property damage or personal injuries beyond the scope of our insurance coverage. If the in-service date for one or more of our transmission projects is delayed due to economic events or factors, or regulatory or other delays, including permitting and siting, the risk of failures in the electric transmission system may increase. We also implement new information technology systems from time to time, which may disrupt operations. Any failure of our transmission and distribution systems to operate as planned may result in increased capital costs, reduced earnings or unplanned increases in operations and maintenance costs. The inability to recover a significant amount of such costs could have an adverse effect on our financial position, results of operations, and cash flows. 20
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New technology and alternative energy sources could adversely affect our operations and financial results. Advances in technology that reduce the costs of alternative methods of producing electric energy to a level that is competitive with that of current electric production methods, could result in loss of market share and customers and may require us to make significant expenditures to remain competitive. These changes in technology, including micro-grids and advances in energy or battery storage, could also alter the channels through which electric customers buy or utilize energy, which could reduce our revenues or increase our expenses. Economic downturns or periods of high energy supply costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency and self-generation by customers. Additionally, in response to risks posed by climate change, we may need to make investments in our system including upgrades or retrofits to meet enhanced design criteria, which can incur additional costs over conventional solutions. We rely on third-party suppliers for equipment, materials, and services and we outsource certain business functions to third-party suppliers and service providers, and substandard performance or inability to fulfill obligations by those third parties could harm our business, reputation and results of operations. We outsource certain services to third parties in areas including information technology, transaction processing, human resources, payroll and payroll processing and certain operational areas. Outsourcing services to third parties could expose us to substandard quality of service delivery, which may result in missed deadlines or other timeliness issues, non-compliance (including with applicable legal requirements and industry standards) or reputational harm, which could negatively impact our results of operations. Our contractual arrangements with these contractors typically include performance standards, progress payments, insurance requirements and security for performance. The global supply chain of goods and services generally has stabilized; however, certain specialized equipment has long lead times and inflated prices, as well as competition from within and outside the utility industry. Additionally, rising geo-political tensions could negatively impact the global supply chain. If significant difficulties in the global supply chain cycle or inflationary impacts were to reemerge, they could adversely affect our results of operations, or adversely affect our ability to work with regulators, unions, customers or employees. The loss of key personnel, the inability to hire and retain qualified employees, or the failure to maintain a positive relationship with our workforce could have an adverse effect on our business, financial position and results of operations. Our operations depend on the continued efforts of our employees. We cannot guarantee that any member of our management or any key employee at the Eversource parent or subsidiary level will continue to serve in any capacity for any period. Our workforce in our subsidiaries includes many workers with highly specialized skills safely maintaining and servicing the electric, natural gas and water infrastructure that cannot be quickly replaced due to the technically complex work they perform. We have developed strategic workforce plans to identify key functions and proactively implement plans to ensure a ready and qualified workforce, but we cannot predict the impact of these plans on our ability to hire and retain key employees. Labor disputes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms, as well as the increased competition for talent or the intentional misconduct of employees or contractors, may also have an adverse effect on our business, financial position and results of operations. Financial, Economic, and Market Risks: Limits on our access to, or increases in, the cost of capital may adversely impact our ability to execute our business plan. We use short-term debt and long-term capital markets as a significant source of liquidity and funding for capital requirements not obtained from our operating cash flow. If access to these sources of liquidity becomes constrained, our ability to implement our business strategy could be adversely affected. Interest rate increases on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly, which could adversely impact our financial position, results of operations and cash flows. Downgrades of our credit ratings or events beyond our control, such as a disruption in global capital and credit markets, could increase our cost of borrowing and cost of capital or restrict our ability to access the capital markets and negatively affect our ability to maintain and to expand our businesses. Market performance or changes in assumptions may require us to make significant contributions to our pension and other postretirement benefit plans. We provide a defined benefit pension plan and other postretirement benefits for a substantial number of employees, former employees and retirees. Our future pension obligations, costs and liabilities are highly dependent on a variety of factors, many of which are beyond our control. If our assumptions prove to be inaccurate, our future costs could increase significantly. In addition, various factors, including underperformance of plan investments and changes in law or regulation, could increase the required contribution amount to fund our pension plan in the future. Additional large funding requirements, when combined with the financing requirements of our construction program, could impact the timing, amounts, and number of future financings and negatively affect our financial position, results of operations and cash flows. Goodwill and long-lived assets if impaired and written down, could adversely affect our future operating results and total capitalization. We have a significant amount of goodwill on our consolidated balance sheet, which, as of December 31, 2025 totaled $4.23 billion. The carrying value of goodwill represents the fair value of an acquired business in excess of the fair value of identifiable assets and liabilities as of the acquisition date. We test our goodwill balances for impairment on an annual basis or whenever events occur, or circumstances change that would indicate a potential for impairment. A determination that goodwill is deemed to be impaired would result in a non-cash charge that could materially adversely affect our financial position, results of operations, and total capitalization.
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We assess our long-lived assets for impairment whenever events or circumstances indicate that the carrying amount of the investment may not be recoverable. To the extent the value of the investment becomes impaired, the impairment charge could have a material adverse effect on our financial position and results of operations. Our counterparties may not meet their obligations to us or may elect to exercise their termination rights, which could adversely affect our earnings. We are exposed to the risk that counterparties to various arrangements that owe us money, have contracted to supply us with energy or other commodities or services, or that work with us as strategic partners including on significant capital projects, will not be able to perform their obligations, will terminate such arrangements or, with respect to our credit facilities, fail to honor their commitments. Should any of these counterparties fail to perform their obligations or terminate such arrangements, we might be forced to replace the underlying commitment at higher market prices and/or delay the completion of, or cancel, a capital project. Should any lenders under our credit facilities fail to perform, the level of borrowing capacity under those arrangements could decrease. In any such events, our financial position, results of operations or cash flows could be adversely affected. As a holding company with no revenue-generating operations, Eversource parent's liquidity is dependent on dividends from its subsidiaries, its commercial paper program, and its ability to access the long-term debt and equity capital markets. Eversource parent is a holding company and as such has no revenue-generating operations of its own. Its ability to meet its debt service obligations and to pay dividends on its common shares is largely dependent on the ability of its subsidiaries to pay dividends to, or repay borrowings from, Eversource parent, and/or Eversource parent's ability to access its commercial paper program or the long-term debt and equity capital markets. Prior to funding Eversource parent, the subsidiary companies have financial obligations that must be satisfied, including among others, their operating expenses, debt service, preferred dividends of certain subsidiaries, and obligations to trade creditors. Should the subsidiary companies not be able to pay dividends or repay funds due to Eversource parent or if Eversource parent cannot access its commercial paper programs or the long-term debt and equity capital markets, Eversource parent's ability to pay interest, dividends and its own debt obligations would be restricted. Item 1B. Unresolved Staff Comments We do not have any unresolved SEC staff comments. Item 1C. Cybersecurity The Company’s policies, practices and technologies allow it to protect its information systems and operational assets from threats. The Board of Trustees and its Finance and Risk Management Committee and Audit Committee continue to provide substantial and focused attention to cyber and system security. The Finance and Risk Management Committee of the Board of Trustees is responsible for oversight of the Company’s enterprise-wide risks, including risks associated with cyber and physical security, and the Company’s programs and practices to monitor and mitigate these risks. Management prepares comprehensive cyber security reports that are discussed at each meeting of the Finance and Risk Management Committee. The reports focus on the changing threat landscape and the risks to the Company, describe Eversource’s cyber security drills and exercises, attempted and actual breaches on our systems, cyber incidents within the utility industry and around the world, and mitigation strategies. In addition, third-party experts of cyber security risks provide periodic assessments to the utility industry and the Company in particular to the Finance and Risk Management Committee. The Company regularly reviews and updates its cyber and system security programs, and the Finance and Risk Management Committee continues to enhance its robust oversight activities, including meetings with financial, information technology, legal and accounting management, other members of the Board, representatives of the Company’s independent registered public accounting firm, and outside advisors and experts in cyber security risks, at which cyber and system security programs and issues that might affect the Company’s financial statements and operational systems are discussed. The Company has a robust Enterprise Risk Management Program that has identified cyber security as a top enterprise risk. The managing and monitoring of risks are the responsibility of the Company’s Risk Committee, which meets quarterly and is chaired by the Chief Financial Officer. Members include key leaders of the Company, including the Presidents of each operating business unit, the Chief Information Officer, Chief Customer Officer, Chief Accounting Officer and Chief Compliance Officer. The Company is committed to continuous monitoring and assessment of cyber security controls. The Chief Information Security Officer is responsible for developing, implementing, and enforcing our cyber security program and information security policies to protect the Company’s information systems and operational assets. The Chief Information Security Officer position requires at least 15 years of relevant information security experience and relevant security certifications. The Chief Information Security Officer reports directly to the Chief Information Officer and provides regular updates to the executive management team. Our Chief Information Security Officer has over 20 years of relevant experience. The Company created a Cyber Governance Committee, which includes the Chief Information Security Officer, Chief Information Technology Officer, Chief Accounting Officer, members of the executive management team, and other assurance functions such as Corporate Compliance, Enterprise Risk Management, and Internal Audit. 22
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To assess, identify and manage material risks from cybersecurity threats and to prevent, detect, mitigate and remediate a cyber security incident, the following key processes and programs have been implemented and are performed by the Company’s Cyber Security Group, which is overseen by the Chief Information Security Officer: • Implementation of security solutions and standards based on industry best practices to prevent unauthorized access. The Company’s cyber program has been modeled after the Department of Energy’s Cyber Capability Maturity Model and the National Institute of Standards and Technology framework; both widely accepted frameworks utilized by utilities and other critical infrastructure industries. • Periodic external assessments, including outside system access testing, are performed. Rigorous auditing of all safeguards is performed on a regular basis. Risk assessments are held to identify and address new and changing risks to protect systems and sensitive data. Identified areas are monitored and improvements are implemented. • Eversource participates in information sharing programs both within and outside the utility industry, including with the U.S. government and industry organizations, to be able to identify and respond to emerging threats. • Established an Artificial Intelligence Executive Working Committee to ensure a “Secure by Design” approach to implementations of artificial intelligence. • The Company maintains current incident response and business continuity plans, which are periodically updated and tested. • Network activity is monitored on an ongoing basis. • Anti-phishing and malware tools are utilized and assessed. • Employees are trained to recognize phishing attempts and are periodically tested. Results of phishing testing are benchmarked against other companies both within and outside the utility industry. Specific to third parties, Eversource has implemented formal screening processes for any applicable vendors by the Company’s Cyber Security Group as part of the Procurement process. The vendors are risk ranked based on the type of work being performed. Periodic rescreening is performed on critical vendors. Vendors are required to attest to their business continuity programs and provide evidence of appropriate insurance and indemnification agreements. The Company bars sourcing from countries included on the Department of Homeland Security’s list of Prohibited Nations to further protect the Company’s supply chain. The Company maintains cyber insurance which covers breaches of networks and operational technology. Our existing insurance limits may be inadequate to cover a material cyber incident. This could expose us to potentially significant claims and damages. As of December 31, 2025, there were no cyber incidents that have materially affected or are reasonably likely to materially affect the Company, its business strategy, results of operations, or financial condition. Item 2. Properties Transmission and Distribution System As of December 31, 2025, Eversource and our electric operating subsidiaries owned the following: Electric Distribution Electric TransmissionEversource Number of substations owned 458 77 Transformer capacity (in kVa) 48,310,570 16,312,600 Overhead lines (in circuit miles) 40,650 4,007 Underground lines (in circuit miles) 19,220 460 Capacity range of overhead transmission lines (in kV) N/A 69 to 345 Capacity range of underground transmission lines (in kV) N/A 69 to 345 CL&P NSTAR Electric PSNH Distribution Transmission Distribution Transmission Distribution Transmission Number of substations owned 157 22 175 30 126 25 Transformer capacity (in kVa) 21,973,500 3,184,000 21,607,370 8,688,000 4,729,700 4,440,600 Overhead lines (in circuit miles) 16,749 1,684 11,515 1,272 12,386 1,051 Underground lines (in circuit miles) 6,989 158 10,052 299 2,179 3 Capacity range of overhead transmission lines (in kV) N/A 69 to 345 N/A 69 to 345 N/A 115 to 345 Capacity range of underground transmission lines (in kV) N/A 69 to 345 N/A 115 to 345 N/A 115 Eversource CL&P NSTAR Electric PSNH Underground and overhead line transformers in service 654,639 295,913 185,043 173,683 Aggregate capacity (in kVa) 40,274,114 17,201,091 15,427,848 7,645,175 23
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Electric Generating Plants As of December 31, 2025, NSTAR Electric owned the following solar power facilities: Type of Plant Numberof Sites YearInstalled Capacity(kilowatts, dc) Solar Fixed Tilt, Photovoltaic 22 2010 - 2019 70,000 CL&P and PSNH do not own any electric generating plants. Natural Gas Distribution System As of December 31, 2025, NSTAR Gas owned 21 active gate stations, 162 district regulator stations, and approximately 3,332 miles of natural gas main pipeline. Hopkinton, another subsidiary of Eversource, owns a satellite vaporization plant and above ground storage tanks in Acushnet, Massachusetts (0.5 Bcf of natural gas). In addition, Hopkinton owns a liquefaction and vaporization plant with above ground storage tanks in Hopkinton, Massachusetts (3.0 Bcf of natural gas). Combined, the two plants' tanks have an aggregate storage capacity equivalent to 3.5 Bcf of natural gas that is provided to NSTAR Gas under contract. As of December 31, 2025, EGMA owned 15 active gate stations, 168 district regulator stations, and approximately 5,040 miles of natural gas main pipeline. Hopkinton, another subsidiary of Eversource, owns liquefaction and vaporization plants and above ground storage tanks at four locations throughout Massachusetts with an aggregate storage capacity equivalent to 1.8 Bcf of natural gas. In addition, Hopkinton owns three propane peak shaving plants at three locations throughout Massachusetts with an aggregate storage capacity equivalent to 0.1 Bcf. Combined, these seven plants have an aggregate storage capacity equivalent to 1.9 Bcf of natural gas that is provided to EGMA under contract. As of December 31, 2025, Yankee Gas owned 28 active gate stations, 189 district regulator stations, and approximately 3,526 miles of natural gas main pipeline. Yankee Gas also owns a liquefaction and vaporization plant and above ground storage tank with a storage capacity equivalent of 1.2 Bcf of natural gas in Waterbury, Connecticut. Natural Gas Transmission System As of December 31, 2025, NSTAR Gas owned 0.65 miles of intrastate transmission natural gas pipeline. Water Distribution System Aquarion’s properties consist of water transmission and distribution mains and associated valves, hydrants and service lines, water treatment plants, pumping facilities, wells, tanks, meters, dams, reservoirs, buildings, and other facilities and equipment used for the operation of our systems, including the collection, treatment, storage, and distribution of water. As of December 31, 2025, Aquarion owned and operated sources of water supply with a combined yield of approximately 135 million gallons per day; 3,861 miles of transmission and distribution mains; 10 surface water treatment plants; 37 dams; and 119 wellfields. Franchises CL&P Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to provide electric transmission and distribution services in the respective areas in which it is now supplying such service. In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth under Connecticut law and the special acts of the General Assembly constituting its charter, to manufacture, generate, purchase and/or sell electricity at retail, including to provide Standard Service, Supplier of Last Resort service and backup service, to sell electricity at wholesale and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain. Connecticut law prohibits an electric distribution company from owning or operating generation assets. However, under "An Act Concerning Electricity and Energy Efficiency," enacted in 2007, an electric distribution company, such as CL&P, is permitted to purchase an existing electric generating plant located in Connecticut that is offered for sale, subject to prior approval from PURA and a determination by PURA that such purchase is in the public interest. NSTAR Electric Through its charter, which is unlimited in time, NSTAR Electric has the right to engage in the business of delivering and selling electricity within its respective service territory, and has the power incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon electric companies under Massachusetts laws. The locations in public ways for electric transmission and distribution lines are obtained from municipal and other state authorities who, in granting these locations, act as agents for the state. In some cases, the actions of these authorities are subject to appeal to the DPU. The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature. Under Massachusetts law, no other entity may provide electric delivery service to retail customers within NSTAR Electric service territory without the written consent of NSTAR Electric. This consent must be filed with the DPU and the municipality so affected. The franchises of NSTAR Electric include the power of eminent domain, obtained through application to the DPU. 24
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Massachusetts restructuring legislation defines service territories as those territories actually served on July 1, 1997 and following municipal boundaries to the extent possible. The restructuring legislation further provides that until terminated by law or otherwise, distribution companies shall have the exclusive obligation to serve all retail customers within their service territories and no other person shall provide distribution service within such service territories without the written consent of such distribution companies. PSNH The NHPUC, pursuant to statutory requirements, has issued orders granting PSNH exclusive franchises to distribute electricity in the respective areas in which it is now supplying such service. In addition to the right to distribute electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, and transmit electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. PSNH's status as a public utility gives it the ability to petition the NHPUC for the right to exercise eminent domain for distribution services and for transmission eligible for regional cost allocation. PSNH is also subject to certain regulatory oversight by the Maine Public Utilities Commission and the Vermont Public Utility Commission in connection with facilities it owns in those states. NSTAR Gas Through its charter, which is unlimited in time, NSTAR Gas has the right to engage in the business of delivering and selling natural gas within its respective service territory, and has the power incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon natural gas companies under Massachusetts laws. The locations in public ways for natural gas distribution pipelines are obtained from municipal and other state authorities who, in granting these locations, act as agents for the state. In some cases, the actions of these authorities are subject to appeal to the DPU. The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature. Under Massachusetts law, no other entity may provide natural gas delivery service to retail customers within the NSTAR Gas service territory without the written consent of NSTAR Gas. This consent must be filed with the DPU and the municipality so affected. EGMA Through its charter, which is unlimited in time, EGMA has the right to engage in the business of delivering and selling natural gas within its respective service territory, and has the power incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon natural gas companies under Massachusetts laws. The locations in public ways for natural gas distribution pipelines are obtained from municipal and other state authorities who, in granting these locations, act as agents for the state. In some cases, the actions of these authorities are subject to appeal to the DPU. The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature. Under Massachusetts law, no other entity may provide natural gas delivery service to retail customers within the EGMA service territory without the written consent of EGMA. This consent must be filed with the DPU and the municipality so affected. Yankee Gas Yankee Gas holds valid franchises to sell natural gas in the areas in which Yankee Gas supplies natural gas service. Generally, Yankee Gas holds franchises to serve customers in areas designated by those franchises as well as in most other areas throughout Connecticut so long as those areas are not occupied and served by another natural gas utility under a valid franchise of its own or are not subject to an exclusive franchise of another natural gas utility or by consent. Yankee Gas' franchises are perpetual but remain subject to the power of alteration, amendment or repeal by the General Assembly of the State of Connecticut, the power of revocation by PURA and certain approvals, permits and consents of public authorities and others prescribed by statute. Generally, Yankee Gas' franchises include, among other rights and powers, the right and power to manufacture, generate, purchase, transmit and distribute natural gas and to erect and maintain certain facilities on public highways and grounds, and the right of eminent domain, all subject to such consents and approvals of public authorities and others as may be required by law. Aquarion Water Company of Connecticut and The Torrington Water Company AWC-CT and The Torrington Water Company derive their rights and franchises to operate from special acts of the Connecticut General Assembly and subject to certain approvals, permits and consents of public authority and others prescribed by statute and by its charter, they have, with minor exceptions, valid franchises free from burdensome restrictions and unlimited as to time, and are authorized to sell potable water in the towns (or parts thereof) in which water is now being supplied by AWC-CT and The Torrington Water Company. In addition to the right to sell water as set forth above, the franchises of AWC-CT and The Torrington Water Company include rights and powers to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. Under the Connecticut General Statutes, AWC-CT and The Torrington Water Company may, upon payment of compensation, take and use such lands, springs, streams or ponds, or such rights or interests therein as the Connecticut Superior Court, upon application, may determine is necessary to enable AWC-CT and The Torrington Water Company to supply potable water for public or domestic use in its franchise areas. Aquarion Water Company of Massachusetts Through its charters, which are unlimited in time, AWC-MA has the right to engage in the business of distributing and selling water within its service territories, and has the power incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon water companies under Massachusetts laws. AWC-MA has the right to construct and maintain its mains and distribution pipes in and under any public ways and to take and hold water within its respective service territories. Subject to DPU regulation, AWC-MA has the right to establish and fix rates for use of the water distributed and to establish reasonable regulations regarding the same. Certain of the towns within our service area have the right, at any time, to purchase the corporate property and all rights and privileges of AWC-MA according to pricing formulas and procedures specifically described in AWC-MA's respective charters and in compliance with Massachusetts law. 25
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Aquarion Water Company of New Hampshire and Abenaki Water Company The NHPUC, pursuant to statutory law, has issued orders granting and affirming AWC-NH’s and Abenaki Water Company’s exclusive franchises to own, operate, and manage plant and equipment and any part of the same, for the conveyance of water for the public located within its franchise territory. AWC-NH’s franchise territory encompasses the towns of Hampton, North Hampton, Rye and a limited portion of Stratham. Abenaki Water Company’s franchises extend to the boundaries of the water systems in the towns of Belmont, Bow, Carroll, and Gilford. Subject to NHPUC’s regulations, AWC-NH and Abenaki have the right to establish and fix rates for use of the water distributed and to establish reasonable regulations regarding the same. In addition to the right to provide water supply, the franchise also allows AWC-NH and Abenaki to sell water at wholesale to other water utilities and municipalities and to construct plant and equipment and maintain such plant and equipment on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. AWC-NH's and Abenaki’s status as regulated public utilities gives them the ability to petition the NHPUC for the right to exercise eminent domain for the establishment of plant and equipment. They can also petition the NHPUC for exemption from the operation of any local ordinance when certain utility structures are reasonably necessary for the convenience or welfare of the public and the local conditions, and, if the purpose of the structure relates to water supply withdrawal, the exemption is recommended by the New Hampshire Department of Environmental Services. Item 3. Legal Proceedings We are involved in legal, tax and regulatory proceedings regarding matters arising in the ordinary course of business. For information regarding material lawsuits and proceedings, see Note 13, “Commitments and Contingencies,” of the Combined Notes to Financial Statements. In addition, see Item 1, Business: "– Electric Distribution Segment," "– Electric Transmission Segment," "– Natural Gas Distribution Segment," and "– Water Distribution Segment" for information about various state and federal regulatory and rate proceedings, civil lawsuits related thereto, and information about proceedings relating to power, transmission and pricing issues; "– Nuclear Fuel Storage" for information related to nuclear waste; and "– Other Regulatory and Environmental Matters" for information about toxic substances and hazardous materials, climate change, and other matters. In addition, see Item 1A, Risk Factors, for general information about several significant risks. Item 4. Mine Safety Disclosures Not applicable. INFORMATION ABOUT OUR EXECUTIVE OFFICERS The following sets forth the executive officers of Eversource Energy as of February 17, 2026. All of Eversource Energy’s officers serve terms of one year and until their successors are elected and qualified. Name Age Title Joseph R. Nolan, Jr. 62 Chairman of the Board, President, Chief Executive Officer and a Trustee John M. Moreira 64 Executive Vice President, Chief Financial Officer and Treasurer Gregory B. Butler 68 Executive Vice President and General Counsel Paul Chodak III 62 Executive Vice President and Chief Operating Officer Penelope M. Conner 62 Executive Vice President-Customer Experience and Energy Strategy James W. Hunt, III 54 Executive Vice President-Corporate Relations and Sustainability and Secretary Susan Sgroi 61 Executive Vice President-Human Resources and Information Technology Jay S. Buth 56 Vice President, Controller and Chief Accounting Officer Joseph R. Nolan, Jr. Mr. Nolan has served as Chairman of the Board of Eversource Energy since January 1, 2023, and has served as President and Chief Executive Officer and a Trustee of Eversource Energy since 2021. Previously, Mr. Nolan served as Executive Vice President-Strategy, Customer and Corporate Relations of Eversource Energy from February 5, 2020 until May 5, 2021. Based on his experience as described, Mr. Nolan has the skills and qualifications necessary to serve as a Trustee of Eversource Energy. John M. Moreira. Mr. Moreira has served as Executive Vice President, Chief Financial Officer and Treasurer of Eversource Energy since May 4, 2022. He previously served as Senior Vice President-Financial and Regulatory and Treasurer of Eversource Energy from September 12, 2018 until May 4, 2022. Gregory B. Butler. Mr. Butler has served as General Counsel of Eversource Energy since May 1, 2001. He has served as Executive Vice President of Eversource Energy since August 8, 2016. Paul Chodak III. Mr. Chodak has served as Executive Vice President and Chief Operating Officer of Eversource Energy since November 13, 2023. Previously, Mr. Chodak served as Executive Vice President – Generation of American Electric Power Company, Inc. (AEP) from January 1, 2019 until September 15, 2023, and as Executive Vice President – Utilities of AEP from January 1, 2017 until December 31, 2018. 26
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Penelope M. Conner. Ms. Conner has served as Executive Vice President-Customer Experience and Energy Strategy of Eversource Energy since May 5, 2021. Previously, Ms. Conner served as Senior Vice President and Chief Customer Officer of Eversource Service from March 2, 2013 until May 5, 2021. James W. Hunt, III. Mr. Hunt has served as Executive Vice President-Corporate Relations and Sustainability of Eversource Energy since May 5, 2021 and as Secretary of Eversource Energy since July 9, 2021. Previously Mr. Hunt served as Senior Vice President-Communications, External Affairs and Sustainability of Eversource Service from December 17, 2019 until May 5, 2021. Susan Sgroi. Ms. Sgroi has served as Executive Vice President-Human Resources and Information Technology of Eversource Energy since January 8, 2024. Previously, Ms. Sgroi served as Executive Vice President and Chief Human Resources Officer of Blue Cross and Blue Shield of Massachusetts from 2015 until October 31, 2023. Jay S. Buth. Mr. Buth has served as Vice President, Controller and Chief Accounting Officer of Eversource Energy since June 9, 2009. PART II Item 5. Market for the Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities (a) Market Information Our common shares are listed on the New York Stock Exchange. The ticker symbol is "ES." There is no established public trading market for the common stock of CL&P, NSTAR Electric and PSNH. All of the common stock of CL&P, NSTAR Electric and PSNH is held solely by Eversource. (b) Holders As of January 31, 2026, there were 26,445 registered common shareholders of our company on record. As of the same date, there were a total of 375,496,611 shares outstanding. (c) Dividends Information with respect to dividends and dividend restrictions for Eversource, CL&P, NSTAR Electric and PSNH is contained in Item 8, Financial Statements and Supplementary Data, in the Combined Notes to Financial Statements, within this Annual Report on Form 10-K. (d) Securities Authorized for Issuance Under Equity Compensation Plans For information regarding securities authorized for issuance under equity compensation plans, see Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, included in this Annual Report on Form 10-K. 27
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(e) Performance Graph The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in 2020 in Eversource Energy common stock, as compared with the S&P 500 Stock Index and the EEI Index for the period 2020 through 2025, assuming all dividends are reinvested. December 31, 2020 2021 2022 2023 2024 2025 Eversource Energy $100 $108 $103 $79 $77 $94 EEI Index $100 $117 $118 $108 $129 $144 S&P 500 $100 $129 $105 $133 $166 $196 Purchases of Equity Securities by the Issuer and Affiliated Purchasers The following table discloses purchases of our common shares made by us or on our behalf for the periods shown below. The common shares purchased consist of open market purchases made by the Company or an independent agent. These share transactions related to matching contributions under the Eversource 401k Plan. Period Total Number ofShares Purchased Average Price Paidper Share Total Number of SharesPurchased asPart of PubliclyAnnounced Plans orPrograms Approximate DollarValue of Shares thatMay Yet Be PurchasedUnder the Plans andPrograms (at month end) October 1 - October 31, 2025 — $ — — — November 1 - November 30, 2025 638 63.73 — — December 1 - December 31, 2025 2,492 67.43 — — Total 3,130 $ 66.67 — — Item 6. Removed and Reserved 28
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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations EVERSOURCE ENERGY AND SUBSIDIARIES The following discussion and analysis should be read in conjunction with our consolidated financial statements and related combined notes included in this combined Annual Report on Form 10-K. References in this combined Annual Report on Form 10-K to "Eversource," the "Company," "we," "us," and "our" refer to Eversource Energy and its consolidated subsidiaries. All per-share amounts are reported on a diluted basis. The consolidated financial statements of Eversource, NSTAR Electric and PSNH and the financial statements of CL&P are herein collectively referred to as the "financial statements." Our discussion of fiscal year 2025 compared to fiscal year 2024 is included herein. Unless expressly stated otherwise, for discussion and analysis of fiscal year 2023 items and of fiscal year 2024 compared to fiscal year 2023, please refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in our combined 2024 Annual Report on Form 10-K, which is incorporated herein by reference. Refer to the Glossary of Terms included in this combined Annual Report on Form 10-K for abbreviations and acronyms used throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations. The only common equity securities that are publicly traded are common shares of Eversource. Our earnings discussion includes financial measures that are not recognized under GAAP (non-GAAP) referencing our earnings and EPS excluding losses associated with our previous offshore wind investments, a loss on the pending sale of the Aquarion water distribution business, and a loss on the disposition of land that was initially acquired to construct the Northern Pass Transmission project and was subsequently abandoned. EPS by business is also a non-GAAP financial measure and is calculated by dividing the Net Income Attributable to Common Shareholders of each business by the weighted average diluted Eversource common shares outstanding for the period. The earnings and EPS of each business do not represent a direct legal interest in the assets and liabilities of such business, but rather represent a direct interest in our assets and liabilities as a whole. We use these non-GAAP financial measures to evaluate and provide details of earnings results by business and to more fully compare and explain our results without including these items. This information is among the primary indicators we use as a basis for evaluating performance and planning and forecasting of future periods. We believe the impacts of the losses associated with our previous offshore wind investments, the loss on the pending sale of the Aquarion water distribution business, and the loss on the disposition of land associated with an abandoned project are not indicative of our ongoing costs and performance. We view these charges as not directly related to the ongoing operations of the business and therefore not an indicator of baseline operating performance. Due to the nature and significance of the effect of these items on Net Income Attributable to Common Shareholders and EPS, we believe that the non-GAAP presentation is a more meaningful representation of our financial performance and provides additional and useful information to readers of this report in analyzing historical and future performance of our business. These non-GAAP financial measures should not be considered as alternatives to reported Net Income Attributable to Common Shareholders or EPS determined in accordance with GAAP as indicators of operating performance. Financial Condition and Business Analysis Executive Summary Eversource Energy is a public utility holding company primarily engaged, through its wholly-owned regulated utility subsidiaries, in the energy delivery business. Eversource Energy's wholly-owned regulated utility subsidiaries consist of CL&P, NSTAR Electric and PSNH (electric utilities), Yankee Gas, NSTAR Gas and EGMA (natural gas utilities) and Aquarion (water utilities). Eversource is organized into the electric distribution, electric transmission, natural gas distribution, and water distribution reportable segments. The following items in this executive summary are explained in more detail in this combined Annual Report on Form 10-K: Earnings Overview and Future Outlook: • We earned $1.69 billion, or $4.56 per share, in 2025, compared with $811.7 million, or $2.27 per share, in 2024. Our 2025 results include an aggregate, net after-tax charge resulting from our previous offshore wind investments of $75.0 million, or $0.20 per share. Our 2024 results include an aggregate, net after-tax loss on the sale of our offshore wind investments of $524.0 million, or $1.47 per share. These 2025 and 2024 charges were recorded within Eversource Parent and Other Companies. Our 2024 results also include an after-tax loss resulting from the expected sale of Aquarion of $298.3 million, or $0.83 per share. This 2024 charge was recorded within the Water Distribution segment. Excluding these charges, our 2025 non- GAAP earnings were $1.77 billion, or $4.76 per share, and our 2024 non-GAAP earnings of $1.63 billion, or $4.57 per share. • We project that we will earn within a 2026 earning guidance range of between $4.80 per share and $4.95 per share. We also project that our long- term EPS growth rate through 2030 will be in a 5 to 7 percent range, using 2025 non-GAAP EPS of $4.76 per share as the base year. Liquidity: • Cash flows provided by operating activities totaled $4.11 billion in 2025, compared with $2.16 billion in 2024. Investments in property, plant and equipment totaled $4.16 billion in 2025, compared with $4.48 billion in 2024. 29
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• Cash totaled $135.4 million as of December 31, 2025, compared with $26.7 million as of December 31, 2024. Our available borrowing capacity under our commercial paper programs totaled $1.12 billion as of December 31, 2025. • In 2025, we issued $2.94 billion of new long-term debt and we repaid $1.40 billion of long-term debt. • In 2025, we paid dividends totaling $3.01 per common share, compared with dividends of $2.86 per common share in 2024. Our quarterly common share dividend payment was $0.7525 per share in 2025, as compared to $0.715 per share in 2024. On January 27, 2026, our Board of Trustees approved a common share dividend payment of $0.7875 per share, payable on March 31, 2026 to shareholders of record as of March 5, 2026. • On May 30, 2025, we entered into an equity distribution agreement pursuant to which we may offer and sell up to $1.2 billion of our common shares from time to time through an “at-the-market” (ATM) equity offering program. In 2025, we issued 7,130,134 common shares, which resulted in proceeds of $465.4 million, net of issuance costs. • We project to make capital expenditures of $26.51 billion from 2026 through 2030, of which we expect $11.24 billion to be in our electric distribution segment, $6.80 billion to be in our natural gas distribution segment, and $7.24 billion to be in our electric transmission segment. We also project to invest $1.23 billion in information technology and facilities upgrades and enhancements. Regulatory Developments: • On July 25, 2025, the NHPUC issued its decision in the PSNH distribution rate case and approved a permanent rate increase of $100.7 million, effective August 1, 2025, inclusive of the temporary rate increase that went into effect in August 2024. The order established an authorized regulatory ROE of 9.5 percent with a 50 percent common equity ratio for PSNH’s capital structure. The NHPUC approved an alternative regulatory framework that authorizes formulaic annual revenue adjustments on August 1st of 2026, 2027 and 2028. • On November 3, 2025, EGMA, NSTAR Electric, and the Massachusetts Office of the Attorney General reached a joint settlement agreement that resolved outstanding issues in multiple open Pension Adjustment Mechanism (PAM) dockets and open Resiliency Tree Work (RTW) dockets at NSTAR Electric and allows recovery of transaction and integration costs related to Eversource’s acquisition of EGMA. The settlement agreement was approved by the DPU on December 1, 2025. The settlement resulted in a net pre-tax benefit to earnings of $64.8 million on the Eversource income statement in the fourth quarter of 2025. • On November 5, 2025, PURA issued a final decision in the Yankee Gas distribution rate case that included a distribution rate increase of $95.7 million, which excluded a previously recorded non-firm margin rate credit of $13.5 million to be refunded annually over three years, effective November 1, 2025. The final decision also established an authorized net regulatory ROE of 9.32 percent and a 53 percent common equity ratio for Yankee Gas’ capital structure. Yankee Gas filed motions to request PURA reconsider the disallowances of certain capitalized overhead costs, certain computational errors, and other issues identified in its final decision. A final decision on the reconsideration is expected from PURA by March 15, 2026. • On November 19, 2025, PURA denied an application to approve the sale of the Aquarion Water Company, finding that the transaction did not meet managerial suitability and responsibility requirements due to concerns with governance and oversight structure over Aquarion and its consumer advocate. On January 15, 2026, the Connecticut Superior Court issued a decision on the appeal of PURA’s denial, sustaining the appeal and remanding back to PURA. A final decision is expected by PURA on March 25, 2026. • On December 30, 2025, NSTAR Gas and the Massachusetts Office of the Attorney General reached a joint settlement agreement that allowed for the reinstatement of a rate base reset of $45.0 million increase to base distribution rates effective January 1, 2026 and for continuation of NSTAR Gas’ PBR program through November 1, 2030. The settlement agreement also required NSTAR Gas to provide credits to customers and a concession to the Office of the Attorney General, among other items. The DPU approved the settlement agreement on January 16, 2026. The settlement agreement resulted in a pre-tax charge to earnings of $12.2 million in the fourth quarter of 2025. • On January 30, 2026, the New Hampshire Department of Energy filed a notice of appeal with the New Hampshire Supreme Court challenging certain aspects of the PSNH distribution rate case decision approved by the NHPUC on July 25, 2025, including the alternative regulatory framework and the revenue requirement. On February 6, 2026, the Office of the Consumer Advocate filed a notice of cross-appeal challenging other aspects of the rate case decision. Eversource is currently evaluating the appeals. 30
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Earnings Overview Consolidated: Below is a summary of our earnings/(loss) by business, which also reconciles the non-GAAP financial measures of consolidated non- GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income/(Loss) Attributable to Common Shareholders and diluted EPS. For the Years Ended December 31, 2025 2024 2023 (Millions of Dollars, Except Per Share Amounts) Amount Per Share Amount Per Share Amount Per Share Net Income/(Loss) Attributable to Common Shareholders (GAAP) $ 1,692.4 $ 4.56 $ 811.7 $ 2.27 $ (442.2) $ (1.26) Regulated Companies (Non-GAAP) $ 1,848.5 $ 4.98 $ 1,691.9 $ 4.73 $ 1,509.3 $ 4.31 Eversource Parent and Other Companies (Non-GAAP) (81.1) (0.22) (57.9) (0.16) 8.4 0.03 Non-GAAP Earnings $ 1,767.4 $ 4.76 $ 1,634.0 $ 4.57 $ 1,517.7 $ 4.34 Losses on Offshore Wind (after-tax) (75.0) (0.20) (524.0) (1.47) (1,953.0) (5.58) Loss on Pending Sale of Aquarion (after-tax) — — (298.3) (0.83) — — Land Abandonment Loss and Other Charges (after-tax) — — — — (6.9) (0.02) Net Income/(Loss) Attributable to Common Shareholders (GAAP) $ 1,692.4 $ 4.56 $ 811.7 $ 2.27 $ (442.2) $ (1.26) In 2025, we recorded a pre-tax charge of $284 million associated with increasing our offshore wind contingent liability for expected future payments under the terms of the 2024 sale agreement with Global Infrastructure Partners (GIP) for the South Fork Wind and Revolution Wind projects, offset by expected tax benefits from the offshore wind sale of $209 million. In 2024, we recorded a pre-tax loss on the sales of our offshore wind investments of $464 million and a $60 million increase in income tax expense, resulting in an after-tax loss of $524 million. In 2023, we recorded impairment charges resulting from the expected sales of these offshore wind investments. For further information, see the "Offshore Wind Sale and Contingent Liability" section below included in this Management's Discussion and Analysis of Financial Condition and Results of Operations. The 2024 loss includes an impairment charge of $297 million to write down the carrying value of the water business to fair value resulting from the expected sale of Aquarion, as well as transaction costs. For further information, see "Business Development and Capital Expenditures – Aquarion Sale Status and Regulatory Denial" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations. The 2023 charges primarily include a loss on the disposition of abandoned land intended to be used for the cancelled Northern Pass Transmission project. The impact of higher shares outstanding resulted in $0.17 earnings per share dilution in 2025, as compared to 2024. Regulated Companies: Our regulated companies comprise the electric distribution, electric transmission, natural gas distribution, and water distribution segments. A summary of our segment earnings and EPS is as follows: For the Years Ended December 31, 2025 2024 2023 (Millions of Dollars, Except Per Share Amounts) Amount Per Share Amount Per Share Amount Per Share Net Income - Regulated Companies (GAAP) $ 1,848.5 $ 4.98 $ 1,393.6 $ 3.90 $ 1,509.3 $ 4.31 Electric Distribution $ 667.1 $ 1.80 $ 631.7 $ 1.77 $ 608.0 $ 1.74 Electric Transmission 776.7 2.09 724.6 2.03 643.4 1.84 Natural Gas Distribution 360.5 0.97 291.0 0.81 224.8 0.64 Water Distribution, excluding Loss on Pending Sale (Non-GAAP) 44.2 0.12 44.6 0.12 33.1 0.09 Net Income - Regulated Companies (Non-GAAP) $ 1,848.5 $ 4.98 $ 1,691.9 $ 4.73 $ 1,509.3 $ 4.31 Loss on Pending Sale of Aquarion (after-tax) — — (298.3) (0.83) — — Net Income - Regulated Companies (GAAP) $ 1,848.5 $ 4.98 $ 1,393.6 $ 3.90 $ 1,509.3 $ 4.31 Our electric distribution segment earnings increased $35.4 million in 2025, as compared to 2024, due primarily to higher revenues from base distribution rate increases at PSNH effective August 1, 2024 and August 1, 2025 and at NSTAR Electric effective January 1, 2025 and from CL&P's capital tracking mechanism due to increased electric system improvements. Earnings also benefited from a lower effective tax rate and the impact of the PSNH rate case decision in July 2025. Those earnings increases were partially offset by higher interest expense, higher operations and maintenance expense, higher property tax expense, higher depreciation expense, and a charge for customer credits at NSTAR Electric as a result of the joint settlement agreement approved in Massachusetts on December 1, 2025. Our electric transmission segment earnings increased $52.1 million in 2025, as compared to 2024, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure and lower interest expense. (1) (2) (3) (1) (2) (3) 31
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Our natural gas distribution segment earnings increased $69.5 million in 2025, as compared to 2024, due primarily to higher revenues from base distribution rate increases effective November 1, 2024 and November 1, 2025 at both EGMA and NSTAR Gas, effective November 1, 2025 at Yankee Gas, and from capital tracking mechanisms due to continued investments in natural gas infrastructure. Those earnings increases were partially offset by higher operations and maintenance expense, higher depreciation expense, higher interest expense, the impact of the NSTAR Gas settlement agreement in December 2025, higher property tax expense, and the impact of the Yankee Gas rate case decision in November 2025. Our water distribution segment recognized a $297 million impairment charge in 2024 as a result of writing down the carrying value of the business to fair value due to the expected sale of Aquarion. Excluding the 2024 impairment charge and transaction costs associated with the expected sale, water distribution segment earnings decreased $0.4 million in 2025, as compared to 2024. Eversource Parent and Other Companies: Eversource parent and other companies’ losses decreased $425.8 million in 2025, as compared to 2024, due primarily to an after-tax charge of $524.0 million recorded in 2024 resulting from the sale of Eversource parent’s offshore wind investments, as compared to an aggregate net after-tax charge of $75.0 million recorded in 2025 resulting from an increase to the offshore wind contingent liability, net of tax benefits associated with the tax losses on the sales of its offshore wind investments. Excluding these charges, Eversource parent and other companies losses increased $23.2 million due to higher interest expense from the absence in 2025 of capitalized interest as a result of the sale of our offshore wind projects in the third quarter of 2024 and higher interest costs from short-term debt, partially offset by the allowed recovery of previously expensed acquisition-related and integration costs of EGMA as part of the joint settlement agreement approved in Massachusetts on December 1, 2025. Offshore Wind Sale and Contingent Liability: On July 9, 2024, Eversource completed the sale of its 50 percent ownership share of Sunrise Wind to Ørsted. On September 30, 2024, Eversource completed the sale of its 50 percent ownership share in the South Fork Wind and Revolution Wind projects to GIP. Eversource recorded a contingent liability relating to expected future payments to GIP as part of the sale of the South Fork Wind and Revolution Wind projects. As part of the definitive agreement with GIP, Eversource is responsible for certain post-closing purchase price adjustments. This obligation includes an expected cost overrun sharing obligation, an expected obligation to maintain GIP’s internal rate of return, and an obligation for other future costs prior to commercial operation. Eversource recognized an aggregate after-tax loss on the sales of its offshore wind investments of $524 million, which included a net $60 million increase in income tax expense including an increase in the valuation allowance for unused capital losses, in 2024. In the third quarter of 2025, Eversource received an updated report from GIP on the construction status of Revolution Wind, which included revised projections of total construction costs. The revised cost projections reflected known and quantifiable cost increases, including those associated with the impacts of damage to the wind turbine installation vessel, insurance costs, tariff impacts, and costs incurred as a result of the stop-work order for Revolution Wind received on August 22, 2025 from the Bureau of Ocean Energy Management that halted all offshore wind construction activities through September 22, 2025. Based on those developments, Eversource recognized a pre-tax charge of $284.0 million in the third quarter of 2025 as a result of the aggregate impact of these items to increase the liability for purchase price adjustments associated with the offshore wind projects. Payments made in 2025 reduced the contingent liability and are reflected within investing activities on the statement of cash flows. These payments included cost overruns for the Revolution Wind project paid to GIP, insurance payments, and the purchase price adjustment payment related to the South Fork Wind project paid to GIP. Eversource continually evaluates the contingent liability and will reassess the balance as new information becomes available. Based on most recent updates from GIP on the construction status of Revolution Wind, factoring in estimated costs incurred as a result of a second stop-work order for Revolution Wind received on December 22, 2025 and removed on January 12, 2026, revised insurance costs, and other information currently available, Eversource believes that the contingent liability balance as of December 31, 2025 is a reasonable estimate to cover this contingent liability for purchase price adjustments. As of December 31, 2025, the contingent liability totaled $448.2 million and is recorded as a current liability on Eversource’s balance sheet, based upon the timing of expected payments to GIP. The contingent liability totaled $365.0 million as of December 31, 2024. Eversource relies on information that it receives from the project owners for the construction-related, delay-related, and insurance-related costs of Revolution Wind. Eversource uses its judgment to adjust, as needed, its expected obligations to GIP while construction of Revolution Wind is completed. New information or future developments that arise as the construction of Revolution Wind progresses will necessitate a reassessment of the estimated liability to GIP. The Company reviews available projections of total construction costs, including the latest cost estimates and project timeline, to determine if any changes to this liability are warranted. It is reasonably possible that as additional updated cost estimates become available, and if additional cost overruns materialize or other adverse changes in facts, regulations and circumstances occur, it could result in additional losses and increases to the offshore wind contingent liability, which could be material. The Company will continue to monitor developments and evaluate potential exposures related to this contingency and will revise its estimated liability as additional information becomes available. Contingencies are evaluated using the best information available at the time the financial statements are published, and this assessment involves judgments and assumptions about future events. Factors that could increase the obligation to GIP include construction cost overruns for Revolution Wind as well as the timing and extent of construction delays, which would impact the economics associated with the purchase price adjustment, and the eligibility for federal investment tax credits for Revolution Wind at a value lower than assumed and included in the purchase 32
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price. The purchase price of Revolution Wind included the sales value related to a 40 percent level of federal investment tax credits. A change in the expected value or qualification of investment tax credit adders could result in a significant loss in a future period. Total net proceeds could also be adjusted for a benefit due to Eversource if there are lower operation costs or higher availability of the projects through the period that is four years following the commercial operation of Revolution Wind. Eversource recognized an aggregate, net after-tax charge of $75.0 million, or $0.20 per share, in 2025 resulting from our previous offshore wind investments. This charge consists of the pre-tax $284 million increase to the offshore wind contingent liability, offset by $209 million of tax benefits associated with tax losses on the sale of the South Fork Wind and Revolution Wind projects that Eversource expects to realize. Liquidity Sources and Uses of Cash: Eversource’s regulated business is capital intensive and requires considerable capital resources. Eversource’s regulated companies’ capital resources are provided by cash flows generated from operations, short-term borrowings, long-term debt issuances, capital contributions from Eversource parent, and existing cash, and are used to fund their liquidity and capital requirements. Eversource’s regulated companies typically maintain minimal cash balances and use short-term borrowings to meet their working capital needs and other cash requirements. Short-term borrowings are also used as a bridge to long-term debt financings. The levels of short-term borrowing may vary significantly over the course of the year due to the impact of fluctuations in cash flows from operations (including timing of storm costs and regulatory recoveries), dividends paid, capital contributions received and the timing of long-term debt financings. Eversource, CL&P, NSTAR Electric and PSNH each uses its available capital resources to fund its respective construction expenditures, meet debt requirements, pay operating costs, including storm-related costs, pay dividends, and fund corporate obligations. Eversource's regulated companies recover their electric, natural gas and water distribution construction expenditures as the related project costs are depreciated over the life of the assets. This impacts the timing of the revenue stream designed to fully recover the total investment including a return on the equity and debt used to finance the investments. Eversource's regulated companies spend a significant amount of cash on capital improvements and construction projects that have a long- term return on investment and recovery period. These factors have resulted in current liabilities exceeding current assets by $2.73 billion, $268.6 million, $9.0 million and $19.6 million at Eversource, CL&P, NSTAR Electric and PSNH, respectively, as of December 31, 2025. We expect the future operating cash flows of Eversource, CL&P, NSTAR Electric and PSNH, along with our existing borrowing availability and access to both debt and equity markets, will be sufficient to meet any working capital and future operating requirements, and capital investment forecasted opportunities. As of December 31, 2025, $1.39 billion of Eversource's long-term debt, including $1.00 billion at Eversource parent and $300.0 million at NSTAR Electric, matures within the next 12 months. Eversource, with its current credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. Eversource, CL&P, NSTAR Electric and PSNH will reduce their short-term borrowings with operating cash flows or with the issuance of new long-term debt, determined by considering capital requirements and maintenance of Eversource's credit rating and profile. Cash totaled $135.4 million as of December 31, 2025, compared with $26.7 million as of December 31, 2024. Short-Term Debt - Commercial Paper Programs and Credit Agreements: Eversource parent has a $2.00 billion commercial paper program allowing Eversource parent to issue commercial paper as a form of short-term debt. Eversource parent, CL&P, PSNH, NSTAR Gas, Yankee Gas, EGMA and Aquarion Water Company of Connecticut are parties to a five-year $2.00 billion revolving credit facility. Effective October 11, 2025, the revolving credit facility’s termination date was extended for one additional year to October 11, 2030, pursuant to the extension provisions contained in the existing credit agreement. This revolving credit facility serves to backstop Eversource parent's $2.00 billion commercial paper program. NSTAR Electric has a $650 million commercial paper program allowing NSTAR Electric to issue commercial paper as a form of short-term debt. NSTAR Electric is also a party to a five-year $650 million revolving credit facility. Effective October 11, 2025, the revolving credit facility’s termination date was extended for one additional year to October 11, 2030, pursuant to the extension provisions contained in the existing credit agreement. This revolving credit facility serves to backstop NSTAR Electric's $650 million commercial paper program. The amount of borrowings outstanding and available under the commercial paper programs were as follows: Borrowings Outstanding as of December 31, Available Borrowing Capacity as ofDecember 31, Weighted-Average Interest Rate as ofDecember 31, (Millions of Dollars) 2025 2024 2025 2024 2025 2024 Eversource Parent Commercial Paper Program $ 1,280.0 $ 1,538.0 $ 720.0 $ 462.0 3.98 % 4.76 % NSTAR Electric Commercial Paper Program 245.4 504.8 404.6 145.2 3.87 % 4.55 % There were no borrowings outstanding on the revolving credit facilities as of December 31, 2025 or 2024. 33
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CL&P and PSNH have uncommitted line of credit agreements totaling $375 million and $250 million, respectively, all of which will expire in either May 2026, September 2026 or October 2026. There are no borrowings outstanding on either the CL&P or PSNH uncommitted line of credit agreements as of December 31, 2025. Amounts outstanding under the commercial paper programs are included in Notes Payable and classified in current liabilities on the Eversource and NSTAR Electric balance sheets, as all borrowings are outstanding for no more than 364 days at one time. Intercompany Borrowings: Eversource parent uses its available capital resources to provide loans to its subsidiaries to assist in meeting their short-term borrowing needs. Eversource parent records intercompany interest income from its loans to subsidiaries, which is eliminated in consolidation. Intercompany loans from Eversource parent to its subsidiaries are eliminated in consolidation on Eversource's balance sheets. As of December 31, 2025 and 2024, there were intercompany loans from Eversource parent to PSNH of $49.3 million and $131.1 million, respectively. As of December 31, 2024, there were intercompany loans from Eversource parent to CL&P of $280.0 million. Eversource parent charges interest on these intercompany loans at the same weighted-average interest rate as its commercial paper program. Intercompany loans from Eversource parent are included in Notes Payable to Eversource Parent and classified in current liabilities on the respective subsidiary's balance sheets, as these intercompany borrowings are outstanding for no more than 364 days at one time. Availability under Long-Term Debt Issuance Authorizations: On May 1, 2024, the DPU approved NSTAR Electric’s request for authorization to issue up to $2.40 billion in long-term debt through December 31, 2026. On August 12, 2024, the DPU approved EGMA’s request for authorization to issue up to $325 million in long-term debt through December 31, 2026. On December 18, 2024, the DPU approved NSTAR Gas’ request for authorization to issue up to $475 million in long-term debt through December 31, 2027. On March 26, 2025, PURA approved Yankee Gas’ request for authorization to issue up to $360 million in long-term debt through December 31, 2026. PSNH has utilized its long-term debt authorizations in place with NHPUC. CL&P has no long-term debt authorization remaining with PURA. Long-Term Debt Issuances and Repayments: The following table summarizes long-term debt issuances and repayments: (Millions of Dollars) InterestRate Issuance/(Repayment) Issue Date orRepayment Date Maturity Date Use of Proceeds for Issuance/Repayment Information CL&P 2025 Series A First Mortgage Bonds 4.95 % 400.0 January 2025 January 2030 Repaid short-term debt, paid capital expendituresand working capital CL&P 2020 Series A First Mortgage Bonds 0.75 % (400.0) December 2025 December 2025 Paid at maturity NSTAR Electric Debentures 4.85 % 400.0 February 2025 March 2030 Repaid 3.25% Debentures at maturity, repaid short-term debt, paid capital expenditures and workingcapital NSTAR Electric Debentures 5.20 % 400.0 February 2025 March 2035 Repaid 3.25% Debentures at maturity, repaid short-term debt, paid capital expenditures and workingcapital NSTAR Electric Debentures 5.20 % 300.0 October 2025 March 2035 Repaid short-term debt, paid capital expendituresand working capital NSTAR Electric Debentures 3.25 % (250.0) November 2025 November 2025 Paid at maturity PSNH Series Y First Mortgage Bonds 4.40 % 300.0 June 2025 July 2028 Repaid short-term debt, paid capital expendituresand working capital Eversource Parent Series HH Senior Notes 4.45 % 600.0 October 2025 December 2030 Repay Series J bonds at maturity and repaid short-term debt Eversource Parent Series H Senior Notes 3.15 % (300.0) January 2025 January 2025 Paid at maturity Eversource Parent Series Q Senior Notes 0.80 % (300.0) August 2025 August 2025 Paid at maturity NSTAR Gas Series Y First Mortgage Bonds 4.86 % 205.0 June 2025 June 2030 Repaid short-term debt, paid capital expendituresand working capital NSTAR Gas Series Z First Mortgage Bonds 5.30 % 20.0 June 2025 June 2035 Repaid short-term debt, paid capital expendituresand working capital NSTAR Gas Series R First Mortgage Bonds 2.33 % (75.0) May 2025 May 2025 Paid at maturity Yankee Gas Series Y First Mortgage Bonds 5.02 % 148.0 July 2025 January 2031 Repaid Series M bonds at maturity, repaid short-term debt, paid capital expenditures and workingcapital Yankee Gas Series Z First Mortgage Bonds 5.55 % 37.0 July 2025 July 2035 Repaid Series M bonds at maturity, repaid short-term debt, paid capital expenditures and workingcapital Yankee Gas Series M First Mortgage Bonds 3.35 % (75.0) September 2025 September 2025 Paid at maturity EGMA Series F First Mortgage Bonds 4.77 % 125.0 September 2025 October 2030 Repaid short-term debt, paid capital expendituresand working capital Rate Reduction Bonds: PSNH's RRB payments consist of principal and interest and are paid semi-annually. PSNH paid $43.2 million of RRB principal payments in each of 2025 and 2024, and paid $13.4 million and $14.9 million of interest payments in 2025 and 2024, respectively. 34
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Common Share Issuances and Equity Distribution Agreement: On May 30, 2025, Eversource entered into an equity distribution agreement pursuant to which it may offer and sell up to $1.2 billion of its common shares from time to time through an ATM equity offering program. In 2025, Eversource issued 7,130,134 common shares, which resulted in proceeds of $465.4 million, net of issuance costs. Eversource used the net proceeds received for general corporate purposes. Cash Flows: Cash flows from operating activities primarily result from the transmission and distribution of electricity, and the distribution of natural gas and water. Cash flows provided by operating activities totaled $4.11 billion in 2025, compared with $2.16 billion in 2024. Operating cash flows were favorably impacted by an improvement in regulatory recoveries driven primarily by the timing of collections for CL&P’s non-bypassable FMCC, CL&P’s SBC, energy efficiency costs, wholesale and retail transmission costs, and other regulatory tracking mechanisms. The CL&P non-bypassable FMCC retail rates in effect for 2025 were higher than those set in 2024 and the net Millstone and Seabrook contract cash flows were higher in 2025 as compared to 2024. These higher collections within the non-bypassable FMCC resulted in an improvement to operating cash flows of $428.2 million for the year. Higher collections from CL&P’s SBC mechanism resulted in a cash flow improvement of $113.3 million. The impacts of regulatory collections are included in both Regulatory Recoveries and Amortization on the statements of cash flows. Additionally, CL&P received general obligation bond proceeds from the State of Connecticut for the reimbursement of hardship costs and for electric vehicle charging program costs of $107.8 million in 2025, which are reflected in Regulatory Recoveries. Operating cash flows were also favorably impacted by a $321.4 million decrease in cash payments to vendors for storm costs, the timing of cash collections on our accounts receivable, the timing of cash payments made on our accounts payable, a $19.1 million decrease in cost of removal expenditures, and the timing of other working capital items. These favorable impacts were partially offset by an increase in capitalized implementation costs for cloud-based service arrangements and a $21.2 million decrease in income tax refunds received in 2025 as compared to 2024. In 2025, we paid cash dividends of $1.09 billion and issued non-cash dividends of $23.4 million in the form of treasury shares, totaling dividends of $1.12 billion, or $3.01 per common share. In 2024, we paid cash dividends of $1.00 billion and issued non-cash dividends of $23.5 million in the form of treasury shares, totaling dividends of $1.03 billion, or $2.86 per common share. Our quarterly common share dividend payment was $0.7525 per share in 2025, as compared to $0.715 per share in 2024. On January 27, 2026, our Board of Trustees approved a common share dividend payment of $0.7875 per share, payable on March 31, 2026 to shareholders of record as of March 5, 2026. Eversource issues treasury shares to satisfy awards under the Company's incentive plans, shares issued under the dividend reinvestment and share purchase plan, and matching contributions under the Eversource 401k Plan. In 2025, CL&P, NSTAR Electric and PSNH paid $430.0 million, $436.0 million and $175.0 million, respectively, in common stock dividends to Eversource parent. Investments in Property, Plant and Equipment on the statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized and deferred portions of pension and PBOP income/expense. In 2025, investments for Eversource, CL&P, NSTAR Electric, and PSNH were $4.16 billion, $867.8 million, $1.56 billion and $537.8 million, respectively. Capital expenditures were primarily for continuing projects to maintain and improve infrastructure and operations, including enhancing reliability to the transmission and distribution systems. Contractual Obligations: For information regarding our cash requirements from contractual obligations and payment schedules, see Note 9, "Long-Term Debt," Note 10, "Rate Reduction Bonds and Variable Interest Entities," Note 11A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pension," Note 13, "Commitments and Contingencies," and Note 14, "Leases," to the financial statements. Estimated interest payments on existing long-term fixed-rate debt are calculated by multiplying the coupon rate on the debt by its scheduled notional amount outstanding for the period of measurement as of December 31, 2025 and are as follows: (Millions of Dollars) 2026 2027 2028 2029 2030 Thereafter Total Eversource $ 1,214.9 $ 1,153.1 $ 1,041.4 $ 919.7 $ 828.8 $ 6,540.8 $ 11,698.7 Our commitments to make payments in addition to these contractual obligations include other liabilities reflected on our balance sheets, and guarantees of certain obligations primarily associated with construction of our previously owned offshore wind investments. For information regarding our projected capital expenditures over the next five years, see "Business Development and Capital Expenditures - Projected Capital Expenditures" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations. Credit Ratings: A summary of our current corporate credit ratings and outlooks by S&P, Moody's, and Fitch is as follows: S&P Moody's Fitch Current Outlook Current Outlook Current Outlook Eversource Parent BBB+ Stable Baa2 Negative BBB Negative CL&P A- Stable Baa1 Stable A- Negative NSTAR Electric A- Stable A2 Negative A- Negative PSNH A- Stable A3 Stable A- Negative 35
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A summary of the current credit ratings and outlooks by S&P, Moody's, and Fitch for senior unsecured debt of Eversource parent and NSTAR Electric, and senior secured debt of CL&P and PSNH is as follows: S&P Moody's Fitch Current Outlook Current Outlook Current Outlook Eversource Parent BBB Stable Baa2 Negative BBB Negative CL&P A Stable A2 Stable A+ Negative NSTAR Electric A- Stable A2 Negative A Negative PSNH A Stable A1 Stable A+ Negative Business Development and Capital Expenditures Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized and deferred portions of pension and PBOP income/expense (all of which are non-cash factors), totaled $4.61 billion in 2025, $4.64 billion in 2024, and $4.59 billion in 2023. These amounts included $240.2 million in 2025, $260.5 million in 2024, and $214.4 million in 2023 related to information technology and facilities upgrades and enhancements, primarily at Eversource Service and The Rocky River Realty Company. Electric Transmission Business: Our consolidated electric transmission business capital expenditures decreased by $118.8 million in 2025, as compared to 2024. A summary of electric transmission capital expenditures by company is as follows: For the Years Ended December 31, (Millions of Dollars) 2025 2024 2023 CL&P $ 398.6 $ 450.0 $ 470.4 NSTAR Electric 522.9 502.0 567.4 PSNH 287.5 375.8 410.0 Total Electric Transmission $ 1,209.0 $ 1,327.8 $ 1,447.8 Our transmission projects are designed to improve the reliability of the electric grid, meet customer demand for power, and strengthen the electric grid's resilience against extreme weather and other safety and security threats. In Connecticut, Massachusetts and New Hampshire, our transmission projects include transmission line upgrades, the installation of new transmission interconnection facilities, substations and lines, and transmission substation enhancements. Greater Cambridge Energy Program: The Greater Cambridge Energy Program will construct Eversource’s first underground transmission substation in Cambridge, Massachusetts, along with associated transmission and distribution lines. The project will address the increased electric demand in the region, enhance the resiliency of the transmission system, and ensure a flexible grid to reliably serve customers. The flexibility to transmit and distribute mixed energy sources will support the decarbonization and electrification goals of both the City of Cambridge and the state of Massachusetts. The new 115/13.8- kV, 35,000 square foot substation will be located in an underground vault and includes three distribution power transformers supplying thirty-six distribution circuits. The project also includes five underground duct banks housing eight new 115-kV transmission lines. The Massachusetts Energy Facilities Siting Board approved the project on June 28, 2024. Environmental permits are acquired to support ongoing construction activities. Additional required permits for transmission line trenchless crossings, including a license from the MA DEP, are expected to be approved by the end of 2026. The initial in-service date for the project is June 2029, which includes two 115-kV transmission lines and the transmission portion of the substation. The first distribution circuits and substation distribution will be placed in-service by the end of 2029. The remaining transmission and distribution circuits will be placed in-service throughout 2030 and into 2031. The total estimated project cost is approximately $1.84 billion, with $1.38 billion allocated for transmission and $460 million for distribution. As of December 31, 2025, $200.9 million has been spent on the project, with $154.7 million for transmission and $46.2 million for distribution. 36
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Distribution Business: A summary of distribution capital expenditures is as follows: For the Years Ended December 31, (Millions of Dollars) CL&P NSTAR Electric PSNH Total Electric Natural Gas Water Total 2025 Basic Business $ 300.8 $ 558.1 $ 118.0 $ 976.9 $ 201.0 $ 19.4 $ 1,197.3 Aging Infrastructure 132.5 403.6 92.1 628.2 731.6 152.5 1,512.3 Load Growth and Other 115.8 228.3 60.1 404.2 42.9 0.8 447.9 Total Distribution $ 549.1 $ 1,190.0 $ 270.2 $ 2,009.3 $ 975.5 $ 172.7 $ 3,157.5 2024 Basic Business $ 298.8 $ 471.7 $ 136.2 $ 906.7 $ 226.9 $ 21.8 $ 1,155.4 Aging Infrastructure 161.3 365.8 65.4 592.5 743.6 140.5 1,476.6 Load Growth and Other 110.6 194.3 66.4 371.3 52.3 0.8 424.4 Total Distribution $ 570.7 $ 1,031.8 $ 268.0 $ 1,870.5 $ 1,022.8 $ 163.1 $ 3,056.4 2023 Basic Business $ 280.3 $ 376.6 $ 91.1 $ 748.0 $ 208.2 $ 18.5 $ 974.7 Aging Infrastructure 260.7 310.0 86.4 657.1 719.5 142.3 1,518.9 Load Growth and Other 138.0 191.3 37.2 366.5 70.1 0.9 437.5 Total Distribution $ 679.0 $ 877.9 $ 214.7 $ 1,771.6 $ 997.8 $ 161.7 $ 2,931.1 For the electric distribution business, basic business includes the purchase of meters, tools, vehicles, information technology, transformer replacements, equipment facilities, and the relocation of plant. Aging infrastructure relates to reliability and the replacement of overhead lines, plant substations, underground cable replacement, and equipment failures. Load growth and other includes requests for new business and capacity additions on distribution lines and substation additions and expansions. We are also focused on making strategic AI investments currently in outage discovery, maintenance management and data analytics to better maintain our system and provide value to our customers. For the natural gas distribution business, basic business addresses daily operational needs including meters, pipe relocations due to public works projects, vehicles, and tools. Aging infrastructure projects seek to improve the reliability of the system through enhancements related to cast iron and bare steel replacement of main and services, corrosion mediation, and station upgrades. Load growth and other reflects growth in existing service territories including new developments, installation of services, and expansion. For the water distribution business, basic business addresses daily operational needs including periodic meter replacement, water main relocation, facility maintenance, and tools. Aging infrastructure relates to reliability and the replacement of water mains, regulators, storage tanks, pumping stations, wellfields, reservoirs, and treatment facilities. Load growth and other reflects growth in our service territory, including improvements of acquisitions, installation of new services, and interconnections of systems. Aquarion Sale Status and Regulatory Denial: In December 2024, Eversource obtained approval from its Board of Trustees to sell the Aquarion water distribution business. On January 27, 2025, Eversource entered into a definitive agreement to sell Aquarion to the Aquarion Water Authority (AWA), a quasi-public corporation and political subdivision of the State of Connecticut and a standalone, newly created water authority alongside the South Central Connecticut Regional Water Authority. In June 2024, a Connecticut law chartered AWA and enabled it to acquire, own and operate Aquarion as a not-for- profit water authority. Subject to certain closing adjustments, the aggregate enterprise value of the sale is approximately $2.4 billion in cash, which included approximately $1.6 billion for the equity and $800 million of net debt that will either be extinguished at closing or transferred to the buyer. The sale requires approval by PURA and the DPU, as well as other approvals pursuant to the Hart-Scott-Rodino Antitrust Improvements Act, for which the relevant waiting period has expired, as well as other customary closing conditions. Regulatory approvals in New Hampshire and Maine were received. Eversource plans to use the net proceeds from sale to pay down parent company debt. In the fourth quarter of 2024, upon classifying the assets and liabilities as held for sale, Eversource concluded that the likely sale of Aquarion at a loss resulted in the requirement to test water distribution goodwill for impairment. Eversource performed an impairment test by comparing the fair value of the business to its carrying value and recorded a goodwill impairment of $297 million, as the estimated fair value of the business based on the anticipated sale was less than the carrying value. The fair value included future cash outflows of approximately $140 million of estimated income taxes as a result of the transaction. The goodwill impairment charge was presented separately within Operating Income on the Eversource statement of income for the year ended December 31, 2024. On November 19, 2025, PURA denied the application to approve the sale, finding that the transaction did not meet managerial suitability and responsibility requirements due to concerns with governance and oversight structure over Aquarion and its consumer advocate. On December 2, 2025, the denial was appealed to the Connecticut Superior Court. On January 15, 2026, the Court issued its decision, sustaining the appeal and remanding back to PURA, finding that PURA acted illegally in denying the application as those disputed governance elements were mandated under Connecticut law. The Court upheld that operational aspects of the consumer advocate were within PURA’s statutory authority and regulatory discretion. A final decision is expected by PURA on March 25, 2026. 37
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Based on PURA’s November 19, 2025 denial of the sale and the uncertainty of the ultimate outcome, the Aquarion water distribution business no longer met the criteria to be classified as held for sale and its assets and liabilities were reclassified as held and used on the balance sheet as of December 31, 2025. The reclassification to held and used did not result in an adjustment to Aquarion’s carrying values. Projected Capital Expenditures: A summary of the projected capital expenditures for the regulated companies' electric transmission and for the total electric distribution and natural gas distribution for 2026 through 2030, including information technology and facilities upgrades and enhancements on behalf of the regulated companies, is as follows: Years (Millions of Dollars) 2026 2027 2028 2029 2030 2026 - 2030 Total CL&P Transmission $ 520 $ 358 $ 349 $ 241 $ 130 $ 1,598 NSTAR Electric Transmission 574 727 852 1,181 1,381 4,715 PSNH Transmission 181 275 291 85 97 929 Total Electric Transmission 1,275 1,360 1,492 1,507 1,608 7,242 Electric Distribution 2,291 2,278 2,180 2,197 2,296 11,242 Natural Gas Distribution 1,247 1,320 1,404 1,456 1,376 6,803 Total Electric and Natural Gas Distribution 3,538 3,598 3,584 3,653 3,672 18,045 Information Technology and All Other 259 217 276 219 256 1,227 Total $ 5,072 $ 5,175 $ 5,352 $ 5,379 $ 5,536 $ 26,514 Additionally, investments for the water distribution business are expected to total approximately $1.3 billion from 2026 through 2030. Actual capital expenditures could vary from the projected amounts for the companies and years above. FERC Regulatory Matters FERC ROE Complaints: Four separate complaints were filed at the FERC by combinations of New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (collectively, the Complainants). In each of the first three complaints, filed on October 1, 2011, December 27, 2012, and July 31, 2014, respectively, the Complainants challenged the NETOs' base ROE of 11.14 percent that had been utilized since 2005 and sought an order to reduce it prospectively from the date of the final FERC order and for the separate 15- month complaint periods. In the fourth complaint, filed April 29, 2016, the Complainants challenged the NETOs' base ROE billed of 10.57 percent and the maximum ROE for transmission incentive (incentive cap) of 11.74 percent, asserting that these ROEs were unjust and unreasonable. The ROE originally billed during the period October 1, 2011 (beginning of the first complaint period) through October 15, 2014 consisted of a base ROE of 11.14 percent and incentives up to 13.1 percent. On October 16, 2014, FERC issued Opinion No. 531-A and set the base ROE at 10.57 percent and the incentive cap at 11.74 percent for the first complaint period. This was also effective for all prospective billings to customers beginning October 16, 2014. This FERC order was vacated on April 14, 2017 by the U.S. Court of Appeals for the D.C. Circuit (the Court). All amounts associated with the first complaint period have been refunded. Eversource has recorded a reserve of $39.1 million (pre-tax and excluding interest) for the second complaint period as of both December 31, 2025 and 2024. This reserve represents the difference between the billed rates during the second complaint period and a 10.57 percent base ROE and 11.74 percent incentive cap. The reserve consisted of $21.4 million for CL&P, $14.6 million for NSTAR Electric and $3.1 million for PSNH as of both December 31, 2025 and 2024. On October 16, 2018, FERC issued an order on all four complaints describing how it intends to address the issues that were remanded by the Court. FERC proposed a new framework to determine (1) whether an existing ROE is unjust and unreasonable and, if so, (2) how to calculate a replacement ROE. Initial briefs were filed by the NETOs, Complainants and FERC Trial Staff on January 11, 2019 and reply briefs were filed on March 8, 2019. The NETOs' brief was supportive of the overall ROE methodology determined in the October 16, 2018 order provided the FERC does not change the proposed methodology or alter its implementation in a manner that has a material impact on the results. The FERC order included illustrative calculations for the first complaint using FERC's proposed frameworks with financial data from that complaint. Those illustrative calculations indicated that for the first complaint period, the preliminary just and reasonable base ROE for the NETOs, which FERC concludes are of average financial risk, is 10.41 percent and the preliminary incentive cap on total ROE is 13.08 percent. If the results of the illustrative calculations were included in a final FERC order for each of the complaint periods, then a 10.41 percent base ROE and a 13.08 percent incentive cap would not have a significant impact on our financial statements for all of the complaint periods. These preliminary calculations are not binding and do not represent what we believe to be the most likely outcome of a final FERC order. On November 21, 2019, FERC issued Opinion No. 569 affecting the two pending transmission ROE complaints against the Midcontinent ISO (MISO) transmission owners, in which FERC adopted a new methodology for determining base ROEs. Various parties sought rehearing. On December 23, 2019, the NETOs filed supplementary materials in the NETOs' four pending cases to respond to this new methodology because of the uncertainty of the applicability to the NETOs' cases. On May 21, 2020, the FERC issued its order in Opinion No. 569-A on the rehearing of the MISO transmission owners' cases, in which FERC again changed its methodology for determining the MISO transmission owners' base ROEs. On November 19, 2020, the FERC issued Opinion No. 569-B denying rehearing of Opinion No. 569-A and reaffirmed the methodology previously adopted in Opinion No. 569-A. The new methodology differs significantly from the methodology proposed by FERC in its October 16, 2018 order 38
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to determine the NETOs' base ROEs in their four pending cases. FERC Opinion Nos. 569-A and 569-B were appealed to the Court. On August 9, 2022, the Court issued its decision vacating MISO ROE FERC Opinion Nos. 569, 569-A and 569-B and remanded to FERC to reopen the proceedings. The Court found that FERC’s development of the new return methodology was arbitrary and capricious due to FERC’s failure to offer a reasonable explanation for its decision to reintroduce the risk-premium financial model in its new methodology for calculating a just and reasonable return. On October 17, 2024, FERC issued an order on the remand of the MISO ROE proceedings. The order addressed the Court’s decision that the reintroduction of the risk-premium financial model in the ROE methodology was arbitrary and capricious by removing the risk-premium financial model from the ROE methodology. The removal of the risk-premium financial model was the only revision to FERC’s ROE methodology and resulted in a two- model approach utilizing the two-step discounted cash flow model and the capital asset pricing model. MISO transmission owners were directed to provide refunds for the period November 12, 2013 to February 11, 2015 (the first MISO ROE complaint refund period) and for the period from September 28, 2016 (the date of FERC’s order on the first MISO ROE complaint) to October 17, 2024 by December 1, 2025. The order also stated that FERC does not preclude the use of the risk-premium financial model in future proceedings if the parties can demonstrate that FERC’s stated concerns around the inclusion of the model have been addressed. On March 25, 2025, FERC issued an order addressing arguments raised on rehearing, sustaining the result, and denying rehearing. On November 13, 2024, the NETOs filed a supplemental brief in their four pending ROE proceedings to explain to FERC that it cannot apply the reasoning and methodologies of the MISO ROE case to the NETOs’ cases due to the entirely different set of facts in the MISO and NETOs ROE proceedings. Doing so would violate the substance of the Court’s April 14, 2017 order and would violate the legal standard required by the Federal Power Act. On February 4, 2025, the MISO transmission owners submitted a petition for review with the Court requesting review of the October 17, 2024 MISO ROE order on remand and a December 19, 2024 notice of denial of rehearing. The petition requests review of FERC’s decision to retroactively backdate the MISO transmission owners’ base ROE to the date of an earlier order that FERC abandoned when it issued Order No. 569, treat an underlying unlawful complaint as if it were legitimate, and order eight years of interest as part of the directed refunds. On August 21, 2025, the NETOs submitted a brief in support of the MISO transmission owners with the Court. Final briefs in the Court proceeding were submitted on January 26, 2026 and oral argument is scheduled for March 17, 2026. Given the significant uncertainty regarding the applicability of the FERC order in the MISO transmission owners’ two complaint cases to the NETOs’ pending four complaint cases due to the complex differences between the cases, Eversource concluded that there is no reasonable basis for a change to the reserve or recognized ROEs for any of the complaints or subsequent periods at this time and Eversource cannot reasonably estimate any potential range of loss for any of the four complaint proceedings at this time. The resolution of these proceedings could have a material impact on the financial condition, results of operations, and cash flows. Eversource, CL&P, NSTAR Electric and PSNH currently record revenues at the 10.57 percent base ROE and incentive cap at 11.74 percent established in the October 16, 2014 FERC order. A change of 10 basis points to the base ROE used to establish the reserves would impact Eversource’s after-tax earnings by an average of approximately $3 million for each of the four 15-month complaint periods. Prospectively from the date of a final FERC order implementing a new base ROE, based off of estimated 2025 rate base, a change of 10 basis points to the base ROE would impact Eversource’s future annual after-tax earnings by approximately $7 million per year, and will increase slightly over time as we continue to invest in our transmission infrastructure. Transmission Rates and Other Transmission Rates-Related Proceedings: CL&P, NSTAR Electric and PSNH transmission rates are calculated in accordance with a FERC-approved formula ratemaking framework and each utility is required to file an annual update on or before July 31st with resulting rates effective January 1st the following year. The formula rate framework provides for an annual reconciliation of the prior calendar year actual costs incurred related to our transmission facilities, including an allowed ROE, plus forecasted information through the next rate period. The annual update process includes formula rate protocols that provide disclosure of cost inputs, an opportunity for informal discovery procedures and a challenge process, which provides transparency to stakeholders. From time to time, various matters are pending before FERC relating to transmission rates, incentives, interconnections and transmission planning. Depending on the outcome, any of these matters could materially impact our results of operations and financial condition. At this time, Eversource cannot predict the ultimate outcome of the matters currently pending before FERC, and the resulting impact on its transmission incentives or planning. Regulatory Developments and Rate Matters Electric, Natural Gas and Water Utility Retail Tariff Rates: Each Eversource utility subsidiary is subject to the regulatory jurisdiction of the state in which it operates: CL&P, Yankee Gas and Aquarion operate in Connecticut and are subject to PURA regulation; NSTAR Electric, NSTAR Gas, EGMA and Aquarion operate in Massachusetts and are subject to DPU regulation; and PSNH and Aquarion operate in New Hampshire and are subject to NHPUC regulation. The regulated companies' distribution rates are set by their respective state regulatory commissions, and their tariffs include mechanisms for periodically adjusting their rates for the recovery of specific incurred costs. Base Distribution Rates: In Connecticut, PURA is required to conduct a review and investigation of the financial and operating records of each electric, natural gas and water utility serving more than seventy-five thousand customers within four years of its last general rate hearing. PURA can elect to convene a general rate hearing at an interval of less than four years unless prohibited from doing so by an agency decision or other law. 39
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In Massachusetts, electric distribution companies are required to file distribution rate schedules every five years, and natural gas local distribution companies to file distribution rate schedules every 10 years, and those companies are limited to one settlement agreement in any 10-year period. Aquarion is not required to initiate a rate review with the DPU. In New Hampshire, PSNH is not required to initiate a rate review with the NHPUC on any set timeframe, and the NHPUC has no obligation to hear any rate matter that it has investigated within a period of two years, though it may elect to do so at its discretion. Rate Reconciling Mechanisms: The Eversource electric distribution companies obtain and resell power to retail customers who choose not to buy energy from a competitive energy supplier. CL&P, NSTAR Electric and PSNH enter into full requirements energy supply procurement contracts for its customers that choose to purchase power from the electric distribution company (standard offer, basic service or default energy service, respectively). The natural gas distribution companies procure natural gas for firm and seasonal customers. These energy supply and natural gas supply procurement costs are recovered from customers in supply rates that are approved by the respective state regulatory commission. The rates are reset periodically (every six months for electric residential customers) and are fully reconciled to their costs. New energy supply rates for residential customers are established effective July 1st at CL&P and NSTAR Electric and effective August 1st at PSNH. Each electric and natural gas distribution company fully recovers its energy supply costs through approved regulatory rate mechanisms on a timely basis and, therefore, such costs have no impact on earnings. Increases or decreases in energy supply retail rates result in corresponding fluctuations in both energy supply procurement revenues and purchased power or purchased natural gas expenses on the statements of income. The electric and natural gas distribution companies also recover certain other costs from customers in retail rates on a fully reconciling basis through regulatory commission-approved cost tracking mechanisms and therefore, recovery of these costs has no impact on earnings. Costs recovered through cost tracking mechanisms include, among others, state mandated energy purchase agreements and other energy-related costs, electric retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for the Massachusetts utilities, pension and PBOP benefits, net metering for distributed generation, and solar-related programs. The reconciliation filings compare the total actual costs allowed to revenue requirements related to these services and the difference between the costs incurred (or the rate recovery allowed) and the actual costs allowed is deferred and included, to be either recovered or refunded, in future customer rates. These cost tracking mechanisms also include certain incentives earned, return on capital tracking mechanisms, and carrying charges that are billed in rates to customers, which do impact earnings. Connecticut: CL&P Performance Based Rate Making: On May 26, 2021, in accordance with an October 2020 Connecticut law, PURA opened a proceeding to begin to evaluate and eventually implement performance-based regulation (PBR) for electric distribution companies. PURA is conducting the proceeding in two phases. On April 26, 2023, PURA issued a final decision on the first phase and identified various objectives to guide PBR development and evaluate adoption of a PBR framework. The decision commenced Phase 2 by initiating three reopener dockets focused on revenue adjustment mechanisms, performance metrics, and integrated distribution system planning. On November 16, 2023, PURA issued a straw proposal in the first reopener that focused on revenue adjustment mechanisms. The proposal outlined potential additions and reforms to the current revenue adjustment mechanisms, such as multi-year rate plans, earnings sharing mechanisms and the revenue decoupling mechanism. On March 14, 2024, PURA issued a straw proposal in the second reopener docket that concentrated on performance mechanisms in a PBR framework. The proposal suggested the development of performance incentive mechanisms, reported metrics and scorecards. On February 27, 2025, PURA issued revised straw proposals for both the first and second reopener dockets, resulting in some edits to the previous proposals based on participant feedback. On April 4, 2025, PURA issued a straw proposal in the third reopener docket that focused on the establishment of integrated distribution system planning under a PBR framework. On July 14, 2025, PURA issued proposed final decisions in the first two reopener dockets. The proposed final decision in the first reopener docket adopted a PBR framework inclusive of a multi-year rate plan with an attrition relief mechanism that uses a revenue-cap formula approach to adjust revenues based on a variety of factors including inflation, a productivity factor, a customer dividend percentage, an exogenous cost factor and a capital funding mechanism, as well as an earnings sharing mechanism and a revenue decoupling mechanism for implementation in CL&P’s next distribution rate case. The multi-year rate plan has a stay out period of four years, but certain situations, such as deteriorating financial condition, exceeding authorized return, falling interest rates, or excess storm costs, could trigger the initiation of a new rate amendment proceeding during the multi-year rate plan. The proposed final decision in the second reopener docket established reporting parameters, including the commencement of scorecards and reported metrics and the development of company specific performance incentive mechanisms. Results of scorecards and reported metrics are proposed to be reported annually to PURA, beginning March 1, 2026. Company specific performance incentive mechanisms will be implemented in CL&P’s next rate case proceeding. On August 8, 2025, PURA issued a proposed final decision in the third reopener docket, adopting the contents and reporting process for an integrated distribution system plan (IDSP) under a PBR framework. The IDSP report will document the grid planning process for available distribution system capacity and system needs, including the development, operation, and evolution of the electrical distribution grid. The IDSP report will include CL&P’s planned investments over a four-year plan period and long-term capital investment strategy, and will be utilized by PURA in determining the amount of allowable capital additions within a multi-year rate plan included in the calculation of the capital funding mechanism adopted in the first reopener docket. The draft decision requires CL&P to submit a comprehensive IDSP filing every four years in alignment with the submittal of a rate amendment application and to also submit an annual IDSP filing to report on IDSP investments throughout the four-year period. Final decisions on the three reopener dockets have not yet been scheduled. We continue to monitor developments in this proceeding, and at this time, we cannot predict the ultimate outcome of this proceeding and the resulting impact to CL&P. 40
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CL&P Storm Filings: On March 28, 2024, PURA established a prudency review proceeding for the purpose of receiving and reviewing evidence of the costs reported by CL&P in response to catastrophic storms and pre-staging events totaling approximately $634 million that occurred between January 1, 2018 and December 31, 2021. On December 31, 2024, CL&P filed a supplement to its March 2024 prudency review application to request that PURA evaluate the prudence of its costs for nine additional catastrophic storms and two additional pre-staging events for the period January 1, 2022 through January 31, 2023 totaling approximately $173 million. On July 10, 2025, CL&P filed a second supplement to its March 2024 prudency review application to request that PURA evaluate the prudence of its costs for ten additional catastrophic storms for the period February 1, 2023 through December 31, 2023 totaling approximately $171 million. On July 25, 2025, CL&P filed a third supplement in this application to include carrying charges calculated at the weighted average cost of capital on the deferred storm costs totaling $246 million, which reflects CL&P’s actual financing costs on the unpaid storm costs from the date the deferred storm costs first began to accrue through May 2025. These carrying charges have not been deferred on the balance sheet. On December 13, 2025, PURA opened a new proceeding for the prudency determination of CL&P’s 2018 to 2023 storm costs either by a settled or litigated process and a separate future docket will be needed to consider CL&P’s application to issue rate reduction bonds for the securitization of approved storm costs. A final decision is expected on or about July 29, 2026. Although we cannot predict the ultimate outcome of these storm proceedings, we continue to believe these deferred storm restoration costs were prudently incurred and are probable of recovery. CL&P RAM Filing: On March 28, 2025, PURA issued an interim decision in CL&P’s Rate Adjustment Mechanisms (RAM) filing and approved rates for six RAM components, with rates effective May 1, 2025 through April 30, 2026. The rates include recovery of over- or under-collection balances as of December 31, 2024, actual costs from the prior year, and adjustments to incorporate certain known and measurable cost changes not reflected in prior year costs that CL&P will incur in 2025. On August 13, 2025, PURA issued a final decision that approved a further adjustment to the Non-Bypassable Federally Mandated Congestion Charge (NBFMCC) and System Benefits Charge (SBC) rates based on a July 1, 2025 Connecticut law that authorized the State of Connecticut to issue new general obligation bonds to reduce certain hardship costs and electric vehicle program costs recovered from customers. Proceeds from the general obligation bond funding of $107.8 million will be provided back to customers through a reduction to the NBFMCC and SBC rates. The updated NBFMCC and SBC rates are effective September 1, 2025 through April 30, 2026. These rates are included in the “Public Benefits” portion of the customer bills in Connecticut. On September 19, 2025, CL&P received $107.8 million in general obligation bond proceeds from the State of Connecticut, which represent reimbursement of incurred costs that were previously recognized as regulatory assets on CL&P’s balance sheets. The proceeds received for the reimbursement of hardship costs and for electric vehicle charging program costs were credited against the SBC and NBFMCC regulatory deferrals on CL&P’s balance sheet as of December 31, 2025. The proceeds from the state bond funding are presented as a cash inflow in Regulatory Recoveries within operating activities on CL&P’s statement of cash flows. CL&P Advanced Metering Infrastructure Filing: On January 3, 2024, PURA issued a final decision regarding CL&P’s Advanced Metering Infrastructure (AMI) investment and implementation plan. In CL&P’s view, the final decision did not provide a reasonable path for cost recovery and would delay implementation. In addition, in CL&P’s view, the final decision modifies the prudence standard for recovery of costs expended on the project, improperly linking recovery to outcomes not known at the outset of the project. On January 18, 2024, CL&P submitted a motion for reconsideration to PURA, asking that the agency modify these aspects of the decision, which PURA subsequently denied on February 14, 2024. On March 6, 2024, CL&P filed written comments citing four major problems associated with PURA’s guidelines for recovery of the costs of AMI implementation, which if not addressed, represent obstacles to AMI implementation in Connecticut. On April 16, 2024, PURA issued a procedural order directing Eversource and inviting all parties and intervenors to submit pre-filed testimony pertaining to AMI. CL&P witnesses filed testimony, including an updated estimate of $855 million for capital costs and operating expenses, and then subsequently participated in the AMI cost recovery hearing on June 6,2024. On October 17, 2024, PURA issued a proposed final decision on recovery of the costs for AMI implementation. On October 31, 2024, CL&P filed written exceptions focused on three main aspects of the proposed decision, which included (1) clarifying the prudence standard to be used in evaluating AMI investments, (2) timing of prudency reviews, and (3) cost recovery related to incremental O&M expenses. On December 4, 2024, PURA issued a final decision on the recovery of costs for AMI implementation. On December 9, 2024, CL&P filed a petition for reconsideration because PURA had not fully resolved the issues CL&P raised in its October 31, 2024 written exceptions. On November 25, 2025, PURA issued correspondence in connection with CL&P’s October 31, 2025 annual AMI compliance filing asserting that it was no longer evaluating the merits of CL&P’s petition for reconsideration, that PURA approval is not required for CL&P to deploy AMI, and that CL&P may invest in AMI at any time and seek cost recovery under the AMI tariff after meeting established filing criteria. On December 19, 2025, CL&P filed a motion responding to the legal issues raised in PURA’s correspondence and requested that PURA reopen the prior proceeding for the purpose of lawfully acting upon CL&P’s December 9, 2024 petition for reconsideration and resolving the open questions on AMI cost recovery. Yankee Gas Distribution Rate Case: On November 12, 2024, Yankee Gas filed an application with PURA to amend its existing distribution rates for effect on November 1, 2025. Yankee Gas had subsequently amended its rate application to request approval of a distribution rate increase of $193 million. On September 22, 2025, PURA issued a proposed final (draft) decision in Yankee Gas’s distribution rate case that included a distribution rate increase of $55.6 million, effective November 1, 2025. On November 5, 2025, PURA issued a final decision in the Yankee Gas distribution rate case that included a distribution rate increase of $82.2 million and a total distribution revenue requirement of $802.2 million, effective November 1, 2025. The approved revenue requirement includes a previously recorded rate credit of $37.4 million plus carrying charges for non-firm margin credits over three years beginning November 1, 2025. Excluding the rate credit, the distribution rate increase totaled $95.7 million. The final decision also established an authorized net regulatory ROE of 9.32 percent, adopting a 9.48 percent ROE net of certain reductions totaling 16 basis points, and a 53 percent common equity ratio for Yankee Gas’ capital structure. PURA declined to approve the multi-year performance-based rate making plan that would adjust rates annually as proposed by Yankee Gas. PURA also implemented an annual cap on contemporaneous cost recovery of aging infrastructure replacement spending in the 41
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Distribution Integrity Management Program (DIMP) rate tracking mechanism of $139.9 million, in which spending above the annual cap will be deferred for recovery until the next distribution rate case. The final decision resulted in a net pre-tax loss to earnings of $8.5 million in the fourth quarter of 2025, primarily for the write off of certain capitalized employee compensation costs that were disallowed from rate base. Yankee Gas filed motions to request PURA reconsider the disallowances of these capitalized costs, certain computational errors, and other issues identified in its final decision. On December 15, 2025, PURA issued a notice of reconsideration to reconsider the final decision. A final decision on the reconsideration is expected from PURA by March 15, 2026. Aquarion Water Company of Connecticut Distribution 2022 Rate Case: On August 29, 2022, Aquarion Water Company of Connecticut (AWC-CT) filed an application with PURA to amend its existing rate schedules to address an operating revenue deficiency. AWC-CT’s rate application requested approval of rate increases of $27.5 million, an additional $13.6 million, and an additional $8.8 million, effective March 15, 2023, 2024, and 2025, respectively. On March 15, 2023, PURA issued a final decision that rejected this request. In this decision, PURA ordered a decrease to total authorized revenues of $4.0 million effective March 15, 2023. The decision allows an authorized regulatory ROE of 8.70 percent. On March 30, 2023, AWC-CT filed an appeal on the decision. On March 25, 2024, the State of Connecticut Superior Court issued a decision on the appeal which dismissed nine, remanded back to PURA two, and partially remanded one of AWC-CT’s twelve claims of error in its appeal. On April 18, 2024, PURA initiated a docket to address the matters on remand. On July 31, 2024, PURA issued a final decision in this docket and increased AWC-CT’s approved revenue requirement by $0.1 million above the amount authorized in the March 15, 2023 decision. Rates went into effect on July 31, 2024. On September 13, 2024, AWC-CT filed an appeal of PURA’s July 31, 2024 final decision to the Connecticut Superior Court. On December 9, 2025, the Connecticut Superior Court remanded the disallowance of approximately $0.4 million of rate case expenses back to PURA. PURA’s decision on the remand is pending. On March 28, 2024, AWC-CT filed an appeal of the March 25, 2024 Connecticut Superior Court decision to the Connecticut Appellate Court, and that appeal was subsequently transferred to the Connecticut Supreme Court. On July 9, 2025, the Connecticut Supreme Court issued a decision that overturned PURA’s disallowance of $1.5 million in water conservation program expenses, but affirmed the remaining portions of PURA’s decision that were challenged on appeal. The Connecticut Supreme Court decision also validated AWC-CT’s argument that the correct legal standard PURA must use in determining whether costs can be recovered through customer rates is the longstanding prudence standard, which evaluates the prudence of management decision-making as of the time the utility made the decision to incur costs; PURA cannot use improper hindsight analysis to evaluate prudence. On December 10, 2025, PURA revised its July 31, 2024 decision and increased AWC-CT’s approved revenue requirement by $0.3 million reflecting recovery of the $1.5 million conservation program expenses over six years. Massachusetts: NSTAR Electric Distribution Rates: NSTAR Electric’s PBR mechanism allows for an annual adjustment to base distribution rates for inflation, exogenous events and future capital additions based on a historical five-year average of total capital additions. On September 15, 2025, NSTAR Electric submitted its annual PBR Adjustment filing for a $55.1 million increase to base distribution rates and a total base distribution revenue requirement of $1.34 billion for effect on January 1, 2026. The requested base distribution rate increase is comprised of a $25.2 million inflation-based adjustment and a $29.9 million K- bar adjustment for capital additions based on the difference between the historical five-year average of total capital additions and the base capital revenue requirement. On December 30, 2025, the DPU approved this filing. NSTAR Electric’s Electric Sector Modernization Plan (ESMP) Filing: On August 29, 2024, the DPU approved the overall ESMP as a strategic plan for a five-year period commencing July 1, 2025 through June 30, 2030. The initial five-year plan proposed incremental distribution capital investments of $608 million and incremental distribution expense of $211 million. On November 21, 2024, the DPU opened a second phase of the proceeding (Phase II) to consider a short-term ESMP-focused cost recovery mechanism and metrics. The DPU limited the review of investment in this docket and excluded NSTAR Electric’s ESMP capital proposals regarding the EV Phase II extension and the new capital investment projects, and expense for the funding of low and moderate income solar. These investments will be reviewed in separate proceedings. This reduced the amount of company-proposed incremental capital investment to $295 million and the incremental expense to $44 million related to resiliency and grid modernization for a total spending cap of $339 million. NSTAR Electric filed its proposed tariff and testimony on December 18, 2024. On June 13, 2025, the DPU issued an order in the Phase II proceeding on the interim cost recovery mechanism for the ESMP, which approved the interim cost recovery mechanism with certain modifications. In the order, the DPU emphasized its attempt to balance affordability and the goals of advancing Massachusetts’ clean energy goals through proactive investments to support electrification and distributed generation. NSTAR Electric received approval for its proposed grid modernization and resiliency investments and incremental expense for a total spending cap of $139 million, reflecting an ordered reduction in capital spending on undergrounding for resiliency. In compliance with the Phase II order, a revised tariff was filed June 23, 2025, and the revised ESMP spending cap for the first term of July 1, 2025 through June 30, 2030, which included company-proposed incremental capital investment of $95 million and incremental expense of $44 million, was filed June 30, 2025. The DPU is conducting another phase of this proceeding to establish a long- term cost recovery mechanism, which is expected to be through base distribution rates. NSTAR Gas Distribution Rates: NSTAR Gas’ PBR mechanism allows for an annual adjustment to base distribution rates for inflation and exogenous events. On June 16, 2025, NSTAR Gas submitted its annual PBR Adjustment filing for rates to be effective on November 1, 2025. On September 11, 2025, NSTAR Gas updated its filing to request approval of a $162.6 million increase to base distribution rates and a total base distribution revenue requirement of $447.7 million. The base distribution rate increase is comprised of a $10.3 million inflation-based adjustment and, in accordance with the DPU’s final decision in the 2020 NSTAR Gas rate case, a $152.3 million rate-base reset to incorporate capital additions for the period 2021 through 2024, which includes the transfer of GSEP revenues totaling $107.3 million into base rates, as well as other non-GSEP plant additions totaling $45.0 million. 42
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On October 29, 2025, the DPU issued a decision determining that NSTAR Gas was not eligible to increase its distribution rates for the rate base reset because it did not achieve certain performance metrics under its PBR plan, and did not allow the base rate increase of $45.0 million for the incorporation of non-GSEP plant additions into base rates. The decision stated that those investments could be considered for inclusion in base distribution rates in NSTAR Gas’s next base rate proceeding. The DPU did allow NSTAR Gas to transfer its GSEP revenues through 2024 of $107.3 million for recovery through base distribution rates effective November 1, 2025. The DPU approved the base distribution rate increase of $10.3 million for the inflation-based adjustment. The DPU also approved NSTAR Gas’ mitigation proposal, in which NSTAR Gas paused recovery of the Gas System Enhancement Adjustment Factor (GSEAF) and reduced the current GSEAF to zero on November 1, 2025 in order to align this decrease with the base rate increase and to mitigate November 1, 2025 bill impacts to customers. NSTAR Gas will begin to recover the remaining 2025 GSEP revenue requirement on May 1, 2026 over 18 months. On November 4, 2025, NSTAR Gas filed a motion requesting the DPU to reconsider its decision denying the rate base reset citing legal concerns and arguing that the decision will ultimately result in higher costs for customers. NSTAR Gas also notified the DPU of its intention to file a base distribution rate case. On December 30, 2025, NSTAR Gas and the Massachusetts Office of the Attorney General reached a joint settlement agreement that allowed for the reinstatement of the rate base reset of $45.0 million increase to base distribution rates effective January 1, 2026, for NSTAR Gas to not petition for a rate case with new rates effective December 1, 2026, and for continuation of NSTAR Gas’ PBR program through November 1, 2030. The settlement agreement also required NSTAR Gas to provide a credit to customers of $10.2 million over a ten-month period beginning January 2026 as penalty for its failure to meet three performance metrics as required for eligibility for the rate base reset, pay a $2 million concession to the Office of the Attorney General to fund customer energy assistance programs, waive recovery of certain carrying charges, delay recovery of $53 million of capital pipeline investments until the next rate case, and provide bill stabilization credit deferrals. The DPU approved the settlement agreement on January 16, 2026. The settlement agreement resulted in a pre-tax charge to earnings of $12.2 million in the fourth quarter of 2025. NSTAR Electric and EGMA Settlement: On November 3, 2025, EGMA, NSTAR Electric, and the Massachusetts Office of the Attorney General reached a joint settlement agreement that resolved outstanding issues in multiple open Pension Adjustment Mechanism (PAM) dockets and open Resiliency Tree Work (RTW) dockets at NSTAR Electric and allows recovery of transaction and integration costs related to Eversource’s acquisition of EGMA. Certain PAM and RTW collections are being refunded to NSTAR Electric’s customers over a one-year period beginning January 1, 2026 and the transaction and integration costs of $82.3 million will be collected from EGMA customers over a ten-year period from the time of the next EGMA rate case. The settlement agreement was approved by the DPU on December 1, 2025. The settlement resulted in a net pre-tax benefit to earnings of $64.8 million on the Eversource income statement in the fourth quarter of 2025 ($82.3 million benefit at Eversource Parent and Other Companies for the allowed recovery of previously expensed acquisition-related and integration costs and $17.5 million charge at NSTAR Electric) and a net increase to regulatory assets on the Eversource balance sheet. Massachusetts 2026 Winter Bill Relief Program: In February 2026, NSTAR Electric, NSTAR Gas and EGMA implemented a winter electric and natural gas bill relief program as required by the DPU. Under this program, in February and March 2026, residential electric customers in Massachusetts will receive an aggregate bill reduction of approximately 25 percent and residential natural gas customers will receive an aggregate bill reduction of approximately 10 percent, a portion of which will be funded by the Commonwealth of Massachusetts. The remaining bill credits will be deferred for recovery from electric customers between April and December 2026 and from natural gas customers between May and October 2026, subject to DPU approval. No carrying charges will be collected. The bill relief program results in delayed collections from customers, impacting the timing of cash flows. Proceeds of $84.1 million were received by NSTAR Electric in January 2026 and will reduce regulatory assets recorded on its balance sheet in the first quarter of 2026. New Hampshire: PSNH Distribution Rate Case: On June 11, 2024, PSNH filed an application with the NHPUC for approval of a temporary annual base distribution rate increase. On July 31, 2024, the NHPUC approved a settlement agreement that was reached by PSNH, New Hampshire Department of Energy, and the Office of the Consumer Advocate to implement a temporary annual base distribution rate increase of $61.2 million effective August 1, 2024. Temporary rates were in effect until permanent rates were approved and took effect August 1, 2025. Also on June 11, 2024, PSNH filed an application with the NHPUC to request an increase in permanent base distribution rates of $181.9 million, which is inclusive of the temporary rate increase. Throughout the course of the proceeding, PSNH amended the requested revenue requirement to account for developments in the case, and arrived at a final proposed rate increase of $103 million, which primarily reflects the removal of deferred storm costs that will be addressed in a separate proceeding. On July 25, 2025, the NHPUC issued its decision on permanent rates and approved a permanent rate increase of $100.7 million, effective August 1, 2025, inclusive of the temporary rate increase referenced above. The total base distribution revenue requirement effective August 1, 2025 is $519 million. The order also established an authorized regulatory ROE of 9.5 percent with a 50 percent common equity ratio for PSNH’s capital structure. This revenue requirement also contains an alternative regulation revenue requirement adjustment. This adjustment was part of the NHPUC’s alternative regulatory framework that the NHPUC adopted as an alternative to PSNH’s proposed performance-based regulation plan. The alternative regulatory framework authorizes formulaic annual revenue adjustments on August 1st of 2026, 2027 and 2028. PSNH is required to file its next base distribution rate case for effect in June 2029 and committed not to file its next distribution rate case until 2029. The alternative regulatory framework calculates the annual revenue adjustment using a productivity factor and an adjustment for inflation to provide PSNH with increased revenue for operations. The framework also contains an exogenous events recovery mechanism for certain unforeseen events out of PSNH’s control and exceeding a specified threshold, a performance metric, and an earnings sharing mechanism where PSNH would have to return 75 percent of all revenue back to customers that exceeds 25 basis points more than the authorized ROE of 9.5 percent. Consistent with PSNH’s proposal, lost base revenues for both net metering and energy efficiency were eliminated effective August 1, 2025.
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To the extent permanent rates exceed the level of temporary rates, the difference will reconcile back to the date that the temporary rates took effect and the company recovers the difference over a twelve-month term. On August 11, 2025, PSNH filed its recoupment calculation, and on September 10, 2025, the NHPUC issued an order that the recoupment is $9.1 million and will be collected through the RRA regulatory tracking mechanism over a one-year period. As part of the decision, unrecovered storm costs of $247 million were removed from the rate proceeding for consideration in a separate proceeding. Approval of the ultimate amount of storm costs to be recovered is subject to a separate prudency review that was filed in March of 2024 and is being considered by the NHPUC in a separate dedicated docket, which is at this time complete and awaiting the issuance of an order. Approved storm costs in excess of the amount approved in base rates will be recovered through the Regulatory Reconciliation Adjustment (RRA) regulatory tracking mechanism. The NHPUC increased the level of storm costs recovered in base rates from $12 million to $19 million. The impact of the rate case decision resulted in a pre-tax benefit to earnings of $15.6 million at PSNH due primarily to the recoupment and the allowed recovery of other deferrals that will be recovered in the RRA. The majority of this amount was recorded as a reduction to amortization expense on PSNH’s statement of income in 2025. On January 30, 2026, the New Hampshire Department of Energy filed a notice of appeal with the New Hampshire Supreme Court challenging certain aspects of the PSNH distribution rate case. The appeal raises issues regarding the lawfulness of the Company’s alternative regulatory framework, the adequacy of the NHPUC’s findings supporting the approved revenue requirement, and whether the NHPUC sufficiently addressed required regulatory factors in its final order. The Department of Energy contends that additional findings were necessary to support the final determinations. On February 6, 2026, the Office of the Consumer Advocate filed a notice of cross-appeal with the New Hampshire Supreme Court challenging other aspects of the rate case decision. The NHPUC, as the deciding agency, is afforded the highest level of deference by the New Hampshire Supreme Court, and therefore the Department of Energy and the Office of Consumer Advocate will have a very high burden to meet to be successful on appeal. Eversource is currently evaluating the appeals and will respond consistent with applicable legal and regulatory processes. Legislative and Policy Matters Federal: On July 4, 2025, An Act to Provide for Reconciliation Pursuant to Title II of H. Con. Res. 14 (known as the One Big Beautiful Bill Act or OBBBA), a budget and reconciliation package, was signed into law. Among various items, the law includes changes to federal tax policy and modifications to clean energy tax incentives originally enacted under the Inflation Reduction Act of 2022. One of the key provisions notable for Eversource is the restoration of bonus depreciation for its affiliates other than rate-regulated utility companies. The deduction is for qualifying depreciable tangible property acquired and placed in service after January 19, 2025. The OBBBA maintains a federal corporate income tax rate of 21 percent. The OBBBA also includes provisions that remove federal tax credits for renewable energy. The OBBBA phases out the clean electricity production credit and the clean electricity investment tax credit for wind and solar projects that begin construction after July 4, 2026 and are not placed in service before December 31, 2027. Projects that begin construction prior to July 4, 2026 will remain eligible for investment tax credit benefits under the Inflation Reduction Act of 2022. The Company has evaluated the impacts of the OBBBA on our consolidated financial statements. The law will not have an impact on Eversource’s tax equity investment in the South Fork Wind project or the Revolution Wind project for which Eversource has remaining financial obligations. Under the OBBBA, clean energy credits, such as clean electricity investment, can lose eligibility if an entity is owned by, controlled by, or receives material assistance from certain prohibited foreign entities. This foreign ownership would include equity ownership and indirect involvement such as debt holdings and supply-chain relationships. The Company currently does not have any tax credits that qualify under the new OBBBA rules. Connecticut: On July 1, 2025, Connecticut enacted Public Act No. 25-173, An Act Concerning Energy Affordability, Access, and Accountability, (Senate Bill No. 4) (the Act), which aims to reduce electric rates for Connecticut retail customers by up to $300 million over the next two years in the public benefits charges on electric bills for hardship protection measures and electric vehicle program costs through the issuance of state bonds that would fully fund these state-mandated program costs in lieu of collecting these amounts in electric rates. The Act authorizes the State of Connecticut to issue up to $125 million in new general obligation bonds for each fiscal year 2026 and 2027 to reduce costs of hardship protection measures charged to retail customers, of which 67 percent of each issuance will be allocated to CL&P, and $30 million for fiscal year 2026 and $20 million for fiscal year 2027 in new general obligation bonds to fund the electric vehicle charging program, of which 80 percent of each issuance will be allocated to CL&P. Rate reductions were implemented prospectively beginning September 1, 2025 in CL&P’s revenue adjustment mechanism. The Act authorizes the securitization of storm-related expenses for the period January 1, 2018 through January 1, 2025, which covers the majority of deferred storm costs on the CL&P balance sheet, as well as advanced metering infrastructure (AMI) and legacy meter investments, allowing for the recovery of these costs from customers over a longer term to mitigate short-term rate impacts. The Act also seeks to reduce electric rates for retail customers by revising the statutory framework for renewable portfolio standards. The Act also directs PURA’s procurement manager, after consultation with the electric distribution companies, the Consumer Counsel and the Commissioner of DEEP, to file with PURA a proposed amendment to the plan to procure standard electric service that would authorize electric distribution companies to, among other things, make dynamic market purchases to attempt to reduce the average cost and minimize the price volatility of standard electric service. 44
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Implementation of the Act’s provisions will require further regulatory proceedings and administrative action. We do not anticipate any significant impact to our operating revenues or earnings as a result of the Act’s enactment. However, we expect PURA to initiate proceedings related to securitization, renewable portfolio standard obligations, and other provisions in the Act, which may impact future rate design and recovery mechanisms. On October 20, 2025, Governor Lamont nominated four new PURA commissioners who, along with an existing commissioner, enable the agency to now operate with the maximum number of commissioners. The four nominees will serve in an interim capacity until they are confirmed by the legislature. PFAS Settlements: Aquarion opted into class-action settlements with the defendants 3M Company, E.I. duPont de Nemours and Company, Tyco Fire Products LP, and BASF Corporation. These settlement agreements were entered to resolve claims of per- and polyfluoroalkyl substances (PFAS) contamination in the drinking water provided by public water systems. In July 2024 and April 2025, Aquarion and other qualifying class members submitted claims to receive settlement awards; these awards were allocated based on the overall number of claimants, PFAS concentrations and flow rates of water sources, and a variety of other factors. The final, total recovery from these settlements is unknown and will be based on the Claims Administrator’s review of the submitted claims and the subsequent allocation procedures. Aquarion anticipates receiving recovery from 3M Company over the next nine years and from E.I. duPont de Nemours and Company over the next two years. The schedule for BASF Corporation and Tyco Fire Products LP are unknown at this time. Aquarion has received $17.8 million of proceeds in 2025. Proceeds from the settlements will be used to fund capital expenditures. Critical Accounting Policies The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and, at times, difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows. Our management discusses with the Audit Committee of our Board of Trustees significant matters relating to critical accounting policies. Our critical accounting policies are discussed below. See the combined notes to our financial statements for further information concerning the accounting policies, estimates and assumptions used in the preparation of our financial statements. Regulatory Accounting: Our regulated companies are subject to rate regulation that is based on cost recovery and meets the criteria for application of accounting guidance for rate-regulated operations, which considers the effect of regulation on the timing of the recognition of certain revenues and expenses. The regulated companies' financial statements reflect the effects of the rate-making process. The rates charged to the customers of our regulated companies are designed to collect each company's costs to provide service, including a return on investment. We believe that the operations of each of our regulated companies currently satisfy the criteria for application of regulatory accounting. If events or circumstances should change in a future period so that those criteria are no longer satisfied, we would be required to eliminate any associated regulatory assets and liabilities and the impact would be recognized in the statement of income and may result in a material adverse effect on results of operations and financial condition. The application of accounting guidance for rate-regulated enterprises results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base our conclusion on certain factors, including, but not limited to, regulatory precedent. Regulatory liabilities represent either revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers. We make judgments regarding the future outcome of regulatory proceedings that involve potential future refund to customers and record liabilities for these loss contingencies when probable and reasonably estimable based upon available information. Regulatory liabilities are recorded at the best estimate, or at a low end of the range of possible loss. The amount recorded may differ from when the uncertainty is resolved. Such differences could have a significant impact on our financial statements. We continually assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or refund. This assessment includes consideration of recent orders issued by regulatory commissions, the passage of new legislation, historical regulatory treatment for similar costs in each of our jurisdictions, discussions with legal counsel, the status of any appeals of regulatory decisions, and changes in applicable regulatory and political environments. We believe that we will continue to be able to defer and recover prudently incurred costs, including additional storm costs, based on the legal and regulatory framework. We use judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our financial statements. The ultimate outcome of regulatory rate proceedings could have a significant effect on our ability to recover costs or earn an adequate return. Established rates are also often subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed. 45
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Storm restoration and pre-staging costs are subject to prudency reviews from our regulators. We have $2.06 billion of deferred storm costs that either have yet to be filed with the applicable regulatory commission, are pending regulatory approval, or are subject to prudency review as of December 31, 2025. Tropical Storm Isaias in August 2020 resulted in deferred storm restoration costs of approximately $232 million at CL&P as of December 31, 2025. Although in 2021 PURA found that CL&P’s performance in its preparation for, and response to, Tropical Storm Isaias fell below applicable performance standards in certain instances, CL&P believes it presented in its 2023 storm filing credible evidence demonstrating there is no reasonably close causal connection between the alleged sub-standard performance and the storm costs incurred. While it is possible that some amount of the Tropical Storm Isaias costs may be disallowed by PURA, any such amount cannot be estimated at this time. We believe that our storm restoration costs deferred were prudently incurred, meet the criteria for cost recovery, and are probable of recovery. We believe it is probable that each of our regulated companies will recover its respective investments in long-lived assets and the regulatory assets that have been recorded. If we determine that we can no longer apply the accounting guidance applicable to rate-regulated enterprises, or that we cannot conclude it is probable that costs will be recovered from customers in future rates, the applicable costs would be charged to net income in the period in which the determination is made. Pension, SERP and PBOP: We sponsor Pension, SERP and PBOP Plans to provide retirement benefits to our employees. Plan assets and the benefit obligation are presented on a net basis and we recognize the overfunded or underfunded status of the plans as an asset or liability on the balance sheet. These amounts are remeasured annually using a December 31st measurement date. For each of these plans, several significant assumptions are used to determine the projected benefit obligation, funded status, and net periodic benefit expense/income. These assumptions include the expected long-term rate of return on plan assets, discount rate, compensation/progression rate, cash balance interest crediting rate and mortality and retirement assumptions. We evaluate these assumptions annually and adjust them as necessary. Changes in these assumptions could have a material impact on our financial position, results of operations or cash flows. Expected Long-Term Rate of Return on Plan Assets Assumption: In developing the expected long-term rate of return, we consider historical and expected returns, as well as input from our consultants. Our expected long-term rate of return on assets is based on assumptions regarding target asset allocations and corresponding expected rates of return for each asset class. We routinely review the actual asset allocations and periodically rebalance the investments to the targeted asset allocations. For the year ended December 31, 2025, our expected long-term rate-of-return assumption used to determine our pension and PBOP expense was 8.25 percent for the Eversource Service Pension and PBOP plans. For the forecasted 2026 pension and PBOP expense, an expected long-term rate of return of 8.25 percent for the Eversource Service Pension and PBOP plans will be used reflecting our target asset allocations. Discount Rate Assumptions: Payment obligations related to the Pension, SERP and PBOP Plans are discounted at interest rates applicable to the expected timing of each plan's cash flows. The discount rate that was utilized in determining the pension, SERP and PBOP obligations was based on a yield-curve approach. This approach utilizes a population of bonds with an average rating of AA based on bond ratings by Moody's, S&P and Fitch, and uses bonds with above median yields within that population. As of December 31, 2025, the discount rates used to determine the funded status were within a range of 4.9 percent to 5.5 percent for the Pension and SERP Plans, and 5.4 percent to 5.5 percent for the PBOP Plans. As of December 31, 2024, the discount rates used were within a range of 5.6 percent to 5.7 percent for the Pension and SERP Plans, and 5.7 percent for the PBOP Plans. The decrease in the discount rates used to calculate the funded status resulted in an increase to the Pension and SERP Plans’ projected benefit obligation of $98.2 million and an increase to the PBOP Plans' projected benefit obligation of $11.2 million as of December 31, 2025. The Company uses the spot rate methodology for the service and interest cost components of Pension, SERP and PBOP expense because it provides a relatively precise measurement by matching projected cash flows to the corresponding spot rates on the yield curve. The discount rates used to estimate the 2025 expense were within a range of 5.2 percent to 5.8 percent for the Pension and SERP Plans, and within a range of 5.4 percent to 5.9 percent for the PBOP Plans. Mortality Assumptions: Assumptions as to mortality of the participants in our Pension, SERP and PBOP Plans are a key estimate in measuring the expected payments a participant may receive over their lifetime and the corresponding plan liability we need to record. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. In 2025, our mortality assumption utilized the Society of Actuaries base mortality tables (Pri-2012), adjusted to reflect Eversource’s own mortality experience, and projected generationally using the MP-2021 improvement scale. Compensation/Progression Rate Assumptions: This assumption reflects the expected long-term salary growth rate, including consideration of the levels of increases built into collective bargaining agreements, and impacts the estimated benefits that Pension and SERP Plan participants will receive in the future. As of December 31, 2025 and 2024, the compensation/progression rates used to determine the Pension and SERP Plan funded status were within a range of 3.5 percent to 4.0 percent. Health Care Cost Assumptions: The Eversource Service PBOP Plan is not subject to health care cost trends. Cash Balance Interest Crediting Rate Assumption: The Cash Balance Pension Plan is a recent additional obligation of the existing Eversource Service Pension Plan and the liability began to accrue benefits upon the effective date of January 1, 2025. The cash balance interest crediting rate assumption represents the long-term rate by which the Pension Plan’s cash balance accounts are expected to grow. Actual interest on the cash balance accounts is based on the 30-year U.S. Treasury securities rate in effect for September of the preceding year, with a minimum rate of 4 percent. The cash balance interest crediting rate assumption used in determining the forecasted 2026 pension expense was 4.8 percent. 46
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Actuarial Gains and Losses: Actuarial gains and losses represent the differences between actuarial assumptions and actual information or updated assumptions. Unamortized actuarial gains or losses arising at the December 31st measurement date are primarily from differences in actual investment performance compared to our expected return and changes in the discount rate assumption. The Eversource Service Pension and PBOP Plans use the corridor approach to determine the amount of gain or loss to amortize into net periodic benefit expense/income. The corridor approach defers all actuarial gains and losses arising at remeasurement and the net unrecognized actuarial gain or loss balance is amortized as a component of expense if, as of the beginning of the year, that net gain or loss exceeds 10 percent of the greater of the market value of the plan’s assets or the projected benefit obligation. The amount of net unrecognized actuarial gain or loss in excess of the 10 percent corridor is amortized to expense over the estimated average future employee service period. For the Eversource Service Pension Plan, the net actuarial gain or loss is amortized as a component of expense over the estimated average future employee service period of thirteen years. For the Eversource Service PBOP Plan, the net unrecognized actuarial gain or loss was within the 10 percent corridor and therefore there was no amortization to expense during 2025. A decrease in the discount rate used to determine our pension funded status would increase our projected benefit obligation at December 31st, resulting in a higher unamortized actuarial loss to be recognized in future years’ pension expense, subject to exceeding the 10 percent corridor. A decrease in the discount rate at December 31st would also result in a decrease in the interest cost component and an increase in the service cost component of the subsequent year’s benefit plan expense. The calculated expected return on plan assets is compared to the actual return or loss on plan assets at the end of each year to determine the investment gains or losses to be immediately reflected in unamortized actuarial gains and losses. An underperformance of our pension plan investment returns relative to the expected returns would increase our pension liability at December 31st, resulting in a higher unamortized actuarial loss to be recognized in future years’ pension expense, subject to exceeding the 10 percent corridor, and a lower expected return on assets component of pension expense in future years’ pension expense. Net Periodic Benefit Expense/Income: Pension, SERP and PBOP expense/income is determined by our actuaries and consists of service cost and prior service cost/credit, interest cost based on the discounting of the obligations, amortization of actuarial gains and losses, and the expected return on plan assets. For the Pension and SERP Plans, pre-tax net periodic benefit income was $83.5 million, $76.8 million and $108.4 million for the years ended December 31, 2025, 2024 and 2023, respectively. For the PBOP Plans, pre-tax net periodic benefit income was $68.7 million, $64.3 million and $57.3 million for the years ended December 31, 2025, 2024 and 2023, respectively. The change in pension, SERP and PBOP expense/income arising from the annual remeasurement does not fully impact earnings. Our Massachusetts utilities recover qualified pension and PBOP expenses related to their distribution operations through a rate reconciling mechanism that fully tracks the change in net pension and PBOP expenses each year, and therefore the change in their pension and PBOP expense does not impact earnings. Our electric transmission companies' rates provide for an annual true-up of estimated to actual costs, which include pension expenses, and therefore the change in their pension expense does not impact earnings. Any differences between the fixed level of PBOP expense included in our formula rate and the PBOP expense calculated in accordance with authoritative accounting guidance is accumulated as a regulatory asset or liability, and is expected, over time, to be recovered from or returned to customers. Additionally, the portion of our pension and PBOP expense that relates to company labor devoted to capital projects is capitalized on the balance sheet instead of being charged to expense. Forecasted Expense/Income and Expected Contributions: We estimate that net periodic benefit income in 2026 for the Pension and SERP Plans will be approximately $124 million and for the PBOP Plans will be approximately $79 million. The increase in pension income from 2025 to 2026 is driven primarily by a decrease in the interest cost component and by favorable expected return on assets due to a higher asset balance, partially offset by an increase in the service cost component. The increase in PBOP income from 2025 to 2026 is driven primarily by favorable expected return on assets due to a higher asset balance and a decrease in the interest cost component. For the PBOP Plans, there is no amortization of actuarial loss in 2026. Pension, SERP and PBOP expense/income for subsequent years will depend on future investment performance, changes in future discount rates and other assumptions, and various other factors related to the populations participating in the plans. Our policy is to fund the Pension Plans annually, as necessary, in an amount at least equal to the amount that will satisfy all federal funding requirements. Based on the current status of the Pension Plans and federal pension funding requirements, for our Eversource Service Pension Plan there is no minimum funding requirement in 2026 and we do not expect to make pension contributions in 2026. It is our policy to fund the PBOP Plans annually, as necessary, through tax deductible contributions to external trusts. We do not expect to make any contributions to the Eversource Service PBOP Plan in 2026. Sensitivity Analysis: The following table illustrates the hypothetical effect on reported annual net periodic benefit income as a result of a change in the following assumptions by 50 basis points: Pension Plans (excluding SERP Plans) PBOP Plans Decrease in Plan Income Decrease/(Increase) in Plan Income (Millions of Dollars) For the Years Ended December 31, For the Years Ended December 31, Eversource 2025 2024 2025 2024 Lower expected long-term rate of return $ 28.4 $ 28.9 $ 5.2 $ 5.0 Lower discount rate 14.5 27.4 (0.3) (0.5) Higher compensation rate 4.1 5.9 N/A N/A 47
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Goodwill: Goodwill is recognized on our balance sheet from previous mergers and acquisitions to the extent that the consideration paid exceeded the net fair value of the identified assets and liabilities acquired in each business combination. We are required to test goodwill balances for impairment at least annually by considering the fair values of the reporting units, which requires us to use estimates and judgments. Additionally, we monitor all relevant events and circumstances during the year to determine if an interim impairment test is required. We have selected October 1st of each year as the annual goodwill impairment test date. Goodwill impairment is deemed to exist if the carrying amount of a reporting unit exceeds its estimated fair value. If goodwill were to be impaired, it would be written down in the current period to the extent of the impairment. We have identified our reporting units for purposes of allocating and testing goodwill as Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution. The Electric Distribution and Electric Transmission reporting units include carrying values for the respective components of CL&P, NSTAR Electric and PSNH. The Natural Gas Distribution reporting unit includes the carrying values of NSTAR Gas, Yankee Gas and EGMA. The Water Distribution reporting unit includes the Aquarion water utility businesses. As of December 31, 2025, goodwill was allocated to the reporting units as follows: $2.54 billion to Electric Distribution, $577 million to Electric Transmission, $451 million to Natural Gas Distribution, and $662 million to Water Distribution. In assessing goodwill for impairment, an entity is permitted to first assess qualitatively whether it is more likely than not that goodwill impairment exists as of the annual impairment test date. If we perform the qualitative assessment but determine it is more likely than not that a reporting unit’s fair value is less than its carrying amount, we perform a quantitative test to compare the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, we record an impairment loss as a reduction to goodwill and a charge to operating expenses, but the loss recognized would not exceed the total amount of goodwill allocated to the reporting unit. We completed our annual goodwill impairment assessment for the Electric Distribution, Electric Transmission and Natural Gas Distribution reporting units as of October 1, 2025 and determined it was more likely than not that their fair value exceeded carrying value and no impairment existed. The annual goodwill assessment included a qualitative evaluation of multiple factors that impact the fair value of the reporting units, including general, macroeconomic and market conditions, and entity-specific assumptions that affect the future cash flows of the reporting units. Key considerations include discount rates, utility sector market performance and merger transaction multiples, the Company's share price and credit ratings, analyst reports, financial performance, cost and risk factors, internal estimates and projections of future cash flows and net income, long-term strategy, the timing and outcome of rate cases, and recent regulatory and legislative proceedings. For these reporting units, we believe that their fair value was substantially in excess of their carrying value. Adverse regulatory actions, changes in the regulatory and political environment, or changes in significant assumptions could potentially result in future goodwill impairment indicators. For the Water Distribution reporting unit, in the fourth quarter of 2024, we concluded that the likely sale of Aquarion at a loss resulted in the requirement to perform an interim goodwill impairment test for Water Distribution goodwill. We compared the estimated fair value of the business from the anticipated transaction to its carrying value. Assumptions used in the valuation were the future cash flows from the sale, including the estimated income tax impacts as a result of the transaction. Based on the interim impairment test, we recorded a goodwill impairment of $297 million to write down the carrying value of the water distribution reporting unit to its estimated fair value. The remaining goodwill held by the Water Distribution reporting unit was reclassified to Assets Held for Sale on the Eversource balance sheet as of December 31, 2024 and became part of the water distribution disposal group. As of October 1, 2025, our annual goodwill impairment test date, the goodwill of the Water Distribution reporting unit was classified within Assets Held for Sale, and the disposal group was carried at fair value less cost to sell. Based on PURA’s November 19, 2025 denial of the Aquarion sale and the uncertainty of the ultimate outcome, the Aquarion water distribution business no longer met the criteria to be classified as held for sale. The goodwill held by the Water Distribution reporting unit of $662.5 million that was previously classified within Assets Held for Sale has been reclassified to Goodwill on the Eversource balance sheet as of December 31, 2025. In the fourth quarter of 2025, we performed a goodwill impairment test for Water Distribution goodwill and determined that no impairment existed. Long-Lived Assets: Impairment evaluations of long-lived assets, including property, plant and equipment and other assets, involve a significant degree of estimation and judgment, including identifying circumstances that indicate an impairment may exist. An impairment analysis is required when events or changes in circumstances indicate that the carrying value of a long-lived asset may not be recoverable. Indicators of potential impairment include a deteriorating business climate, unfavorable regulatory action, decline in value that is other than temporary in nature, plans to dispose of a long-lived asset significantly before the end of its useful life, and accumulation of costs that are in excess of amounts allowed for recovery. The evaluation of long-lived assets for impairment utilizes significant assumptions about operating strategies and external developments, including assessment of current and projected market conditions that can impact future cash flows. If indicators are present for a long-lived asset or asset group, a comparison of the undiscounted expected future cash flows to the carrying value is performed. No significant impairments occurred during the year 2025. Loss Contingencies: We make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information. The assessment of loss contingencies involves judgments and assumptions about future events. Our estimates are subject to revision in future periods based on actual costs or new information. The amount recorded may differ from the actual expense incurred when the uncertainty is resolved. Such difference would be a change in estimate and could have a significant impact on the financial statements. Upon the sales of our offshore wind investments in 2024, we recorded a contingent liability reflecting our estimate of the future obligations under the terms of the sale to GIP for the South Fork Wind and Revolution Wind projects. As of December 31, 2025 and 2024, the contingent liability totaled $448.2 million and $365.0 million, respectively. Assumptions and key judgments in determining the estimated liability include the expected cost overrun sharing obligation, expected obligation to maintain GIP’s internal rate of return through the construction period, expected 48
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attainment of commercial operation, obligation for other future costs prior to commercial operation, as well as the likelihood of realization of investment tax credit adders that were included in the purchase price. The use of different assumptions, estimates, or judgments could materially impact the financial statements. We rely on information that we receive from the project owners for the construction-related, delay-related, and insurance-related costs of Revolution Wind. We use our judgment to adjust, as needed, the expected obligations to GIP while construction of Revolution Wind is completed. New information or future developments that arise as the construction of Revolution Wind progresses will necessitate a reassessment of the estimated liability to GIP. Adverse changes in facts, regulations and circumstances could result in additional losses that could be material to the financial statements. Accounting for Environmental Reserves: Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated. Increases to estimates of environmental liabilities could have an adverse impact on earnings. We estimate these liabilities based on findings through various phases of the assessment, considering the most likely action plan from a variety of available remediation options (ranging from no action required to full site remediation and long-term monitoring), current site information from our site assessments, remediation estimates from third-party engineering and remediation contractors, and our prior experience in remediating contaminated sites. If a most likely action plan cannot yet be determined, we estimate the liability based on the low end of a range of possible action plans. A significant portion of our environmental sites and reserve amounts relate to former MGP sites that were operated several decades ago and manufactured natural gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment, for which we may have potential liability. Estimates are based on the expected remediation plan. Our estimates are subject to revision in future periods based on actual costs or new information from other sources, including the level of contamination at the site, the extent of our responsibility or the extent of remediation required, recently enacted laws and regulations or a change in cost estimates. Allowance for Uncollectible Accounts: We estimate the allowance for uncollectible accounts based upon various judgments and factors, including an aging-based quantitative assessment that applies an estimated uncollectible percentage to each receivable aging category. Factors in determining credit loss include historical collection, write-off experience, analysis of delinquency statistics, and management's assessment of collectability from customers, including current economic conditions, customer payment trends, the impact on customer bills because of energy usage trends and changes in rates, flexible payment plans and financial hardship arrearage management programs offered to customers, reasonable forecasts, and expectations of future collectability and collection efforts. Management continuously assesses the collectability of receivables and adjusts estimates based on actual experience and future expectations based on economic conditions, collection efforts and other factors. Management also monitors the aging analysis of receivables to determine if there are changes in the collections of accounts receivable. Income Taxes: Income tax expense is estimated for each of the jurisdictions in which we operate and is recorded each quarter using an estimated annualized effective tax rate. This process to record income tax expense involves estimating current and deferred income tax expense or benefit and the impact of temporary differences resulting from differing treatment of items for financial reporting and income tax return reporting purposes. Such differences are the result of timing of the deduction for expenses, as well as any impact of permanent differences, or other items that directly impact income tax expense as a result of regulatory activity (flow-through items). The temporary differences and flow-through items result in deferred tax assets and liabilities that are included in the balance sheets. We also account for uncertainty in income taxes, which applies to all income tax positions previously filed in a tax return and income tax positions expected to be taken in a future tax return that have been reflected on our balance sheets. The determination of whether a tax position meets the recognition threshold under applicable accounting guidance is based on facts and circumstances available to us. The interpretation of tax laws and associated regulations involves uncertainty since tax authorities may interpret the laws differently. Ultimate resolution or clarification of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material. Significant management judgment is required in determining the provision for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. We evaluate the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and our intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. We also assess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate the inability to realize the deferred tax assets. Valuation allowances are provided to reduce deferred tax assets to the amount that will more likely than not be realized in future periods. This requires management to make judgments and estimates regarding the amount and timing of the reversal of taxable temporary differences, expected future taxable income, and the impact of tax planning strategies. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, not realizing expected tax planning strategy amounts, as well as results of audits and examinations of filed tax returns by taxing authorities. Derivative Instruments: The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative. Many of the electric and natural gas companies' contracts for the purchase and sale of energy or energy- related products for delivery to customers in the normal course of business are derivatives that are designated as “normal purchases” or “normal sales” and follow accrual accounting. If a contract is a derivative and the energy is settled in the energy market rather than delivered to customers, it is recorded at fair value on the balance sheet. The application of derivative accounting is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, election and designation of a contract as normal, and determination of the fair value of derivative contracts. All of these judgments can have a significant impact on the financial statements. 49
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The fair values of derivative contracts are estimated based on the best market information available, including valuation models that estimate future energy and energy-related prices. Fair value estimates involve assumptions, uncertainties and matters of judgment. Valuations are sensitive to the prices of energy-related products in future years and assumptions made. Changes in fair value of our derivative contracts are recorded as Regulatory Assets or Liabilities, as we recover the costs or include the benefits of these contracts in rates charged to customers. Fair Value Measurements: We follow fair value measurement guidance that defines fair value as the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). We have applied this guidance to our Company's derivative contracts that are not elected or designated as "normal purchases” or “normal sales,” to marketable securities held in trusts, and to our investments in our Pension and PBOP Plans. Fair value measurements are also incorporated into the accounting for goodwill, long-lived assets, equity method investments, AROs, and in the valuation of business combinations and asset acquisitions. We use quoted market prices when available to determine the fair value of financial instruments. When quoted prices in active markets for the same or similar instruments are not available, we value financial instruments and derivative contracts using models that incorporate both observable and unobservable inputs. Discounted cash flow valuations incorporate estimates of premiums or discounts, reflecting risk-adjusted profit that would be required by a market participant to arrive at an exit price, using available historical market transaction information and expectations. Valuations of derivative contracts also reflect our estimates of nonperformance risk, including credit risk. RESULTS OF OPERATIONS – EVERSOURCE ENERGY AND SUBSIDIARIES The following provides the amounts and variances in operating revenues and expense line items in the statements of income for Eversource for the years ended December 31, 2025 and 2024 included in this Annual Report on Form 10-K: For the Years Ended December 31, (Millions of Dollars) 2025 2024 Increase/(Decrease) Operating Revenues $ 13,547.2 $ 11,900.8 $ 1,646.4 Operating Expenses: Purchased Power, Purchased Natural Gas and Transmission 4,209.2 3,736.1 473.1 Operations and Maintenance 2,073.8 2,012.9 60.9 Depreciation 1,568.6 1,433.5 135.1 Amortization 835.9 342.9 493.0 Energy Efficiency Programs 778.2 671.8 106.4 Taxes Other Than Income Taxes 1,092.9 997.9 95.0 Loss on Pending Sale of Aquarion — 297.0 (297.0) Total Operating Expenses 10,558.6 9,492.1 1,066.5 Operating Income 2,988.6 2,408.7 579.9 Interest Expense 1,243.3 1,111.3 132.0 Losses on Offshore Wind 284.0 464.0 (180.0) Other Income, Net 378.9 410.5 (31.6) Income Before Income Tax Expense 1,840.2 1,243.9 596.3 Income Tax Expense 140.3 424.7 (284.4) Net Income 1,699.9 819.2 880.7 Net Income Attributable to Noncontrolling Interests 7.5 7.5 — Net Income Attributable to Common Shareholders $ 1,692.4 $ 811.7 $ 880.7 Operating Revenues Sales Volumes: A summary of our retail electric GWh sales volumes, our firm natural gas MMcf sales volumes, and our water MG sales volumes, and percentage changes, is as follows: Electric Firm Natural Gas Water Sales Volumes (GWh) PercentageIncrease/ (Decrease) Sales Volumes (MMcf) Percentage Increase Sales Volumes (MG) Percentage(Decrease)/ Increase2025 2024 2025 2024 2025 2024 Traditional 7,907 7,807 1.3 % — — — % 1,663 1,669 (0.4)% Decoupled 43,409 43,516 (0.2)% 160,784 147,293 9.2 % 24,788 24,308 2.0 % Total Sales Volumes 51,316 51,323 — % 160,784 147,293 9.2 % 26,451 25,977 1.8 % Weather, fluctuations in energy supply rates, conservation measures (including utility-sponsored energy efficiency programs), and economic conditions affect customer energy usage and water consumption. Industrial sales volumes are less sensitive to temperature variations than residential and commercial sales volumes. In our service territories, weather impacts both electric and water sales volumes during the summer and both electric and natural gas sales volumes during the winter; however, natural gas sales volumes are more sensitive to temperature variations than electric sales volumes. Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur. 50
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Fluctuations in retail electric sales volumes at PSNH impact earnings ("Traditional" in the table above). For CL&P, NSTAR Electric, NSTAR Gas, EGMA, Yankee Gas, and our Connecticut water distribution business, fluctuations in retail sales volumes do not materially impact earnings due to their respective regulatory commission-approved distribution revenue decoupling mechanisms ("Decoupled" in the table above). These distribution revenues are decoupled from their customer sales volumes, which breaks the relationship between sales volumes and revenues recognized. Operating Revenues: The variance in Operating Revenues by segment in 2025, as compared to 2024, is as follows: (Millions of Dollars) Increase/(Decrease) Electric Distribution $ 973.1 Natural Gas Distribution 530.9 Electric Transmission 162.3 Water Distribution 7.6 Other 31.4 Eliminations (58.9) Total Operating Revenues $ 1,646.4 Electric and Natural Gas Distribution Revenues: Base Distribution Revenues: Base distribution rates are the approved, regulated charges to recover the utility’s cost of service, including operations and building and maintaining infrastructure, that allow utilities to recover investments and earn a reasonable return. Base distribution rates are established in base rate proceedings and approved by state regulators. Fluctuations in base distribution revenues impact earnings. • Base electric distribution revenues increased $114.1 million due primarily to base distribution rate increases at PSNH effective August 1, 2024 and August 1, 2025 and at NSTAR Electric effective January 1, 2025. • Base natural gas distribution revenues increased $198.1 million due primarily to base distribution rate increases effective November 1, 2024 and November 1, 2025 at both EGMA and NSTAR Gas and effective November 1, 2025 at Yankee Gas. The base revenue increase also includes a shift of recovery into base rates of certain GSEP investments, which does not impact earnings. NSTAR Electric’s PBR mechanism allows for an annual adjustment to base distribution rates for inflation, exogenous events and future capital additions based on a historical five-year average of total capital additions. On December 23, 2024, the DPU approved a $55.8 million increase to base distribution rates for effect on January 1, 2025. On July 31, 2024, the NHPUC approved a settlement agreement to implement a temporary annual base distribution rate increase of $61.2 million effective August 1, 2024 at PSNH. On July 25, 2025, the NHPUC approved a permanent rate increase of $100.7 million, effective August 1, 2025, inclusive of the temporary rate increase. NSTAR Gas’ PBR mechanism allows for an annual adjustment to base distribution rates for inflation and exogenous events. On October 30, 2024, the DPU approved the annual PBR Adjustment filing for a $12.7 million increase to base distribution rates for effect November 1, 2024. On October 29, 2025, the DPU approved a $10.3 million increase to base distribution rates for effect on November 1, 2025. EGMA was allowed two rate base resets in a DPU-approved October 7, 2020 rate settlement agreement, with the first rate base reset on November 1, 2024. After adjusting for a cap required under the terms of the rate settlement agreement, the increase to base distribution rates was $85.6 million effective November 1, 2024 (of which $8.8 million is offset by a reduction in the GSEP revenue requirement and GSEP rate also taking effect on November 1, 2024 for a net distribution rate change on November 1, 2024 of $76.8 million). Base distribution rates were increased effective November 1, 2025 to incorporate the $62.2 million remaining revenue requirement. On November 7, 2024, the DPU approved this filing. On November 5, 2025, PURA issued a final decision in the Yankee Gas distribution rate case that included a distribution rate increase of $82.2 million, effective November 1, 2025. The approved revenue requirement includes a previously recorded rate credit of $37.4 million plus carrying charges for non- firm margin credits over three years beginning November 1, 2025. Excluding the rate credit, the distribution rate increase totaled $95.7 million. Tracked Distribution Revenues: Tracked distribution revenues consist of certain costs that are recovered from customers in retail rates on a fully reconciling basis through regulatory commission-approved cost tracking mechanisms and therefore, recovery of these costs has no impact on earnings. Costs recovered through cost tracking mechanisms include, among others, energy supply and natural gas supply procurement, state mandated energy purchase agreements and other energy-related costs, electric retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for the Massachusetts utilities, pension and PBOP benefits, net metering for distributed generation, and solar-related programs. Revenues from certain of these cost tracking mechanisms also include certain incentives earned, return on capital tracking mechanisms, and carrying charges that are billed in rates to customers, which do impact earnings. Tracked revenues also include wholesale market sales transactions, such as sales of energy and energy-related products into the ISO-NE wholesale electricity market, sales of natural gas to third-party marketers, and the sale of RECs to various counterparties. Customers have the choice to purchase electricity from their Eversource electric utility or from a competitive third-party supplier. For customers who have contracted separately with these competitive suppliers, revenue is not recorded for the sale of the electricity commodity, as the utility is acting as an agent on behalf of the third-party supplier. For customers that choose to purchase electric generation from CL&P, NSTAR Electric or 51
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PSNH, each utility purchases power on behalf of, and is permitted to recover the related energy supply cost without mark-up from, its customers, and records offsetting amounts in revenues and purchased power related to this energy supply procurement. CL&P, NSTAR Electric and PSNH each remain as the distribution service provider for all customers and charge a regulated rate for distribution delivery service recorded in revenues. Certain eligible natural gas customers may elect to purchase natural gas from their Eversource natural gas utility or may contract separately with a gas supply operator. Revenue is not recorded for the sale of the natural gas commodity to customers who have contracted separately with these operators, only the delivery to a customer, as the utility is acting as an agent on behalf of the gas supply operator. The variance in tracked distribution revenues in 2025, as compared to 2024, is due primarily to the following: (Millions of Dollars) Electric Distribution Natural Gas Distribution Retail Tariff Tracked Revenues: Energy supply procurement $ (128.7) $ 231.7 Retail transmission 245.2 — CL&P NBFMCC 153.3 — CL&P System Benefit Charge 94.6 — Energy efficiency 26.1 80.5 Other distribution tracking mechanisms 123.4 (2.3) Wholesale Market Sales Revenue 345.8 22.1 Fluctuations in retail tariff tracked revenues are driven by adjustments to retail rates to recover costs and changes in sales volumes. The decrease in energy supply procurement within electric distribution was driven by lower average prices, partially offset by higher average supply- related sales volumes. The increase in energy supply procurement within natural gas distribution was driven by higher average prices and higher average supply-related sales volumes. The variance in CL&P’s NBFMCC revenues was driven by changes in the retail NBFMCC rate. The CL&P NBFMCC rate includes the recovery of costs incurred under long-term state mandated energy purchase contracts with the Millstone and Seabrook nuclear power plants, net of the benefits received from selling this energy into the ISO-NE wholesale market. The rate changes primarily resulted from the timing of recovery of net costs associated with power purchase agreements with the Millstone and Seabrook nuclear power plants. The average NBFMCC rates are as follows: Effective Date September 1, 2023 July 1, 2024 September 1, 2024 May 1, 2025 September 1, 2025 Average NBFMCC Rate $ 0.00293 $ 0.03906 $ 0.04290 $ 0.02109 $ 0.01675 The increase in electric distribution wholesale market sales revenue in 2025, as compared to 2024, was due primarily to higher average electricity market prices received for wholesale sales at CL&P. ISO-NE average market prices received for CL&P’s wholesale sales increased to an average price of $67.50 per MWh in 2025, as compared to $39.53 per MWh for the same period in 2024, driven primarily by higher natural gas prices in New England. Volumes sold into the market were primarily from the sale of output generated by the Millstone PPA and Seabrook PPA with CL&P. CL&P is required by both state legislation and regulation to purchase electric generation from Millstone and Seabrook under PURA-approved PPAs entered in 2019. CL&P does not have legislative authority to use this purchased output to serve its customer load and therefore sells the energy into the wholesale market and uses the proceeds from the energy sales to offset the contract costs. The net cost or net sales amount is recovered from, or refunded to, customers in the non-bypassable component of the CL&P FMCC rate. CL&P does not earn any margin or return from the sale of this contracted output, which solely offsets the cost of the legislatively required purchases from Millstone and Seabrook. Changes in CL&P’s NBFMCC retail revenues and CL&P’s wholesale market sales, as compared to the actual costs incurred, are deferred on the income statement by an offset to amortization expense. Electric Transmission Revenues: Electric transmission revenues increased $162.3 million due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure. Other Revenues and Eliminations: Other revenues primarily include the revenues of Eversource's service company, most of which are eliminated in consolidation. Eliminations are also related to the Eversource electric transmission revenues that are derived from ISO-NE regional transmission charges to the distribution businesses of CL&P, NSTAR Electric and PSNH that recover the costs of the wholesale transmission business in rates charged to their customers. Purchased Power, Purchased Natural Gas and Transmission expense includes costs associated with providing electric generation service supply and natural gas to all customers who have not migrated to third-party suppliers, the cost of energy purchase contracts entered into as required by regulation, and transmission costs. These electric and natural gas supply procurement costs, other energy-related costs, and transmission costs are recovered from customers in rates through commission-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). 52
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The variance in Purchased Power, Purchased Natural Gas and Transmission expense in 2025, as compared to 2024, is due primarily to the following: (Millions of Dollars) Increase/(Decrease) Energy supply procurement costs $ (117.0) Other electric distribution costs 159.1 Natural gas supply costs 218.7 Transmission costs 231.6 Eliminations (19.3) Total Purchased Power, Purchased Natural Gas and Transmission $ 473.1 The variance in energy supply procurement costs is offset in Operating Revenues (tracked energy supply procurement revenues). The variance in other electric distribution costs is due to an increase in the long-term renewable energy purchase contract cost deferral and higher net metering costs at NSTAR Electric, higher long-term contractual energy-related costs and the cost of renewable energy credits that are recovered in the non-bypassable component of the FMCC mechanism at CL&P, and higher net metering costs at PSNH. Costs at the natural gas distribution segment relate to supply procurement costs for retail customers. Total natural gas costs increased due primarily to higher average prices, higher average purchased volumes and an increase in the retail cost deferral. Included in transmission costs are charges that recover the cost of transporting electricity over high-voltage lines from generation facilities to substations, including costs allocated by ISO-NE to maintain the wholesale electric system. The increase in transmission costs was primarily the result of an increase in costs billed by ISO-NE that support regional grid investments. The increase was partially offset by a decrease in the retail transmission cost deferral, which reflects the actual cost of transmission service compared to estimated amounts billed to customers. Operations and Maintenance expense includes tracked costs and costs that are part of base electric, natural gas and water distribution rates with changes impacting earnings (non-tracked costs). The variance in Operations and Maintenance expense in 2025, as compared to 2024, is due primarily to the following: (Millions of Dollars) Increase/(Decrease) Base Electric Distribution (Non-Tracked Costs): Employee-related expenses (including labor and benefits) $ 15.3 Shared corporate costs (including IT system depreciation at Eversource Service) 12.7 Storm costs 12.2 Uncollectible expense 9.4 Operations-related expenses (including vegetation management, vendor services, vehicles and materials) (7.4) Total Base Electric Distribution (Non-Tracked Costs) 42.2 Tracked Electric Costs (Electric Distribution and Electric Transmission): Customer credits at NSTAR Electric as a result of the joint settlement agreement approved in Massachusetts (earnings charge) 17.5 Other tracked - Increase due primarily to higher transmission expense, and higher pension tracking mechanism at NSTAR Electric,partially offset by a decrease in grid modernization mechanism at NSTAR Electric and lower uncollectible expenses 42.2 Total Tracked Electric Costs 59.7 Total Electric Distribution and Electric Transmission 101.9 Natural Gas Distribution: Base (Non-Tracked Costs): Increase due primarily to higher uncollectible expense, higher shared corporate costs, and higher corporate vendor services 36.6 Customer credits and concession at NSTAR Gas as a result of the settlement agreement approved in Massachusetts 12.2 Impact of Yankee Gas rate case decision on November 5, 2025; primarily due to the write off of certain capitalized employeecompensation costs disallowed from rate base 11.9 Base (Non-Tracked Costs) 60.7 Tracked Costs 3.7 Total Natural Gas Distribution 64.4 Eversource Parent, Water Distribution and Other Companies: Acquisition-related and integration costs allowed for recovery through EGMA distribution rates as a result of the joint settlement agreement approved in Massachusetts (earnings benefit) (82.3) Other operations and maintenance 13.8 Eliminations (36.9) Total Operations and Maintenance $ 60.9 Depreciation expense increased due primarily to higher net plant in service balances. 53
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Amortization expense includes the deferral of energy-related costs and other costs that are included in certain regulatory commission-approved cost tracking mechanisms. This deferral adjusts expense to match the corresponding revenues compared to the actual costs incurred. These costs are recovered from customers in rates and have no impact on earnings. Amortization expense also includes the amortization of certain costs as those costs are collected in rates. The variance in Amortization is due primarily to the deferral adjustments of energy-related and other tracked costs at CL&P (included in the non- bypassable component of the FMCC mechanism and the SBC mechanism), partially offset by NSTAR Electric and PSNH (included in the stranded cost recovery mechanism), which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs, as well as the impact of the PSNH rate case decision. The CL&P non-bypassable FMCC retail rates in effect were higher than those in the prior period and the net Millstone and Seabrook contract cash flows were higher in 2025 as compared to 2024. These higher collections within the non-bypassable FMCC resulted in a corresponding increase to amortization expense of $428.2 million for the CL&P non-bypassable FMCC deferral adjustment. The PSNH rate case decision allowed for the recoupment of temporary rates and the allowed recovery of other deferrals resulting in a pre-tax benefit to earnings of $15.6 million, the majority of which was recorded as a reduction to amortization expense on the statement of income in the third quarter of 2025. Energy Efficiency Programs expense includes costs of various state energy policy initiatives and expanded energy efficiency programs that are recovered from customers in rates, most of which have no impact on earnings. Energy Efficiency Programs expense includes a deferral adjustment that reflects the actual costs of energy efficiency programs compared to the amounts billed to customers, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs. Energy Efficiency Programs expense increased due primarily to the deferral adjustment that matched costs to the corresponding revenues recorded as well as higher program spending. Taxes Other Than Income Taxes expense increased due primarily to higher property taxes as a result of higher utility plant balances across our subsidiaries and higher mill rates at NSTAR Electric and higher Connecticut gross earnings taxes. Loss on Pending Sale of Aquarion relates to the impairment charge recorded in 2024 to write down the carrying value of the water business to fair value resulting from the expected sale of Aquarion. For further information, see "Business Development and Capital Expenditures – Aquarion Sale Status and Regulatory Denial" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations. Interest Expense increased due primarily to the following: (Millions of Dollars) Increase/(Decrease) Long-term debt $ 91.3 Absence in 2025 of capitalized interest as a result of the sale of our offshore wind projects in the third quarter of 2024 69.3 Capitalized AFUDC related to debt funds 0.3 Amortization of debt discounts and premiums, net 4.5 Regulatory deferrals (31.3) Short-term notes payable (2.4) RRBs (1.5) Other 1.8 Total Interest Expense $ 132.0 Losses on Offshore Wind for 2025 relates to the pre-tax charge of $284 million associated with increasing our offshore wind contingent liability for expected future payments under the terms of the 2024 sale agreement with GIP for the South Fork Wind and Revolution Wind projects. In 2024, it related to the loss recorded for sales of our equity method offshore wind investments. See "Earnings Overview – Offshore Wind Sale and Contingent Liability" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations for further information. Other Income, Net decreased due primarily to the following: (Millions of Dollars) Increase/(Decrease) Pension, SERP and PBOP Non-Service Income Components, Net of Deferred Portion 23.9 Interest Income (primarily on regulatory deferrals) (12.7) Capitalized AFUDC related to equity funds 1.2 Equity in Earnings of Unconsolidated Affiliates (32.0) Investment (Loss)/Income (6.0) Other (6.0) Total Other Income, Net $ (31.6) 54
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Income Tax Expense decreased due primarily to a decrease in reserves ($394.6 million), a decrease in return to provision adjustments ($23.6 million), an increase in amortization of EDIT ($13.6 million) and a decrease in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($30.2 million), partially offset by higher pre-tax earnings ($125.2 million), higher state taxes ($51.9 million), and higher share-based payment tax deficiency ($0.5 million). RESULTS OF OPERATIONS – THE CONNECTICUT LIGHT AND POWER COMPANY NSTAR ELECTRIC COMPANY AND SUBSIDIARY PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES The following provides the amounts and variances in operating revenues and expense line items in the statements of income for CL&P, NSTAR Electric and PSNH for the years ended December 31, 2025 and 2024 included in this Annual Report on Form 10-K: For the Years Ended December 31, CL&P NSTAR Electric PSNH (Millions of Dollars) 2025 2024 Increase/(Decrease) 2025 2024 Increase/(Decrease) 2025 2024 Increase/(Decrease) Operating Revenues $ 5,241.0 $ 4,615.0 $ 626.0 $ 3,986.6 $ 3,720.9 $ 265.7 $ 1,376.4 $ 1,294.5 $ 81.9 Operating Expenses: Purchased Power and Transmission 1,815.8 1,836.9 (21.1) 1,141.7 1,045.3 96.4 280.2 244.4 35.8 Operations and Maintenance 849.0 815.3 33.7 792.3 735.0 57.3 299.2 288.3 10.9 Depreciation 432.7 406.5 26.2 446.0 407.7 38.3 168.0 154.1 13.9 Amortization of Regulatory Assets, Net 649.7 104.5 545.2 107.6 130.9 (23.3) 68.2 136.1 (67.9) Energy Efficiency Programs 170.2 171.7 (1.5) 294.4 263.4 31.0 46.2 42.9 3.3 Taxes Other Than Income Taxes 452.9 419.6 33.3 320.5 280.3 40.2 106.1 96.9 9.2 Total Operating Expenses 4,370.3 3,754.5 615.8 3,102.5 2,862.6 239.9 967.9 962.7 5.2 Operating Income 870.7 860.5 10.2 884.1 858.3 25.8 408.5 331.8 76.7 Interest Expense 211.9 231.0 (19.1) 256.1 222.7 33.4 90.0 77.8 12.2 Other Income, Net 59.7 77.6 (17.9) 192.6 191.4 1.2 43.0 31.1 11.9 Income Before Income Tax Expense 718.5 707.1 11.4 820.6 827.0 (6.4) 361.5 285.1 76.4 Income Tax Expense 167.2 194.5 (27.3) 190.0 190.6 (0.6) 92.1 70.2 21.9 Net Income $ 551.3 $ 512.6 $ 38.7 $ 630.6 $ 636.4 $ (5.8) $ 269.4 $ 214.9 $ 54.5 Operating Revenues Sales Volumes: A summary of our retail electric GWh sales volumes is as follows: For the Years Ended December 31, 2025 2024 Increase/(Decrease) PercentageIncrease/(Decrease) CL&P 20,351 20,151 200 1.0 % NSTAR Electric 23,058 23,365 (307) (1.3)% PSNH 7,907 7,807 100 1.3 % Fluctuations in retail electric sales volumes at PSNH impact earnings. For CL&P and NSTAR Electric, fluctuations in retail electric sales volumes do not impact earnings due to their respective regulatory commission-approved distribution revenue decoupling mechanisms. Operating Revenues: Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased $626.0 million at CL&P, $265.7 million at NSTAR Electric, and $81.9 million at PSNH in 2025, as compared to 2024. Base Distribution Revenues: Base distribution rates are the approved, regulated charges to recover the utility’s cost of service, including operations and building and maintaining infrastructure, that allow utilities to recover investments and earn a reasonable return. Base distribution rates are established in base rate proceedings and approved by state regulators. Fluctuations in base distribution revenues impact earnings. • CL&P's distribution revenues were flat. • NSTAR Electric's distribution revenues increased $54.2 million due primarily to a base distribution rate increase effective January 1, 2025. • PSNH's distribution revenues increased $59.9 million due primarily to base distribution rate increases effective August 1, 2024 and August 1, 2025. 55
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Tracked Distribution Revenues: Tracked distribution revenues consist of certain costs that are recovered from customers in retail rates on a fully reconciling basis through regulatory commission-approved cost tracking mechanisms and therefore, recovery of these costs has no impact on earnings. Costs recovered through cost tracking mechanisms include, among others, energy supply procurement, state mandated energy purchase agreements and other energy-related costs, retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for NSTAR Electric, pension and PBOP benefits, net metering for distributed generation, and solar-related programs. Revenues from certain of these cost tracking mechanisms also include certain incentives earned, return on capital tracking mechanisms, and carrying charges that are billed in rates to customers, which do impact earnings. Tracked revenues also include wholesale market sales transactions, such as sales of energy and energy-related products into the ISO-NE wholesale electricity market and the sale of RECs to various counterparties. Customers have the choice to purchase electricity from their Eversource electric utility or from a competitive third-party supplier. For customers who have contracted separately with these competitive suppliers, revenue is not recorded for the sale of the electricity commodity, as the utility is acting as an agent on behalf of the third-party supplier. For customers that choose to purchase electric generation from CL&P, NSTAR Electric or PSNH, each utility purchases power on behalf of, and is permitted to recover the related energy supply cost without mark-up from, its customers, and records offsetting amounts in revenues and purchased power related to this energy supply procurement. CL&P, NSTAR Electric and PSNH each remain as the distribution service provider for all customers and charge a regulated rate for distribution delivery service recorded in revenues. The variance in tracked distribution revenues in 2025, as compared to 2024, is due primarily to the following: (Millions of Dollars) CL&P NSTAR Electric PSNH Retail Tariff Tracked Revenues: Energy supply procurement $ (44.1) $ (93.4) $ 8.8 Retail transmission 56.3 135.0 53.9 CL&P NBFMCC 153.3 — — CL&P System Benefit Charge 94.6 — — Other distribution tracking mechanisms 56.7 143.7 (50.9) Wholesale Market Sales Revenue 309.4 38.5 (2.1) Fluctuations in retail tariff tracked revenues are driven by adjustments to retail rates to recover costs and changes in sales volumes. The decrease in energy supply procurement at CL&P was driven by lower average prices, partially offset by higher average supply-related sales volumes. The decrease in energy supply procurement at NSTAR Electric was driven by lower average prices and lower average supply-related sales volumes. The increase in energy supply procurement at PSNH was driven by higher average prices and higher average supply-related sales volumes. The variance in CL&P’s NBFMCC revenues was driven by changes in the retail NBFMCC rate. The CL&P NBFMCC rate includes the recovery of costs incurred under long-term state mandated energy purchase contracts with the Millstone and Seabrook nuclear power plants, net of the benefits received from selling this energy into the ISO-NE wholesale market. The rate changes primarily resulted from the timing of recovery of net costs associated with power purchase agreements with the Millstone and Seabrook nuclear power plants. The average NBFMCC rates are as follows: Effective Date September 1, 2023 July 1, 2024 September 1, 2024 May 1, 2025 September 1, 2025 Average NBFMCC Rate $ 0.00293 $ 0.03906 $ 0.04290 $ 0.02109 $ 0.01675 The increase in CL&P’s wholesale market sales revenue in 2025, as compared to 2024, was due primarily to higher average electricity market prices received for wholesale sales. ISO-NE average market prices received for CL&P’s wholesale sales increased to an average price of $67.50 per MWh in 2025, as compared to $39.53 per MWh for the same period in 2024, driven primarily by higher natural gas prices in New England. Volumes sold into the market were primarily from the sale of output generated by the Millstone PPA and Seabrook PPA with CL&P. CL&P is required by both state legislation and regulation to purchase electric generation from Millstone and Seabrook under PURA-approved PPAs entered in 2019. CL&P does not have legislative authority to use this purchased output to serve its customer load and therefore sells the energy into the wholesale market and uses the proceeds from the energy sales to offset the contract costs. The net cost or net sales amount is recovered from, or refunded to, customers in the non-bypassable component of the CL&P FMCC rate. CL&P does not earn any margin or return from the sale of this contracted output, which solely offsets the cost of the legislatively required purchases from Millstone and Seabrook. Changes in CL&P’s NBFMCC retail revenues and CL&P’s wholesale market sales, as compared to the actual costs incurred, are deferred on the income statement by an offset to amortization expense. Transmission Revenues: Transmission revenues increased $55.9 million at CL&P, $64.0 million at NSTAR Electric and $42.4 million at PSNH due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure. Eliminations: Eliminations are related to the Eversource electric transmission revenues that are derived from ISO-NE regional transmission charges to the distribution businesses of CL&P, NSTAR Electric and PSNH that recover the costs of the wholesale transmission business in rates charged to their customers. The impact of eliminations decreased revenues by $55.7 million at CL&P, $75.0 million at NSTAR Electric and $31.9 million at PSNH. 56
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Purchased Power and Transmission expense includes costs associated with providing electric generation service supply to all customers who have not migrated to third-party suppliers, the cost of energy purchase contracts entered into as required by regulation, and transmission costs. These energy supply procurement costs, other energy-related costs, and transmission costs are recovered from customers in rates through commission-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). The variance in Purchased Power and Transmission expense in 2025, as compared to 2024, is due primarily to the following: (Millions of Dollars) CL&P NSTAR Electric PSNH Energy supply procurement costs $ (41.1) $ (85.1) $ 9.2 Other electric distribution costs 29.1 122.5 7.5 Transmission costs 46.6 134.0 51.0 Eliminations (55.7) (75.0) (31.9) Total Purchased Power and Transmission $ (21.1) $ 96.4 $ 35.8 The variance in energy supply procurement costs is offset in Operating Revenues (tracked energy supply procurement revenues). The variance in other electric distribution costs is due to an increase in the long-term renewable energy purchase contract cost deferral and higher net metering costs at NSTAR Electric, higher long-term contractual energy-related costs and the cost of renewable energy credits that are recovered in the non-bypassable component of the FMCC mechanism at CL&P, and higher net metering costs at PSNH. Included in transmission costs are charges that recover the cost of transporting electricity over high-voltage lines from generation facilities to substations, including costs allocated by ISO-NE to maintain the wholesale electric system. • The increase in transmission costs at CL&P was due primarily to an increase in costs billed by ISO-NE that support regional grid investments and an increase in Local Network Service charges, which reflect the cost of transmission service provided by Eversource over our local transmission network. These increases were partially offset by a decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers. • The increase in transmission costs at NSTAR Electric was due primarily to an increase in costs billed by ISO-NE and an increase in the retail transmission cost deferral. These increases were partially offset by a decrease in Local Network Service charges. • The increase in transmission costs at PSNH was due primarily to an increase in costs billed by ISO-NE and an increase in Local Network Service charges. These increases were partially offset by a decrease in the retail transmission cost deferral. Operations and Maintenance expense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non- tracked costs). The variance in Operations and Maintenance expense in 2025, as compared to 2024, is due primarily to the following: (Millions of Dollars) CL&P NSTAR Electric PSNH Base Electric Distribution (Non-Tracked Costs): Employee-related expenses (including labor and benefits) $ 17.6 $ 0.3 $ (2.6) Storm costs 7.8 2.6 1.8 Shared corporate costs (including IT system depreciation at Eversource Service) 2.6 8.6 1.5 Uncollectible expense 0.2 8.3 0.9 General corporate costs (including vendor services in corporate areas, insurance, fees andassessments) (6.8) 11.4 (4.7) Vegetation management (3.7) (5.9) 10.1 Operations-related expenses (including vendor services, vehicles and materials) (3.0) (4.6) (0.2) Total Base Electric Distribution (Non-Tracked Costs) 14.7 20.7 6.8 Tracked Costs: Customer credits at NSTAR Electric as a result of the joint settlement agreement approved inMassachusetts (earnings charge) — 17.5 — Other tracked - Increase due primarily to higher transmission expense, and higher pension trackingmechanism at NSTAR Electric, partially offset by a decrease in grid modernization mechanism atNSTAR Electric and lower uncollectible expenses 19.0 19.1 4.1 Total Tracked Costs 19.0 36.6 4.1 Total Operations and Maintenance $ 33.7 $ 57.3 $ 10.9 Depreciation expense increased for CL&P, NSTAR Electric and PSNH due to higher net plant in service balances. Amortization of Regulatory Assets, Net expense includes the deferral of energy-related costs and other costs that are included in certain regulatory commission-approved cost tracking mechanisms. This deferral adjusts expense to match the corresponding revenues compared to the actual costs incurred. These costs are recovered from customers in rates and have no impact on earnings. Amortization expense also includes the amortization of certain costs as those costs are collected in rates. The variance in Amortization of Regulatory Assets, Net is due primarily to the following: • The variance at CL&P was due primarily to the deferral adjustment of energy-related and other tracked costs that are included in the non- bypassable component of the FMCC mechanism and the SBC mechanism, which can fluctuate from period to period based on the 57
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timing of costs incurred and related rate changes to recover these costs. The CL&P non-bypassable FMCC retail rates in effect were higher than those in the prior period and the net Millstone and Seabrook contract cash flows were higher in 2025 as compared to 2024. These higher collections within the non-bypassable FMCC resulted in a corresponding increase to amortization expense of $428.2 million for the CL&P non- bypassable FMCC deferral adjustment. • The variance at NSTAR Electric was due primarily to the deferral adjustment of costs included in the solar facilities and advanced metering infrastructure regulatory mechanisms, partially offset by the deferral adjustment of energy-related and other tracked costs that are included in the grid modernization regulatory mechanism and higher amortization of storm costs recovered in rates. • The variance at PSNH was due to the deferral adjustment of energy-related and other tracked costs that are included in the stranded cost recovery mechanism as well as the impact of the PSNH rate case decision. The rate case decision allowed for the recoupment of temporary rates and the allowed recovery of other deferrals resulting in a pre-tax benefit to earnings of $15.6 million, the majority of which was recorded as a reduction to amortization expense on the statement of income in the third quarter of 2025. Energy Efficiency Programs expense includes costs of various state energy policy initiatives and expanded energy efficiency programs that are recovered from customers in rates, most of which have no impact on earnings. Energy Efficiency Programs expense includes a deferral adjustment that reflects the actual costs of energy efficiency programs compared to the amounts billed to customers, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs. The variance in Energy Efficiency Programs expense is due primarily to the following: • The decrease at CL&P was due to lower program spending, partially offset by the deferral adjustment that matched costs to the corresponding revenues recorded. • The increase at NSTAR Electric was due to the deferral adjustment that matched costs to the corresponding revenues recorded, partially offset by lower program spending. • The increase at PSNH was due to higher program spending, partially offset by the deferral adjustment that matched costs to the corresponding revenues recorded. Taxes Other Than Income Taxes - the variance is due primarily to the following: • The increase at CL&P was due to higher Connecticut gross earnings taxes and higher property taxes as a result of higher utility plant balances. • The increase at NSTAR Electric was due to higher property taxes as a result of higher utility plant balances and higher mill rates. • The increase at PSNH was due to higher property taxes as a result of higher utility plant balances. Interest Expense - the variance is due primarily to the following: (Millions of Dollars) CL&P NSTAR Electric PSNH Long-term debt $ 20.8 $ 48.7 $ 10.9 Capitalized AFUDC related to debt funds (6.4) (1.7) 3.2 Amortization of debt discounts and premiums, net 1.0 1.3 0.4 Regulatory deferrals (20.9) (9.9) 3.4 Short-term notes payable (13.8) (5.2) (4.0) RRBs — — (1.5) Other 0.2 0.2 (0.2) Total Interest Expense $ (19.1) $ 33.4 $ 12.2 Other Income, Net - the variance is due primarily to the following: (Millions of Dollars) CL&P NSTAR Electric PSNH Pension, SERP and PBOP Non-Service Income Components, Net of Deferred Portion $ 8.0 $ 8.6 $ 2.7 Interest Income (primarily on regulatory deferrals) (15.4) (4.3) 3.4 Capitalized AFUDC related to equity funds (10.2) (0.4) 6.0 Investment (Loss)/Income (0.3) (3.5) (0.2) Other — 0.8 — Total Other Income, Net $ (17.9) $ 1.2 $ 11.9 Income Tax Expense - the variance is due primarily to the following: • The decrease at CL&P was due primarily to a decrease in reserves ($17.6 million), an increase in amortization of EDIT ($7.8 million), a decrease in return to provision adjustments ($2.5 million), and a decrease in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($3.6 million), partially offset by higher pre-tax earnings ($2.4 million), higher state taxes ($1.6 million) and higher share-based payment tax deficiency ($0.2 million). • The decrease at NSTAR Electric was due primarily to lower pre-tax earnings ($1.4 million) and lower state taxes ($0.1 million), partially offset by higher share-based payment tax deficiency ($0.3 million), and an increase in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($0.6 million). 58
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• The increase at PSNH was due primarily to higher pre-tax earnings ($16.0 million), higher state taxes ($4.7 million), and an increase in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($2.8 million), partially offset by an increase in amortization of EDIT ($1.6 million). EARNINGS SUMMARY CL&P's earnings increased $38.7 million in 2025, as compared to 2024, due primarily to higher revenues from its capital tracking mechanism due to increased electric system improvements, a lower effective tax rate, and an increase in transmission earnings driven primarily by a higher transmission rate base and lower interest expense. The earnings increase was partially offset by lower net interest income on regulatory deferrals, higher depreciation expense, higher operations and maintenance expense, and higher property tax expense. NSTAR Electric's earnings decreased $5.8 million in 2025, as compared to 2024, due primarily to higher interest expense on long-term debt, higher property tax expense, higher operations and maintenance expense, a charge to earnings for customer credits as a result of the joint settlement agreement approved in Massachusetts on December 1, 2025, and lower net interest income on regulatory deferrals. The earnings decrease was partially offset by higher revenues as a result of the base distribution rate increase effective January 1, 2025, an increase in transmission earnings driven primarily by a higher transmission rate base and lower interest expense, and higher earnings from its AMI tracking mechanism. PSNH's earnings increased $54.5 million in 2025, as compared to 2024, due primarily to higher revenues as a result of the base distribution rate increases effective August 1, 2024 and August 1, 2025, an increase in transmission earnings driven primarily by a higher transmission rate base and lower interest expense, and the impact of the rate case decision in July 2025. The earnings increase was partially offset by higher operations and maintenance expense, higher depreciation expense, and a higher effective tax rate. LIQUIDITY Cash Flows: CL&P had cash flows provided by operating activities of $1.68 billion in 2025, as compared to $683.4 million in 2024. The increase in operating cash flows was due primarily to an improvement in regulatory recoveries driven primarily by the timing of collections for the non-bypassable FMCC and SBC regulatory tracking mechanisms. The CL&P non-bypassable FMCC retail rates in effect for 2025 were higher than those set in 2024 and the net Millstone and Seabrook contract cash flows were higher in 2025 as compared to 2024. These higher collections within the non-bypassable FMCC resulted in an improvement to operating cash flows of $428.2 million for the year. Higher collections from the SBC mechanism resulted in a cash flow improvement of $113.3 million. The impacts of regulatory collections are included in both Regulatory Recoveries and Amortization of Regulatory Assets/(Liabilities) on the statements of cash flows. Additionally, CL&P received general obligation bond proceeds from the State of Connecticut for the reimbursement of hardship costs and for electric vehicle charging program costs of $107.8 million in 2025, which are reflected in Regulatory Recoveries. Operating cash flows were also favorably impacted by the timing of cash collections on our accounts receivable, a $100.2 million decrease in cash payments to vendors for storm costs, the timing of cash payments made on our accounts payable, and the timing of other working capital items. These favorable impacts were partially offset by a decrease of $183.1 million in operating cash flows due to income tax payments made in 2025 compared to income tax refunds received in 2024. NSTAR Electric had cash flows provided by operating activities of $980.5 million in 2025, as compared to $687.6 million in 2024. The increase in operating cash flows was due primarily to an improvement in regulatory recoveries driven primarily by the timing of collections for energy efficiency costs, energy supply costs, retail and wholesale transmission costs, and other regulatory tracking mechanisms, a decrease of $119.6 million in cash payments to vendors for storm costs, the timing of cash payments made on our accounts payable, and the timing of other working capital items. The impacts of regulatory collections are included in both Regulatory Recoveries and Amortization of Regulatory Assets on the statements of cash flows. These favorable impacts were partially offset by an increase in capitalized implementation costs for cloud-based service arrangements, the timing of cash collections on our accounts receivable, a $46.1 million increase in income tax payments, and a $7.4 million increase in cost of removal expenditures. PSNH had cash flows provided by operating activities of $483.3 million in 2025, as compared to $321.3 million in 2024. The increase in operating cash flows was due primarily to a decrease of $101.7 million in cash payments to vendors for storm costs, an improvement in regulatory recoveries driven by the timing of collections for wholesale and retail transmission costs and other regulatory tracking mechanisms, a $15.5 million decrease in cost of removal expenditures, the timing of cash payments made on our accounts payable, and the timing of other working capital items. The impacts of regulatory collections are included in both Regulatory Recoveries and Amortization of Regulatory Assets/(Liabilities) on the statements of cash flows. These favorable impacts were partially offset by a decrease of $119.0 million in operating cash flows due to income tax payments made in 2025 compared to income tax refunds received in 2024 and the timing of cash collections on our accounts receivable. For further information on CL&P's, NSTAR Electric's and PSNH's liquidity and capital resources, see "Liquidity" and "Business Development and Capital Expenditures" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations. 59
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Item 7A. Quantitative and Qualitative Disclosures about Market Risk Market Risk Information Commodity Price Risk Management: Our regulated companies enter into energy contracts to serve our customers, and the economic impacts of those contracts are passed on to our customers. Accordingly, the regulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments. Eversource's Energy Supply Risk Committee, comprised of senior officers, reviews and approves all large-scale energy related transactions entered into by its regulated companies. Other Risk Management Activities We have an Enterprise Risk Management (ERM) program for identifying the principal risks of the Company. Our ERM program involves the application of a well-defined, enterprise-wide methodology designed to allow our Risk Committee, comprised of our senior officers of the Company, to identify, categorize, prioritize, and mitigate the principal risks to the Company. The ERM program is integrated with other assurance functions throughout the Company including Compliance, Auditing, and Insurance to ensure appropriate coverage of risks that could impact the Company. In addition to known risks, ERM identifies emerging risks to the Company, through participation in industry groups, discussions with management and in consultation with outside advisers. Our management then analyzes risks to determine materiality, likelihood and impact, and develops mitigation strategies. Management broadly considers our business model, the utility industry, the global economy, climate change, sustainability and the current environment to identify risks. The Finance and Risk Management Committee of the Board of Trustees is responsible for oversight of the Company's ERM program and enterprise-wide risks as well as specific risks associated with insurance, credit, financing, investments, pensions and overall system security including cyber security. The findings of the ERM process are periodically discussed with the Finance and Risk Management Committee of our Board of Trustees, as well as with other Board Committees or the full Board of Trustees, as appropriate, including reporting on how these issues are being measured and managed. However, there can be no assurances that the ERM process will identify or manage every risk or event that could impact our financial position, results of operations or cash flows. Interest Rate Risk Management: Interest rate risk is associated with changes in interest rates for our outstanding long-term debt. Our interest rate risk is significantly reduced as typically all or most of our debt financings have fixed interest rates. As of December 31, 2025, all of our long-term debt was at a fixed interest rate. Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations. We serve a wide variety of customers and transact with suppliers that include IPPs, industrial companies, natural gas and electric utilities, oil and natural gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process. Our regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. Our regulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and monitor contracting risks, including credit risk. As of December 31, 2025, our regulated companies held collateral (letters of credit or cash) of $21.3 million from counterparties related to our standard service contracts. As of December 31, 2025, Eversource had $38.6 million of cash posted with ISO-NE related to energy transactions. If the respective unsecured debt ratings of Eversource or its subsidiaries were reduced to below investment grade by either Moody's, S&P or Fitch, certain of Eversource's contracts would require additional collateral in the form of cash or letters of credit to be provided to counterparties and independent system operators. Eversource would have been and remains able to provide that collateral. 60
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Item 8. Financial Statements and Supplementary Data Eversource Management’s Report on Internal Controls Over Financial Reporting Reports of Independent Registered Public Accounting Firm (PCAOB ID No. 34) Consolidated Financial Statements CL&P Management’s Report on Internal Controls Over Financial Reporting Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34) Financial Statements NSTAR Electric Management’s Report on Internal Controls Over Financial Reporting Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34) Consolidated Financial Statements PSNH Management’s Report on Internal Controls Over Financial Reporting Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34) Consolidated Financial Statements 61
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Management’s Report on Internal Controls Over Financial Reporting Eversource Energy Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Eversource Energy and subsidiaries (Eversource or the Company) and of other sections of this annual report. Eversource's internal controls over financial reporting were audited by Deloitte & Touche LLP. Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment. Under the supervision and with the participation of the principal executive officer and principal financial officer, Eversource conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2025. February 17, 2026 62
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Trustees and Shareholders of Eversource Energy: Opinion on Internal Control over Financial Reporting We have audited the internal control over financial reporting of Eversource Energy and subsidiaries (the “Company”) as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2025, of the Company and our report dated February 17, 2026, expressed an unqualified opinion on those financial statements. Basis for Opinion The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Controls Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ Deloitte & Touche LLP Hartford, Connecticut February 17, 2026 63
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Trustees and Shareholders of Eversource Energy: Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Eversource Energy and subsidiaries (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, common shareholders’ equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes and the schedules listed in the Index at Item 15 of Part IV (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 17, 2026, expressed an unqualified opinion on the Company’s internal control over financial reporting. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. Regulatory Accounting - Impact of Rate Regulation on the Financial Statements - Refer to Note 2 to the Financial Statements Critical Audit Matter Description The Company is subject to regulation by federal, Connecticut, Massachusetts, and New Hampshire utility regulatory agencies (the “Commissions”), which have jurisdiction with respect to the rates of the Company’s electric, natural gas, and water distribution companies. Management has determined it meets the criteria for the application of regulated operations accounting in preparing its financial statements under accounting principles generally accepted in the United States of America. Judgment can be required to determine if otherwise recognizable incurred costs qualify to be presented as a regulatory asset and deferred because such costs are probable of future recovery in customer rates. As discussed in Note 2, regulatory proceedings in recent years have focused on the recoverability of costs, including storm costs, regulatory tracking mechanisms and benefit costs, amongst others. In some cases, the Company records regulatory assets before approval for recovery has been received from the applicable regulatory commission. As a result, assessing the potential outcomes of future regulatory orders requires management judgment. We identified the impact of rate regulation related to regulatory assets as a critical audit matter due to the judgments made by management, including assumptions regarding the outcome of future decisions by the Commissions to support its assertions on the likelihood of future recovery for deferred costs. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the ratemaking process due to its inherent complexities as it relates to regulatory assets. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others: • We tested the effectiveness of management’s controls over the evaluation of the likelihood of the recovery in future rates of costs deferred as regulatory assets. 64
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• We evaluated the Company’s disclosures related to the applicability and impacts of rate regulation, including the balances recorded and regulatory developments disclosed in the financial statements. • We read relevant regulatory orders issued by the Commissions for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness. • For regulatory matters in process, we inspected the Company’s filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions. • We performed audit procedures on deferred storm restoration costs for completeness and accuracy. • We made inquiries of management, including legal counsel, and obtained the regulatory orders and analysis from management that support the probability of recovery in rates for regulatory assets to assess management’s assertion that amounts are probable of recovery. Offshore Wind Contingent Liability – Impact of Offshore Wind Investment Divestiture - Refer to Notes 6 and 13G to the Financial Statements Critical Audit Matter Description In 2024, Eversource sold its interests in the Revolution Wind, South Fork Wind, and Sunrise Wind projects, while retaining a noncontrolling tax equity investment in South Fork Wind through full ownership of Class A shares in South Fork Wind Holdings, LLC. As part of the sale, Eversource initially recorded a $365 million liability for post-closing purchase price adjustment obligations, primarily related to cost overrun sharing, maintaining the buyer’s internal rate of return, and other future costs. Subsequent to the sale, Eversource receives updated reports from project management on the construction status of Revolution Wind, which include revised projections of total construction costs. The revised cost projections reflect known and quantifiable cost increases. Based on 2025 developments and other available information, Eversource increased its contingent liability associated with the offshore wind projects in 2025 to reflect changes in cost estimates, expected timing of completion and other purchase price adjustments. As of December 31, 2025, the contingent liability is $448.2 million and is recorded as a current liability on Eversource’s balance sheet, based upon the timing of expected payments to GIP. We identified the evaluation of the offshore wind investment divestiture as a critical audit matter because of the extensive effort required to audit the subjective and complex judgments associated with the determination of the loss on sale and related contingent liability. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to the offshore wind investment divestiture included the following, among others: • We tested the effectiveness of management’s controls over the contingent liability considerations including the recording and disclosure of the loss on the offshore wind investments, including estimates and assumptions used to measure the loss. We tested the effectiveness of management’s controls over the loss recognition on the investments. • We evaluated the Company’s disclosures related to the offshore wind transactions in the financial statements. • We evaluated management’s assumptions utilized in recording the contingent liability on investments. • We evaluated the sufficiency of the contingent liability based on facts and circumstances that existed as of the reporting date. • We made inquiries of management and evaluated management’s analysis that supported the project forecast, the timing of the loss, and the assumptions made in the recording of the contingent liability. /s/ Deloitte & Touche LLP Hartford, Connecticut February 17, 2026 We have served as the Company’s auditor since 2002.
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EVERSOURCE ENERGY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS As of December 31, (Thousands of Dollars) 2025 2024 ASSETS Current Assets: Cash $ 135,351 $ 26,656 Receivables, Net (net of allowance for uncollectible accounts of $580,539 and $556,164 as of December 31, 2025 and 2024, respectively) 1,847,094 1,651,325 Unbilled Revenues 275,108 242,169 Materials, Supplies, Natural Gas and REC Inventory 491,592 594,568 Regulatory Assets 1,975,083 2,189,660 Current Assets Held for Sale — 56,327 Prepayments and Other Current Assets 352,958 315,368 Total Current Assets 5,077,186 5,076,073 Property, Plant and Equipment, Net 45,930,959 40,986,578 Deferred Debits and Other Assets: Regulatory Assets 5,718,646 4,880,974 Goodwill 4,233,767 3,571,333 Prepaid Pension and PBOP 1,511,169 1,336,633 Marketable Securities 317,101 320,272 Long-Term Assets Held for Sale — 2,611,145 Other Long-Term Assets 997,883 811,521 Total Deferred Debits and Other Assets 12,778,566 13,531,878 Total Assets $ 63,786,711 $ 59,594,529 LIABILITIES AND CAPITALIZATION Current Liabilities: Notes Payable $ 1,525,445 $ 2,042,793 Long-Term Debt – Current Portion 1,392,948 1,003,150 Rate Reduction Bonds – Current Portion 43,210 43,210 Accounts Payable 1,859,692 1,736,880 Accrued Interest 380,231 341,558 Regulatory Liabilities 1,264,609 632,282 Current Liabilities Held for Sale — 52,593 Offshore Wind Contingent Liability - Current Portion 448,158 15,000 Other Current Liabilities 894,219 853,491 Total Current Liabilities 7,808,512 6,720,957 Deferred Credits and Other Liabilities: Accumulated Deferred Income Taxes 5,647,218 5,411,206 Regulatory Liabilities 4,273,465 4,032,564 Derivative Liabilities 753,149 — Asset Retirement Obligations 595,442 590,890 Accrued SERP and PBOP 100,859 95,400 Long-Term Liabilities Held for Sale — 398,859 Offshore Wind Contingent Liability - Long-Term Portion — 350,000 Other Long-Term Liabilities 1,101,932 773,999 Total Deferred Credits and Other Liabilities 12,472,065 11,652,918 Long-Term Debt 26,872,433 25,701,627 Rate Reduction Bonds 280,862 324,072 Noncontrolling Interest - Preferred Stock of Subsidiaries 155,568 155,568 Common Shareholders' Equity: Common Shares 1,914,273 1,878,622 Capital Surplus, Paid In 9,937,878 9,428,905 Retained Earnings 4,504,983 3,929,141 Accumulated Other Comprehensive Loss (20,507) (26,472) Treasury Stock (139,356) (170,809) Common Shareholders' Equity 16,197,271 15,039,387 Commitments and Contingencies (Note 13) Total Liabilities and Capitalization $ 63,786,711 $ 59,594,529 The accompanying notes are an integral part of these consolidated financial statements. 66
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EVERSOURCE ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME/(LOSS) For the Years Ended December 31, (Thousands of Dollars, Except Share Information) 2025 2024 2023 Operating Revenues $ 13,547,244 $ 11,900,809 $ 11,910,705 Operating Expenses: Purchased Power, Purchased Natural Gas and Transmission 4,209,172 3,736,078 5,168,241 Operations and Maintenance 2,073,778 2,012,926 1,895,703 Depreciation 1,568,578 1,433,503 1,305,840 Amortization 835,909 342,864 (490,117) Energy Efficiency Programs 778,348 671,828 691,344 Taxes Other Than Income Taxes 1,092,870 997,901 940,359 Loss on Pending Sale of Aquarion — 297,000 — Total Operating Expenses 10,558,655 9,492,100 9,511,370 Operating Income 2,988,589 2,408,709 2,399,335 Interest Expense 1,243,266 1,111,336 855,441 Losses on Offshore Wind 284,000 464,019 2,167,000 Other Income, Net 378,854 410,482 348,069 Income/(Loss) Before Income Tax Expense 1,840,177 1,243,836 (275,037) Income Tax Expense 140,286 424,664 159,684 Net Income/(Loss) 1,699,891 819,172 (434,721) Net Income Attributable to Noncontrolling Interests 7,519 7,519 7,519 Net Income/(Loss) Attributable to Common Shareholders $ 1,692,372 $ 811,653 $ (442,240) Basic Earnings/(Loss) Per Common Share $ 4.56 $ 2.27 $ (1.27) Diluted Earnings/(Loss) Per Common Share $ 4.56 $ 2.27 $ (1.26) Weighted Average Common Shares Outstanding: Basic 370,852,601 357,482,965 349,580,638 Diluted 371,259,264 357,779,408 349,840,481 The accompanying notes are an integral part of these consolidated financial statements. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS) For the Years Ended December 31, (Thousands of Dollars) 2025 2024 2023 Net Income/(Loss) $ 1,699,891 $ 819,172 $ (434,721) Other Comprehensive Income, Net of Tax: Qualified Cash Flow Hedging Instruments 20 20 20 Changes in Unrealized Gains on Marketable Securities — — 1,252 Changes in Funded Status of Pension, SERP and PBOP Benefit Plans 5,945 7,245 4,412 Other Comprehensive Income, Net of Tax 5,965 7,265 5,684 Comprehensive Income Attributable to Noncontrolling Interests (7,519) (7,519) (7,519) Comprehensive Income/(Loss) Attributable to Common Shareholders $ 1,698,337 $ 818,918 $ (436,556) The accompanying notes are an integral part of these consolidated financial statements. 67
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EVERSOURCE ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY Common Shares CapitalSurplus,Paid In RetainedEarnings AccumulatedOtherComprehensiveLoss TreasuryStock Total CommonShareholders'Equity(Thousands of Dollars, Except Share Information) Shares Amount Balance as of January 1, 2023 348,443,855 $ 1,799,920 $ 8,401,731 $ 5,527,153 $ (39,421) $ (216,225) $ 15,473,158 Net Loss (434,721) (434,721) Dividends on Common Shares - $2.70 Per Share (942,398) (942,398) Dividends on Preferred Stock (7,519) (7,519) Long-Term Incentive Plan Activity 1,375 1,375 Issuance of Treasury Shares 1,096,411 57,770 20,543 78,313 Other Comprehensive Income 5,684 5,684 Balance as of December 31, 2023 349,540,266 1,799,920 8,460,876 4,142,515 (33,737) (195,682) 14,173,892 Net Income 819,172 819,172 Dividends on Common Shares - $2.86 Per Share (1,025,027) (1,025,027) Dividends on Preferred Stock (7,519) (7,519) Issuance of Common Shares - $5 par value 15,740,294 78,702 921,387 1,000,089 Capital Stock Expense (10,642) (10,642) Long-Term Incentive Plan Activity (6,557) (6,557) Issuance of Treasury Shares 1,327,492 63,841 24,873 88,714 Other Comprehensive Income 7,265 7,265 Balance as of December 31, 2024 366,608,052 1,878,622 9,428,905 3,929,141 (26,472) (170,809) 15,039,387 Net Income 1,699,891 1,699,891 Dividends on Common Shares - $3.01 Per Share (1,116,530) (1,116,530) Dividends on Preferred Stock (7,519) (7,519) Issuance of Common Shares - $5 par value 7,130,134 35,651 435,298 470,949 Capital Stock Expense (5,560) (5,560) Long-Term Incentive Plan Activity (5,900) (5,900) Issuance of Treasury Shares 1,678,694 85,135 31,453 116,588 Other Comprehensive Income 5,965 5,965 Balance as of December 31, 2025 375,416,880 $ 1,914,273 $ 9,937,878 $ 4,504,983 $ (20,507) $ (139,356) $ 16,197,271 The accompanying notes are an integral part of these consolidated financial statements. 68
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EVERSOURCE ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, (Thousands of Dollars) 2025 2024 2023 Operating Activities: Net Income/(Loss) $ 1,699,891 $ 819,172 $ (434,721) Adjustments to Reconcile Net Income/(Loss) to Net Cash Flows Provided by Operating Activities: Depreciation 1,568,578 1,433,503 1,305,840 Deferred Income Taxes 27,313 435,889 85,405 Uncollectible Expense 101,141 74,069 72,468 Pension, SERP and PBOP Income, Net (80,628) (73,564) (90,706) Regulatory Over/(Under) Recoveries, Net 13,062 (919,359) (151,548) Amortization 835,909 342,864 (490,117) Cost of Removal Expenditures (275,906) (294,984) (315,699) Losses on Offshore Wind 284,000 464,019 2,167,000 Loss on Pending Sale of Aquarion — 297,000 — Other (4,826) (108,365) (59,886) Changes in Current Assets and Liabilities: Receivables and Unbilled Revenues, Net (364,156) (432,620) (124,393) Taxes Receivable/Accrued, Net 143,331 55,502 36,357 Accounts Payable 84,192 47,082 (287,637) Other Current Assets and Liabilities, Net 81,671 19,529 (66,202) Net Cash Flows Provided by Operating Activities 4,113,572 2,159,737 1,646,161 Investing Activities: Investments in Property, Plant and Equipment (4,158,669) (4,480,529) (4,336,849) Proceeds from Sales of Marketable Securities 439,311 268,164 395,604 Purchases of Marketable Securities (416,082) (242,959) (336,779) Payments for Offshore Wind Contingent Liability (200,842) — — Investments in Unconsolidated Affiliates (701) (929,688) (1,680,473) Proceeds from Sales of Offshore Wind Investments — 862,713 1,090,662 Other Investing Activities 30,820 (13,365) (2,897) Net Cash Flows Used in Investing Activities (4,306,163) (4,535,664) (4,870,732) Financing Activities: Issuance of Common Shares, Net of Issuance Costs 465,389 989,447 — Cash Dividends on Common Shares (1,093,074) (1,001,488) (918,995) Cash Dividends on Preferred Stock (7,519) (7,519) (7,519) (Decrease)/Increase in Notes Payable (517,348) (94,959) 695,552 Repayment of Rate Reduction Bonds (43,210) (43,210) (43,210) Issuance of Long-Term Debt 2,942,353 4,501,623 5,198,345 Retirement of Long-Term Debt (1,400,331) (1,949,995) (2,008,470) Other Financing Activities (34,732) (57,082) (46,466) Net Cash Flows Provided by Financing Activities 311,528 2,336,817 2,869,237 Net Increase/(Decrease) in Cash and Restricted Cash 118,937 (39,110) (355,334) Cash and Restricted Cash - Beginning of Year 127,308 166,418 521,752 Cash and Restricted Cash - End of Year $ 246,245 $ 127,308 $ 166,418 The accompanying notes are an integral part of these consolidated financial statements. 69
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Management’s Report on Internal Controls Over Financial Reporting The Connecticut Light and Power Company Management is responsible for the preparation, integrity, and fair presentation of the accompanying financial statements of The Connecticut Light and Power Company (CL&P or the Company) and of other sections of this annual report. Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment. Under the supervision and with the participation of the principal executive officer and principal financial officer, CL&P conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2025. February 17, 2026 70
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholder of The Connecticut Light and Power Company: Opinion on the Financial Statements We have audited the accompanying balance sheets of The Connecticut Light and Power Company (the “Company”) as of December 31, 2025 and 2024, the related statements of income, comprehensive income, common stockholder’s equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes and the schedule listed in the Index at Item 15 of Part IV (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matter The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Regulatory Accounting - Impact of Rate Regulation on the Financial Statements - Refer to Note 2 to the Financial Statements Critical Audit Matter Description The Company is subject to regulation by federal and Connecticut utility regulatory agencies (the “Commissions”), which have jurisdiction with respect to the rates of the Company’s electric distribution business. Management has determined it meets the criteria for the application of regulated operations accounting in preparing its financial statements under accounting principles generally accepted in the United States of America. Judgment can be required to determine if otherwise recognizable incurred costs qualify to be presented as a regulatory asset and deferred because such costs are probable of future recovery in customer rates. As discussed in Note 2, regulatory proceedings in recent years have focused on the recoverability of costs, including storm costs, regulatory tracking mechanisms and benefit costs, amongst others. In some cases, the Company records regulatory assets before approval for recovery has been received from the applicable regulatory commission. As a result, assessing the potential outcomes of future regulatory orders requires management judgment. We identified the impact of rate regulation related to regulatory assets as a critical audit matter due to the judgments made by management, including assumptions regarding the outcome of future decisions by the Commissions to support its assertions on the likelihood of future recovery for deferred costs. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the ratemaking process due to its inherent complexities as it relates to regulatory assets. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others: • We tested the effectiveness of management’s controls over the evaluation of the likelihood of the recovery in future rates of costs deferred as regulatory assets.
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• We evaluated the Company’s disclosures related to the applicability and impacts of rate regulation, including the balances recorded and regulatory developments disclosed in the financial statements. • We read relevant regulatory orders issued by the Commissions for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness. • For regulatory matters in process, we inspected the Company’s filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions. • We performed audit procedures on deferred storm restoration costs for completeness and accuracy. • We made inquiries of management, including legal counsel, and obtained the regulatory orders and analysis from management that support the probability of recovery in rates for regulatory assets to assess management’s assertion that amounts are probable of recovery. /s/ Deloitte & Touche LLP Hartford, Connecticut February 17, 2026 We have served as the Company’s auditor since 2002. 72
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THE CONNECTICUT LIGHT AND POWER COMPANY BALANCE SHEETS As of December 31, (Thousands of Dollars) 2025 2024 ASSETS Current Assets: Cash $ 87,615 $ 1,093 Receivables, Net (net of allowance for uncollectible accounts of $258,514 and $279,108 as of December 31, 2025 and 2024, respectively) 652,150 663,171 Accounts Receivable from Affiliated Companies 60,995 68,723 Unbilled Revenues 63,508 59,759 Materials and Supplies 133,908 217,316 Regulatory Assets 265,175 638,529 Prepayments and Other Current Assets 50,579 51,688 Total Current Assets 1,313,930 1,700,279 Property, Plant and Equipment, Net 13,623,296 13,002,193 Deferred Debits and Other Assets: Regulatory Assets 1,716,212 1,687,029 Prepaid Pension and PBOP 204,067 182,483 Other Long-Term Assets 321,234 267,861 Total Deferred Debits and Other Assets 2,241,513 2,137,373 Total Assets $ 17,178,739 $ 16,839,845 LIABILITIES AND CAPITALIZATION Current Liabilities: Notes Payable to Eversource Parent $ — $ 280,000 Long-Term Debt – Current Portion — 2,944 Accounts Payable 637,467 548,100 Accounts Payable to Affiliated Companies 141,610 137,150 Accrued Taxes 165,362 41,654 Regulatory Liabilities 417,498 124,122 Derivative Liabilities 128 71,090 Other Current Liabilities 220,464 193,040 Total Current Liabilities 1,582,529 1,398,100 Deferred Credits and Other Liabilities: Accumulated Deferred Income Taxes 2,005,888 2,052,806 Regulatory Liabilities 1,445,140 1,395,883 Other Long-Term Liabilities 239,289 204,801 Total Deferred Credits and Other Liabilities 3,690,317 3,653,490 Long-Term Debt 5,110,067 5,108,173 Preferred Stock Not Subject to Mandatory Redemption 116,200 116,200 Common Stockholder's Equity: Common Stock 60,352 60,352 Capital Surplus, Paid In 3,684,265 3,684,265 Retained Earnings 2,934,877 2,819,107 Accumulated Other Comprehensive Income 132 158 Common Stockholder's Equity 6,679,626 6,563,882 Commitments and Contingencies (Note 13) Total Liabilities and Capitalization $ 17,178,739 $ 16,839,845 The accompanying notes are an integral part of these financial statements. 73
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THE CONNECTICUT LIGHT AND POWER COMPANY STATEMENTS OF INCOME For the Years Ended December 31, (Thousands of Dollars) 2025 2024 2023 Operating Revenues $ 5,240,994 $ 4,614,977 $ 4,578,804 Operating Expenses: Purchased Power and Transmission 1,815,820 1,836,911 2,612,949 Operations and Maintenance 848,979 815,345 733,287 Depreciation 432,763 406,540 376,904 Amortization of Regulatory Assets/(Liabilities), Net 649,691 104,446 (500,367) Energy Efficiency Programs 170,209 171,690 133,453 Taxes Other Than Income Taxes 452,880 419,575 401,135 Total Operating Expenses 4,370,342 3,754,507 3,757,361 Operating Income 870,652 860,470 821,443 Interest Expense 211,856 231,004 193,361 Other Income, Net 59,736 77,591 61,560 Income Before Income Tax Expense 718,532 707,057 689,642 Income Tax Expense 167,203 194,459 170,909 Net Income $ 551,329 $ 512,598 $ 518,733 The accompanying notes are an integral part of these financial statements. STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, (Thousands of Dollars) 2025 2024 2023 Net Income $ 551,329 $ 512,598 $ 518,733 Other Comprehensive (Loss)/Income, Net of Tax: Qualified Cash Flow Hedging Instruments (26) (27) (26) Changes in Unrealized Gains on Marketable Securities — — 42 Other Comprehensive (Loss)/Income, Net of Tax (26) (27) 16 Comprehensive Income $ 551,303 $ 512,571 $ 518,749 The accompanying notes are an integral part of these financial statements. 74
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THE CONNECTICUT LIGHT AND POWER COMPANY STATEMENTS OF COMMON STOCKHOLDER'S EQUITY Common Stock CapitalSurplus,Paid In RetainedEarnings AccumulatedOtherComprehensiveIncome TotalCommonStockholder'sEquity(Thousands of Dollars, Except Stock Information) Stock Amount Balance as of January 1, 2023 6,035,205 $ 60,352 $ 3,260,765 $ 2,463,094 $ 169 $ 5,784,380 Net Income 518,733 518,733 Dividends on Preferred Stock (5,559) (5,559) Dividends on Common Stock (330,400) (330,400) Capital Contributions from Eversource Parent 123,500 123,500 Other Comprehensive Income 16 16 Balance as of December 31, 2023 6,035,205 60,352 3,384,265 2,645,868 185 6,090,670 Net Income 512,598 512,598 Dividends on Preferred Stock (5,559) (5,559) Dividends on Common Stock (333,800) (333,800) Capital Contributions from Eversource Parent 300,000 300,000 Other Comprehensive Loss (27) (27) Balance as of December 31, 2024 6,035,205 60,352 3,684,265 2,819,107 158 6,563,882 Net Income 551,329 551,329 Dividends on Preferred Stock (5,559) (5,559) Dividends on Common Stock (430,000) (430,000) Other Comprehensive Loss (26) (26) Balance as of December 31, 2025 6,035,205 $ 60,352 $ 3,684,265 $ 2,934,877 $ 132 $ 6,679,626 The accompanying notes are an integral part of these financial statements. 75
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THE CONNECTICUT LIGHT AND POWER COMPANY STATEMENTS OF CASH FLOWS For the Years Ended December 31, (Thousands of Dollars) 2025 2024 2023 Operating Activities: Net Income $ 551,329 $ 512,598 $ 518,733 Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities: Depreciation 432,763 406,540 376,904 Deferred Income Taxes (94,819) 175,424 184,037 Uncollectible Expense 17,949 17,190 11,675 Pension, SERP and PBOP Income, Net (14,023) (12,019) (18,316) Regulatory (Under)/Over Recoveries, Net (13,145) (257,561) 157,200 Amortization of Regulatory Assets/(Liabilities), Net 649,691 104,446 (500,367) Cost of Removal Expenditures (59,928) (60,536) (80,479) Other 46,379 (47,680) (16,194) Changes in Current Assets and Liabilities: Receivables and Unbilled Revenues, Net (33,660) (175,162) (100,684) Taxes Receivable/Accrued, Net 123,240 64,914 25,633 Accounts Payable 37,800 4,232 (88,040) Other Current Assets and Liabilities, Net 31,590 (48,973) (20,535) Net Cash Flows Provided by Operating Activities 1,675,166 683,413 449,567 Investing Activities: Investments in Property, Plant and Equipment (867,772) (978,532) (1,093,121) Other Investing Activities — — 173 Net Cash Flows Used in Investing Activities (867,772) (978,532) (1,092,948) Financing Activities: Cash Dividends on Common Stock (430,000) (333,800) (330,400) Cash Dividends on Preferred Stock (5,559) (5,559) (5,559) (Decrease)/Increase in Notes Payable to Eversource Parent (280,000) (177,000) 457,000 Issuance of Long-Term Debt 400,000 650,000 800,000 Retirement of Long-Term Debt (400,000) (139,800) (400,000) Capital Contributions from Eversource Parent — 300,000 123,500 Other Financing Activities (5,268) (8,856) (9,244) Net Cash Flows (Used In)/Provided by Financing Activities (720,827) 284,985 635,297 Net Increase/(Decrease) in Cash and Restricted Cash 86,567 (10,134) (8,084) Cash and Restricted Cash - Beginning of Year 2,109 12,243 20,327 Cash and Restricted Cash - End of Year $ 88,676 $ 2,109 $ 12,243 The accompanying notes are an integral part of these financial statements. 76
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Management’s Report on Internal Controls Over Financial Reporting NSTAR Electric Company Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of NSTAR Electric Company and subsidiary (NSTAR Electric or the Company) and of other sections of this annual report. Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment. Under the supervision and with the participation of the principal executive officer and principal financial officer, NSTAR Electric conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2025. February 17, 2026 77
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholder of NSTAR Electric Company: Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of NSTAR Electric Company and subsidiary (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, common stockholder’s equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes and the schedule listed in the Index at Item 15 of Part IV (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matter The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Regulatory Accounting - Impact of Rate Regulation on the Financial Statements - Refer to Note 2 to the Financial Statements Critical Audit Matter Description The Company is subject to regulation by federal and Massachusetts utility regulatory agencies (the “Commissions”), which have jurisdiction with respect to the rates of the Company’s electric distribution business. Management has determined it meets the criteria for the application of regulated operations accounting in preparing its financial statements under accounting principles generally accepted in the United States of America. Judgment can be required to determine if otherwise recognizable incurred costs qualify to be presented as a regulatory asset and deferred because such costs are probable of future recovery in customer rates. As discussed in Note 2, regulatory proceedings in recent years have focused on the recoverability of costs. In some cases, the Company records regulatory assets before approval for recovery has been received from the applicable regulatory commission. As a result, assessing the potential outcomes of future regulatory orders requires management judgment. We identified the impact of rate regulation related to regulatory assets as a critical audit matter due to the judgments made by management, including assumptions regarding the outcome of future decisions by the Commissions to support its assertions on the likelihood of future recovery for deferred costs. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the ratemaking process due to its inherent complexities as it relates to regulatory assets. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others: • We tested the effectiveness of management’s controls over the evaluation of the likelihood of the recovery in future rates of costs deferred as regulatory assets.
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• We evaluated the Company’s disclosures related to the applicability and impacts of rate regulation, including the balances recorded and regulatory developments disclosed in the financial statements. • We read relevant regulatory orders issued by the Commissions for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness. • For regulatory matters in process, we inspected the Company’s filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions. • We made inquiries of management, including legal counsel, and obtained the regulatory orders and analysis from management that support the probability of recovery in rates for regulatory assets to assess management’s assertion that amounts are probable of recovery. /s/ Deloitte & Touche LLP Hartford, Connecticut February 17, 2026 We have served as the Company’s auditor since 2012. 79
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NSTAR ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS As of December 31, (Thousands of Dollars) 2025 2024 ASSETS Current Assets: Cash $ 8,302 $ 911 Receivables, Net (net of allowance for uncollectible accounts of $132,561 and $114,910 as of December 31, 2025 and2024, respectively) 616,280 614,563 Accounts Receivable from Affiliated Companies 280,099 82,921 Unbilled Revenues 56,948 59,079 Materials, Supplies and REC Inventory 210,865 220,621 Regulatory Assets 978,754 902,770 Derivative Assets 91,011 — Prepayments and Other Current Assets 90,040 72,986 Total Current Assets 2,332,299 1,953,851 Property, Plant and Equipment, Net 15,308,896 14,037,828 Deferred Debits and Other Assets: Regulatory Assets 1,823,522 1,204,337 Prepaid Pension and PBOP 804,109 724,661 Other Long-Term Assets 264,073 154,571 Total Deferred Debits and Other Assets 2,891,704 2,083,569 Total Assets $ 20,532,899 $ 18,075,248 LIABILITIES AND CAPITALIZATION Current Liabilities: Notes Payable $ 245,445 $ 504,782 Long-Term Debt – Current Portion 300,000 250,000 Accounts Payable 558,227 534,868 Accounts Payable to Affiliated Companies 198,085 153,672 Obligations to Third-Party Suppliers 179,757 163,711 Regulatory Liabilities 650,813 436,312 Other Current Liabilities 208,979 202,197 Total Current Liabilities 2,341,306 2,245,542 Deferred Credits and Other Liabilities: Accumulated Deferred Income Taxes 2,087,287 2,005,439 Regulatory Liabilities 1,702,059 1,643,079 Derivative Liabilities 753,149 — Other Long-Term Liabilities 401,625 377,462 Total Deferred Credits and Other Liabilities 4,944,120 4,025,980 Long-Term Debt 5,645,638 4,844,920 Preferred Stock Not Subject to Mandatory Redemption 43,000 43,000 Common Stockholder's Equity: Common Stock — — Capital Surplus, Paid In 4,238,842 3,788,842 Retained Earnings 3,319,768 3,127,105 Accumulated Other Comprehensive Income/(Loss) 225 (141) Common Stockholder's Equity 7,558,835 6,915,806 Commitments and Contingencies (Note 13) Total Liabilities and Capitalization $ 20,532,899 $ 18,075,248 The accompanying notes are an integral part of these consolidated financial statements. 80
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NSTAR ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, (Thousands of Dollars) 2025 2024 2023 Operating Revenues $ 3,986,599 $ 3,720,877 $ 3,515,539 Operating Expenses: Purchased Power and Transmission 1,141,748 1,045,306 1,154,013 Operations and Maintenance 792,319 735,019 668,466 Depreciation 446,045 407,699 372,578 Amortization of Regulatory Assets, Net 107,553 130,869 16,150 Energy Efficiency Programs 294,343 263,405 325,593 Taxes Other Than Income Taxes 320,523 280,261 256,090 Total Operating Expenses 3,102,531 2,862,559 2,792,890 Operating Income 884,068 858,318 722,649 Interest Expense 256,061 222,794 189,254 Other Income, Net 192,646 191,405 164,129 Income Before Income Tax Expense 820,653 826,929 697,524 Income Tax Expense 190,030 190,576 152,996 Net Income $ 630,623 $ 636,353 $ 544,528 The accompanying notes are an integral part of these consolidated financial statements. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, (Thousands of Dollars) 2025 2024 2023 Net Income $ 630,623 $ 636,353 $ 544,528 Other Comprehensive Income/(Loss), Net of Tax: Changes in Funded Status of SERP Benefit Plan 346 (205) (272) Qualified Cash Flow Hedging Instruments 20 20 20 Changes in Unrealized Gains on Marketable Securities — — 12 Other Comprehensive Income/(Loss), Net of Tax 366 (185) (240) Comprehensive Income $ 630,989 $ 636,168 $ 544,288 The accompanying notes are an integral part of these consolidated financial statements. 81
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NSTAR ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY Common Stock CapitalSurplus,Paid In RetainedEarnings AccumulatedOtherComprehensiveIncome/(Loss) TotalCommonStockholder'sEquity(Thousands of Dollars, Except Stock Information) Stock Amount Balance as of January 1, 2023 200 $ — $ 2,778,942 $ 2,921,444 $ 284 $ 5,700,670 Net Income 544,528 544,528 Dividends on Preferred Stock (1,960) (1,960) Dividends on Common Stock (327,400) (327,400) Capital Contributions from Eversource Parent 234,900 234,900 Other Comprehensive Loss (240) (240) Balance as of December 31, 2023 200 — 3,013,842 3,136,612 44 6,150,498 Net Income 636,353 636,353 Dividends on Preferred Stock (1,960) (1,960) Dividends on Common Stock (643,900) (643,900) Capital Contributions from Eversource Parent 775,000 775,000 Other Comprehensive Loss (185) (185) Balance as of December 31, 2024 200 — 3,788,842 3,127,105 (141) 6,915,806 Net Income 630,623 630,623 Dividends on Preferred Stock (1,960) (1,960) Dividends on Common Stock (436,000) (436,000) Capital Contributions from Eversource Parent 450,000 450,000 Other Comprehensive Income 366 366 Balance as of December 31, 2025 200 $ — $ 4,238,842 $ 3,319,768 $ 225 $ 7,558,835 The accompanying notes are an integral part of these consolidated financial statements. 82
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NSTAR ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, (Thousands of Dollars) 2025 2024 2023 Operating Activities: Net Income $ 630,623 $ 636,353 $ 544,528 Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities: Depreciation 446,045 407,699 372,578 Deferred Income Taxes 35,596 111,177 96,224 Uncollectible Expense 41,430 33,607 22,791 Pension, SERP and PBOP Income, Net (39,526) (36,104) (41,554) Regulatory Over/(Under) Recoveries, Net 116,288 (271,689) (141,865) Amortization of Regulatory Assets, Net 107,553 130,869 16,150 Cost of Removal Expenditures (66,611) (59,187) (68,290) Other (116,923) (25,876) (2,123) Changes in Current Assets and Liabilities: Receivables and Unbilled Revenues, Net (256,463) (179,783) (82,659) Taxes Receivable/Accrued, Net (8,468) (37,779) 27,394 Accounts Payable 64,915 1,412 11,357 Other Current Assets and Liabilities, Net 25,993 (23,137) (40,974) Net Cash Flows Provided by Operating Activities 980,452 687,562 713,557 Investing Activities: Investments in Property, Plant and Equipment (1,561,071) (1,563,326) (1,376,135) Other Investing Activities — — 48 Net Cash Flows Used in Investing Activities (1,561,071) (1,563,326) (1,376,087) Financing Activities: Cash Dividends on Common Stock (436,000) (643,900) (327,400) Cash Dividends on Preferred Stock (1,960) (1,960) (1,960) (Decrease)/Increase in Notes Payable (259,337) 138,935 365,847 Capital Contributions from Eversource Parent 450,000 775,000 234,900 Issuance of Long-Term Debt 1,100,000 600,000 150,000 Retirement of Long-Term Debt (250,000) — (80,000) Other Financing Activities (5,163) (6,073) (1,365) Net Cash Flows Provided by Financing Activities 597,540 862,002 340,022 Net Increase/(Decrease) in Cash and Restricted Cash 16,921 (13,762) (322,508) Cash and Restricted Cash - Beginning of Year 9,023 22,785 345,293 Cash and Restricted Cash - End of Year $ 25,944 $ 9,023 $ 22,785 The accompanying notes are an integral part of these consolidated financial statements. 83
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Management’s Report on Internal Controls Over Financial Reporting Public Service Company of New Hampshire Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Public Service Company of New Hampshire and subsidiaries (PSNH or the Company) and of other sections of this annual report. Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment. Under the supervision and with the participation of the principal executive officer and principal financial officer, PSNH conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2025. February 17, 2026 84
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholder of Public Service Company of New Hampshire: Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Public Service Company of New Hampshire and subsidiaries (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, common stockholder’s equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes and the schedule listed in the Index at Item 15 of Part IV (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matter The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Regulatory Accounting - Impact of Rate Regulation on the Financial Statements - Refer to Note 2 to the Financial Statements Critical Audit Matter Description The Company is subject to regulation by federal and New Hampshire utility regulatory agencies (the “Commissions”), which have jurisdiction with respect to the rates of the Company’s electric distribution business. Management has determined it meets the criteria for the application of regulated operations accounting in preparing its financial statements under accounting principles generally accepted in the United States of America. Judgment can be required to determine if otherwise recognizable incurred costs qualify to be presented as a regulatory asset and deferred because such costs are probable of future recovery in customer rates. As discussed in Note 2, regulatory proceedings in recent years have focused on the recoverability of costs. In some cases, the Company records regulatory assets before approval for recovery has been received from the applicable regulatory commission. As a result, assessing the potential outcomes of future regulatory orders requires management judgment. We identified the impact of rate regulation related to regulatory assets as a critical audit matter due to the judgments made by management, including assumptions regarding the outcome of future decisions by the Commissions to support its assertions on the likelihood of future recovery for deferred costs. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the ratemaking process due to its inherent complexities as it relates to regulatory assets. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others: • We tested the effectiveness of management’s controls over the evaluation of the likelihood of the recovery in future rates of costs deferred as regulatory assets.
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• We evaluated the Company’s disclosures related to the applicability and impacts of rate regulation, including the balances recorded and regulatory developments disclosed in the financial statements. • We read relevant regulatory orders issued by the Commissions for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness. • For regulatory matters in process, we inspected the Company’s filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions. • We made inquiries of management, including legal counsel, and obtained the regulatory orders and analysis from management that support the probability of recovery in rates for regulatory assets to assess management’s assertion that amounts are probable of recovery. /s/ Deloitte & Touche LLP Hartford, Connecticut February 17, 2026 We have served as the Company’s auditor since 2002. 86
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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS As of December 31, (Thousands of Dollars) 2025 2024 ASSETS Current Assets: Cash $ 13,665 $ 1,431 Receivables, Net (net of allowance for uncollectible accounts of $23,547 and $14,090 as of December 31, 2025 and 2024, respectively) 214,117 163,063 Accounts Receivable from Affiliated Companies 24,338 27,285 Unbilled Revenues 62,446 57,226 Materials, Supplies and REC Inventory 58,879 75,778 Regulatory Assets 119,871 173,267 Special Deposits 38,343 32,668 Prepayments and Other Current Assets 19,212 15,916 Total Current Assets 550,871 546,634 Property, Plant and Equipment, Net 5,507,663 5,089,943 Deferred Debits and Other Assets: Regulatory Assets 841,203 892,411 Prepaid Pension and PBOP 111,833 91,005 Other Long-Term Assets 17,661 21,948 Total Deferred Debits and Other Assets 970,697 1,005,364 Total Assets $ 7,029,231 $ 6,641,941 LIABILITIES AND CAPITALIZATION Current Liabilities: Notes Payable to Eversource Parent $ 49,300 $ 131,100 Rate Reduction Bonds – Current Portion 43,210 43,210 Accounts Payable 179,137 226,074 Accounts Payable to Affiliated Companies 45,277 45,141 Obligations to Third-Party Suppliers 37,584 1,314 Accrued Interest 35,224 29,062 Regulatory Liabilities 118,443 121,058 Other Current Liabilities 62,334 61,642 Total Current Liabilities 570,509 658,601 Deferred Credits and Other Liabilities: Accumulated Deferred Income Taxes 806,270 781,559 Regulatory Liabilities 417,442 394,982 Other Long-Term Liabilities 46,669 43,859 Total Deferred Credits and Other Liabilities 1,270,381 1,220,400 Long-Term Debt 2,031,323 1,732,066 Rate Reduction Bonds 280,862 324,072 Common Stockholder's Equity: Common Stock — — Capital Surplus, Paid In 1,973,134 1,898,134 Retained Earnings 903,022 808,668 Common Stockholder's Equity 2,876,156 2,706,802 Commitments and Contingencies (Note 13) Total Liabilities and Capitalization $ 7,029,231 $ 6,641,941 The accompanying notes are an integral part of these consolidated financial statements. 87
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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, (Thousands of Dollars) 2025 2024 2023 Operating Revenues $ 1,376,351 $ 1,294,493 $ 1,447,873 Operating Expenses: Purchased Power and Transmission 280,210 244,351 604,983 Operations and Maintenance 299,170 288,342 284,442 Depreciation 168,015 154,072 140,417 Amortization of Regulatory Assets/(Liabilities), Net 68,168 136,113 (16,343) Energy Efficiency Programs 46,214 42,871 39,618 Taxes Other Than Income Taxes 106,102 96,969 93,894 Total Operating Expenses 967,879 962,718 1,147,011 Operating Income 408,472 331,775 300,862 Interest Expense 89,960 77,770 72,786 Other Income, Net 42,988 31,123 26,597 Income Before Income Tax Expense 361,500 285,128 254,673 Income Tax Expense 92,146 70,245 59,014 Net Income $ 269,354 $ 214,883 $ 195,659 The accompanying notes are an integral part of these consolidated financial statements. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, (Thousands of Dollars) 2025 2024 2023 Net Income $ 269,354 $ 214,883 $ 195,659 Other Comprehensive Income, Net of Tax: Changes in Unrealized Gains on Marketable Securities — — 73 Other Comprehensive Income, Net of Tax — — 73 Comprehensive Income $ 269,354 $ 214,883 $ 195,732 The accompanying notes are an integral part of these consolidated financial statements. 88
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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY Common Stock CapitalSurplus,Paid In RetainedEarnings AccumulatedOtherComprehensive(Loss)/Income TotalCommonStockholder'sEquity(Thousands of Dollars, Except Stock Information) Stock Amount Balance as of January 1, 2023 301 $ — $ 1,298,134 $ 572,126 $ (73) $ 1,870,187 Net Income 195,659 195,659 Dividends on Common Stock (112,000) (112,000) Capital Contributions from Eversource Parent 400,000 400,000 Other Comprehensive Income 73 73 Balance as of December 31, 2023 301 — 1,698,134 655,785 — 2,353,919 Net Income 214,883 214,883 Dividends on Common Stock (62,000) (62,000) Capital Contributions from Eversource Parent 200,000 200,000 Balance as of December 31, 2024 301 — 1,898,134 808,668 — 2,706,802 Net Income 269,354 269,354 Dividends on Common Stock (175,000) (175,000) Capital Contributions from Eversource Parent 75,000 75,000 Balance as of December 31, 2025 301 $ — $ 1,973,134 $ 903,022 $ — $ 2,876,156 The accompanying notes are an integral part of these consolidated financial statements. 89
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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, (Thousands of Dollars) 2025 2024 2023 Operating Activities: Net Income $ 269,354 $ 214,883 $ 195,659 Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities: Depreciation 168,015 154,072 140,417 Deferred Income Taxes 11,291 77,082 118,970 Uncollectible Expense 11,973 4,688 3,989 Pension, SERP and PBOP Income, Net (8,915) (8,759) (10,484) Regulatory Over/(Under) Recoveries, Net 10,952 (227,943) (273,472) Amortization of Regulatory Assets/(Liabilities), Net 68,168 136,113 (16,343) Cost of Removal Expenditures (27,030) (42,507) (39,976) Other (1,383) 53 10,391 Changes in Current Assets and Liabilities: Receivables and Unbilled Revenues, Net (42,787) (29,875) (5,434) Taxes Receivable/Accrued, Net (1,000) 30,443 916 Accounts Payable (2,043) (7,204) (55,957) Other Current Assets and Liabilities, Net 26,703 20,255 (36,637) Net Cash Flows Provided by Operating Activities 483,298 321,301 32,039 Investing Activities: Investments in Property, Plant and Equipment (537,771) (608,812) (605,109) Other Investing Activities — — 296 Net Cash Flows Used in Investing Activities (537,771) (608,812) (604,813) Financing Activities: Cash Dividends on Common Stock (175,000) (62,000) (112,000) (Decrease)/Increase in Notes Payable to Eversource Parent (81,800) (101,900) 59,700 Issuance of Long-Term Debt 300,000 300,000 600,000 Retirement of Long-Term Debt — — (325,000) Repayment of Rate Reduction Bonds (43,210) (43,210) (43,210) Capital Contributions from Eversource Parent 75,000 200,000 400,000 Other Financing Activities (2,574) (3,140) (8,524) Net Cash Flows Provided by Financing Activities 72,416 289,750 570,966 Net Increase/(Decrease) in Cash and Restricted Cash 17,943 2,239 (1,808) Cash and Restricted Cash - Beginning of Year 37,243 35,004 36,812 Cash and Restricted Cash - End of Year $ 55,186 $ 37,243 $ 35,004 The accompanying notes are an integral part of these consolidated financial statements. 90
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EVERSOURCE ENERGY AND SUBSIDIARIES THE CONNECTICUT LIGHT AND POWER COMPANY NSTAR ELECTRIC COMPANY AND SUBSIDIARY PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES COMBINED NOTES TO FINANCIAL STATEMENTS Refer to the Glossary of Terms included in this combined Annual Report on Form 10-K for abbreviations and acronyms used throughout the combined notes to the financial statements. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. About Eversource, CL&P, NSTAR Electric and PSNH Eversource Energy is a public utility holding company primarily engaged, through its wholly-owned regulated utility subsidiaries, in the energy delivery business. Eversource Energy's wholly-owned regulated utility subsidiaries consist of CL&P, NSTAR Electric and PSNH (electric utilities), Yankee Gas, NSTAR Gas and EGMA (natural gas utilities), and Aquarion (water utilities). Eversource provides energy delivery and/or water service to approximately 4.6 million electric, natural gas and water customers through twelve regulated utilities in Connecticut, Massachusetts and New Hampshire. Eversource, CL&P, NSTAR Electric and PSNH are reporting companies under the Securities Exchange Act of 1934. Eversource Energy is a public utility holding company under the Public Utility Holding Company Act of 2005. Arrangements among the regulated electric companies and other Eversource companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the FERC. Eversource's regulated companies are subject to regulation of rates, accounting and other matters by the FERC and/or applicable state regulatory commissions (the PURA for CL&P, Yankee Gas and Aquarion, the DPU for NSTAR Electric, NSTAR Gas, EGMA and Aquarion, and the NHPUC for PSNH and Aquarion). CL&P, NSTAR Electric and PSNH furnish franchised retail electric service in Connecticut, Massachusetts and New Hampshire, respectively. NSTAR Gas and EGMA are engaged in the distribution and sale of natural gas to customers within Massachusetts and Yankee Gas is engaged in the distribution and sale of natural gas to customers within Connecticut. Aquarion is engaged in the collection, treatment and distribution of water in Connecticut, Massachusetts and New Hampshire. CL&P, NSTAR Electric and PSNH's results include the operations of their respective distribution and transmission businesses. The distribution business also includes the results of NSTAR Electric's solar power facilities. Eversource Service, Eversource's service company, and several wholly-owned real estate subsidiaries of Eversource, provide support services to Eversource, including its regulated companies. B. Basis of Presentation The consolidated financial statements of Eversource, NSTAR Electric and PSNH include the accounts of each of their respective subsidiaries. Intercompany transactions have been eliminated in consolidation. The accompanying consolidated financial statements of Eversource, NSTAR Electric and PSNH and the financial statements of CL&P are herein collectively referred to as the "financial statements." The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. CYAPC and YAEC are inactive regional nuclear power companies engaged in the long-term storage of their spent nuclear fuel. Eversource consolidates the operations of CYAPC and YAEC because CL&P's, NSTAR Electric's and PSNH's combined ownership and voting interests in each of these entities is greater than 50 percent. Intercompany transactions between CL&P, NSTAR Electric, PSNH and the CYAPC and YAEC companies have been eliminated in consolidation of the Eversource financial statements. Eversource holds equity ownership interests that are not consolidated and are accounted for under the equity method. During 2024, Eversource sold its 50 percent ownership interests in three offshore wind projects that had been accounted for under the equity method. See Note 6, “Investments in Unconsolidated Affiliates,” for further information. In accordance with accounting guidance on noncontrolling interests in consolidated financial statements, the Preferred Stock of CL&P and the Preferred Stock of NSTAR Electric, which are not owned by Eversource or its consolidated subsidiaries and are not subject to mandatory redemption, have been presented as noncontrolling interests in the financial statements of Eversource. The Preferred Stock of CL&P and the Preferred Stock of NSTAR Electric are considered to be temporary equity and have been classified between liabilities and permanent shareholders' equity on the balance sheets of Eversource, CL&P and NSTAR Electric due to a provision in the preferred stock agreements of both CL&P and NSTAR Electric that grant preferred stockholders the right to elect a majority of the CL&P and NSTAR Electric Boards of Directors, respectively, should certain conditions exist, such as if preferred dividends are in arrears for a specified amount of time. The Net Income reported in the statements of income and cash flows represents net income prior to apportionment to noncontrolling interests, which is represented by dividends on preferred stock of CL&P and NSTAR Electric. 91
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Eversource's utility subsidiaries' electric, natural gas and water distribution and transmission businesses are subject to rate-regulation that is based on cost recovery and meets the criteria for application of accounting guidance for entities with rate-regulated operations, which considers the effect of regulation on the differences in the timing of the recognition of certain revenues and expenses from those of other businesses and industries. See Note 2, "Regulatory Accounting," for further information. As of December 31, 2025 and 2024, Eversource's carrying amount of goodwill was $4.23 billion and $3.57 billion, respectively. Eversource performs an assessment for possible impairment of its goodwill at least annually and determined that no impairment existed in 2025. Eversource recorded a goodwill impairment charge of $297 million in the fourth quarter of 2024 as a result of the likely sale of Aquarion at a loss. As of December 31, 2024, the assets and liabilities of the Aquarion water distribution business, including remaining goodwill of $662.5 million, met the criteria to be classified as held for sale. Unless otherwise specified, the amounts and information in the notes presented as of and for the year ended December 31, 2024 did not include assets and liabilities that were classified as held for sale. As of December 31, 2025, the criteria to be classified as held for sale was no longer met and Aquarion’s assets and liabilities, including goodwill, were reclassified as held and used on the Eversource balance sheet as of December 31, 2025. See Note 24, "Assets Held for Sale," and Note 25, "Goodwill," for further information. Certain reclassifications of prior year data were made in the accompanying financial statements to conform to the current year presentation. C. Accounting Standards Accounting Standards Recently Adopted: On January 1, 2025, the Company retrospectively adopted Accounting Standards Update (ASU) 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which requires entities to disclose significant segment expenses, other segment items, and the title and position of the chief operating decision maker (CODM). Additionally, the ASU requires entities to disclose how the CODM assesses segment performance and allocates resources, among certain other required disclosures. Furthermore, disclosures are required in interim periods. The modified disclosures are included in Note 23, “Segment Information.” On January 1, 2026, the Company prospectively adopted ASU 2023-09, Income Taxes (Topic 740) - Improvements to Income Tax Disclosures, which requires enhanced income tax disclosures, primarily requiring consistent categories and greater detailed disclosure information in the tax rate reconciliation as well as income taxes paid disaggregated by jurisdiction. The modified disclosures are included in Note 12, “Income Taxes.” Accounting Standards Issued but Not Yet Adopted: In September 2025, the Financial Accounting Standards Board issued ASU 2025-06, Intangibles — Goodwill and Other — Internal-Use Software (Subtopic 350-40) - Targeted Improvements to the Accounting for Internal-Use Software, to modernize and clarify the accounting for software costs. The ASU’s provisions change the criteria for capitalization of software development costs by eliminating consideration of “project development stages” and instead requiring consideration of the probability of software project completion for its intended use. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2027, with early adoption permitted. Entities are permitted to apply one of three transition approaches: prospective, modified transition that is based on the status of the project and whether software costs were capitalized before the date of adoption, or retrospective. Eversource is currently reviewing the requirements of ASU 2025-06. D. Cash Cash includes cash on hand. At the end of each reporting period, any overdraft amounts are reclassified from Cash to Accounts Payable on the balance sheets. E. Allowance for Uncollectible Accounts Receivables, Net on the balance sheets primarily includes trade receivables from retail customers and customers related to wholesale transmission contracts, wholesale market sales, sales of RECs, and property rentals. Receivables, Net also includes customer receivables for the purchase of electricity from a competitive third-party supplier, the current portion of customer energy efficiency loans, property damage receivables and other miscellaneous receivables. There is no material concentration of receivables. Receivables are recorded at amortized cost, net of a credit loss provision (or allowance for uncollectible accounts). The current expected credit loss (CECL) model is applied to receivables for purposes of calculating the allowance for uncollectible accounts. This model is based on expected losses and results in the recognition of estimated expected credit losses, including uncollectible amounts for both billed and unbilled revenues, over the life of the receivable at the time a receivable is recorded. The allowance for uncollectible accounts is determined based upon various judgments and factors, including an aging-based quantitative assessment that applies an estimated uncollectible percentage to each receivable aging category. Factors in determining credit loss include historical collection, write-off experience, analysis of delinquency statistics, and management's assessment of collectability from customers, including current economic conditions, customer payment trends, the impact on customer bills because of energy usage trends and changes in rates, flexible payment plans and financial hardship arrearage management programs offered to customers, reasonable forecasts, and expectations of future collectability and collection efforts. Management continuously assesses the collectability of receivables and adjusts estimates based on actual experience and future expectations based on economic conditions, collection efforts and other factors. Management also monitors the aging analysis of receivables to determine if there are changes in the collections of accounts receivable. Receivable balances are written off against the allowance for uncollectible accounts when the customer accounts are no longer in service and these balances are deemed to be uncollectible. Management concluded that the reserve balance as of December 31, 2025 adequately reflected the collection risk and net realizable value for its receivables. The PURA allows CL&P and Yankee Gas to accelerate the recovery of accounts receivable balances attributable to qualified customers under financial or medical duress (uncollectible hardship accounts receivable) outstanding for greater than 180 days and 90 days, respectively. The DPU allows NSTAR Electric, NSTAR Gas and EGMA to recover in rates amounts associated with certain uncollectible hardship accounts receivable. 92
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These uncollectible hardship customer account balances are included in Regulatory Assets or Other Long-Term Assets on the balance sheets. Hardship customers are protected from shut off in certain circumstances, and historical collection experience has reflected a higher default risk as compared to the rest of the receivable population. Management uses a higher credit risk profile for this pool of trade receivables as compared to non-hardship receivables. The allowance for uncollectible hardship accounts is included in the total uncollectible allowance balance. The total allowance for uncollectible accounts is included in Receivables, Net on the balance sheets. The activity in the allowance for uncollectible accounts by portfolio segment is as follows: Eversource CL&P NSTAR Electric PSNH (Millions of Dollars) Hardship Accounts Retail (Non-Hardship),Wholesale, and Other Total Allowance Hardship Accounts Retail (Non-Hardship),Wholesale, and Other Total Allowance Hardship Accounts Retail (Non-Hardship),Wholesale, and Other Total Allowance Total Allowance Balance as of January 1, 2023 $ 284.4 $ 201.9 $ 486.3 $ 188.9 $ 36.4 $ 225.3 $ 43.7 $ 51.3 $ 95.0 $ 29.2 Uncollectible Expense — 72.5 72.5 — 11.7 11.7 — 22.8 22.8 4.0 Uncollectible Costs Deferred 137.0 21.2 158.2 114.4 12.0 126.4 1.5 16.0 17.5 (8.7) Write-Offs (55.9) (122.2) (178.1) (44.7) (28.5) (73.2) (1.6) (41.7) (43.3) (10.9) Recoveries Collected 1.3 14.3 15.6 1.1 4.7 5.8 — 5.0 5.0 0.7 Balance as of December 31,2023 $ 366.8 $ 187.7 $ 554.5 $ 259.7 $ 36.3 $ 296.0 $ 43.6 $ 53.4 $ 97.0 $ 14.3 Uncollectible Expense — 74.1 74.1 — 17.2 17.2 — 33.6 33.6 4.7 Uncollectible Costs Deferred 71.4 48.3 119.7 35.5 11.3 46.8 16.2 21.5 37.7 5.1 Write-Offs (74.3) (129.5) (203.8) (55.1) (30.9) (86.0) (4.6) (52.4) (57.0) (10.9) Recoveries Collected 0.7 13.3 14.0 0.6 4.5 5.1 — 3.6 3.6 0.9 Reclassified as Held for Sale — (2.3) (2.3) — — — — — — — Balance as of December 31,2024 $ 364.6 $ 191.6 $ 556.2 $ 240.7 $ 38.4 $ 279.1 $ 55.2 $ 59.7 $ 114.9 $ 14.1 Uncollectible Expense — 101.1 101.1 — 17.9 17.9 — 41.4 41.4 12.0 Uncollectible Costs Deferred 62.4 57.6 120.0 32.0 11.1 43.1 8.3 28.8 37.1 7.2 Write-Offs (61.9) (154.2) (216.1) (48.5) (39.1) (87.6) (2.9) (63.7) (66.6) (10.5) Recoveries Collected 2.1 14.9 17.0 1.5 4.5 6.0 0.1 5.7 5.8 0.7 Reclassified from Held for Sale — 2.3 2.3 — — — — — — — Balance as of December 31,2025 $ 367.2 $ 213.3 $ 580.5 $ 225.7 $ 32.8 $ 258.5 $ 60.7 $ 71.9 $ 132.6 $ 23.5 These expected credit losses are deferred as regulatory costs on the balance sheets, as these amounts are ultimately recovered in rates. Amounts include uncollectible costs for hardship accounts and other customer receivables, including uncollectible amounts related to uncollectible energy supply costs. As of December 31, 2025 and 2023, the allowance for uncollectible accounts attributable to the Aquarion water distribution business are recorded within Receivables, Net on the Eversource balance sheet. As of December 31, 2024, this balance was classified as Assets Held for Sale on the Eversource balance sheet. For further information, see Note 24, “Assets Held for Sale.” In connection with PSNH’s pole purchase agreement on May 1, 2023, the purchase price included the forgiveness of previously reserved receivables for reimbursement of operation and maintenance and vegetation management costs. F. Transfer of Energy Efficiency Loans CL&P transferred a portion of its energy efficiency customer loan portfolio to outside lenders in order to make additional loans to customers. CL&P remains the servicer of the loans and will transmit customer payments to the lenders, with a maximum amount outstanding under this program of $50 million as of December 31, 2025 and $70 million as of December 31, 2024. The amounts of the loans are included in Receivables, Net and Other Long- Term Assets, and are offset by Other Current Liabilities and Other Long-Term Liabilities on CL&P’s balance sheet. The current and long-term portions totaled $8.9 million and $21.8 million, respectively, as of December 31, 2025, and $9.4 million and $17.3 million, respectively, as of December 31, 2024. (3) (1) (1) (2) (1) (2) (1) (2) (3) 93
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G. Materials, Supplies, Natural Gas and REC Inventory Materials, Supplies, Natural Gas and REC Inventory include materials and supplies purchased primarily for construction or operation and maintenance purposes, natural gas purchased for delivery to customers, and RECs. Inventory is valued at the lower of cost or net realizable value. RECs are purchased from suppliers of renewable sources of generation and are used to meet state mandated Renewable Portfolio Standards requirements. The carrying amounts of materials and supplies, natural gas inventory, and RECs, which are included in Current Assets on the balance sheets, were as follows: As of December 31, 2025 2024 (Millions of Dollars) Eversource CL&P NSTARElectric PSNH Eversource CL&P NSTARElectric PSNH Materials and Supplies $ 400.7 $ 133.9 $ 172.8 $ 55.8 $ 498.6 $ 217.3 $ 177.8 $ 72.1 Natural Gas 49.7 — — — 49.5 — — — RECs 41.2 — 38.1 ` 3.1 46.5 — 42.8 3.7 Total $ 491.6 $ 133.9 $ 210.9 $ 58.9 $ 594.6 $ 217.3 $ 220.6 $ 75.8 As of December 31, 2024, the materials and supplies attributable to the Aquarion water distribution business were classified as Assets Held for Sale on the Eversource balance sheet. As of December 31, 2025, these assets were reclassified as materials and supplies on the Eversource balance sheet. For further information, see Note 24, “Assets Held for Sale.” H. Fair Value Measurements Fair value measurement guidance is applied to derivative contracts that are not elected or designated as "normal purchases" or "normal sales" (normal) and to marketable securities held in trusts. Fair value measurement guidance is also applied to valuations of the investments used to calculate the funded status of pension and PBOP plans, the nonrecurring fair value measurements of nonfinancial assets such as goodwill, long-lived assets, equity method investments, AROs, and in the valuation of business combinations and asset acquisitions. The fair value measurement guidance was also applied in estimating the fair value of preferred stock, long-term debt and RRBs. Fair Value Hierarchy: In measuring fair value, Eversource uses observable market data when available in order to minimize the use of unobservable inputs. Inputs used in fair value measurements are categorized into three fair value hierarchy levels for disclosure purposes. The entire fair value measurement is categorized based on the lowest level of input that is significant to the fair value measurement. Eversource evaluates the classification of assets and liabilities measured at fair value on a quarterly basis. The levels of the fair value hierarchy are described below: Level 1 - Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 - Inputs are quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs are observable. Level 3 - Quoted market prices are not available. Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable. Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products. Uncategorized - Investments that are measured at net asset value are not categorized within the fair value hierarchy. Determination of Fair Value: The valuation techniques and inputs used in Eversource's fair value measurements are described in Note 4, "Derivative Instruments," Note 5, "Marketable Securities," Note 6, "Investments in Unconsolidated Affiliates," Note 7, "Asset Retirement Obligations," Note 11A, "Employee Benefits – Pension Benefits and Postretirement Benefits Other Than Pension," Note 15, "Fair Value of Financial Instruments," and Note 25, “Goodwill,” to the financial statements. I. Derivative Accounting The electric and natural gas companies enter into contracts to purchase and procure energy and energy-related products for their customers, the costs of which are recoverable from customers in future rates. The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative. Many of the electric and natural gas companies' contracts for the purchase and sale of energy or energy-related products for delivery to customers in the normal course of business are derivatives that are designated as “normal purchases” or “normal sales” and follow accrual accounting. If a contract is a derivative and the energy is settled in the energy market rather than delivered to customers, it is recorded at fair value on the balance sheet. The application of derivative accounting is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, election and designation of a contract as normal, and determination of the fair value of derivative contracts. All of these judgments can have a significant impact on the financial statements. The judgment applied in the election of a contract as normal (and resulting accrual accounting) includes the conclusion that it is probable at the inception of the contract and throughout its term that it will result in physical delivery of the underlying product and that the quantities will be used or sold by the business in the normal course of business. If facts and 94
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circumstances change and management can no longer support this conclusion, then a contract cannot be considered normal, accrual accounting is terminated, and fair value accounting is applied prospectively. The fair value of derivative contracts is based upon the contract terms and conditions and the underlying market price or fair value per unit. When quantities are not specified in the contract, the Company determines whether the contract has a determinable quantity by using amounts referenced in default provisions and other relevant sections of the contract. The fair values of derivative contracts are estimated based on the best market information available, including valuation models that estimate future energy and energy-related prices. Fair value estimates involve assumptions, uncertainties and matters of judgment. The fair value of derivative assets and liabilities with the same counterparty are offset and recorded as a net derivative asset or liability on the balance sheets. Regulatory assets or regulatory liabilities are recorded to offset the fair values of these derivative contracts related to energy and energy-related products, as contract settlements are recovered from, or refunded to, customers in future rates. All changes in the fair value of these derivative contracts are recorded as regulatory assets or liabilities on the balance sheets and do not impact net income. For further information regarding derivative contracts, see Note 4, "Derivative Instruments," to the financial statements. J. Operating Expenses The cost of natural gas included in Purchased Power, Purchased Natural Gas and Transmission on the statements of income was as follows: For the Years Ended December 31, (Millions of Dollars) 2025 2024 2023 Eversource - Cost of Natural Gas $ 857.0 $ 689.6 $ 792.2 K. Allowance for Funds Used During Construction AFUDC represents the cost of borrowed and equity funds used to finance construction and is included in the cost of the electric, natural gas and water companies' utility plant on the balance sheet. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of Interest Expense, and the AFUDC related to equity funds is recorded as Other Income, Net on the statements of income. AFUDC costs are recovered from customers over the service life of the related plant in the form of increased revenue collected as a result of higher depreciation expense. The average AFUDC rate is based on a FERC-prescribed formula using the cost of a company's short-term financings and capitalization (preferred stock, long-term debt and common equity), as appropriate. The average rate is applied to average eligible CWIP amounts to calculate AFUDC. As part of the annual FERC Transmission Formula Rate protocols process, the AFUDC calculation methodology utilized in formula transmission rates was updated effective January 1, 2025. This calculation methodology resulted in an adjustment to the AFUDC equity and AFUDC debt amounts recognized on the statement of income in the third quarter of 2025 in accordance with the AFUDC policy. AFUDC costs and the weighted-average AFUDC rates were as follows: Eversource For the Years Ended December 31, (Millions of Dollars, except percentages) 2025 2024 2023 Borrowed Funds $ 64.1 $ 64.4 $ 44.6 Equity Funds 99.0 97.8 78.1 Total AFUDC $ 163.1 $ 162.2 $ 122.7 Average AFUDC Rate 6.4 % 6.5 % 5.8 % For the Years Ended December 31, 2025 2024 2023 (Millions of Dollars, except percentages) CL&P NSTARElectric PSNH CL&P NSTARElectric PSNH CL&P NSTARElectric PSNH Borrowed Funds $ 14.5 $ 28.9 $ 5.7 $ 8.1 $ 27.2 $ 8.9 $ 7.7 $ 17.2 $ 6.1 Equity Funds 12.2 58.4 13.0 22.4 58.8 7.0 20.0 45.7 5.4 Total AFUDC $ 26.7 $ 87.3 $ 18.7 $ 30.5 $ 86.0 $ 15.9 $ 27.7 $ 62.9 $ 11.5 Average AFUDC Rate 6.0 % 6.7 % 7.3 % 6.7 % 7.0 % 5.5 % 6.7 % 5.9 % 5.1 % 95
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L. Other Income, Net The components of Other Income, Net on the statements of income were as follows: Eversource For the Years Ended December 31, (Millions of Dollars) 2025 2024 2023 Pension, SERP and PBOP Non-Service Income Components, Net of Deferred Portion $ 139.3 $ 115.4 $ 132.9 AFUDC Equity 99.0 97.8 78.1 Equity in Earnings of Unconsolidated Affiliates 19.9 51.9 15.5 Investment (Loss)/Income (5.4) 0.6 (4.9) Interest Income 125.5 138.2 94.2 Other 0.6 6.6 32.3 Total Other Income, Net $ 378.9 $ 410.5 $ 348.1 For the Years Ended December 31, 2025 2024 2023 (Millions of Dollars) CL&P NSTARElectric PSNH CL&P NSTARElectric PSNH CL&P NSTARElectric PSNH Pension, SERP and PBOP Non-Service IncomeComponents, Net of Deferred Portion $ 36.2 $ 61.4 $ 17.6 $ 28.2 $ 52.8 $ 14.9 $ 34.9 $ 57.4 $ 16.2 AFUDC Equity 12.2 58.4 13.0 22.4 58.8 7.0 20.0 45.7 5.4 Investment (Loss)/Income (1.7) (1.6) (0.7) (1.4) 1.9 (0.5) (2.4) (0.2) (0.7) Interest Income 12.9 72.7 13.0 28.3 77.0 9.6 9.0 60.6 5.3 Other 0.1 1.7 0.1 0.1 0.9 0.1 0.1 0.6 0.4 Total Other Income, Net $ 59.7 $ 192.6 $ 43.0 $ 77.6 $ 191.4 $ 31.1 $ 61.6 $ 164.1 $ 26.6 See Note 11A, "Employee Benefits – Pension Benefits and Postretirement Benefits Other Than Pension," for the components of net periodic benefit income/expense for the Pension, SERP and PBOP Plans. The non-service related components of pension, SERP and PBOP benefit income/expense, after capitalization or deferral, are presented as non-operating income and recorded in Other Income, Net on the statements of income. Equity in Earnings of Unconsolidated Affiliates includes $23.4 million of pre-tax income recorded at Eversource in the second quarter of 2024 from Eversource’s previously-held wind equity method investment, North East Offshore, as a result of a vendor settlement agreement payment received by the joint venture. In the third quarter of 2024, Eversource sold its equity method investments in three offshore wind projects. In March 2023, Eversource’s equity method investment in a renewable energy fund was liquidated. Liquidation proceeds in excess of the carrying value were recorded in 2023 within Other in the table above. See Note 6, “Investments in Unconsolidated Affiliates,” for further information on the 2024 sales of the offshore wind investments and the 2023 liquidation of the renewable energy fund. M. Other Taxes Eversource's companies that serve customers in Connecticut collect gross receipts taxes levied by the state of Connecticut from their customers. These gross receipts taxes are recorded separately with collections in Operating Revenues and with payments in Taxes Other Than Income Taxes on the statements of income as follows: For the Years Ended December 31, (Millions of Dollars) 2025 2024 2023 Eversource $ 232.4 $ 209.4 $ 202.9 CL&P 203.8 185.1 174.9 As agents for state and local governments, Eversource's companies that serve customers in Connecticut and Massachusetts collect certain sales taxes that are recorded on a net basis with no impact on the statements of income. (1) (2) (2) (1) (1) (2) 96
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N. Supplemental Cash Flow Information Eversource(Millions of Dollars) As of and For the Years Ended December 31, 2025 2024 2023 Cash Paid During the Year for: Interest, Net of Amounts Capitalized $ 1,182.6 $ 1,014.4 $ 783.2 Non-Cash Investing Activities: Plant Additions Included in Accounts Payable (As of) 508.2 472.5 564.1 As of and For the Years Ended December 31, 2025 2024 2023 (Millions of Dollars) CL&P NSTARElectric PSNH CL&P NSTARElectric PSNH CL&P NSTARElectric PSNH Cash Paid During the Year for: Interest, Net of Amounts Capitalized $ 208.4 $ 232.4 $ 83.9 $ 216.8 $ 215.1 $ 78.4 $ 176.8 $ 182.8 $ 62.8 Non-Cash Investing Activities: Plant Additions Included in Accounts Payable (As of) 143.2 160.5 59.2 95.8 155.4 77.7 139.8 178.9 65.9 The following table reconciles cash as reported on the balance sheets to the cash and restricted cash balance as reported on the statements of cash flows: As of December 31, 2025 2024 (Millions of Dollars) Eversource CL&P NSTARElectric PSNH Eversource CL&P NSTARElectric PSNH Cash as reported on the Balance Sheets $ 135.4 $ 87.6 $ 8.3 $ 13.7 $ 26.7 $ 1.1 $ 0.9 $ 1.4 Restricted cash included in: Special Deposits 93.6 1.1 17.6 38.3 75.8 1.0 8.1 32.7 Assets Held for Sale, Current — — — — 5.8 — — — Marketable Securities 14.0 — — — 10.0 — — — Other Long-Term Assets 3.2 — — 3.2 9.0 — — 3.1 Cash and Restricted Cash as reported on the Statements of Cash Flows $ 246.2 $ 88.7 $ 25.9 $ 55.2 $ 127.3 $ 2.1 $ 9.0 $ 37.2 Special Deposits represent cash collections related to the PSNH RRB customer charges that are held in trust, required ISO-NE cash deposits, cash held in escrow accounts, and CYAPC and YAEC cash balances. Special Deposits are included in Current Assets on the balance sheets. Restricted cash included in Marketable Securities represents money market funds held in restricted trusts to fund CYAPC and YAEC's spent nuclear fuel storage obligations. Eversource’s restricted cash also includes an Energy Relief Fund for energy efficiency and clean energy measures in the Merrimack Valley established under the terms of an EGMA 2020 settlement agreement. This restricted cash held in escrow accounts included $21.4 million and $20.0 million recorded as short-term in Special Deposits as of December 31, 2025 and December 31, 2024, respectively and $5.9 million recorded in Other Long-Term Assets on the balance sheets as of December 31, 2024. O. Related Parties Eversource Service, Eversource's service company, provides centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, tax, and other services to Eversource's companies. The Rocky River Realty Company and Properties, Inc., two other Eversource subsidiaries, construct, acquire or lease some of the property and facilities used by Eversource's companies. Included in the CL&P, NSTAR Electric and PSNH balance sheets as of December 31, 2025 and 2024 were Accounts Receivable from Affiliated Companies and Accounts Payable to Affiliated Companies relating to transactions between CL&P, NSTAR Electric and PSNH and other subsidiaries that are wholly-owned by Eversource. These amounts have been eliminated in consolidation on the Eversource financial statements. Included in the PSNH balance sheets as of December 31, 2025 and 2024 and the CL&P balance sheet as of December 31, 2024 were Notes Payable to Eversource Parent. These amounts have been eliminated in consolidation on the Eversource financial statements. See Note 8, “Short-Term Debt” for intercompany borrowing amounts. The Eversource Energy Foundation is an independent not-for-profit charitable entity and is not included in the consolidated financial statements of Eversource as the Company does not have title to, and cannot receive contributions back from, the Eversource Energy Foundation's assets. Eversource made contributions to the Eversource Energy Foundation of $7.0 million in 2025, and $20.0 million in 2023. Eversource did not make any contributions in 2024. 97
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2. REGULATORY ACCOUNTING Eversource's utility companies are subject to rate regulation that is based on cost recovery and meets the criteria for application of accounting guidance for rate-regulated operations, which considers the effect of regulation on the timing of the recognition of certain revenues and expenses. The regulated companies' financial statements reflect the effects of the rate-making process. The rates charged to the customers of Eversource's regulated companies are designed to collect each company's costs to provide service, including a return on investment. The application of accounting guidance for rate-regulated enterprises results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. Regulatory liabilities represent either revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers. Management believes it is probable that each of the regulated companies will recover its respective investments in long-lived assets and the regulatory assets that have been recorded. If management were to determine that it could no longer apply the accounting guidance applicable to rate-regulated enterprises, or if management could not conclude it is probable that costs would be recovered from customers in future rates, the applicable costs would be charged to net income in the period in which the determination is made. Regulatory Assets: The components of regulatory assets were as follows: As of December 31, 2025 2024 (Millions of Dollars) Eversource CL&P NSTARElectric PSNH Eversource CL&P NSTARElectric PSNH Storm Costs, Net $ 1,959.3 $ 991.3 $ 499.6 $ 468.4 $ 2,039.4 $ 971.1 $ 609.8 $ 458.5 Regulatory Tracking Mechanisms 1,573.8 206.5 705.6 93.2 1,781.6 507.7 650.0 162.8 Income Taxes, Net 1,044.5 546.1 161.5 23.3 968.4 521.0 145.4 20.7 Benefit Costs 992.8 173.7 300.0 61.7 967.4 168.8 293.6 65.6 Derivative Contracts 753.2 0.1 753.1 — 57.2 57.2 — — Securitized Stranded Costs 306.1 — — 306.1 349.3 — — 349.3 Cost of Removal 262.5 — 8.1 — 198.4 — 8.5 — Goodwill-related 230.4 — 197.8 — 247.2 — 212.3 — Asset Retirement Obligations 162.8 44.2 84.6 5.4 150.2 41.2 78.3 5.1 Environmental Remediation Costs 136.1 — — — 116.2 — — — EGMA Acquisition and Integration Costs 82.3 — — — — — — — Other Regulatory Assets 189.9 19.5 92.0 3.0 195.4 58.5 109.2 3.7 Total Regulatory Assets 7,693.7 1,981.4 2,802.3 961.1 7,070.7 2,325.5 2,107.1 1,065.7 Less: Current Portion 1,975.1 265.2 978.8 119.9 2,189.7 638.5 902.8 173.3 Total Long-Term Regulatory Assets $ 5,718.6 $ 1,716.2 $ 1,823.5 $ 841.2 $ 4,881.0 $ 1,687.0 $ 1,204.3 $ 892.4 As of December 31, 2024, the Regulatory Assets attributable to the Aquarion water distribution business were classified as Assets Held for Sale on the Eversource balance sheet. As of December 31, 2025, these assets were reclassified as Regulatory Assets on the Eversource balance sheet. For further information, see Note 24, “Assets Held for Sale.” Storm Costs, Net: The storm cost deferrals relate to costs incurred for storm events at CL&P, NSTAR Electric and PSNH that each company expects to recover from customers. A storm must meet certain criteria to qualify for deferral and recovery with the criteria specific to each state jurisdiction and utility company. Once a storm qualifies for recovery, all qualifying expenses incurred during storm restoration efforts are deferred and recovered from customers. Costs for storms that do not meet the specific criteria are expensed as incurred. In addition to storm restoration costs, CL&P and PSNH are each allowed to recover pre-staging storm costs. Management believes storm costs deferred were prudently incurred and meet the criteria for specific cost recovery in Connecticut, Massachusetts and New Hampshire, and that recovery from customers is probable through the applicable regulatory recovery processes. For CL&P, under the current regulatory construct, the unamortized regulatory asset balance earns a return once authorized for recovery in rates. NSTAR Electric recovers a carrying charge on its deferred storm cost regulatory asset balance. PSNH earns a return on the regulatory asset balance. Multiple tropical and severe storms over the past several years have caused extensive damage to Eversource’s electric distribution systems resulting in significant numbers and durations of customer outages, along with significant pre-staging costs. Storms in 2025 that qualified for future recovery resulted in deferred storm restoration costs and pre-staging costs totaling $129 million at Eversource, including $82 million at CL&P, $25 million at NSTAR Electric, and $22 million at PSNH. Management believes that all of these storm costs were prudently incurred and meet the criteria for specific cost recovery. Of Eversource’s total deferred storm costs, $2.06 billion either have yet to be filed with the applicable regulatory commission, are pending regulatory approval, or are subject to prudency review (including $1.19 billion at CL&P, $409 million at NSTAR Electric and $456 million at PSNH) as of December 31, 2025. These storm cost totals exclude storm funding amounts that are collected in rates, which are recorded as a reduction to the deferred storm cost regulatory asset balance. CL&P, NSTAR Electric and PSNH are seeking approval of their deferred storm restoration costs through the applicable regulatory recovery process. 98
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CL&P Storm Filings: On March 28, 2024, PURA established a prudency review proceeding for the purpose of receiving and reviewing evidence of the costs reported by CL&P in response to catastrophic storms and pre-staging events totaling approximately $634 million that occurred between January 1, 2018 and December 31, 2021. On December 31, 2024, CL&P filed a supplement to its March 2024 prudency review application to request that PURA evaluate the prudence of its costs for nine additional catastrophic storms and two additional pre-staging events for the period January 1, 2022 through January 31, 2023 totaling approximately $173 million. On July 10, 2025, CL&P filed a second supplement to its March 2024 prudency review application to request that PURA evaluate the prudence of its costs for ten additional catastrophic storms for the period February 1, 2023 through December 31, 2023 totaling approximately $171 million. On July 25, 2025, CL&P filed a third supplement in this application to include carrying charges calculated at the weighted average cost of capital on the deferred storm costs totaling $246 million, which reflects CL&P’s actual financing costs on the unpaid storm costs from the date the deferred storm costs first began to accrue through May 2025. These carrying charges have not been deferred on the balance sheet. On December 13, 2025, PURA opened a new proceeding for the prudency determination of CL&P’s 2018 to 2023 storm costs either by a settled or litigated process and a separate future docket will be needed to consider CL&P’s application to issue rate reduction bonds for the securitization of approved storm costs. A final decision is expected on or about July 29, 2026. Although we cannot predict the ultimate outcome of these storm proceedings, we continue to believe these deferred storm restoration costs were prudently incurred and are probable of recovery. CL&P’s storm events include the August 4, 2020 Tropical Storm Isaias, which resulted in deferred storm restoration costs of approximately $232 million at CL&P as of December 31, 2025. Although in 2021 PURA found that CL&P’s performance in its preparation for, and response to, Tropical Storm Isaias fell below applicable performance standards in certain instances, CL&P believes it presented in its 2023 storm filing credible evidence demonstrating there is no reasonably close causal connection between the alleged sub-standard performance and the storm costs incurred. While it is possible that some amount of storm costs may be disallowed by PURA, any such amount cannot be estimated at this time. CL&P continues to believe that these storm restoration costs associated with Tropical Storm Isaias were prudently incurred and meet the criteria for cost recovery. Regulatory Tracking Mechanisms: The regulated companies' approved rates are designed to recover costs incurred to provide service to customers. The regulated companies recover certain of their costs on a fully-reconciling basis through regulatory commission-approved tracking mechanisms. The differences between the costs incurred (or the rate recovery allowed) and the actual revenues are recorded as regulatory assets (for undercollections) or as regulatory liabilities (for overcollections) to be included in future customer rates each year. Carrying charges are recovered in rates on all material regulatory tracking mechanisms. The electric and natural gas distribution companies recover, on a fully reconciling basis, the costs associated with the procurement of energy and natural gas supply, state mandated energy purchase agreements and other energy-related costs, electric transmission related costs from FERC-approved transmission tariffs, energy efficiency programs, low income assistance programs, certain uncollectible accounts receivable for hardship customers, restructuring and stranded costs as a result of deregulation (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for the Massachusetts utilities, pension and PBOP benefits, net metering for distributed generation, and solar-related programs. CL&P, NSTAR Electric, Yankee Gas, NSTAR Gas, EGMA and the Aquarion Water Company of Connecticut each have a regulatory commission approved revenue decoupling mechanism. Distribution revenues are decoupled from customer sales volumes, where applicable, which breaks the relationship between sales volumes and revenues. Each company reconciles its annual base distribution rate recovery amount to the pre-established levels of baseline distribution delivery service revenues. Any difference between the allowed level of distribution revenue and the actual amount realized during a 12-month period is adjusted through rates in the following period. Income Taxes, Net: The tax effect of temporary book-tax differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income, including those differences relating to uncertain tax positions) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and accounting guidance for income taxes. Differences in income taxes between the accounting guidance and the rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets. As these assets are offset by deferred income tax liabilities, no carrying charge is collected. The amortization period of these assets varies depending on the nature and/or remaining life of the underlying assets and liabilities. For further information regarding income taxes, see Note 12, "Income Taxes," to the financial statements. Benefit Costs: Deferred benefit costs represent unrecognized actuarial losses and gains and unrecognized prior service costs and credits attributable to Eversource's Pension, SERP and PBOP Plans. The regulated companies record actuarial losses and gains and prior service costs and credits arising at the December 31st remeasurement date of the funded status of the benefit plans as a regulatory asset or regulatory liability in lieu of a charge to Accumulated Other Comprehensive Income/(Loss), reflecting ultimate recovery from customers through rates. The regulatory asset or regulatory liability is amortized with the recognition of actuarial losses and gains and prior service costs and credits to net periodic benefit expense/income over the estimated average future employee service period using the corridor approach. Regulatory accounting is also applied to the portions of Eversource's service company costs that support the regulated companies, as these amounts are also recoverable. As these regulatory assets or regulatory liabilities do not represent a cash outlay for the regulated companies, no carrying charge is recovered from customers. See Note 11A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pension," for further information on regulatory benefit plan amounts arising and amortized during the year. Eversource, CL&P, NSTAR Electric, and PSNH recover benefit costs related to their distribution and transmission operations from customers in rates as allowed by their applicable regulatory commissions. NSTAR Electric, NSTAR Gas and EGMA recover qualified pension and PBOP expenses related to their distribution operations through a rate reconciling mechanism that fully tracks the change in net pension and PBOP expenses each year. The electric transmission companies' rates provide for an annual true-up of estimated to actual costs, which include pension and PBOP expenses as allowed by FERC. 99
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Derivative Contracts: For the regulated companies, regulatory assets (for losses) or regulatory liabilities (for gains) are recorded to offset the fair value of derivative contracts used to purchase energy and energy-related products that will be recovered from or refunded to customers in future rates. These regulatory assets and liabilities are excluded from rate base and contract costs are being recovered in energy supply rates over the duration of the contracts. See Note 4, "Derivative Instruments," to the financial statements for further information on these contracts. Securitized Stranded Costs: In 2018, a subsidiary of PSNH issued $635.7 million of securitized RRBs to finance PSNH's unrecovered remaining costs associated with the divestiture of its generation assets. Securitized regulatory assets, which are not earning an equity return, are being recovered over the amortization period of the associated RRBs. The PSNH RRBs are expected to be repaid by February 1, 2033. For further information, see Note 10, "Rate Reduction Bonds and Variable Interest Entities," to the financial statements. Cost of Removal: Eversource's regulated companies currently recover amounts in rates for future costs of removal of plant assets over the lives of the assets. The estimated cost to remove utility assets from service is recognized as a component of depreciation expense, and the cumulative amount collected from customers but not yet expended is recognized as a regulatory liability. Expended removal costs that exceed amounts collected from customers are recognized as regulatory assets, as they are probable of recovery in future rates. Goodwill-related: The goodwill regulatory asset originated from a 1999 transaction, and the DPU allowed its recovery in NSTAR Electric and NSTAR Gas rates. This regulatory asset is currently being amortized and recovered from customers in rates without a carrying charge over a 40-year period, and as of December 31, 2025, there were 14 years of amortization remaining. Asset Retirement Obligations: The costs associated with the depreciation of the regulated companies' ARO assets and accretion of the ARO liabilities are recorded as regulatory assets in accordance with regulatory accounting guidance. The regulated companies' ARO assets, regulatory assets, and ARO liabilities offset and are excluded from rate base. These costs are being recovered over the life of the underlying property, plant and equipment. Environmental Remediation Costs: Recoverable costs associated with the remediation of environmental sites are recorded as regulatory assets in accordance with PURA and DPU regulation. These costs do not earn a return. For further information, see Note 13A, "Commitments and Contingencies - Environmental Matters," to the financial statements. EGMA Acquisition and Integration Costs: As part of a DPU-approved settlement agreement on December 1, 2025, acquisition-related and integration costs incurred from the October 2020 acquisition of Columbia Gas of Massachusetts (now Eversource Gas Company of Massachusetts) are allowed for recovery over a 10-year period beginning at the time EGMA’s next base distribution rate change becomes in effect. These regulatory assets are being carried with no return. Other Regulatory Assets: Other Regulatory Assets primarily include certain uncollectible accounts receivable for hardship customers, contractual obligations associated with the spent nuclear fuel storage costs of the CYAPC, YAEC and MYAPC decommissioned nuclear power facilities, removal costs incurred that exceed amounts collected from customers, electric vehicle program costs, certain exogenous property taxes and merger-related costs allowed for recovery, losses associated with the reacquisition or redemption of long-term debt, and various other items. Regulatory Costs in Other Long-Term Assets: Eversource's regulated companies had $244.2 million (including $127.1 million for CL&P, $51.0 million for NSTAR Electric and $5.4 million for PSNH) and $221.0 million (including $116.3 million for CL&P, $41.1 million for NSTAR Electric and $4.5 million for PSNH) of additional regulatory costs not yet specifically approved as of December 31, 2025 and 2024, respectively, that were included in Other Long-Term Assets on the balance sheets. These amounts will be reclassified to Regulatory Assets upon approval by the applicable regulatory agency. Based on regulatory policies or past precedent on similar costs, management believes it is probable that these costs will ultimately be approved and recovered from customers in rates. As of December 31, 2025 and 2024, these regulatory costs included $123.2 million (including $57.0 million for CL&P and $34.0 million for NSTAR Electric) and $92.5 million (including $47.2 million for CL&P and $24.4 million for NSTAR Electric), respectively, of deferred uncollectible hardship costs. Equity Return on Regulatory Assets: For rate-making purposes, the regulated companies recover the carrying costs related to their regulatory assets. For certain regulatory assets, the carrying cost recovered includes an equity return component. This equity return is not recorded on the balance sheets. 100
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Regulatory Liabilities: The components of regulatory liabilities were as follows: As of December 31, 2025 2024 (Millions of Dollars) Eversource CL&P NSTARElectric PSNH Eversource CL&P NSTARElectric PSNH EDIT due to Tax Cuts and Jobs Act of 2017 $ 2,423.4 $ 933.3 $ 847.9 $ 319.8 $ 2,442.7 $ 956.6 $ 877.6 $ 330.6 Regulatory Tracking Mechanisms 1,186.6 457.3 535.2 111.2 702.4 180.3 413.6 114.4 Cost of Removal 867.1 275.1 479.4 45.5 684.1 212.8 451.3 20.1 Deferred Portion of Non-Service Income Components of Pension, SERP and PBOP 509.4 72.8 252.5 48.5 427.1 61.6 211.6 42.6 AFUDC - Transmission 179.4 72.0 107.4 — 154.8 65.1 89.7 — Derivative Contract 91.0 — 91.0 — — — — — Benefit Costs 80.4 8.8 24.5 6.8 69.3 4.5 21.4 3.9 Other Regulatory Liabilities 200.8 43.3 15.0 4.0 184.5 39.1 14.2 4.5 Total Regulatory Liabilities 5,538.1 1,862.6 2,352.9 535.8 4,664.9 1,520.0 2,079.4 516.1 Less: Current Portion 1,264.6 417.5 650.8 118.4 632.3 124.1 436.3 121.1 Total Long-Term Regulatory Liabilities $ 4,273.5 $ 1,445.1 $ 1,702.1 $ 417.4 $ 4,032.6 $ 1,395.9 $ 1,643.1 $ 395.0 As of December 31, 2024, the Regulatory Liabilities attributable to the Aquarion water distribution business were classified as Liabilities Held for Sale on the Eversource balance sheet. As of December 31, 2025, these liabilities were reclassified as Regulatory Liabilities on the Eversource balance sheet. For further information, see Note 24, “Assets Held for Sale.” EDIT due to Tax Cuts and Jobs Act of 2017: Pursuant to the Tax Cuts and Jobs Act of 2017, Eversource had remeasured its existing deferred federal income tax balances to reflect the decrease in the U.S. federal corporate income tax rate from 35 percent to 21 percent. The remeasurement resulted in provisional regulated excess accumulated deferred income tax (excess ADIT or EDIT) liabilities that will benefit customers in future periods and were recognized as regulatory liabilities on the balance sheet. EDIT liabilities related to property, plant, and equipment are subject to IRS normalization rules and will be returned to customers using the same timing as the remaining useful lives of the underlying assets that gave rise to the ADIT liabilities. Eversource's regulated companies are in the process of refunding the EDIT liabilities to customers based on orders issued by applicable state and federal regulatory commissions. Deferred Portion of Non-Service Income Components of Pension, SERP and PBOP: Regulatory liabilities were recorded for the deferred portion of the non-service related components of net periodic benefit expense/(income) for the Pension, SERP and PBOP Plans. These regulatory liabilities will be amortized over the remaining useful lives of the various classes of utility property, plant and equipment. AFUDC - Transmission: Regulatory liabilities were recorded by CL&P and NSTAR Electric for AFUDC accrued on certain reliability-related transmission projects to reflect local rate base recovery. These regulatory liabilities will be amortized over the depreciable life of the related transmission assets. Other Regulatory Liabilities: Other Regulatory Liabilities primarily include EGMA’s acquired regulatory liability as a result of the 2020 DPU-approved rate settlement agreement and the CMA asset acquisition on October 9, 2020, and various other items. FERC ROE Complaints: As of December 31, 2025 and 2024, Eversource has a reserve established for the second ROE complaint period in the pending FERC ROE complaint proceedings, which was recorded as a regulatory liability and is reflected within Regulatory Tracking Mechanisms in the table above. The cumulative pre-tax reserve (excluding interest) as of December 31, 2025 and 2024 totaled $39.1 million for Eversource (including $21.4 million for CL&P, $14.6 million for NSTAR Electric and $3.1 million for PSNH). See Note 13E, "Commitments and Contingencies – FERC ROE Complaints," for further information on developments in the pending ROE complaint proceedings. Regulatory Developments: CL&P State Bonding Proceeds: On July 1, 2025, Connecticut enacted Public Act No. 25-173 (Senate Bill No. 4) (the Act). The Act authorizes the State of Connecticut to issue up to $125 million in new general obligation bonds for each fiscal year 2026 and 2027 to reduce costs of hardship protection measures charged to retail customers, of which 67 percent of each issuance will be allocated to CL&P, and $30 million for fiscal year 2026 and $20 million for fiscal year 2027 in new general obligation bonds to fund the electric vehicle charging program, of which 80 percent of each issuance will be allocated to CL&P. On September 19, 2025, CL&P received $107.8 million in general obligation bond proceeds from the State of Connecticut, which represent reimbursement of incurred costs that were previously recognized as regulatory assets on CL&P’s balance sheets. The proceeds received for the reimbursement of hardship costs and for electric vehicle charging program costs were credited against the System Benefits Charge (SBC) and Non- Bypassable Federally Mandated Congestion Charge (NBFMCC) regulatory deferrals on CL&P’s balance sheet as of December 31, 2025. The proceeds from the state bond funding are presented as a cash inflow in Regulatory Recoveries within operating activities on CL&P’s statement of cash flows. 101
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Yankee Gas Distribution Rate Case: On November 12, 2024, Yankee Gas filed an application with PURA to amend its existing distribution rates for effect on November 1, 2025. Yankee Gas had subsequently amended its rate application to request approval of a distribution rate increase of $193 million. On September 22, 2025, PURA issued a proposed final (draft) decision in Yankee Gas’s distribution rate case that included a distribution rate increase of $55.6 million, effective November 1, 2025. On November 5, 2025, PURA issued a final decision in the Yankee Gas distribution rate case that included a distribution rate increase of $82.2 million and a total distribution revenue requirement of $802.2 million, effective November 1, 2025. The approved revenue requirement includes a previously recorded rate credit of $37.4 million plus carrying charges for non-firm margin credits over three years beginning November 1, 2025. Excluding the rate credit, the distribution rate increase totaled $95.7 million. The final decision also established an authorized net regulatory ROE of 9.32 percent, adopting a 9.48 percent ROE net of certain reductions totaling 16 basis points, and a 53 percent common equity ratio for Yankee Gas’ capital structure. PURA declined to approve the multi-year performance-based rate making plan that would adjust rates annually as proposed by Yankee Gas. PURA also implemented an annual cap on contemporaneous cost recovery of aging infrastructure replacement spending in the Distribution Integrity Management Program (DIMP) rate tracking mechanism of $139.9 million, in which spending above the annual cap will be deferred for recovery until the next distribution rate case. The final decision resulted in a net pre-tax loss to earnings of $8.5 million in the fourth quarter of 2025, primarily for the write off of certain capitalized employee compensation costs that were disallowed from rate base. Yankee Gas filed motions to request PURA reconsider the disallowances of these capitalized costs, certain computational errors, and other issues identified in its final decision. On December 15, 2025, PURA issued a notice of reconsideration to reconsider the final decision. A final decision on the reconsideration is expected from PURA by March 15, 2026. NSTAR Electric Distribution Rates: NSTAR Electric’s performance based regulation (PBR) mechanism allows for an annual adjustment to base distribution rates for inflation, exogenous events and future capital additions based on a historical five-year average of total capital additions. On September 15, 2025, NSTAR Electric submitted its annual PBR Adjustment filing for a $55.1 million increase to base distribution rates and a total base distribution revenue requirement of $1.34 billion for effect on January 1, 2026. The requested base distribution rate increase is comprised of a $25.2 million inflation-based adjustment and a $29.9 million K-bar adjustment for capital additions based on the difference between the historical five- year average of total capital additions and the base capital revenue requirement. On December 30, 2025, the DPU approved this filing. On September 16, 2024, NSTAR Electric submitted its annual PBR Adjustment filing for a $55.8 million increase to base distribution rates, for effect on January 1, 2025. The requested base distribution rate increase is comprised of a $35.3 million inflation-based adjustment and a $20.5 million adjustment for capital additions based on the difference between the historical five-year average of total capital additions and the base capital revenue requirement. On December 23, 2024, the DPU approved this filing. NSTAR Gas Distribution Rates: NSTAR Gas’ PBR mechanism allows for an annual adjustment to base distribution rates for inflation and exogenous events. On June 16, 2025, NSTAR Gas submitted its annual PBR Adjustment filing for rates to be effective on November 1, 2025. On September 11, 2025, NSTAR Gas updated its filing to request approval of a $162.6 million increase to base distribution rates and a total base distribution revenue requirement of $447.7 million. The base distribution rate increase is comprised of a $10.3 million inflation-based adjustment and, in accordance with the DPU’s final decision in the 2020 NSTAR Gas rate case, a $152.3 million rate-base reset to incorporate capital additions for the period 2021 through 2024, which includes the transfer of GSEP revenues totaling $107.3 million into base rates, as well as other non-GSEP plant additions totaling $45.0 million. On October 29, 2025, the DPU issued a decision determining that NSTAR Gas was not eligible to increase its distribution rates for the rate base reset because it did not achieve certain performance metrics under its PBR plan, and did not allow the base rate increase of $45.0 million for the incorporation of non-GSEP plant additions into base rates. The decision stated that those investments could be considered for inclusion in base distribution rates in NSTAR Gas’s next base rate proceeding. The DPU did allow NSTAR Gas to transfer its GSEP revenues through 2024 of $107.3 million for recovery through base distribution rates effective November 1, 2025. The DPU approved the base distribution rate increase of $10.3 million for the inflation-based adjustment. The DPU also approved NSTAR Gas’ mitigation proposal, in which NSTAR Gas paused recovery of the Gas System Enhancement Adjustment Factor (GSEAF) and reduced the current GSEAF to zero on November 1, 2025 in order to align this decrease with the base rate increase and to mitigate November 1, 2025 bill impacts to customers. NSTAR Gas will begin to recover the remaining 2025 GSEP revenue requirement on May 1, 2026 over 18 months. On November 4, 2025, NSTAR Gas filed a motion requesting the DPU to reconsider its decision denying the rate base reset citing legal concerns and arguing that the decision will ultimately result in higher costs for customers. NSTAR Gas also notified the DPU of its intention to file a base distribution rate case. On December 30, 2025, NSTAR Gas and the Massachusetts Office of the Attorney General reached a joint settlement agreement that allowed for the reinstatement of the rate base reset of $45.0 million increase to base distribution rates effective January 1, 2026, for NSTAR Gas to not petition for a rate case with new rates effective December 1, 2026, and for continuation of NSTAR Gas’ PBR program through November 1, 2030. The settlement agreement also required NSTAR Gas to provide a credit to customers of $10.2 million over a ten-month period beginning January 2026 as penalty for its failure to meet three performance metrics as required for eligibility for the rate base reset, pay a $2 million concession to the Office of the Attorney General to fund customer energy assistance programs, waive recovery of certain carrying charges, delay recovery of $53 million of capital pipeline investments until the next rate case, and provide bill stabilization credit deferrals. The DPU approved the settlement agreement on January 16, 2026. The settlement agreement resulted in a pre-tax charge to earnings of $12.2 million in the fourth quarter of 2025. On September 16, 2024, NSTAR Gas submitted its annual PBR Adjustment filing for a $12.7 million increase to base distribution rates for effect on November 1, 2024. On October 30, 2024, the DPU approved this filing. 102
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NSTAR Electric and EGMA Settlement: On November 3, 2025, EGMA, NSTAR Electric, and the Massachusetts Office of the Attorney General reached a joint settlement agreement that resolved outstanding issues in multiple open Pension Adjustment Mechanism (PAM) dockets and open Resiliency Tree Work (RTW) dockets at NSTAR Electric and allows recovery of transaction and integration costs related to Eversource’s acquisition of EGMA. Certain PAM and RTW collections are being refunded to NSTAR Electric’s customers over a one-year period beginning January 1, 2026 and the transaction and integration costs of $82.3 million will be collected from EGMA customers over a ten-year period from the time of the next EGMA rate case. The settlement agreement was approved by the DPU on December 1, 2025. The settlement resulted in a net pre-tax benefit to earnings of $64.8 million on the Eversource income statement in the fourth quarter of 2025 ($82.3 million benefit at Eversource Parent and Other Companies for the allowed recovery of previously expensed acquisition-related and integration costs and $17.5 million charge at NSTAR Electric) and a net increase to regulatory assets on the Eversource balance sheet. EGMA Distribution Rates: On November 4, 2024, EGMA submitted a revised filing for its first rate base reset for rates effective November 1, 2024, in accordance with an October 7, 2020 EGMA Rate Settlement Agreement approved by the DPU. The compliance filing was ordered by the DPU on October 31, 2024. The rate base reset occurring on November 1, 2024 adjusted distribution rates to account for capital additions (including the roll-in of GSEP capital additions), depreciation expense, property taxes, and return on rate base for capital additions placed into service through December 31, 2023. The total revenue requirement calculated for the first rate base reset was an increase to base distribution rates of $147.8 million, of which $34.0 million is associated with GSEP investments through December 31, 2023. Under the terms of the Rate Settlement Agreement, EGMA applied a cap on the revenue change effective November 1, 2024, and the amount in excess of the cap was deferred for recovery through the Local Distribution Adjustment Clause (LDAC) on May 1, 2025, including carrying charges. After adjusting for the cap, the increase to base distribution rates was $85.6 million effective November 1, 2024 (of which $8.8 million is offset by a reduction in the GSEP revenue requirement and GSEP rate also taking effect on November 1, 2024 for a net distribution rate change on November 1, 2024 of $76.8 million). Base distribution rates increased effective November 1, 2025 to incorporate the $62.2 million remaining revenue requirement. On November 7, 2024, the DPU approved this filing. PSNH Distribution Rate Case: On June 11, 2024, PSNH filed an application with the NHPUC for approval of a temporary annual base distribution rate increase. On July 31, 2024, the NHPUC approved a settlement agreement that was reached by PSNH, New Hampshire Department of Energy, and the Office of the Consumer Advocate to implement a temporary annual base distribution rate increase of $61.2 million effective August 1, 2024. Temporary rates were in effect until permanent rates were approved and took effect August 1, 2025. Also on June 11, 2024, PSNH filed an application with the NHPUC to request an increase in permanent base distribution rates of $181.9 million, which is inclusive of the temporary rate increase. Throughout the course of the proceeding, PSNH amended the requested revenue requirement to account for developments in the case, and arrived at a final proposed rate increase of $103 million, which primarily reflects the removal of deferred storm costs that will be addressed in a separate proceeding. On July 25, 2025, the NHPUC issued its decision on permanent rates and approved a permanent rate increase of $100.7 million, effective August 1, 2025, inclusive of the temporary rate increase referenced above. The total base distribution revenue requirement effective August 1, 2025 is $519 million. The order also established an authorized regulatory ROE of 9.5 percent with a 50 percent common equity ratio for PSNH’s capital structure. This revenue requirement also contains an alternative regulation revenue requirement adjustment. This adjustment was part of the NHPUC’s alternative regulatory framework that the NHPUC adopted as an alternative to PSNH’s proposed performance-based regulation plan. The alternative regulatory framework authorizes formulaic annual revenue adjustments on August 1st of 2026, 2027 and 2028. PSNH is required to file its next base distribution rate case for effect in June 2029 and committed not to file its next distribution rate case until 2029. The alternative regulatory framework calculates the annual revenue adjustment using a productivity factor and an adjustment for inflation to provide PSNH with increased revenue for operations. The framework also contains an exogenous events recovery mechanism for certain unforeseen events out of PSNH’s control and exceeding a specified threshold, a performance metric, and an earnings sharing mechanism where PSNH would have to return 75 percent of all revenue back to customers that exceeds 25 basis points more than the authorized ROE of 9.5 percent. Consistent with PSNH’s proposal, lost base revenues for both net metering and energy efficiency were eliminated effective August 1, 2025. To the extent permanent rates exceed the level of temporary rates, the difference will reconcile back to the date that the temporary rates took effect and the company recovers the difference over a twelve-month term. On August 11, 2025, PSNH filed its recoupment calculation, and on September 10, 2025, the NHPUC issued an order that the recoupment is $9.1 million and will be collected through the RRA regulatory tracking mechanism over a one-year period. As part of the decision, unrecovered storm costs of $247 million were removed from the rate proceeding for consideration in a separate proceeding. Approval of the ultimate amount of storm costs to be recovered is subject to a separate prudency review that was filed in March of 2024 and is being considered by the NHPUC in a separate dedicated docket, which is at this time complete and awaiting the issuance of an order. Approved storm costs in excess of the amount approved in base rates will be recovered through the Regulatory Reconciliation Adjustment (RRA) regulatory tracking mechanism. The NHPUC increased the level of storm costs recovered in base rates from $12 million to $19 million. The impact of the rate case decision resulted in a pre-tax benefit to earnings of $15.6 million at PSNH due primarily to the recoupment and the allowed recovery of other deferrals that will be recovered in the RRA. The majority of this amount was recorded as a reduction to amortization expense on PSNH’s statement of income in 2025. 103
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On January 30, 2026, the New Hampshire Department of Energy filed a notice of appeal with the New Hampshire Supreme Court challenging certain aspects of the PSNH distribution rate case. The appeal raises issues regarding the lawfulness of the Company’s alternative regulatory framework, the adequacy of the NHPUC’s findings supporting the approved revenue requirement, and whether the NHPUC sufficiently addressed required regulatory factors in its final order. The Department of Energy contends that additional findings were necessary to support the final determinations. On February 6, 2026, the Office of the Consumer Advocate filed a notice of cross-appeal with the New Hampshire Supreme Court challenging other aspects of the rate case decision. The NHPUC, as the deciding agency, is afforded the highest level of deference by the New Hampshire Supreme Court, and therefore the Department of Energy and the Office of Consumer Advocate will have a very high burden to meet to be successful on appeal. Eversource is currently evaluating the appeals and will respond consistent with applicable legal and regulatory processes. 3. PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION Utility property, plant and equipment is recorded at original cost. Original cost includes materials, labor, construction overheads and AFUDC for regulated property. The cost of repairs and maintenance is charged to Operations and Maintenance expense as incurred. The following tables summarize property, plant and equipment by asset category: Eversource As of December 31, (Millions of Dollars) 2025 2024 Distribution - Electric $ 22,695.3 $ 21,144.1 Distribution - Natural Gas 9,888.0 8,922.2 Transmission - Electric 17,082.4 16,130.9 Distribution - Water 2,577.3 — Solar 206.8 201.0 Utility 52,449.8 46,398.2 Other 2,476.3 2,254.1 Property, Plant and Equipment, Gross 54,926.1 48,652.3 Less: Accumulated Depreciation Utility (10,911.7) (9,636.5) Other (1,246.1) (1,044.1) Total Accumulated Depreciation (12,157.8) (10,680.6) Property, Plant and Equipment, Net 42,768.3 37,971.7 Construction Work in Progress 3,162.7 3,014.9 Total Property, Plant and Equipment, Net $ 45,931.0 $ 40,986.6 As of December 31, 2025 2024 (Millions of Dollars) CL&P NSTAR Electric PSNH CL&P NSTAR Electric PSNH Distribution - Electric $ 8,906.0 $ 10,635.7 $ 3,193.8 $ 8,437.9 $ 9,782.3 $ 2,964.2 Transmission - Electric 7,222.5 6,722.9 3,138.7 6,937.7 6,375.2 2,819.6 Solar — 206.8 — — 201.0 — Property, Plant and Equipment, Gross 16,128.5 17,565.4 6,332.5 15,375.6 16,358.5 5,783.8 Less: Accumulated Depreciation (3,081.3) (4,014.2) (1,085.4) (2,928.0) (3,782.0) (1,032.3) Property, Plant and Equipment, Net 13,047.2 13,551.2 5,247.1 12,447.6 12,576.5 4,751.5 Construction Work in Progress 576.1 1,757.7 260.6 554.6 1,461.3 338.4 Total Property, Plant and Equipment, Net $ 13,623.3 $ 15,308.9 $ 5,507.7 $ 13,002.2 $ 14,037.8 $ 5,089.9 As of December 31, 2024, the property, plant and equipment balance, net of accumulated depreciation, attributable to the Aquarion water distribution business was classified to Assets Held for Sale on the Eversource balance sheet. As of December 31, 2025, these assets were reclassified as Property, Plant and Equipment, Net on the Eversource balance sheet. For further information, see Note 24, “Assets Held for Sale. These assets are primarily comprised of computer software, hardware and equipment at Eversource Service and buildings at The Rocky River Realty Company. Depreciation: Depreciation of utility assets is calculated on a straight-line basis using composite rates based on the estimated remaining useful lives of the various classes of property (estimated useful life for PSNH distribution and the water utilities). The composite rates, which are subject to approval by the appropriate state regulatory agency, include a cost of removal component, which is collected from customers over the lives of the plant assets and is recognized as a regulatory liability. Depreciation rates are applied to property from the time it is placed in service. Upon retirement from service, the cost of the utility asset is charged to the accumulated provision for depreciation. The actual incurred removal costs are applied against the related regulatory liability. (1) (2) (1) (2) 104
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The depreciation rates for the various classes of utility property, plant and equipment aggregate to composite rates as follows: (Percent) 2025 2024 2023 Eversource 3.3 % 3.2 % 3.1 % CL&P 2.9 % 2.9 % 2.8 % NSTAR Electric 2.8 % 2.8 % 2.7 % PSNH 3.0 % 3.0 % 3.0 % The following table summarizes average remaining useful lives of depreciable assets: As of December 31, 2025 (Years) Eversource CL&P NSTAR Electric PSNH Distribution - Electric 33.0 34.7 32.5 30.4 Distribution - Natural Gas 32.8 — — — Transmission - Electric 39.2 35.4 44.1 39.6 Distribution - Water 43.9 — — — Solar 21.8 — 21.8 — Other 9.9 — — — The estimated useful life of computer software, hardware and equipment primarily ranges from 5 to 15 years and of buildings is 40 years. 4. DERIVATIVE INSTRUMENTS The electric and natural gas companies enter into contracts to purchase and procure energy and energy-related products for their customers, which are subject to price volatility. The costs associated with supplying energy to customers are recoverable from customers in future rates. These regulated companies manage the risks associated with the price volatility of energy and energy-related products through the use of derivative and non-derivative contracts. Many of the derivative contracts meet the definition of, and are designated as, normal and qualify for accrual accounting under the applicable accounting guidance. The costs and benefits of derivative contracts that meet the definition of normal are recognized in Operating Expenses on the statements of income as electricity or natural gas is delivered. Derivative contracts that are not designated as normal are recorded at fair value as derivative assets or liabilities on the balance sheets. For the electric and natural gas companies, regulatory assets or regulatory liabilities are recorded to offset the fair values of derivatives, as contract amounts are recovered from, or refunded to, customers in their respective energy supply rates. The mark to market unrealized losses or gains of these derivative contracts are deferred as regulatory assets (if the derivative is a liability) or as regulatory liabilities (if the derivative is an asset). The gross fair values of derivative assets and liabilities with the same counterparty are offset and reported as net Derivative Assets or Derivative Liabilities, with current and long-term portions, on the balance sheets. The following table presents the gross fair values of contracts, categorized by risk type, and the net amounts recorded as current or long-term derivative assets or liabilities: As of December 31, 2025 2024 (Millions of Dollars) Fair Value Hierarchy Commodity Supplyand Price Risk Management Netting Net AmountRecorded as a Derivative Commodity Supplyand Price Risk Management Netting Net AmountRecorded as a Derivative Current Derivative Assets: CL&P Level 2 $ — $ — $ — $ 14.2 $ (0.3) $ 13.9 NSTAR Electric Level 3 91.0 — 91.0 — — — Current Derivative Liabilities: CL&P Level 2 (0.1) — (0.1) (71.1) — (71.1) Long-Term Derivative Liabilities: NSTAR Electric Level 3 (753.1) — (753.1) — — — Amounts represent derivative assets and liabilities that Eversource elected to record net on the balance sheets. These amounts are subject to master netting agreements or similar agreements for which the right of offset exists. Derivative Contracts at Fair Value with Offsetting Regulatory Amounts Commodity Supply and Price Risk Management: In accordance with Massachusetts clean energy legislation and under the Massachusetts Clean Energy 83D procurement, in June 2018, NSTAR Electric entered into a 20-year power purchase agreement for the purchase of renewable hydroelectric energy and renewable energy attributes from Hydro-Québec. The agreement requires NSTAR Electric to purchase 579 MW of energy per hour through January 2046. Upon notice of commercial operation of the transmission line needed to deliver this energy, received on December 31, 2025, the power purchase agreement was marked to market on the balance sheet. The current and long-term portions of the contract were recorded as derivative assets and derivative liabilities, respectively, and were offset by current and long-term regulatory liabilities and regulatory assets, respectively, reflecting full recovery from or refund to NSTAR Electric’s customers. (1) (1) (1) (1) (1) 105
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As required by regulation, CL&P, along with UI, has capacity-related contracts with generation facilities. CL&P has a sharing agreement with UI, with 80 percent of the costs or benefits of each contract borne by or allocated to CL&P and 20 percent borne by or allocated to UI. The combined capacities of these contracts as of December 31, 2025 and 2024 were 3 MW and 610 MW, respectively. The capacity contracts extend through 2026 and obligate both CL&P and UI to make or receive payments on a monthly basis to or from the generation facilities based on the difference between a set capacity price and the capacity market price received in the ISO-NE capacity markets. For the years ended December 31, 2025, 2024 and 2023, losses from changes in fair value associated with these derivative contracts of $662.9 million, $3.8 million and $3.9 million, respectively, were deferred in Regulatory Assets or Regulatory Liabilities on the balance sheet. Fair Value Measurements of Derivative Instruments The fair value of derivative contracts utilizes both observable and unobservable inputs. The fair value is modeled using income techniques, such as discounted cash flow valuations adjusted for assumptions related to exit price. Valuations of derivative contracts using a discounted cash flow methodology include assumptions regarding future energy and energy-related prices, the timing and likelihood of scheduled payments, selection of a discount rate, and also reflect non-performance risk, including credit, using the default probability approach based on the counterparty’s credit rating for assets and the Company’s credit rating for liabilities. Valuations also give consideration to premiums or discounts that would be required by a market participant to arrive at an exit price. Future energy prices that are not quoted in an active market are based on available market data with assumptions of future market dynamics and inflation to address the full time period of the contract. Fair value measurements are prepared and reviewed by individuals with expertise in valuation techniques, pricing of energy-related products, and accounting requirements. For NSTAR Electric’s derivative contract, unobservable inputs for future energy prices using a forward electricity bid price curve are significant to the valuation and are classified as Level 3. As of December 31, 2025, Level 3 unobservable inputs utilized in the valuation of NSTAR Electric’s power purchase agreement include energy prices ranging from $24.65 per MWh through $145.33 per MWh, or a weighted average of $53.44 per MWh, over the contractual period of 2026 through 2046. For CL&P derivative contracts, observable inputs for energy-related product prices in future years for which quoted prices in an active market exist are significant to the valuation and are classified as Level 2. The following table presents changes in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis. The derivative assets and liabilities are presented on a net basis. NSTAR Electric(Millions of Dollars) For the Year Ended December 31, 2025 Derivatives, Net: Fair Value as of Beginning of Year $ — Net Realized/Unrealized Losses Included inRegulatory Assets or Regulatory Liabilities (662.1) Settlements — Fair Value as of End of Year $ (662.1) 5. MARKETABLE SECURITIES Eversource’s marketable securities include the CYAPC and YAEC legally restricted trusts that each hold equity and available-for-sale debt securities to fund the spent nuclear fuel removal obligations of their nuclear fuel storage facilities. Equity and available-for-sale debt marketable securities are recorded at fair value. CYAPC and YAEC’s spent nuclear fuel trusts are restricted and are classified in long-term Marketable Securities on the balance sheets. Eversource’s water business also holds a trust. As of December 31, 2024, the securities held in this trust of $4.1 million were classified as Assets Held for Sale on the Eversource balance sheet. As of December 31, 2025, these securities held in this trust of $3.5 million were reclassified as Marketable Securities on the Eversource balance sheet. For further information, see Note 24, “Assets Held for Sale.” For the years ended December 31, 2025 and 2024, there were unrealized losses of $0.7 million and unrealized gains of $0.9 million recorded in Other Income, Net, related to these equity securities, respectively. Equity Securities: Eversource's equity securities include CYAPC's and YAEC's marketable securities held in spent nuclear fuel trusts, which had fair values of $161.8 million and $163.1 million as of December 31, 2025 and 2024, respectively. Unrealized gains and losses for these spent nuclear fuel trusts are subject to regulatory accounting treatment and are recorded in Marketable Securities with the corresponding offset to long-term liabilities on the balance sheets, with no impact on the statements of income. Available-for-Sale Debt Securities: The following is a summary of available-for-sale debt securities, which are held in CYAPC’s and YAEC’s spent nuclear fuel trusts: As of December 31, 2025 2024 Eversource(Millions of Dollars) Amortized Cost Pre-TaxUnrealized Gains Pre-TaxUnrealized Losses Fair Value Amortized Cost Pre-TaxUnrealized Gains Pre-TaxUnrealized Losses Fair Value Debt Securities $ 156.5 $ 0.7 $ (1.8) $ 155.4 $ 163.2 $ 0.1 $ (6.1) $ 157.2 106
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Unrealized gains and losses for available-for-sale debt securities included in the CYAPC and YAEC spent nuclear fuel trusts are subject to regulatory accounting treatment and are recorded in Marketable Securities with the corresponding offset to long-term liabilities on the balance sheets, with no impact on the statements of income. As of December 31, 2025, the contractual maturities of available-for-sale debt securities were as follows: Eversource (Millions of Dollars) AmortizedCost FairValue Less than one year $ 15.7 $ 15.8 One to five years 39.9 40.6 Six to ten years 26.0 26.1 Greater than ten years 74.9 72.9 Total Debt Securities $ 156.5 $ 155.4 Realized Gains and Losses: Realized gains and losses are offset in long-term liabilities for CYAPC and YAEC and are recorded in Other Income, Net for Eversource's benefit trusts. Eversource utilizes the average cost basis method for the CYAPC and YAEC spent nuclear fuel trusts. Fair Value Measurements: The following table presents the marketable securities recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy: Eversource (Millions of Dollars) As of December 31, 2025 2024 Level 1: Mutual Funds and Equities $ 165.3 $ 163.1 Money Market Funds 14.0 10.0 Total Level 1 $ 179.3 $ 173.1 Level 2: U.S. Government Issued Debt Securities (Agency and Treasury) $ 82.0 $ 92.0 Corporate Debt Securities 37.9 32.5 Asset-Backed Debt Securities 6.4 7.8 Municipal Bonds 7.2 6.8 Other Fixed Income Securities 7.9 8.1 Total Level 2 $ 141.4 $ 147.2 Total Marketable Securities $ 320.7 $ 320.3 U.S. government issued debt securities are valued using market approaches that incorporate transactions for the same or similar bonds and adjustments for yields and maturity dates. Corporate debt securities are valued using a market approach, utilizing recent trades of the same or similar instruments and also incorporating yield curves, credit spreads and specific bond terms and conditions. Asset-backed debt securities include collateralized mortgage obligations, commercial mortgage backed securities, and securities collateralized by auto loans, credit card loans or receivables. Asset-backed debt securities are valued using recent trades of similar instruments, prepayment assumptions, yield curves, issuance and maturity dates, and tranche information. Municipal bonds are valued using a market approach that incorporates reported trades and benchmark yields. Other fixed income securities are valued using pricing models, quoted prices of securities with similar characteristics, and discounted cash flows. 6. INVESTMENTS IN UNCONSOLIDATED AFFILIATES Investments in entities that are not consolidated are included in long-term assets on the balance sheets. Investments in affiliates where Eversource has the ability to exercise significant influence, but not control, over an investee are initially recognized as an equity method investment at cost. Earnings impacts from these equity investments are included in Other Income, Net on the statements of income. Eversource's investments accounted for under the equity method include the following: Investment Balance as of December 31, (Millions of Dollars) Ownership Interest 2025 2024 Tax Equity Investment in South Fork Wind 100% $ 19.1 $ 22.2 Natural Gas Pipeline - Algonquin Gas Transmission, LLC 15% 110.8 112.6 Other various 36.3 33.9 Total Investments in Unconsolidated Affiliates $ 166.2 $ 168.7 For the years ended December 31, 2025, 2024 and 2023, Eversource had equity in earnings of unconsolidated affiliates of $19.9 million, $51.9 million, and $15.5 million, respectively. Eversource received dividends from its equity method investees (excluding proceeds received from sale or liquidation of investments) of $20.7 million, $20.5 million, and $20.1 million, respectively, for the years ended December 31, 2025, 2024 and 2023. 107
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Tax Equity Investment in South Fork Wind: Eversource holds a noncontrolling tax equity investment in South Fork Wind through a 100 percent ownership in South Fork Wind Holdings, LLC Class A interests. In September 2023, Eversource made a $528 million investment in a tax equity interest for South Fork Wind. South Fork Wind was restructured as a tax equity investment, with Eversource purchasing 100 percent ownership of a new Class A tax equity membership interest. This investment will result in Eversource receiving cash flow benefits from investment tax credits (ITC) and other future cash flow benefits as well. During 2024, $459 million of expected investment tax credits and other expected tax benefits were reclassified from the South Fork Wind tax equity investment balance reported in Investments in Unconsolidated Affiliates as a decrease in Accumulated Deferred Income Taxes on the Eversource balance sheet, which represented a non-cash reclassification. As a result of these investment tax credits, Eversource expects lower federal income tax payments through 2028. Offshore Wind Investments: During 2024, Eversource sold its 50 percent ownership interests in each of North East Offshore and South Fork Class B Member, LLC and in doing so, sold its interests in the Revolution Wind project, the South Fork Wind project, and the Sunrise Wind project. For more information on the sale, see Note 13G, "Commitments and Contingencies – Offshore Wind Sale and Contingent Liability," to the financial statements. Eversource recognized an aggregate pre-tax loss on the sales of its offshore wind investments of $464 million ($524 million after-tax) in 2024. In 2023, Eversource recorded pre-tax other-than-temporary impairment charges totaling $2.17 billion ($1.95 billion after-tax) in connection with the process to divest these offshore wind investments. In the impairment assessments, Eversource evaluated its investments and determined that the carrying value of the equity method offshore wind investments exceeded the fair value of the investments and that the decline in fair value was other-than-temporary. Impairment charges were recorded to reflect the investments at estimated fair value at that time. Capital contributions in the offshore wind investments in 2023 and 2024, including the 2023 contribution for the tax equity investment in South Fork Wind, were included in Investments in Unconsolidated Affiliates on the statements of cash flows. Proceeds received from the sales of the offshore wind investments of $863 million in 2024, the sale of an unused lease area to Ørsted for $625 million in 2023, and an October 2023 distribution of $318 million received primarily as a result of being a 50 percent joint owner in the Class B shares of South Fork Wind which was restructured as a tax equity investment, were included in Proceeds from Unconsolidated Affiliates on the statements of cash flows. Payments made in 2025 related to Eversource’s remaining offshore wind contingent obligation are reflected in investing activities on the statement of cash flows. Liquidation of Renewable Energy Investment Fund: On March 21, 2023, Eversource’s equity method investment in a renewable energy investment fund was liquidated by the fund’s general partner in accordance with the partnership agreement. Proceeds received from the liquidation totaled $147.6 million and were included in Proceeds from Unconsolidated Affiliates on the statement of cash flows for the year ended December 31, 2023. A portion of the proceeds was used to make a charitable contribution to the Eversource Energy Foundation (a related party) of $20.0 million in 2023. The liquidation benefit received in excess of the investment’s carrying value and the charitable contribution were included in Other Income, Net on the statement of income. Impairments: Equity method investments are assessed for impairment when conditions exist as of the balance sheet date that indicate that the fair value of the investment may be less than book value. Eversource continually monitors and evaluates its equity method investments to determine if there are indicators of an other-than-temporary impairment. If the decline in value is considered to be other-than-temporary, the investment is written down to its estimated fair value, which establishes a new cost basis in the investment. Impairment evaluations are based on best information available at the impairment assessment date. Subsequent declines or recoveries after the reporting date are not considered in the impairment recognized. Investments that are other-than-temporarily impaired and written down to their estimated fair value cannot subsequently be written back up for increases in estimated fair value. Impairment evaluations involve a significant degree of judgment and estimation, including identifying circumstances that indicate an impairment may exist at the equity method investment level, selecting discount rates used to determine fair values, and developing an estimate of discounted future cash flows expected from investment operations or the sale of the investment. NSTAR Electric: As of December 31, 2025 and 2024, NSTAR Electric's investments included a 14.5 percent ownership interest in two companies that transmit hydro-electricity imported from the Hydro-Quebec system in Canada of $12.2 million and $11.5 million, respectively. 7. ASSET RETIREMENT OBLIGATIONS Eversource, including CL&P, NSTAR Electric and PSNH, recognizes a liability for the fair value of an ARO on the obligation date if the liability's fair value can be reasonably estimated, even if it is conditional on a future event. Settlement dates and future costs are reasonably estimated when sufficient information becomes available. Management has identified various categories of AROs, primarily CYAPC's and YAEC's obligation to dispose of spent nuclear fuel and high level waste, and also certain assets containing asbestos and hazardous contamination. Management has performed fair value calculations reflecting expected probabilities for settlement scenarios. The fair value of an ARO is recorded as a long-term liability with a corresponding amount included in Property, Plant and Equipment, Net on the balance sheets. The ARO assets are depreciated, and the ARO liabilities are accreted over the estimated life of the obligation and the corresponding credits are recorded as accumulated depreciation and ARO liabilities, respectively. As the electric and natural gas companies are rate-regulated on a cost-of-service basis, these companies apply regulatory accounting guidance and both the depreciation and accretion costs associated with these companies' AROs are recorded as increases to Regulatory Assets on the balance sheets. 108
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A reconciliation of the beginning and ending carrying amounts of ARO liabilities is as follows: As of December 31, 2025 2024 (Millions of Dollars) Eversource CL&P NSTARElectric PSNH Eversource CL&P NSTARElectric PSNH Balance as of Beginning of Year $ 590.9 $ 42.5 $ 109.3 $ 5.6 $ 505.8 $ 39.9 $ 104.8 $ 5.2 Liabilities Settled During the Year (24.2) — — — (24.6) — — — Accretion 34.0 2.9 4.7 0.3 29.5 2.6 4.5 0.4 Revisions in Estimated Cash Flows (5.3) — — — 80.2 — — — Balance as of End of Year $ 595.4 $ 45.4 $ 114.0 $ 5.9 $ 590.9 $ 42.5 $ 109.3 $ 5.6 Eversource's amounts include CYAPC and YAEC's AROs of $386.6 million and $391.7 million as of December 31, 2025 and 2024, respectively. The fair value of the ARO for CYAPC and YAEC includes uncertainties of the fuel off-load dates related to the DOE's timing of performance regarding its obligation to dispose of the spent nuclear fuel and high level waste and other assumptions, including discount rates. The incremental asset recorded as an offset to the ARO liability was fully depreciated since the plants have no remaining useful life. Any changes in the ARO liability are recorded with a corresponding offset to the related regulatory asset. The assets held in the CYAPC and YAEC spent nuclear fuel trusts are restricted for settling the ARO and all other nuclear fuel storage obligations. For further information on the assets held in the spent nuclear fuel trusts, see Note 5, "Marketable Securities," to the financial statements. The increase in the ARO balance at Eversource for the year ended December 31, 2024 was due primarily to updated cost estimates that extended the end of life date from 2039 to 2044 for CYAPC and YAEC. These updated cost estimates were approved by FERC in November 2024. 8. SHORT-TERM DEBT Short-Term Debt - Borrowing Limits: The amount of short-term borrowings that may be incurred by CL&P and NSTAR Electric is subject to periodic approval by the FERC. Because the NHPUC has jurisdiction over PSNH's short-term debt, PSNH is not currently required to obtain FERC approval for its short-term borrowings. On December 12, 2025, the FERC granted authorization that allows CL&P to issue total short-term borrowings in an aggregate principal amount not to exceed $600 million outstanding at any one time, through December 31, 2027. On December 12, 2025, the FERC granted authorization that allows NSTAR Electric to issue total short-term borrowings in an aggregate principal amount not to exceed $655 million outstanding at any one time, through December 31, 2027. PSNH is authorized by regulation of the NHPUC to incur short-term borrowings up to 10 percent of net fixed plant plus an additional $60 million until further ordered by the NHPUC. As of December 31, 2025, PSNH's short-term debt authorization under the 10 percent of net fixed plant test plus $60 million totaled $572.9 million. CL&P's certificate of incorporation contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur, including limiting unsecured indebtedness with a maturity of less than 10 years to 10 percent of total capitalization. As of December 31, 2025, CL&P had $1.19 billion of unsecured debt capacity available under this authorization. Yankee Gas, NSTAR Gas and EGMA are not required to obtain approval from any state or federal authority to incur short-term debt. Short-Term Debt - Commercial Paper Programs and Credit Agreements: Eversource parent has a $2.00 billion commercial paper program allowing Eversource parent to issue commercial paper as a form of short-term debt. Eversource parent, CL&P, PSNH, NSTAR Gas, Yankee Gas, EGMA and Aquarion Water Company of Connecticut are parties to a five-year $2.00 billion revolving credit facility. Effective October 11, 2025, the revolving credit facility’s termination date was extended for one additional year to October 11, 2030, pursuant to the extension provisions contained in the existing credit agreement. This revolving credit facility serves to backstop Eversource parent's $2.00 billion commercial paper program. NSTAR Electric has a $650 million commercial paper program allowing NSTAR Electric to issue commercial paper as a form of short-term debt. NSTAR Electric is also a party to a five-year $650 million revolving credit facility. Effective October 11, 2025, the revolving credit facility’s termination date was extended for one additional year to October 11, 2030, pursuant to the extension provisions contained in the existing credit agreement. This revolving credit facility serves to backstop NSTAR Electric's $650 million commercial paper program. The amount of borrowings outstanding and available under the commercial paper programs were as follows: Borrowings Outstanding as of December 31, Available Borrowing Capacity as of December 31, Weighted-Average Interest Rate as of December 31, (Millions of Dollars) 2025 2024 2025 2024 2025 2024 Eversource Parent Commercial Paper Program $ 1,280.0 $ 1,538.0 $ 720.0 $ 462.0 3.98 % 4.76 % NSTAR Electric Commercial Paper Program 245.4 504.8 404.6 145.2 3.87 % 4.55 % There were no borrowings outstanding on the revolving credit facilities as of December 31, 2025 or 2024. 109
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CL&P and PSNH have uncommitted line of credit agreements totaling $375 million and $250 million, respectively, all of which will expire in either May 2026, September 2026 or October 2026. There are no borrowings outstanding on either the CL&P or PSNH uncommitted line of credit agreements as of December 31, 2025. Amounts outstanding under the commercial paper programs are included in Notes Payable and classified in current liabilities on the Eversource and NSTAR Electric balance sheets, as all borrowings are outstanding for no more than 364 days at one time. Under the credit facilities described above, Eversource and its subsidiaries, including CL&P, NSTAR Electric, PSNH, NSTAR Gas, EGMA, Yankee Gas, and Aquarion Water Company of Connecticut, must comply with certain financial and non-financial covenants, including a consolidated debt to total capitalization ratio. As of December 31, 2025 and 2024, Eversource and its subsidiaries were in compliance with these covenants. If Eversource or its subsidiaries were not in compliance with these covenants, an event of default would occur requiring all outstanding borrowings by such borrower to be repaid, and additional borrowings by such borrower would not be permitted under its respective credit facility. Intercompany Borrowings: Eversource parent uses its available capital resources to provide loans to its subsidiaries to assist in meeting their short-term borrowing needs. Eversource parent records intercompany interest income from its loans to subsidiaries, which is eliminated in consolidation. Intercompany loans from Eversource parent to its subsidiaries are eliminated in consolidation on Eversource's balance sheets. As of December 31, 2025 and 2024, there were intercompany loans from Eversource parent to PSNH of $49.3 million and $131.1 million, respectively. As of December 31, 2024, there were intercompany loans from Eversource parent to CL&P of $280.0 million. Eversource parent charges interest on these intercompany loans at the same weighted-average interest rate as its commercial paper program. Intercompany loans from Eversource parent are included in Notes Payable to Eversource Parent and classified in current liabilities on the respective subsidiary's balance sheets, as these intercompany borrowings are outstanding for no more than 364 days at one time. Sources and Uses of Cash: The Company expects the future operating cash flows of Eversource, CL&P, NSTAR Electric and PSNH, along with existing borrowing availability and access to both debt and equity markets, will be sufficient to meet any working capital and future operating requirements, and capital investment forecasted opportunities. 9. LONG-TERM DEBT Details of long-term debt outstanding are as follows: CL&P (Millions of Dollars) As of December 31, Interest Rate 2025 2024 First Mortgage Bonds: 2004 Series B due 2034 5.750 % 130.0 130.0 2005 Series B due 2035 5.625 % 100.0 100.0 2006 Series A due 2036 6.350 % 250.0 250.0 2007 Series B due 2037 5.750 % 150.0 150.0 2007 Series D due 2037 6.375 % 100.0 100.0 2014 Series A due 2044 4.300 % 475.0 475.0 2015 Series A due 2045 4.150 % 350.0 350.0 2017 Series A due 2027 3.200 % 500.0 500.0 2018 Series A due 2048 4.000 % 800.0 800.0 2020 Series A due 2025 0.750 % — 400.0 2021 Series A due 2031 2.050 % 425.0 425.0 2023 Series A due 2053 5.250 % 500.0 500.0 2023 Series B due 2033 4.900 % 300.0 300.0 2024 Series A due 2029 4.650 % 350.0 350.0 2024 Series B due 2034 4.950 % 300.0 300.0 2025 Series A due 2030 4.950 % 400.0 — Total First Mortgage Bonds 5,130.0 5,130.0 Less Amounts due Within One Year — (400.0) Current Portion Classified as Long-Term Debt — 397.1 Unamortized Premiums and Discounts, Net 12.4 14.3 Unamortized Debt Issuance Costs (32.3) (33.2) CL&P Long-Term Debt $ 5,110.1 $ 5,108.2 (1) 110
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NSTAR Electric (Millions of Dollars) As of December 31, Interest Rate 2025 2024 Debentures: 2006 Debentures due 2036 5.750 % $ 200.0 $ 200.0 2010 Debentures due 2040 5.500 % 300.0 300.0 2014 Debentures due 2044 4.400 % 300.0 300.0 2015 Debentures due 2025 3.250 % — 250.0 2016 Debentures due 2026 2.700 % 250.0 250.0 2017 Debentures due 2027 3.200 % 700.0 700.0 2019 Debentures due 2029 3.250 % 400.0 400.0 2020 Debentures due 2030 3.950 % 400.0 400.0 2021 Debentures due 2051 3.100 % 300.0 300.0 2021 Debentures due 2031 1.950 % 300.0 300.0 2022 Debentures due 2052 4.550 % 450.0 450.0 2022 Debentures due 2052 4.950 % 400.0 400.0 2023 Debentures due 2028 5.600 % 150.0 150.0 2024 Debentures due 2034 5.400 % 600.0 600.0 2025 Debentures due 2030 4.850 % 400.0 — 2025 Debentures due 2035 5.200 % 700.0 — Total Debentures 5,850.0 5,000.0 Notes: 2004 Senior Notes Series B due 2034 5.900 % 50.0 50.0 2007 Senior Notes Series D due 2037 6.700 % 40.0 40.0 2016 Senior Notes Series H due 2026 2.750 % 50.0 50.0 Total Notes 140.0 140.0 Less Amounts due Within One Year (300.0) (250.0) Unamortized Premiums and Discounts, Net (8.1) (14.0) Unamortized Debt Issuance Costs (36.3) (31.1) NSTAR Electric Long-Term Debt $ 5,645.6 $ 4,844.9 PSNH (Millions of Dollars) As of December 31, Interest Rate 2025 2024 First Mortgage Bonds: 2005 Series M due 2035 5.600 % $ 50.0 $ 50.0 2019 Series T due 2049 3.600 % 300.0 300.0 2020 Series U due 2050 2.400 % 150.0 150.0 2021 Series V due 2031 2.200 % 350.0 350.0 2023 Series W due 2053 5.150 % 300.0 300.0 2023 Series X due 2033 5.350 % 600.0 600.0 2025 Series Y due 2028 4.400 % 300.0 — Total First Mortgage Bonds 2,050.0 1,750.0 Unamortized Premiums and Discounts, Net (2.8) (2.6) Unamortized Debt Issuance Costs (15.9) (15.3) PSNH Long-Term Debt $ 2,031.3 $ 1,732.1 111
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OTHER (Millions of Dollars) As of December 31, Interest Rate 2025 2024 Eversource Parent - Senior Notes due 2026 - 2050 1.400 % - 5.950% $ 11,350.0 $ 11,350.0 Yankee Gas - First Mortgage Bonds due 2026 - 2051 1.380 % - 5.740% 1,205.0 1,095.0 NSTAR Gas - First Mortgage Bonds due 2029 - 2051 2.250 % - 7.110% 1,055.0 905.0 EGMA - First Mortgage Bonds due 2028 - 2052 2.110 % - 5.730% 933.0 808.0 Aquarion - Unsecured Notes due 2028 - 2052 3.000 % - 6.430% 596.6 596.8 Aquarion - Secured Debt due 2027 - 2045 1.296 % - 9.290% 47.9 40.7 Pre-1983 Spent Nuclear Fuel Obligation (CYAPC) 5.9 5.6 Fair Value Adjustment 11.6 — Less Fair Value Adjustment - Current Portion (2.4) — Less Amounts due in One Year (1,090.5) (750.3) Unamortized Premiums and Discounts, Net 37.8 41.7 Unamortized Debt Issuance Costs (64.5) (76.1) Total Other Long-Term Debt $ 14,085.4 $ 14,016.4 Total Eversource Long-Term Debt $ 26,872.4 $ 25,701.6 As a result of the CL&P long-term debt issuance in January 2025, $397.1 million of current portion of long-term debt was reclassified to Long-Term Debt on Eversource’s and CL&P’s balance sheets as of December 31, 2024. The fair value adjustment amount is the purchase price adjustments, net of amortization, required to record Aquarion’s long-term debt at fair value upon the 2017 acquisition date. As of December 31, 2024, this fair value adjustment was reclassified to Liabilities Held for Sale. As of December 31, 2025, the fair value adjustment was reclassified to Long-Term Debt. For further information, see Note 24, “Assets Held for Sale.” Availability under Long-Term Debt Issuance Authorizations: On May 1, 2024, the DPU approved NSTAR Electric’s request for authorization to issue up to $2.40 billion in long-term debt through December 31, 2026. On August 12, 2024, the DPU approved EGMA’s request for authorization to issue up to $325 million in long-term debt through December 31, 2026. On December 18, 2024, the DPU approved NSTAR Gas’ request for authorization to issue up to $475 million in long-term debt through December 31, 2027. On March 26, 2025, PURA approved Yankee Gas’ request for authorization to issue up to $360 million in long-term debt through December 31, 2026. PSNH has utilized its long-term debt authorizations in place with NHPUC. CL&P has no long-term debt authorization remaining with PURA. (2) (2) (1) (2) 112
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Long-Term Debt Issuances and Repayments: The following table summarizes long-term debt issuances and repayments: (Millions of Dollars) Interest Rate Issuance/ (Repayment) Issue Date or Repayment Date Maturity Date Use of Proceeds for Issuance/ Repayment Information CL&P 2025 Series A First Mortgage Bonds 4.95 % 400.0 January 2025 January 2030 Repaid short-term debt, paid capital expendituresand working capital CL&P 2020 Series A First Mortgage Bonds 0.75 % (400.0) December 2025 December 2025 Paid at maturity NSTAR Electric Debentures 4.85 % 400.0 February 2025 March 2030 Repaid 3.25% Debentures at maturity, repaid short-term debt, paid capital expenditures and workingcapital NSTAR Electric Debentures 5.20 % 400.0 February 2025 March 2035 Repaid 3.25% Debentures at maturity, repaid short-term debt, paid capital expenditures and workingcapital NSTAR Electric Debentures 5.20 % 300.0 October 2025 March 2035 Repaid short-term debt, paid capital expendituresand working capital NSTAR Electric Debentures 3.25 % (250.0) November 2025 November 2025 Paid at maturity PSNH Series Y First Mortgage Bonds 4.40 % 300.0 June 2025 July 2028 Repaid short-term debt, paid capital expendituresand working capital Eversource Parent Series HH Senior Notes 4.45 % 600.0 October 2025 December 2030 Repay Series J bonds at maturity and repaid short-term debt Eversource Parent Series H Senior Notes 3.15 % (300.0) January 2025 January 2025 Paid at maturity Eversource Parent Series Q Senior Notes 0.80 % (300.0) August 2025 August 2025 Paid at maturity NSTAR Gas Series Y First Mortgage Bonds 4.86 % 205.0 June 2025 June 2030 Repaid short-term debt, paid capital expendituresand working capital NSTAR Gas Series Z First Mortgage Bonds 5.30 % 20.0 June 2025 June 2035 Repaid short-term debt, paid capital expendituresand working capital NSTAR Gas Series R First Mortgage Bonds 2.33 % (75.0) May 2025 May 2025 Paid at maturity Yankee Gas Series Y First Mortgage Bonds 5.02 % 148.0 July 2025 January 2031 Repaid Series M bonds at maturity, repaid short-term debt, paid capital expenditures and workingcapital Yankee Gas Series Z First Mortgage Bonds 5.55 % 37.0 July 2025 July 2035 Repaid Series M bonds at maturity, repaid short-term debt, paid capital expenditures and workingcapital Yankee Gas Series M First Mortgage Bonds 3.35 % (75.0) September 2025 September 2025 Paid at maturity EGMA Series F First Mortgage Bonds 4.77 % 125.0 September 2025 October 2030 Repaid short-term debt, paid capital expendituresand working capital Long-Term Debt Provisions: The utility plant of CL&P, PSNH, Yankee Gas, NSTAR Gas, EGMA and a portion of Aquarion is subject to the lien of each company's respective first mortgage bond indenture. The Eversource parent, NSTAR Electric and a portion of Aquarion debt is unsecured. Additionally, the long-term debt agreements provide that Eversource and certain of its subsidiaries must comply with certain covenants as are customarily included in such agreements, including equity requirements for NSTAR Electric, NSTAR Gas and Aquarion. Under the equity requirements, NSTAR Electric's and Aquarion's senior notes must maintain a certain consolidated indebtedness to capitalization ratio as of the end of any fiscal quarter and NSTAR Gas' outstanding long-term debt must not exceed equity. Certain secured and unsecured long-term debt securities are callable at redemption price or are subject to make-whole provisions. No long-term debt defaults have occurred as of December 31, 2025. CYAPC's Pre-1983 Spent Nuclear Fuel Obligation: Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. CYAPC is obligated to pay the DOE for the costs to dispose of spent nuclear fuel and high-level radioactive waste generated prior to April 7, 1983 (pre-1983 Spent Nuclear Fuel). CYAPC has partially paid this obligation and recorded an accrual for its remaining liability to the DOE. This liability accrues interest costs at the 3-month Treasury bill yield rate. For nuclear fuel used to generate electricity prior to April 7, 1983, payment may be made any time prior to the first delivery of spent fuel to the DOE. As of December 31, 2025 and 2024, as a result of consolidating CYAPC, Eversource has consolidated $5.9 million and $5.6 million, respectively, in pre- 1983 spent nuclear fuel obligations to the DOE. The obligation includes accumulated interest costs of $4.6 million and $4.3 million as of December 31, 2025 and 2024, respectively. CYAPC maintains a trust to fund amounts due to the DOE for the disposal of pre-1983 spent nuclear fuel. For further information, see Note 5, "Marketable Securities," to the financial statements. Fees for disposal of nuclear fuel burned on or after April 7, 1983 were billed to member companies and paid to the DOE. 113
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Long-Term Debt Maturities: Long-term debt maturities on debt outstanding for the years 2026 through 2030 and thereafter are shown below. These amounts exclude PSNH rate reduction bonds, CYAPC pre-1983 spent nuclear fuel obligation, and unamortized premiums, discounts, and debt issuance costs as of December 31, 2025: (Millions of Dollars) Eversource CL&P NSTAR Electric PSNH 2026 $ 1,390.5 $ — $ 300.0 $ — 2027 2,889.5 500.0 700.0 — 2028 2,278.8 — 150.0 300.0 2029 2,300.5 350.0 400.0 — 2030 2,904.0 400.0 800.0 — Thereafter 16,594.2 3,880.0 3,640.0 1,750.0 Total $ 28,357.5 $ 5,130.0 $ 5,990.0 $ 2,050.0 10. RATE REDUCTION BONDS AND VARIABLE INTEREST ENTITIES Rate Reduction Bonds: In May 2018, PSNH Funding, a wholly-owned subsidiary of PSNH, issued $635.7 million of securitized RRBs in multiple tranches with a weighted average interest rate of 3.66 percent, and final maturity dates ranging from 2026 to 2035. The RRBs are expected to be repaid by February 1, 2033. RRB payments consist of principal and interest and are paid semi-annually, beginning on February 1, 2019. The RRBs were issued pursuant to a finance order issued by the NHPUC in January 2018 to recover remaining costs resulting from the divestiture of PSNH’s generation assets. The proceeds were used by PSNH Funding to purchase PSNH’s stranded cost asset-recovery property, including its vested property right to bill, collect and adjust a non-bypassable stranded cost recovery charge from PSNH’s retail customers. The collections are used to pay principal, interest and other costs in connection with the RRBs. The RRBs are secured by the stranded cost asset-recovery property. Cash collections from the stranded cost recovery charges and funds on deposit in trust accounts are the sole source of funds to satisfy the debt obligation. PSNH is not the owner of the RRBs, and PSNH Funding’s assets and revenues are not available to pay PSNH’s creditors. The RRBs are non-recourse senior secured obligations of PSNH Funding and are not insured or guaranteed by PSNH or Eversource Energy. PSNH Funding was formed solely to issue RRBs to finance PSNH's unrecovered remaining costs associated with the divestiture of its generation assets. PSNH Funding is considered a VIE primarily because the equity capitalization is insufficient to support its operations. PSNH has the power to direct the significant activities of the VIE and is most closely associated with the VIE as compared to other interest holders. Therefore, PSNH is considered the primary beneficiary and consolidates PSNH Funding in its consolidated financial statements. The following tables summarize the impact of PSNH Funding on PSNH's balance sheets and income statements: (Millions of Dollars) As of December 31, PSNH Balance Sheets: 2025 2024 Restricted Cash - Current Portion (included in Special Deposits) $ 30.6 $ 31.0 Restricted Cash - Long-Term Portion (included in Other Long-Term Assets) 3.2 3.1 Securitized Stranded Cost (included in Regulatory Assets) 306.1 349.3 Other Regulatory Liabilities (included in Regulatory Liabilities) 7.3 6.9 Accrued Interest (included in Other Current Liabilities) 5.1 5.7 Rate Reduction Bonds - Current Portion 43.2 43.2 Rate Reduction Bonds - Long-Term Portion 280.9 324.1 (Millions of Dollars) PSNH Income Statements: For the Years Ended December 31, 2025 2024 2023 Amortization of RRB Principal (included in Amortization of Regulatory Assets/(Liabilities), Net) $ 43.2 $ 43.2 $ 43.2 Interest Expense on RRB Principal (included in Interest Expense) 12.8 14.3 15.7 Estimated principal payments on RRBs as of December 31, 2025, is summarized annually through 2030 and thereafter as follows: (Millions of Dollars) 2026 2027 2028 2029 2030 Thereafter Total PSNH $ 43.2 $ 43.2 $ 43.2 $ 43.2 $ 43.2 $ 108.1 $ 324.1 Variable Interest Entities - Other: The Company's variable interests outside of the consolidated group include contracts that are required by regulation and provide for regulatory recovery of contract costs and benefits through customer rates. Eversource, CL&P and NSTAR Electric hold variable interests in VIEs through agreements with certain entities that own single renewable energy or peaking generation power plants, with other independent power producers and with transmission businesses. Eversource, CL&P and NSTAR Electric do not control the activities that are economically significant to these VIEs or provide financial or other support to these VIEs. Therefore, Eversource, CL&P and NSTAR Electric do not consolidate these VIEs. 114
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11. EMPLOYEE BENEFITS A. Pension Benefits and Postretirement Benefits Other Than Pension Eversource provides defined benefit retirement plans (Pension Plans) that cover eligible employees and are subject to the provisions of ERISA, as amended by the Pension Protection Act of 2006. Eversource's policy is to annually fund, as necessary, the Pension Plans in an amount at least equal to an amount that will satisfy all federal funding requirements. In addition to the Pension Plans, Eversource maintains non-qualified defined benefit retirement plans (SERP Plans), which provide benefits in excess of Internal Revenue Code limitations to eligible participants consisting of current and retired employees. Eversource also provides defined benefit postretirement plans (PBOP Plans) that provide life insurance and a health reimbursement arrangement created for the purpose of reimbursing retirees and dependents for health insurance premiums and certain medical expenses to eligible employees that meet certain age and service eligibility requirements. The benefits provided under the PBOP Plans are not vested, and the Company has the right to modify any benefit provision subject to applicable laws at that time. Eversource annually funds, as necessary, postretirement costs through tax deductible contributions to external trusts. Effective January 1, 2025, a Cash Balance Pension Plan was established, which replaced employer K-Vantage contributions. Eversource transferred into the Cash Balance Pension Plan employees who were participants in the K-Vantage plan, with the exception of one union group that voted to enter effective January 1, 2026, and will credit employees a set percentage of an employee’s eligible pay based on age and years of service on the employee’s behalf. This benefit is an additional obligation of the existing Pension Plan and will be funded through the existing assets of the Eversource Service Pension Plan. The liability began accruing benefits upon the effective date of January 1, 2025. Funded Status: The Pension, SERP and PBOP Plans are accounted for under the multiple-employer approach, with each operating company's balance sheet reflecting its share of the funded status of the plans. The SERP Plans do not contain any assets. The following tables provide information on the plan benefit obligations, fair values of plan assets, and funded status: Pension and SERP As of December 31, 2025 2024 (Millions of Dollars) Eversource CL&P NSTARElectric PSNH Eversource CL&P NSTARElectric PSNH Change in Benefit Obligation: Benefit Obligation as of Beginning of Year $ (4,745.7) $ (982.9) $ (1,003.5) $ (521.5) $ (5,238.4) $ (1,048.5) $ (1,107.0) $ (562.3) Service Cost (67.9) (15.3) (9.7) (6.5) (44.3) (12.7) (7.7) (4.3) Interest Cost (255.6) (51.5) (53.0) (27.1) (250.0) (50.3) (51.6) (26.8) Actuarial (Loss)/Gain (190.0) (37.8) (54.5) (11.7) 280.2 56.2 74.1 30.7 Benefits Paid - Pension 334.5 69.1 67.2 38.8 320.9 68.1 67.1 38.0 Benefits Paid - Lump Sum 28.5 0.1 12.9 1.3 24.0 — 7.6 0.1 Benefits Paid - SERP 18.8 0.4 0.1 0.4 19.4 0.3 0.2 0.4 Employee Transfers (0.3) 1.2 2.8 0.1 — 4.0 13.8 2.7 Water Reclassified as Assets Held for Sale — — — — 142.5 — — — Water Reclassified from Assets Held for Sale (142.5) — — — — — — — Benefit Obligation as of End of Year $ (5,020.2) $ (1,016.7) $ (1,037.7) $ (526.2) $ (4,745.7) $ (982.9) $ (1,003.5) $ (521.5) Change in Pension Plan Assets: Fair Value of Pension Plan Assets as of Beginning of Year $ 5,514.0 $ 1,144.4 $ 1,378.2 $ 597.5 $ 5,775.0 $ 1,170.0 $ 1,411.6 $ 614.0 Employer Contributions 2.5 — — — 5.0 — — — Actual Return on Pension Plan Assets 588.4 119.3 144.7 61.3 227.0 46.5 55.1 24.3 Benefits Paid - Pension (334.5) (69.1) (67.2) (38.8) (320.9) (68.1) (67.1) (38.0) Benefits Paid - Lump Sum (28.5) (0.1) (12.9) (1.3) (24.0) — (7.6) (0.1) Employee Transfers — (1.2) (2.8) (0.1) — (4.0) (13.8) (2.7) Water Reclassified as Assets Held for Sale — — — — (148.1) — — — Water Reclassified from Assets Held for Sale 148.1 — — — — — — — Fair Value of Pension Plan Assets as of End of Year $ 5,890.0 $ 1,193.3 $ 1,440.0 $ 618.6 $ 5,514.0 $ 1,144.4 $ 1,378.2 $ 597.5 Funded Status as of December 31st $ 869.8 $ 176.6 $ 402.3 $ 92.4 $ 768.3 $ 161.5 $ 374.7 $ 76.0 Actuarial Gain/(Loss): For the year ended December 31, 2025, the actuarial loss was primarily attributable to a decrease in the discount rate, which resulted in an increase to Eversource’s Pension and SERP Plans’ projected benefit obligation of $98.2 million, a $38.1 million loss related to updated census data, and a $28 million loss related to the salary scale assumption. For the year ended December 31, 2024, the actuarial gain was primarily attributable to an increase in the discount rate, which resulted in a decrease to Eversource's Pension and SERP Plans’ projected benefit obligation of $332.9 million, partially offset by an actuarial loss of $42.1 million related to updated census data. 115
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As of December 31, 2025 and 2024, the accumulated benefit obligation for the Pension and SERP Plans is as follows: (Millions of Dollars) Eversource CL&P NSTAR Electric PSNH 2025 $ 4,856.5 $ 981.5 $ 992.2 $ 513.1 2024 4,617.1 953.9 969.5 507.4 PBOP As of December 31, 2025 2024 (Millions of Dollars) Eversource CL&P NSTARElectric PSNH Eversource CL&P NSTARElectric PSNH Change in Benefit Obligation: Benefit Obligation as of Beginning of Year $ (587.4) $ (109.1) $ (171.4) $ (65.9) $ (676.0) $ (120.6) $ (188.3) $ (72.0) Service Cost (6.4) (1.1) (1.1) (0.5) (7.0) (1.2) (1.2) (0.6) Interest Cost (32.0) (5.6) (8.7) (3.4) (31.9) (5.6) (8.8) (3.4) Actuarial (Loss)/Gain (11.3) (1.6) (3.5) (1.2) 41.3 8.9 10.7 3.9 Benefits Paid 51.7 9.3 16.0 6.0 51.7 9.4 15.9 6.2 Employee Transfers — 0.1 — 0.2 — — 0.3 — Water Reclassified as Assets Held for Sale — — — — 34.5 — — — Water Reclassified from Assets Held for Sale (34.5) — — — — — — — Benefit Obligation as of End of Year $ (619.9) $ (108.0) $ (168.7) $ (64.8) $ (587.4) $ (109.1) $ (171.4) $ (65.9) Change in Plan Assets: Fair Value of Plan Assets as of Beginning of Year $ 1,036.3 $ 124.4 $ 519.2 $ 76.4 $ 1,024.4 $ 123.0 $ 490.4 $ 74.7 Actual Return on Plan Assets 131.9 14.9 65.0 9.3 92.3 11.2 45.8 7.6 Employer Contributions 0.7 — — — 0.9 — — — Benefits Paid (51.3) (9.3) (16.0) (5.9) (51.8) (9.4) (15.9) (6.1) Employee Transfers — (0.3) 0.6 (0.2) — (0.4) (1.1) 0.2 Water Reclassified as Assets Held for Sale — — — — (29.5) — — — Water Reclassified from Assets Held for Sale 29.5 — — — — — — — Fair Value of Plan Assets as of End of Year $ 1,147.1 $ 129.7 $ 568.8 $ 79.6 $ 1,036.3 $ 124.4 $ 519.2 $ 76.4 Funded Status as of December 31st $ 527.2 $ 21.7 $ 400.1 $ 14.8 $ 448.9 $ 15.3 $ 347.8 $ 10.5 Actuarial Gain/(Loss): For the year ended December 31, 2025, the actuarial loss was primarily attributable to a decrease in the discount rate, which resulted in an increase to the Eversource PBOP projected benefit obligation of $11.2 million. For the year ended December 31, 2024, the actuarial gain was primarily attributable to an increase in the discount rate, which resulted in a decrease to the Eversource PBOP projected benefit obligation of $39.8 million. A reconciliation of the prepaid assets and liabilities within the Eversource Pension, SERP and PBOP Plans’ funded status to the balance sheets is as follows: As of December 31, 2025 2024 (Millions of Dollars) Eversource CL&P NSTARElectric PSNH Eversource CL&P NSTARElectric PSNH Prepaid Pension $ 982.0 $ 182.4 $ 404.0 $ 97.0 $ 887.7 $ 167.2 $ 376.9 $ 80.5 Prepaid PBOP 529.2 21.7 400.1 14.8 448.9 15.3 347.8 10.5 Prepaid Pension and PBOP $ 1,511.2 $ 204.1 $ 804.1 $ 111.8 $ 1,336.6 $ 182.5 $ 724.7 $ 91.0 Accrued SERP $ (112.2) $ (5.8) $ (1.7) $ (4.6) $ (119.4) $ (5.7) $ (2.2) $ (4.5) Accrued PBOP (2.0) — — — — — — — Less: Accrued SERP - current portion 13.3 0.3 — 0.4 24.0 0.4 0.2 0.4 Accrued SERP and PBOP $ (100.9) $ (5.5) $ (1.7) $ (4.2) $ (95.4) $ (5.3) $ (2.0) $ (4.1) As of December 31, 2024, the Aquarion water distribution business’s prepaid pension was reclassified to Assets Held for Sale and the accrued SERP and PBOP liabilities were reclassified to Liabilities Held for Sale on the Eversource balance sheet. As of December 31, 2025, these balances were reclassified to Prepaid Pension and Accrued SERP and PBOP on the Eversource balance sheet. For further information, see Note 24, “Assets Held for Sale.” (1) (1) (1) (1) 116
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The following actuarial assumptions were used in calculating the Pension, SERP and PBOP Plans' year end funded status: Pension and SERP PBOP As of December 31, As of December 31, 2025 2024 2025 2024 Discount Rate 4.9% — 5.5% 5.6% — 5.7% 5.4% — 5.5% 5.7% Compensation/Progression Rate 3.5% — 4.0% 3.5% — 4.0% N/A Cash Balance Interest Crediting Rate 4.8% N/A N/A For the Eversource Service PBOP Plan, the health care cost trend rate is not applicable. For the Aquarion PBOP Plan, the health care cost trend rate for pre-65 retirees is 7.25 percent, with an ultimate rate of 5 percent in 2035, and for post-65 retirees, the health care trend rate and ultimate rate is 3.5 percent. Expense: Eversource charges net periodic benefit plan expense/(income) for the Pension, SERP and PBOP Plans to its subsidiaries based on the actual participant demographic data for each subsidiary's participants. The actual investment return in the trust is allocated to each of the subsidiaries annually in proportion to the investment return expected to be earned during the year. The Company utilizes the spot rate methodology to estimate the discount rate for the service and interest cost components of benefit plan expense, which provides a relatively precise measurement by matching projected cash flows to the corresponding spot rates on the yield curve. The components of net periodic benefit plan expense/(income) for the Pension, SERP and PBOP Plans, prior to amounts capitalized as Property, Plant and Equipment or deferred as regulatory assets/(liabilities) for future recovery or refund, are shown below. The service cost component of net periodic benefit plan expense/(income), less the capitalized portion, is included in Operations and Maintenance expense on the statements of income. The remaining components of net periodic benefit plan expense/(income), less the deferred portion, are included in Other Income, Net on the statements of income. Pension, SERP and PBOP plan expense/(income) reflected in the statements of cash flows for CL&P, NSTAR Electric and PSNH does not include intercompany allocations of net periodic benefit plan expense/(income), as these amounts are cash settled on a short-term basis. Pension and SERP PBOP For the Year Ended December 31, 2025 For the Year Ended December 31, 2025 (Millions of Dollars) Eversource CL&P NSTARElectric PSNH Eversource CL&P NSTARElectric PSNH Service Cost $ 67.9 $ 15.3 $ 9.7 $ 6.5 $ 6.4 $ 1.1 $ 1.1 $ 0.5 Interest Cost 255.6 51.5 53.0 27.1 32.0 5.6 8.7 3.4 Expected Return on Plan Assets (454.3) (91.8) (110.7) (47.8) (84.6) (9.6) (42.0) (5.7) Actuarial Loss/(Gain) 42.9 5.1 14.3 2.1 (0.9) — — — Prior Service Cost/(Credit) 1.1 — 0.3 — (21.6) 1.1 (17.0) 0.4 Settlement Loss 3.3 — — — — — — — Total Net Periodic Benefit Plan Income $ (83.5) $ (19.9) $ (33.4) $ (12.1) $ (68.7) $ (1.8) $ (49.2) $ (1.4) Intercompany Income Allocations N/A $ (1.4) $ (0.5) $ (0.1) N/A $ (2.1) $ (2.7) $ (0.9) Pension and SERP PBOP For the Year Ended December 31, 2024 For the Year Ended December 31, 2024 (Millions of Dollars) Eversource CL&P NSTAR Electric PSNH Eversource CL&P NSTAR Electric PSNH Service Cost $ 44.3 $ 12.7 $ 7.7 $ 4.3 $ 7.0 $ 1.2 $ 1.2 $ 0.6 Interest Cost 250.0 50.3 51.6 26.8 31.9 5.6 8.8 3.4 Expected Return on Plan Assets (462.6) (93.5) (112.4) (48.9) (81.2) (9.5) (39.5) (5.6) Actuarial Loss/(Gain) 85.9 12.1 25.6 5.0 (0.4) — — — Prior Service Cost/(Credit) 1.3 — 0.3 — (21.6) 1.1 (17.0) 0.4 Settlement Loss 4.3 — — — — — — — Total Net Periodic Benefit Plan Income $ (76.8) $ (18.4) $ (27.2) $ (12.8) $ (64.3) $ (1.6) $ (46.5) $ (1.2) Intercompany Income Allocations N/A $ (1.6) $ (1.3) $ (0.4) N/A $ (2.2) $ (2.6) $ (0.9) 117
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Pension and SERP PBOP For the Year Ended December 31, 2023 For the Year Ended December 31, 2023 (Millions of Dollars) Eversource CL&P NSTARElectric PSNH Eversource CL&P NSTARElectric PSNH Service Cost $ 43.1 $ 12.3 $ 7.8 $ 4.3 $ 7.6 $ 1.3 $ 1.2 $ 0.7 Interest Cost 254.0 50.5 53.9 27.3 33.8 6.2 9.2 3.7 Expected Return on Plan Assets (465.0) (94.2) (113.8) (49.5) (77.1) (9.4) (36.9) (5.5) Actuarial Loss 45.8 2.5 17.1 1.5 — — — — Prior Service Cost/(Credit) 1.3 — 0.3 — (21.6) 1.1 (17.0) 0.4 Settlement Loss 12.4 — — — — — — — Total Net Periodic Benefit Plan Income $ (108.4) $ (28.9) $ (34.7) $ (16.4) $ (57.3) $ (0.8) $ (43.5) $ (0.7) Intercompany Income Allocations N/A $ (4.0) $ (3.0) $ (0.8) N/A $ (1.9) $ (2.1) $ (0.7) The following actuarial assumptions were used to calculate Pension, SERP and PBOP expense amounts: Pension and SERP PBOP For the Years Ended December 31, For the Years Ended December 31, 2025 2024 2023 2025 2024 2023 Discount Rate 5.2% — 5.8% 4.7% — 5.1% 4.9% — 5.3% 5.4% — 5.9% 4.9% —5.2% 5.1% —5.4% Expected Long-Term Rate of Return 8.25% 8.25% 8.25% 8.25% 8.25% 8.25% Compensation/Progression Rate 3.5% — 4.0% 3.5% — 4.0% 3.5% — 4.0% N/A N/A N/A For the Aquarion Pension Plan, the expected long-term rate of return was 8.25 percent for the years ended December 31, 2025 and 2024 and 7.94 percent for the year ended December 31, 2023. For the Aquarion PBOP Plan, the expected long-term rate of return was 7 percent for the years ended December 31, 2025, 2024 and 2023 and the health care cost trend rate was a range of 3.5 percent to 7.5 percent for the year ended December 31, 2025, 3.5 percent to 6.75 percent for the year ended December 31, 2024 and 3.5 percent to 7 percent for the year ended December 31, 2023 . Regulatory Assets and Accumulated Other Comprehensive Income/(Loss) Amounts: The Pension, SERP and PBOP Plans cover eligible employees, including, among others, employees of the regulated companies. The regulated companies record actuarial losses and gains and prior service costs and credits arising at the December 31st remeasurement date of the funded status of the benefit plans as a regulatory asset or regulatory liability in lieu of a charge to Accumulated Other Comprehensive Income/(Loss), reflecting ultimate recovery from customers through rates. Regulatory accounting is also applied to the portions of the Eversource Service retiree benefit costs that support the regulated companies, as these costs are also recovered from customers. Adjustments to the Pension, SERP and PBOP Plans' funded status for the unregulated companies are recorded on an after-tax basis to Accumulated Other Comprehensive Income/(Loss). For further information, see Note 2, "Regulatory Accounting," and Note 16, "Accumulated Other Comprehensive Income/(Loss)," to the financial statements. The difference between the actual return and calculated expected return on plan assets for the Pension and PBOP Plans, as well as changes in actuarial assumptions impacting the projected benefit obligation, are recorded as unamortized actuarial gains or losses arising during the year in Regulatory Assets or Accumulated Other Comprehensive Income/(Loss). Unamortized actuarial gains or losses are amortized as a component of pension and PBOP expense over the estimated average future employee service period using the corridor approach. The following is a summary of the changes in plan assets and benefit obligations recognized in Regulatory Assets and Other Comprehensive Income (OCI) as well as amounts in Regulatory Assets and OCI that were reclassified as net periodic benefit expense during the years presented: Pension and SERP PBOP Regulatory Assets OCI Regulatory Assets OCI For the Years Ended December 31, For the Years Ended December 31, (Millions of Dollars) 2025 2024 2025 2024 2025 2024 2025 2024 Actuarial Loss/(Gain) Arising During the Year $ 57.0 $ (49.2) $ — $ 2.3 $ (36.8) $ (50.9) $ — $ (0.6) Actuarial (Loss)/Gain Reclassified as Net Periodic Benefit(Expense)/Income (38.7) (79.1) (4.2) (6.8) 0.9 0.4 — — Actuarial (Loss)/Gain Reclassified as Held for Sale — (16.6) — — — 7.1 — — Actuarial Loss/(Gain) Reclassified from Held for Sale 16.6 — — — (7.1) — — — Settlement Loss — — (3.3) (4.3) — — — — Prior Service Cost Arising During the Year 0.1 1.3 — — — — — — Prior Service (Cost)/Credit Reclassified as Net Periodic Benefit (Expense)/Income (1.3) (1.2) 0.2 (0.1) 21.8 21.8 (0.2) (0.2) Prior Service Cost Reclassified as Held for Sale — (1.2) — — — (0.6) — — Prior Service Cost Reclassified from Held for Sale 1.2 — — — 0.6 — — — 118
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The following is a summary of the remaining Regulatory Assets and Accumulated Other Comprehensive Income amounts that have not been recognized as components of net periodic benefit expense as of December 31, 2025 and 2024: Regulatory Assets as of December 31, AOCI as of December 31, (Millions of Dollars) 2025 2024 2025 2024 Pension and SERP Actuarial Loss $ 991.0 $ 956.1 $ 40.2 $ 47.7 Prior Service Cost 1.8 1.8 0.4 0.2 PBOP Actuarial (Gain)/Loss $ (36.6) $ 6.4 $ 1.8 $ 1.8 Prior Service (Credit)/Cost (43.8) (66.2) 0.3 0.5 Estimated Future Benefit Payments: The following benefit payments, which reflect expected future service, are expected to be paid by the Pension, SERP and PBOP Plans: (Millions of Dollars) 2026 2027 2028 2029 2030 2031 - 2035 Pension and SERP $ 375.4 $ 383.3 $ 387.3 $ 390.9 $ 394.0 $ 1,969.3 PBOP 53.0 52.3 51.5 50.6 49.6 232.1 Eversource Contributions: Based on the current status of the Pension Plans and federal pension funding requirements, for the Eversource Service Pension Plan there is no minimum funding requirement in 2026 and Eversource does not expect to make pension contributions in 2026. Eversource does not expect to make any contributions to the Eversource Service PBOP Plan in 2026. Eversource contributed $2.5 million and $0.7 million to the Aquarion Pension and PBOP Plans, respectively, in 2025. Eversource currently estimates contributing $2.5 million and $2.8 million to the Aquarion Pension and PBOP Plans, respectively, in 2026. Fair Value of Pension and PBOP Plan Assets: Pension and PBOP funds are held in external trusts. Trust assets, including accumulated earnings, must be used exclusively for Pension and PBOP payments. Eversource's investment strategy for its Pension and PBOP Plans is to maximize the long-term rates of return on these plans' assets within an acceptable level of risk. The investment guidelines for each asset category includes a diversification of asset types, fund strategies and fund managers and it establishes target asset allocations that are routinely reviewed and periodically rebalanced. PBOP assets are comprised of assets held in the PBOP Plan trust, as well as specific assets within the Pension Plan trust (401(h) assets). The investment policy and strategy of the 401(h) assets is consistent with that of the defined benefit pension plan. Eversource's expected long-term rates of return on Pension and PBOP Plan assets are based on target asset allocation assumptions and related expected long-term rates of return. In developing its expected long-term rate of return assumptions for the Pension and PBOP Plans, Eversource evaluated input from consultants, as well as long-term inflation assumptions and historical returns. Management has assumed long-term rates of return of 8.25 percent for the Eversource Service Pension Plan assets and the Eversource Service PBOP Plan assets, and a 7 percent long-term rate of return for the Aquarion Pension Plan assets and the Aquarion PBOP Plan assets, to estimate its 2026 Pension and PBOP costs. These long-term rates of return are based on the assumed rates of return for the target asset allocations as follows: As of December 31, 2025 2024 Target Asset Allocation Assumed Rate of Return Target Asset Allocation Assumed Rate of Return Eversource Pension Plan Eversource PBOP Plan Eversource PensionPlan and PBOP Plan Eversource Pension Plan Eversource PBOP Plan Eversource PensionPlan and PBOP Plan Equity Securities: United States — % 20.0 % 8.5 % — % 20.0 % 8.5 % Global 20.0 % — % 8.8 % 20.0 % — % 8.8 % Non-United States — % 11.0 % 8.5 % — % 11.0 % 8.5 % Emerging Markets — % 6.0 % 10.0 % — % 6.0 % 10.0 % Debt Securities: Fixed Income 16.0 % 17.0 % 5.5 % 16.0 % 17.0 % 5.5 % High Yield Fixed Income 5.0 % — % 7.5 % 5.0 % — % 7.5 % United States Treasuries 11.0 % — % 4.5 % 11.0 % — % 4.5 % Private Debt 10.0 % 13.0 % 10.0 % 10.0 % 13.0 % 10.0 % Private Equity 23.0 % 18.0 % 12.0 % 23.0 % 18.0 % 12.0 % Real Assets 15.0 % 15.0 % 7.5 % 15.0 % 15.0 % 7.5 % 119
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The following tables present, by asset category, the Pension and PBOP Plan assets recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy: Pension Plan Fair Value Measurements as of December 31, (Millions of Dollars) 2025 2024 Asset Category: Level 1 Level 2 Uncategorized Total Level 1 Level 2 Uncategorized Total Equity Securities 302.8 110.9 816.2 1,229.9 323.6 — 826.0 1,149.6 Fixed Income 340.4 502.1 1,325.6 2,168.1 314.3 344.7 1,329.6 1,988.6 Private Equity — — 1,799.1 1,799.1 — — 1,710.9 1,710.9 Real Assets 158.3 127.5 638.9 924.7 243.8 — 652.2 896.0 Total $ 801.5 $ 740.5 $ 4,579.8 $ 6,121.8 $ 881.7 $ 344.7 $ 4,518.7 $ 5,745.1 Less: 401(h) PBOP Assets (231.8) (231.1) Total Pension Assets $ 5,890.0 $ 5,514.0 PBOP Plan Fair Value Measurements as of December 31, (Millions of Dollars) 2025 2024 Asset Category: Level 1 Level 2 Uncategorized Total Level 1 Level 2 Uncategorized Total Equity Securities 132.7 48.3 214.4 395.4 184.8 — 166.3 351.1 Fixed Income 45.5 41.5 185.9 272.9 61.8 44.6 127.5 233.9 Private Equity — — 120.1 120.1 — — 99.0 99.0 Real Assets 79.0 6.3 41.6 126.9 83.7 — 37.5 121.2 Total $ 257.2 $ 96.1 $ 562.0 $ 915.3 $ 330.3 $ 44.6 $ 430.3 $ 805.2 Add: 401(h) PBOP Assets 231.8 231.1 Total PBOP Assets $ 1,147.1 $ 1,036.3 Fixed Income and Equity Securities classified as Level 2 as of December 31, 2025 include pending redemption settlements of $37.2 million and $15.4 million, respectively. Equity Securities classified as Level 2 as of December 31, 2025 include pending redemption settlements of $46.8 million. As of December 31, 2024, the funded status of the Aquarion water distribution business’s Pension and PBOP benefit plans were reclassified as held for sale presentation on the Eversource balance sheet. Therefore, these Pension and PBOP asset balances were excluded from the tables above as of December 31, 2024. As of December 31, 2025, the funded status of the Aquarion water distribution business’ Pension and PBOP benefit plans was no longer classified as held for sale in the Eversource balance sheet and the asset balances are included in the tables above. See Note 24, "Assets Held for Sale," for further information. The assets of the Pension Plan include a 401(h) account that has been allocated to provide health and welfare postretirement benefits under the PBOP Plan. The Company values assets based on observable inputs when available. Equity securities, fixed income exchange traded funds and real asset futures contracts classified as Level 1 in the fair value hierarchy are priced based on the closing price on the primary exchange as of the balance sheet date. Fixed income securities, such as government issued securities and corporate bonds, are included in Level 2 and are valued using pricing models, quoted prices of securities with similar characteristics or discounted cash flows. The pricing models utilize observable inputs such as recent trades for the same or similar instruments, yield curves, discount margins and bond structures. Swaps are valued using pricing models that incorporate interest rates and equity and fixed income index closing prices to determine a net present value of the cash flows. Certain investments, such as commingled funds, private equity investments, fixed income funds, real asset funds and hedge funds are valued using the net asset value (NAV) as a practical expedient. Assets valued at NAV are uncategorized in the fair value hierarchy. These investments are structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. Commingled funds are recorded at NAV provided by the asset manager, which is based on the market prices of the underlying equity securities. Private Equity investments, Fixed Income partnership funds and Real Assets are valued using the NAV provided by the partnerships, which are based on discounted cash flows of the underlying investments, real estate appraisals or public market comparables of the underlying investments, or the NAV of underlying assets held in hedge funds. Equity Securities investments in United States, Global, Non-United States and Emerging Markets that are uncategorized include investments in commingled funds and hedge funds that are overlaid with equity index swaps and futures contracts. Fixed Income investments that are uncategorized include investments in commingled funds, fixed income funds that invest in a variety of opportunistic credit and private debt strategies, and hedge funds that are overlaid with fixed income swaps and futures contracts. (1) (3) (3) (2) (3) (4) (1) (2) (3) (4) 120
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B. Defined Contribution Plans Eversource maintains defined contribution plans on behalf of eligible participants. The Eversource 401k Plan provides for employee and employer contributions up to statutory limits. For the year ended December 31, 2025, for eligible employees, the Eversource 401k Plan provided employer matching contributions of 100 percent up to a maximum of six percent of eligible compensation. For the years ended December 31, 2024 and 2023, for eligible employees, the Eversource 401k Plan provided employer matching contributions of either 100 percent up to a maximum of three percent of eligible compensation or 50 percent up to a maximum of eight percent of eligible compensation. In 2024 and 2023, the Eversource 401k Plan also contained a K-Vantage feature for the benefit of eligible participants, which provided an additional annual employer contribution based on age and years of service. K-Vantage participants were not eligible to actively participate in the Eversource Service Pension Plan. Effective January 1, 2025, with the exception of one union group that voted to enter effective January 1, 2026, Eversource replaced employer K-Vantage contributions with the Cash Balance Pension Plan. See Note 11A, "Employee Benefits – Pension Benefits and Postretirement Benefits Other Than Pension," for further information. The total Eversource 401k Plan employer matching contributions, including the K-Vantage contributions, were as follows: (Millions of Dollars) Eversource CL&P NSTAR Electric PSNH 2025 $ 68.6 $ 9.3 $ 15.7 $ 5.1 2024 76.2 10.6 15.4 6.0 2023 67.3 9.0 13.7 5.4 C. Share-Based Payments Share-based compensation awards are recorded using a fair-value based method at the date of grant. Eversource, CL&P, NSTAR Electric and PSNH record compensation expense related to these awards, as applicable, for shares issued to their respective employees and officers, as well as for the allocation of costs associated with shares issued to Eversource's service company employees and officers that support CL&P, NSTAR Electric and PSNH. Eversource Incentive Plans: Eversource maintains long-term equity-based incentive plans in which Eversource, CL&P, NSTAR Electric and PSNH employees, officers and board members are eligible to participate. The incentive plans authorize Eversource to grant up to 7,400,000 new shares for various types of awards, including RSUs and performance shares, to eligible employees, officers, and board members. As of December 31, 2025 and 2024, Eversource had 3,051,466 and 3,790,353 common shares, respectively, available for issuance under these plans. Eversource accounts for its various share-based plans as follows: • RSUs - Eversource records compensation expense, net of estimated forfeitures, on a straight-line basis over the requisite service period based upon the fair value of Eversource's common shares at the date of grant. The par value of RSUs is reclassified to Common Stock from Capital Surplus, Paid In as RSUs become issued as common shares. • Performance Shares - Eversource records compensation expense, net of estimated forfeitures, over the requisite service period. Performance shares vest based upon the extent to which Company goals are achieved. Vesting of outstanding performance shares is based upon the Company's EPS growth over the requisite service period and level of payout is determined based on the total shareholder return as compared to the Edison Electric Institute (EEI) Index during the requisite service period. The fair value of performance shares is determined at the date of grant using a lattice model. Compensation expense is subject to volatility until payout is established. RSUs: Eversource granted RSUs under the annual long-term incentive programs that are subject to three-year graded vesting schedules for employees, and one-year graded vesting schedules, or immediate vesting, for board members. RSUs are paid in shares, reduced by amounts sufficient to satisfy withholdings for income taxes, subsequent to vesting. A summary of RSU transactions is as follows: RSUs(Units) Weighted AverageGrant-Date Fair Value Outstanding as of December 31, 2024 715,442 $ 61.95 Granted 345,870 $ 57.63 Shares Issued (306,679) $ 65.99 Forfeited (23,452) $ 63.23 Outstanding as of December 31, 2025 731,181 $ 58.17 The weighted average grant-date fair value of RSUs granted for the years ended December 31, 2025, 2024 and 2023 was $57.63, $57.93 and $76.42, respectively. As of December 31, 2025 and 2024, the number and weighted average grant-date fair value of unvested RSUs was 534,754 and $59.50 per share, and 455,620 and $65.29 per share, respectively. During 2025, there were 239,469 RSUs at a weighted average grant-date fair value of $68.77 per share that vested during the year and were either paid or deferred. As of December 31, 2025, 196,427 RSUs were fully vested and deferred and an additional 508,017 are expected to vest. 121
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Performance Shares: Eversource granted performance shares under the annual long-term incentive programs that vest based upon the extent to which Company goals are achieved at the end of three-year performance measurement periods. Performance shares are paid in shares, after the performance measurement period. A summary of performance share transactions is as follows: Performance Shares (Units) Weighted Average Grant-Date Fair Value Outstanding as of December 31, 2024 864,192 $ 71.48 Granted 409,471 $ 57.82 Shares Issued (163,335) $ 88.50 Forfeited (91,885) $ 83.96 Outstanding as of December 31, 2025 1,018,443 $ 62.13 The weighted average grant-date fair value of performance shares granted for the years ended December 31, 2025, 2024 and 2023 was $57.82, $55.87 and $83.39, respectively. As of December 31, 2025 and 2024, the number and weighted average grant-date fair value of unvested performance shares was 941,243 and $61.77 per share, and 737,738 and $69.12 per share, respectively. During 2025, there were 113,252 performance shares at a weighted average grant-date fair value of $77.29 per share that vested during the year and were either paid or deferred. As of December 31, 2025, 77,200 performance shares were fully vested and deferred. Compensation Expense: The total compensation expense and associated future income tax benefits recognized by Eversource, CL&P, NSTAR Electric and PSNH for share-based compensation awards were as follows: Eversource For the Years Ended December 31, (Millions of Dollars) 2025 2024 2023 Compensation Expense $ 33.6 $ 30.0 $ 27.8 Future Income Tax Benefit 8.8 7.8 7.3 For the Years Ended December 31, 2025 2024 2023 (Millions of Dollars) CL&P NSTARElectric PSNH CL&P NSTARElectric PSNH CL&P NSTARElectric PSNH Compensation Expense $ 10.5 $ 11.6 $ 4.3 $ 9.3 $ 9.6 $ 3.6 $ 8.7 $ 8.7 $ 3.0 Future Income Tax Benefit 2.7 3.0 1.1 2.4 2.5 0.9 2.3 2.3 0.8 As of December 31, 2025, there was $30.9 million of total unrecognized compensation expense related to nonvested share-based awards for Eversource, including $5.3 million for CL&P, $9.5 million for NSTAR Electric, and $1.9 million for PSNH. This cost is expected to be recognized ratably over a weighted-average period of 1.75 years for Eversource, CL&P, NSTAR Electric, and PSNH. An income tax rate of 26 percent was used to estimate the tax effect on total share-based payments determined under the fair-value based method for all awards. The Company issues treasury shares to settle fully vested RSUs and performance shares under the Company's incentive plans. For the years ended December 31, 2025, 2024, and 2023, a tax deficiency associated with the distribution of stock compensation awards increased income tax expense by $2.8 million and $2.3 million, $0.5 million respectively, which decreased cash flows from operating activities on the statements of cash flows. D. Other Retirement Benefits Eversource provides retirement and other benefits for certain current and past company officers. These benefits are accounted for on an accrual basis and expensed over a period equal to the service lives of the employees. The actuarially-determined liability for these benefits is included in Other Current and Long-Term Liabilities on the balance sheets. The related expense, which includes the allocation of expense associated with Eversource's service company officers that support CL&P, NSTAR Electric and PSNH, is included in Operations and Maintenance Expense on the income statements. The liability and expense amounts are as follows: Eversource(Millions of Dollars) As of and For the Years Ended December 31, 2025 2024 2023 Actuarially-Determined Liability $ 29.9 $ 30.2 $ 32.6 Other Retirement Benefits Expense 2.3 2.4 2.6 As of and For the Years Ended December 31, 2025 2024 2023 (Millions of Dollars) CL&P NSTARElectric PSNH CL&P NSTARElectric PSNH CL&P NSTARElectric PSNH Actuarially-Determined Liability $ 0.1 $ — $ 1.0 0.1 $ — $ 1.0 $ 0.2 $ — $ 1.1 Other Retirement Benefits Expense 0.8 0.8 0.3 0.8 0.8 0.3 0.8 0.8 0.4 122
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12. INCOME TAXES The components of income tax expense are as follows: Eversource(Millions of Dollars) For the Years Ended December 31, 2025 2024 2023 Current Income Taxes: Federal $ 77.5 $ (23.4) $ 75.8 State 37.5 14.3 0.6 Total Current 115.0 (9.1) 76.4 Deferred Income Taxes, Net: Federal 63.7 266.3 (0.9) State (36.4) 169.6 86.3 Total Deferred 27.3 435.9 85.4 Investment Tax Credits, Net (2.0) (2.1) (2.1) Income Tax Expense $ 140.3 $ 424.7 $ 159.7 For the Years Ended December 31, 2025 2024 2023 (Millions of Dollars) CL&P NSTAR Electric PSNH CL&P NSTAR Electric PSNH CL&P NSTAR Electric PSNH Current Income Taxes: Federal $ 191.1 $ 118.9 $ 57.3 $ 25.9 $ 65.9 $ (1.7) $ (10.8) $ 50.7 $ (40.0) State 70.9 37.2 23.5 (6.8) 15.2 (5.2) (2.3) 7.8 (20.0) Total Current 262.0 156.1 80.8 19.1 81.1 (6.9) (13.1) 58.5 (60.0) Deferred Income Taxes, Net: Federal (66.5) 10.0 3.7 107.9 63.9 50.8 130.3 50.1 81.2 State (28.3) 25.6 7.6 67.5 47.3 26.3 53.7 46.1 37.8 Total Deferred (94.8) 35.6 11.3 175.4 111.2 77.1 184.0 96.2 119.0 Investment Tax Credits, Net — (1.7) — — (1.7) — — (1.7) — Income Tax Expense $ 167.2 $ 190.0 $ 92.1 $ 194.5 $ 190.6 $ 70.2 $ 170.9 $ 153.0 $ 59.0 A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows: For the Year Ended December 31, 2025 Eversource CL&P NSTAR Electric PSNH (Millions of Dollars) Amount Percent Amount Percent Amount Percent Amount Percent Income Before Income Tax Expense 1,840.2 N/A $ 718.5 N/A $ 820.7 N/A $ 361.5 N/A U.S. Federal Statutory Income Tax Expense at21% 386.4 21 % 150.9 21 % 172.3 21 % 75.9 21 % Tax Effect of Differences: State and Local Income Tax Effects, Net ofFederal Impact 2.4 0.1 39.6 5.5 49.6 6.0 24.6 6.8 Federal Tax Credits Research and Development Tax Credits (22.6) (1.2) — — — — — — Changes in Valuation Allowances (241.6) (13.1) (6.2) (0.9) — — — — Nontaxable or Nondeductible Items: Depreciation (23.4) (1.3) 2.5 0.3 (10.6) (1.3) (2.2) (0.6) EDIT Amortization (50.6) (2.7) (17.0) (2.4) (21.7) (2.6) (8.1) (2.2) Loss on Offshore Wind 59.5 3.2 — — — — — — Other 30.2 1.6 (2.6) (0.4) 0.4 — 1.9 0.5 Income Tax Expense/Effective Tax Rate $ 140.3 7.6 % $ 167.2 23.3 % $ 190.0 23.2 % $ 92.1 25.5 % State taxes in Connecticut (for CL&P), Massachusetts (for NSTAR Electric) and New Hampshire (for PSNH) made up the majority of the tax effects in this category for Eversource. (1) (1) 123
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Eversource maintains a valuation allowance recorded on deferred tax assets associated with the loss recorded from the offshore wind investments. In the third quarter of 2025, as part of filing its 2024 tax return to provision process, Eversource partially reversed this valuation allowance by $294 million and also recorded a charge of $129 million as it reconciled the positions on the tax return to what was estimated as of December 31, 2024, resulting in a net benefit of $165 million to tax expense. The adjustment to the valuation allowance was required based on the reconciling of previously recorded tax losses to amounts included in applicable partnership income tax returns. Both adjustments resulted from changes in tax estimates based on information from the partnership tax returns received in the third quarter of 2025. Eversource also recognized state tax benefits and certain tax credits of $118 million as part of the 2024 tax return to provision process. These benefits totaling $283 million were recorded as a reduction to income tax expense on the statement of income in 2025. The Loss on Offshore Wind in the table above of $59.5 million reflects the federal impacts of the $129 million charge, partially offset by the tax benefit of $44 million recorded from the pre-tax increase of $284 million to the offshore wind contingent liability recorded in the third quarter of 2025. For the Years Ended December 31, 2024 2023 (Millions of Dollars, except percentages) Eversource CL&P NSTARElectric PSNH Eversource CL&P NSTARElectric PSNH Income/(Loss) Before Income TaxExpense $ 1,243.8 $ 707.1 $ 826.9 $ 285.1 $ (275.0) $ 689.6 $ 697.5 $ 254.7 Statutory Federal Income Tax Expense at21% 261.2 148.5 173.7 59.9 (57.7) 144.9 146.5 53.5 Tax Effect of Differences: Depreciation (22.6) 0.4 (10.9) (1.0) (25.8) (5.6) (8.8) (1.0) Investment Tax Credit Amortization (2.1) — (1.7) — (2.1) — (1.7) — Other Federal Tax Credits (67.0) — — — (42.5) — — — State Income Taxes, Net of FederalImpact 43.2 (2.8) 49.4 16.7 (11.4) (10.7) 42.5 14.1 Dividends on ESOP (5.5) — — — (5.3) — — — Tax Asset Valuation Allowance/Reserve Adjustments 278.6 50.8 — — 295.8 51.3 — — Share-Based Payment Tax Deficiency 2.3 0.8 0.8 0.3 0.5 0.2 0.2 0.1 EDIT Amortization (37.0) (9.2) (20.0) (6.5) (51.5) (10.5) (28.4) (6.8) Other, Net (26.4) 6.0 (0.7) 0.8 59.7 1.3 2.7 (0.9) Income Tax Expense $ 424.7 $ 194.5 $ 190.6 $ 70.2 $ 159.7 $ 170.9 $ 153.0 $ 59.0 Effective Tax Rate 34.1 % 27.5 % 23.0 % 24.6 % (58.1)% 24.8 % 21.9 % 23.2 % Eversource, CL&P, NSTAR Electric and PSNH file a consolidated federal income tax return and unitary, combined and separate state income tax returns. These entities are also parties to a tax allocation agreement under which taxable subsidiaries do not pay any more taxes than they would have otherwise paid had they filed a separate company tax return, and subsidiaries generating tax losses, if any, are paid for their losses when utilized. 124
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Deferred tax assets and liabilities are recognized for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. The tax effect of temporary differences is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and relevant accounting authoritative literature. The tax effects of temporary differences that give rise to the net accumulated deferred income tax obligations are as follows: As of December 31, 2025 2024 (Millions of Dollars) Eversource CL&P NSTAR Electric PSNH Eversource CL&P NSTAR Electric PSNH Deferred Tax Assets: Employee Benefits $ 273.0 $ 37.3 $ 92.5 $ 16.1 $ 266.9 $ 33.7 $ 83.5 $ 14.5 Derivative Liabilities 205.8 — 205.8 — 19.6 19.6 — — Regulatory Deferrals - Liabilities 716.7 212.7 402.5 48.3 508.7 128.0 316.7 19.6 Allowance for Uncollectible Accounts 151.9 70.2 30.7 6.2 145.3 75.4 26.5 3.8 Tax Effect - Tax Regulatory Liabilities 696.0 310.7 201.1 90.5 720.8 317.6 214.3 93.2 Net Operating Loss Carryforwards 314.0 — — — 198.2 — — 1.5 Purchase Accounting Adjustment 48.2 — — — 52.1 — — — Equity Method Wind Investments 760.3 — — — 1,098.6 — — — Other 229.6 133.3 30.9 19.7 267.1 134.7 31.5 24.1 Total Deferred Tax Assets 3,395.5 764.2 963.5 180.8 3,277.3 709.0 672.5 156.7 Less: Valuation Allowance 293.4 104.2 — — 558.2 104.1 — — Net Deferred Tax Assets $ 3,102.1 $ 660.0 $ 963.5 $ 180.8 $ 2,719.1 $ 604.9 $ 672.5 $ 156.7 Deferred Tax Liabilities: Accelerated Depreciation and Other Plant-Related Differences $ 5,880.4 $ 1,925.0 $ 1,963.2 $ 673.3 $ 5,493.3 $ 1,820.3 $ 1,845.2 $ 618.4 Property Tax Accruals 118.3 56.8 47.5 7.0 107.4 49.8 44.5 6.5 Regulatory Amounts: Regulatory Deferrals - Assets 1,837.0 405.1 725.3 263.4 1,709.1 522.9 519.9 277.8 Tax Effect - Tax Regulatory Assets 308.5 199.6 9.6 10.3 294.5 194.7 10.0 9.4 Goodwill-related Regulatory Asset - 1999Merger 62.9 — 54.0 — 67.5 — 58.0 — Employee Benefits 404.1 60.5 194.7 31.0 353.0 51.0 175.4 23.5 Derivative Assets 24.9 — 24.9 — 3.8 3.8 — — Other 113.2 18.9 31.6 2.1 101.7 15.2 24.9 2.7 Total Deferred Tax Liabilities $ 8,749.3 $ 2,665.9 $ 3,050.8 $ 987.1 $ 8,130.3 $ 2,657.7 $ 2,677.9 $ 938.3 As of December 31, 2025 and 2024, the Eversource Valuation Allowance of $293.4 million and $558.2 million, includes $162.4 million and $427.0 million, respectively, related to Eversource’s share of offshore wind investments. Income Taxes Paid: The following tables present income taxes paid, net of refunds received, disaggregated by jurisdiction. The jurisdictions presented include federal, state, and any individual jurisdictions where the amount of income taxes paid equals or exceeds five percent of the total income taxes paid during the reporting period. Eversource(Millions of Dollars) For the Years Ended December 31, 2025 2024 2023 Cash Paid/(Received) for Income Taxes, Net of Refunds: Federal Income Taxes $ (48.8) State Income Taxes: Connecticut 6.2 Massachusetts (8.7) Other 2.9 State Income Taxes 0.4 Total Cash Paid/(Received) for Income Taxes, Net of Refunds $ (48.4) Total Cash Paid/(Received) for Income Taxes (Prior to ASU 2023-09) $ (69.6) $ 39.2 (1) (1) 125
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For the Years Ended December 31, 2025 2024 2023 (Millions of Dollars) CL&P NSTARElectric PSNH CL&P NSTARElectric PSNH CL&P NSTARElectric PSNH Cash Paid for Income Taxes, Net of Refunds: Federal Income Taxes $ 113.1 $ 124.5 $ 60.0 State Income Taxes: Connecticut 22.4 — — Massachusetts (a) 40.3 (a) New Hampshire — — 22.9 Other 0.2 — 0.1 State Income Taxes 22.6 40.3 23.0 Total Cash Paid for Income Taxes, Net of Refunds $ 135.7 $ 164.8 $ 83.0 Total Cash Paid/(Received) for Income Taxes (Prior toASU 2023-09) $ (47.4) $ 118.7 $ (36.0) $ (44.1) $ 31.3 $ (59.9) (a) Did not meet the five percent threshold required for separate disclosure. Carryforwards: The following table provides the amounts and expiration dates of state tax credit and loss carryforwards and federal tax credit and net operating loss carryforwards: As of December 31, 2025 2024 (Millions of Dollars) Eversource CL&P NSTARElectric PSNH ExpirationRange Eversource CL&P NSTARElectric PSNH ExpirationRange Federal Net Operating Loss $ 1,079.4 $ — $ — $ — — $ 877.7 $ — $ — $ 7.1 — Federal Tax Credit 397.4 0.3 — — 2044 404.1 — — — 2044 Federal Charitable Contribution 1.1 — — — 2029 — — — — — Federal Capital Loss 1,044.6 — — — 2025 - 2029 2,700.0 — — — 2024 - 2029 State Net Operating Loss 1,447.8 — — — 2040 - 2044 214.1 — — — 2024 - 2044 State Tax Credit 236.7 153.9 — — 2025 - 2030 238.3 157.7 — — 2024 - 2029 State Capital Loss 1,044.6 — — — 2025 - 2029 2,700.0 — — — 2024 - 2029 State Charitable Contribution 13.2 — — — 2026 - 2029 15.2 — — — 2024 - 2028 In 2025, the Company decreased its valuation allowance reserve for state credits by $0.2 million (increased by $0.1 million for CL&P), net of tax, and in 2024, the Company increased its valuation allowance reserve for state credits by $27.3 million ($23.5 million for CL&P), net of tax. For 2025 and 2024, state credit and federal and state capital loss carryforwards have been partially reserved by a valuation allowance of $293.4 million and $558.2 million (net of tax), respectively. Unrecognized Tax Benefits: A reconciliation of the activity in unrecognized tax benefits, all of which would impact the effective tax rate if recognized, is as follows: (Millions of Dollars) Eversource CL&P Balance as of January 1, 2023 $ 67.1 $ 25.5 Gross Increases - Current Year 23.4 4.0 Gross Increases - Prior Year 0.1 0.1 Gross Decreases - Prior Year (0.1) — Lapse of Statute of Limitations (9.2) (3.8) Balance as of December 31, 2023 81.3 25.8 Gross Increases - Current Year 14.2 2.9 Gross Increases - Prior Year 11.0 — Gross Decreases - Prior Year (0.2) (0.2) Lapse of Statute of Limitations (12.6) (6.6) Balance as of December 31, 2024 93.7 21.9 Gross Increases - Current Year 11.9 3.2 Gross Increases - Prior Year 5.9 1.1 Lapse of Statute of Limitations (13.3) (4.6) Balance as of December 31, 2025 $ 98.2 $ 21.6 126
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Interest and Penalties: Interest on uncertain tax positions is recorded and generally classified as a component of Other Interest Expense on the statements of income. However, when resolution of uncertainties results in the Company receiving interest income, any related interest benefit is recorded in Other Income, Net on the statements of income. No penalties have been recorded. The amount of interest expense recognized on uncertain tax positions was $2.4 million, $1.3 million and $0.3 million for the years ended December 31, 2025, 2024, and 2023, respectively. Accrued interest payable was $4.1 million and $1.7 million as of December 31, 2025 and 2024, respectively. Tax Positions: During 2025 and 2024, Eversource did not resolve any of its uncertain tax positions. Open Tax Years: The following table summarizes Eversource, CL&P, NSTAR Electric, and PSNH's tax years that remain subject to examination by major tax jurisdictions as of December 31, 2025: Description Tax Years Federal 2022 - 2025 Connecticut 2022 - 2025 Massachusetts 2022 - 2025 New Hampshire 2022 - 2025 The Company’s Corporate Income Tax Returns for 2022 through 2024 were reviewed and closed as part of the annual IRS CAP program, with the exception for partnership investments of the Company. The Company was informed of an IRS audit of one of the partnership returns for the tax year 2022 and the IRS reserves the right to audit any years thereafter. The Company recorded in the above Unrecognized Tax Benefits a reserve associated with this Partnership audit. These years remain open in relation to those audits. 13. COMMITMENTS AND CONTINGENCIES A. Environmental Matters Eversource, CL&P, NSTAR Electric and PSNH are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. Eversource, CL&P, NSTAR Electric and PSNH have an active environmental auditing and training program and each believes it is substantially in compliance with all enacted laws and regulations. Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated. The approach used estimates the liability based on the most likely action plan from a variety of available remediation options, including no action required or several different remedies ranging from establishing institutional controls to full site remediation and monitoring. These liabilities are estimated on an undiscounted basis and do not assume that the amounts are recoverable from insurance companies or other third parties. The environmental reserves include sites at different stages of discovery and remediation and do not include any unasserted claims. These reserve estimates are subjective in nature as they take into consideration several different remediation options at each specific site. The reliability and precision of these estimates can be affected by several factors, including new information concerning either the level of contamination at the site, the extent of Eversource's, CL&P's, NSTAR Electric's and PSNH's responsibility for remediation or the extent of remediation required, recently enacted laws and regulations or changes in cost estimates due to certain economic factors. It is possible that new information or future developments could require a reassessment of the potential exposure to required environmental remediation. As this information becomes available, management will continue to assess the potential exposure and adjust the reserves accordingly. The amounts recorded as environmental reserves are included in Other Current Liabilities and Other Long-Term Liabilities on the balance sheets and represent management's best estimate of the liability for environmental costs, and take into consideration site assessment, remediation and long-term monitoring costs. The environmental reserves also take into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate contaminated sites and any other infrequent and non-recurring clean-up costs. A reconciliation of the activity in the environmental reserves is as follows: (Millions of Dollars) Eversource CL&P NSTAR Electric PSNH Balance as of January 1, 2024 $ 128.2 $ 13.8 $ 5.4 $ 7.6 Additions 11.0 0.8 1.9 0.2 Payments/Reductions (11.2) (1.2) (0.7) (1.5) Balance as of December 31, 2024 128.0 13.4 6.6 6.3 Additions 40.5 3.6 1.8 3.3 Payments/Reductions (14.2) (2.1) (1.4) (0.4) Balance as of December 31, 2025 $ 154.3 $ 14.9 $ 7.0 $ 9.2 (1) (1) 127
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The number of environmental sites for which remediation or long-term monitoring, preliminary site work or site assessment is being performed are as follows: Eversource CL&P NSTAR Electric PSNH 2025 66 15 14 8 2024 65 15 14 8 Included in the number of sites and reserve amounts above are former MGP sites that were operated several decades ago and manufactured natural gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment, for which Eversource may have potential liability. The reserve balances related to these former MGP sites were $140.9 million and $115.9 million as of December 31, 2025 and 2024, respectively, and related primarily to the natural gas business segment. As of December 31, 2025, for 13 environmental sites (7 for CL&P) that are included in the Company's reserve for environmental costs, management cannot reasonably estimate the exposure to loss in excess of the reserve, or range of loss, as these sites are under investigation and/or there is significant uncertainty as to what remedial actions, if any, the Company may be required to undertake. As of December 31, 2025, $33.6 million (including $7.0 million for CL&P) had been accrued as a liability for these sites. As of December 31, 2025, for 9 environmental sites (2 for CL&P and 1 for NSTAR Electric) that are included in the Company's reserve for environmental costs, the information known and the nature of the remediation options allow for the Company to estimate the range of losses for environmental costs. As of December 31, 2025, $30.9 million (including $0.7 million for CL&P) has been accrued as a liability for these sites, which represents the low end of the range of the liabilities for environmental costs. Management believes that additional losses of up to approximately $29.6 million may be incurred in executing current remediation plans for these sites. As of December 31, 2025, for the remaining 44 environmental sites (including 6 for CL&P, 13 for NSTAR Electric and 8 for PSNH) that are included in the Company's reserve for environmental costs, the $89.8 million accrual (including $7.2 million for CL&P, $7.0 million for NSTAR Electric and $9.2 million for PSNH) represents management's best estimate of the probable liability and no additional loss is estimable at this time. PSNH, NSTAR Gas, EGMA and Yankee Gas have rate recovery mechanisms for MGP related environmental costs, therefore, changes in their respective environmental reserves do not impact Net Income. CL&P is allowed to defer certain environmental costs for future recovery. NSTAR Electric does not have a separate environmental cost recovery regulatory mechanism. B. Long-Term Contractual Arrangements Estimated Future Annual Costs: The estimated future annual costs of significant executed, non-cancelable, long-term contractual arrangements in effect as of December 31, 2025 are as follows: Eversource (Millions of Dollars) 2026 2027 2028 2029 2030 Thereafter Total Renewable Energy Purchase Contracts $ 1,113.9 $ 1,235.1 $ 1,246.2 $ 1,115.5 $ 784.1 $ 11,643.4 $ 17,138.2 Natural Gas Procurement 523.3 487.9 359.4 320.1 273.6 781.9 2,746.2 NECEC Transmission Service Agreement 94.6 96.5 98.4 100.4 102.4 1,806.4 2,298.7 Capacity and Purchased Power 2.9 2.7 2.7 2.3 1.8 0.5 12.9 Peaker CfDs 30.2 25.9 25.8 26.2 18.9 55.1 182.1 Transmission Support Commitments 20.1 21.6 22.6 24.1 24.1 24.1 136.6 Total $ 1,785.0 $ 1,869.7 $ 1,755.1 $ 1,588.6 $ 1,204.9 $ 14,311.4 $ 22,514.7 CL&P (Millions of Dollars) 2026 2027 2028 2029 2030 Thereafter Total Renewable Energy Purchase Contracts $ 681.8 $ 774.6 $ 780.4 $ 640.0 $ 300.4 $ 3,603.2 $ 6,780.4 Capacity 0.1 — — — — — 0.1 Peaker CfDs 30.2 25.9 25.8 26.2 18.9 55.1 182.1 Transmission Support Commitments 7.9 8.5 8.9 9.5 9.5 9.5 53.8 Total $ 720.0 $ 809.0 $ 815.1 $ 675.7 $ 328.8 $ 3,667.8 $ 7,016.4 NSTAR Electric (Millions of Dollars) 2026 2027 2028 2029 2030 Thereafter Total Renewable Energy Purchase Contracts $ 432.1 $ 460.5 $ 465.8 $ 475.5 $ 483.7 $ 8,040.2 $ 10,357.8 NECEC Transmission Service Agreement 94.6 96.5 98.4 100.4 102.4 1,806.4 2,298.7 Purchased Power 2.8 2.7 2.7 2.3 1.8 0.5 12.8 Transmission Support Commitments 7.9 8.5 8.9 9.5 9.5 9.5 53.8 Total $ 537.4 $ 568.2 $ 575.8 $ 587.7 $ 597.4 $ 9,856.6 $ 12,723.1 128
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PSNH (Millions of Dollars) 2026 2027 2028 2029 2030 Thereafter Total Transmission Support Commitments $ 4.3 $ 4.6 $ 4.8 $ 5.1 $ 5.1 $ 5.1 $ 29.0 The contractual obligations table above does not include CL&P's, NSTAR Electric's or PSNH's standard/basic service contracts for the purchase of energy supply, the amounts of which vary with customers' energy needs. Renewable Energy Purchase Contracts: Renewable energy purchase contracts include non-cancellable commitments under contracts of CL&P and NSTAR Electric for the purchase of energy and capacity from renewable energy facilities. Such contracts extend through 2046 for CL&P and NSTAR Electric. There are no long-term renewable energy purchase contracts at PSNH. In accordance with Massachusetts clean energy legislation and under the Massachusetts Clean Energy 83D procurement, in June 2018, NSTAR Electric entered into a 20-year power purchase agreement for the purchase of renewable hydroelectric energy and renewable energy attributes from Hydro- Québec. The agreement requires NSTAR Electric to purchase 579 MW of energy per hour through January 2046. On December 31, 2025, NSTAR Electric received notice of commercial operation of the transmission line needed to deliver this energy. Costs under this contract began in January 2026 following commercial operation and range between $260 million and $420 million per year under the 20-year contract, totaling approximately $6.7 billion over the total contract term. The power purchase agreement is supported by New England Clean Energy Connect (NECEC), a 1,200 MW transmission line developed to deliver the hydroelectric power from Hydro ‑ Québec into the New England grid. As required by law, NSTAR Electric cannot use this power to satisfy its customers’ supply obligations. NSTAR Electric will sell the energy purchased under this contract into the market and will use the proceeds from these energy sales to offset the contract costs. The net supply costs under this contract will be recovered from or credited to customers in future rates and do not have an impact on the net income of NSTAR Electric. This contract meets the definition of a derivative and the fair value of the contract is recorded on NSTAR Electric’s balance sheet as a derivative with an offset to regulatory assets and/or liabilities. For further information, see Note 4, "Derivative Instruments," to the financial statements. Renewable energy purchase contracts include long-term commitments of NSTAR Electric pertaining to the Vineyard Wind LLC contract awarded under the Massachusetts Clean Energy 83C procurement solicitation. NSTAR Electric, along with other Massachusetts distribution companies, entered into 20- year contracts to purchase electricity generated by this 800 megawatt offshore wind project. Construction on the Vineyard Wind project commenced in 2022. Estimated energy costs under this contract are expected to begin when the facilities are in service in 2026 and range between $100 million and $200 million per year under NSTAR Electric’s 20-year contract, totaling approximately $3.2 billion. As required by 2018 regulation, CL&P and UI each entered into PURA-approved ten-year contracts in 2019 to purchase a combined total of approximately 9 million MWh annually from the Millstone Nuclear Power Station generation facility, which represents a combined amount of approximately 50 percent of the facility's output (approximately 40 percent by CL&P). Also as required by 2018 regulation, CL&P and UI each entered into PURA-approved eight-year contracts in 2019 to purchase a combined amount of approximately 18 percent of the Seabrook Nuclear Power Plant’s output (approximately 15 percent by CL&P) beginning January 1, 2022. The total estimated remaining future cost of the Millstone Nuclear Power Station and Seabrook Nuclear Power Plant energy purchase contracts are $1.6 billion and are reflected in the table above. As required by law, CL&P cannot use this power to satisfy its customers’ supply obligations. CL&P sells the energy purchased under these contracts into the market and uses the proceeds from these energy sales to offset the contract costs. As the net costs under these contracts are recovered from customers in future rates, the contracts do not have an impact on the net income of CL&P. These contracts do not meet the definition of a derivative, and accordingly, the costs of these contracts are being accounted for as incurred. The contractual obligations table above does not include long-term commitments signed by CL&P and NSTAR Electric, as required by the PURA and the DPU, respectively, for the purchase of renewable energy and related products that are contingent on the future construction of energy facilities. NECEC Transmission Service Agreement: In June 2018, in connection with the Hydro-Québec power purchase agreement, NSTAR Electric entered into a 20-year transmission service agreement (TSA) with NECEC Transmission LLC, the developer and owner of the NECEC transmission line. Under the TSA, NSTAR Electric is obligated to purchase its proportionate share of transmission service at regulated rates, as approved by the DPU and FERC. Costs under the TSA began in January 2026 and range between $95 million and $140 million per year, totaling approximately $2.3 billion over the total contract term. NSTAR Electric’s obligation under this contract are recovered from customers in rates. Natural Gas Procurement: Eversource's natural gas distribution businesses have long-term contracts for the purchase, transportation and storage of natural gas as part of its portfolio of supplies, which extend through 2045. Capacity and Purchased Power: These contracts include a capacity CfD with a generation facility at CL&P through 2026, and a purchase obligation for electricity which extends through 2031 for NSTAR Electric. CL&P's portion of the costs and benefits under these capacity contracts are recovered from, or refunded to, CL&P's customers. Peaker CfDs: CL&P, along with UI, has three peaker CfDs for a total of approximately 500 MW of peaking capacity through 2042. CL&P has a sharing agreement with UI, whereby CL&P is responsible for 80 percent and UI for 20 percent of the net costs or benefits of these CfDs. The Peaker CfDs pay the generation facility owner the difference between capacity, day-ahead ancillary services and energy market revenues and a cost-of-service payment stream for 30 years. The ultimate cost or benefit to CL&P under these contracts will depend on the costs of plant operation and the prices that the projects receive for capacity and other products in the ISO-NE markets. CL&P's portion of the amounts paid or received under the Peaker CfDs are recovered from, or refunded to, CL&P's customers. 129
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Transmission Support Commitments: Along with other New England utilities, CL&P, NSTAR Electric and PSNH have entered into agreements to support the costs of, and receive rights to use, transmission and terminal facilities that import electricity from the Hydro-Québec system in Canada. CL&P, NSTAR Electric and PSNH are obligated to pay, over a 20-year period ending in 2040, their proportionate shares of the annual operation and maintenance expenses and capital costs of those facilities. The total costs incurred under these agreements were as follows: Eversource For the Years Ended December 31, (Millions of Dollars) 2025 2024 2023 Renewable Energy Purchase Contracts $ 631.3 $ 591.4 $ 581.4 Natural Gas Procurement 888.0 695.0 695.8 Capacity and Purchased Power 67.2 70.5 69.0 Peaker CfDs 19.6 23.1 20.1 Transmission Support Commitments 17.4 16.7 14.2 For the Years Ended December 31, 2025 2024 2023 (Millions of Dollars) CL&P NSTAR Electric PSNH CL&P NSTAR Electric PSNH CL&P NSTAR Electric PSNH Renewable Energy Purchase Contracts $ 567.4 $ 63.9 $ — $ 529.0 $ 62.4 $ — $ 474.1 $ 60.0 $ 47.3 Capacity and Purchased Power 64.4 2.8 — 67.6 2.9 — 65.5 2.9 0.6 Peaker CfDs 19.6 — — 23.1 — — 20.1 — — Transmission Support Commitments 6.9 6.8 3.7 6.6 6.6 3.5 5.6 5.6 3.0 C. Spent Nuclear Fuel Obligations - Yankee Companies CL&P, NSTAR Electric and PSNH have plant closure and fuel storage cost obligations to the Yankee Companies, which have each completed the physical decommissioning of their respective nuclear power facilities and are now engaged in the long-term storage of their spent fuel. The Yankee Companies fund these costs through litigation proceeds received from the DOE and, to the extent necessary, through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P, NSTAR Electric and PSNH. CL&P, NSTAR Electric and PSNH, in turn recover these costs from their customers through state regulatory commission-approved retail rates. The Yankee Companies collect amounts that management believes are adequate to recover the remaining plant closure and fuel storage cost estimates for the respective plants. Management believes CL&P and NSTAR Electric will recover their shares of these obligations from their customers. PSNH has recovered its total share of these costs from its customers. Spent Nuclear Fuel Litigation: The Yankee Companies have filed complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to accept delivery of, and provide for a permanent facility to store, spent nuclear fuel pursuant to the terms of the 1983 spent fuel and high-level waste disposal contracts between the Yankee Companies and the DOE. The court previously awarded the Yankee Companies damages for Phases I, II, III and IV of litigation resulting from the DOE's failure to meet its contractual obligations. These Phases covered damages incurred in the years 1998 through 2016, and the awarded damages have been received by the Yankee Companies with certain amounts of the damages refunded to their customers. DOE Phase V Damages - On March 25, 2021, each of the Yankee Companies filed a fifth set of lawsuits against the DOE in the Court of Federal Claims resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal covering the years from 2017 to 2020. The Yankee Companies filed claims seeking monetary damages totaling $120.4 million for CYAPC, YAEC and MYAPC. Pursuant to a June 2, 2022 court order, the Yankee Companies were subsequently permitted to include monetary damages relating to the year 2021 in the DOE Phase V complaint. The Yankee Companies submitted a supplemental filing to include these costs of $33.1 million on June 8, 2022. In September 2024, the parties reached an agreement in principle to settle the Phase V complaint totaling $145 million for CYAPC, YAEC, and MYAPC. The settlement was approved on November 19, 2024 and the Department of Justice filed a Notice of Appeal on January 17, 2025 on an issue outside the scope of the settlement. Oral arguments are expected to be scheduled in 2026. D. Guarantees and Indemnifications In the normal course of business, Eversource parent provides credit assurances on behalf of its subsidiaries, including CL&P, NSTAR Electric and PSNH, in the form of guarantees. Management does not anticipate a material impact to net income or cash flows as a result of these various guarantees and indemnifications. Guarantees issued on behalf of unconsolidated entities, including equity method ownership interests, for which Eversource parent is the guarantor, are recorded at fair value as a liability on the balance sheet at the inception of the guarantee. The fair value of guarantees issued on behalf of unconsolidated entities are recorded within Other Long-Term Liabilities on the balance sheet, and were $1.3 million and $1.2 million as of December 31, 2025 and 2024, respectively. Eversource regularly reviews performance risk under these guarantee arrangements, and believes the likelihood of payments being required under the guarantees is remote. In the event it becomes probable that Eversource parent will be required to perform under the guarantee, the amount of probable payment will be recorded. 130
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On September 30, 2024, Eversource completed the sale of its 50 percent ownership share in the South Fork Wind and Revolution Wind projects to affiliates of Global Infrastructure Partners (GIP). Under the agreement with GIP, Eversource’s existing and certain additional credit support obligations for Revolution Wind are expected to roll off as the project completes construction. On July 9, 2024, Eversource completed the sale of its 50 percent ownership share of Sunrise Wind to Ørsted. Under the agreement with Ørsted, Eversource’s existing credit support obligations for Sunrise Wind were either terminated or indemnified by Ørsted as a result of the sale. The following table summarizes Eversource parent's exposure to guarantees and indemnifications of its subsidiaries and affiliates to external parties, and primarily relates to its previously-owned offshore wind investments: As of December 31, 2025 Company (Obligor) Description Maximum Exposure(in millions) Revolution Wind, LLC and TurbineCo, LLC Offshore wind construction-related purchase agreements with third-party contractors $ 127.0 Eversource Investment LLC, Eversource Investment ServiceCompany LLC and South Fork Class B Member, LLC Offshore wind funding and indemnification obligations 176.7 Eversource TEI LLC South Fork Wind Tax Equity 50.0 South Fork Wind, LLC Power Purchase Agreement Security 7.1 Various Eversource subsidiaries Surety bonds 34.1 Eversource parent issued guarantees on behalf of its previously 50 percent-owned affiliate, Revolution Wind, LLC, and on behalf of TurbineCo, LLC (successor in interest to North East Offshore, LLC (NEO)), under which Eversource parent agreed to guarantee each entity’s performance of obligations under certain construction-related purchase agreements with third-party contractors, in an aggregate amount not to exceed $693.0 million. Eversource parent’s obligations under the guarantees expire upon the earlier of (i) dates ranging between December 2026 and November 2027 and (ii) full performance of the guaranteed obligations. Eversource parent issued guarantees on behalf of its wholly-owned subsidiary Eversource Investment LLC (EI), which held Eversource's previous investments in offshore wind-related equity method investments until sale, and on behalf of its previously 50 percent-owned affiliate, South Fork Class B Member, LLC, whereby Eversource parent will guarantee each entity’s performance of certain funding obligations of the South Fork and Revolution Wind projects. Eversource parent also guaranteed certain indemnification obligations of EI associated with third-party credit support for EI’s investment in NEO. On September 30, 2024, Eversource parent issued a guaranty on behalf of its wholly-owned subsidiary, Eversource Investment Service Company LLC, whereby Eversource parent will guarantee Eversource Investment Service Company LLC’s performance of certain indemnification obligations during the onshore construction phase of the Revolution Wind project, in an amount not to exceed $100.0 million. These guarantees will not exceed $1.62 billion and expire upon the full performance of the guaranteed obligations. Eversource parent issued a guarantee on behalf of its wholly-owned subsidiary, Eversource TEI LLC, whereby Eversource parent will guarantee Eversource TEI LLC’s performance of certain obligations, in an amount not to exceed $50.0 million, in connection with any remaining obligations under the LLC agreement. Eversource parent’s obligations expire upon the full performance of the guaranteed obligations. Eversource parent issued a guarantee on behalf of its previously 50 percent-owned affiliate, South Fork Wind, LLC, whereby Eversource parent will guarantee South Fork Wind, LLC's performance of certain obligations, in an amount not to exceed $7.1 million, under a Power Purchase Agreement between the Long Island Power Authority and South Fork Wind, LLC (the Agreement). The guarantee expires upon the later of (i) the end of the Agreement term, January 2044, with the option to extend to January 2049 and (ii) full performance of the guaranteed obligations. Surety bonds expire in 2026. Expiration dates reflect termination dates, the majority of which will be renewed or extended. Certain surety bonds contain credit ratings triggers that would require Eversource parent to post collateral in the event that the unsecured debt credit ratings of Eversource parent are downgraded. Eversource parent entered into a guarantee on behalf of EI, under which Eversource parent would guarantee EI's obligations under a letter of credit facility with a financial institution that EI may request in an aggregate amount of up to approximately $25 million. As of December 31, 2025, there are no letters of credit issued under this guarantee. The guarantee will remain in effect until full performance of the guaranteed obligations. On September 30, 2024, Eversource entered into an agreement with GIP and Ørsted to contingently provide future credit support up to a maximum of $850 million in guarantees, if required, to support third-party tax equity financing for Revolution Wind. In January 2026, Eversource parent issued a guaranty on behalf of EI totaling $900 million to GIP in order to support certain tax positions related to the Revolution Wind project through June 30, 2035. (1) (2) (3) (4) (5) (1) (2) (3) (4) (5) 131
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E. FERC ROE Complaints Four separate complaints were filed at the FERC by combinations of New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (collectively, the Complainants). In each of the first three complaints, filed on October 1, 2011, December 27, 2012, and July 31, 2014, respectively, the Complainants challenged the NETOs' base ROE of 11.14 percent that had been utilized since 2005 and sought an order to reduce it prospectively from the date of the final FERC order and for the separate 15-month complaint periods. In the fourth complaint, filed April 29, 2016, the Complainants challenged the NETOs' base ROE billed of 10.57 percent and the maximum ROE for transmission incentive (incentive cap) of 11.74 percent, asserting that these ROEs were unjust and unreasonable. The ROE originally billed during the period October 1, 2011 (beginning of the first complaint period) through October 15, 2014 consisted of a base ROE of 11.14 percent and incentives up to 13.1 percent. On October 16, 2014, FERC issued Opinion No. 531-A and set the base ROE at 10.57 percent and the incentive cap at 11.74 percent for the first complaint period. This was also effective for all prospective billings to customers beginning October 16, 2014. This FERC order was vacated on April 14, 2017 by the U.S. Court of Appeals for the D.C. Circuit (the Court). All amounts associated with the first complaint period have been refunded, which totaled $38.9 million (pre-tax and excluding interest) at Eversource and reflected both the base ROE and incentive cap prescribed by the FERC order. The refund consisted of $22.4 million for CL&P, $13.7 million for NSTAR Electric and $2.8 million for PSNH. Eversource has recorded a reserve of $39.1 million (pre-tax and excluding interest) for the second complaint period as of both December 31, 2025 and 2024. This reserve represents the difference between the billed rates during the second complaint period and a 10.57 percent base ROE and 11.74 percent incentive cap. The reserve consisted of $21.4 million for CL&P, $14.6 million for NSTAR Electric and $3.1 million for PSNH as of both December 31, 2025 and 2024. On October 16, 2018, FERC issued an order on all four complaints describing how it intends to address the issues that were remanded by the Court. FERC proposed a new framework to determine (1) whether an existing ROE is unjust and unreasonable and, if so, (2) how to calculate a replacement ROE. Initial briefs were filed by the NETOs, Complainants and FERC Trial Staff on January 11, 2019 and reply briefs were filed on March 8, 2019. The NETOs' brief was supportive of the overall ROE methodology determined in the October 16, 2018 order provided the FERC does not change the proposed methodology or alter its implementation in a manner that has a material impact on the results. The FERC order included illustrative calculations for the first complaint using FERC's proposed frameworks with financial data from that complaint. Those illustrative calculations indicated that for the first complaint period, the preliminary just and reasonable base ROE for the NETOs, which FERC concludes are of average financial risk, is 10.41 percent and the preliminary incentive cap on total ROE is 13.08 percent. If the results of the illustrative calculations were included in a final FERC order for each of the complaint periods, then a 10.41 percent base ROE and a 13.08 percent incentive cap would not have a significant impact on our financial statements for all of the complaint periods. These preliminary calculations are not binding and do not represent what we believe to be the most likely outcome of a final FERC order. On November 21, 2019, FERC issued Opinion No. 569 affecting the two pending transmission ROE complaints against the Midcontinent ISO (MISO) transmission owners, in which FERC adopted a new methodology for determining base ROEs. Various parties sought rehearing. On December 23, 2019, the NETOs filed supplementary materials in the NETOs' four pending cases to respond to this new methodology because of the uncertainty of the applicability to the NETOs' cases. On May 21, 2020, the FERC issued its order in Opinion No. 569-A on the rehearing of the MISO transmission owners' cases, in which FERC again changed its methodology for determining the MISO transmission owners' base ROEs. On November 19, 2020, the FERC issued Opinion No. 569-B denying rehearing of Opinion No. 569-A and reaffirmed the methodology previously adopted in Opinion No. 569-A. The new methodology differs significantly from the methodology proposed by FERC in its October 16, 2018 order to determine the NETOs' base ROEs in their four pending cases. FERC Opinion Nos. 569-A and 569-B were appealed to the Court. On August 9, 2022, the Court issued its decision vacating MISO ROE FERC Opinion Nos. 569, 569-A and 569-B and remanded to FERC to reopen the proceedings. The Court found that FERC’s development of the new return methodology was arbitrary and capricious due to FERC’s failure to offer a reasonable explanation for its decision to reintroduce the risk- premium financial model in its new methodology for calculating a just and reasonable return. On October 17, 2024, FERC issued an order on the remand of the MISO ROE proceedings. The order addressed the Court’s decision that the reintroduction of the risk-premium financial model in the ROE methodology was arbitrary and capricious by removing the risk-premium financial model from the ROE methodology. The removal of the risk-premium financial model was the only revision to FERC’s ROE methodology and resulted in a two- model approach utilizing the two-step discounted cash flow model and the capital asset pricing model. MISO transmission owners were directed to provide refunds for the period November 12, 2013 to February 11, 2015 (the first MISO ROE complaint refund period) and for the period from September 28, 2016 (the date of FERC’s order on the first MISO ROE complaint) to October 17, 2024 by December 1, 2025. The order also stated that FERC does not preclude the use of the risk-premium financial model in future proceedings if the parties can demonstrate that FERC’s stated concerns around the inclusion of the model have been addressed. On March 25, 2025, FERC issued an order addressing arguments raised on rehearing, sustaining the result, and denying rehearing. On November 13, 2024, the NETOs filed a supplemental brief in their four pending ROE proceedings to explain to FERC that it cannot apply the reasoning and methodologies of the MISO ROE case to the NETOs’ cases due to the entirely different set of facts in the MISO and NETOs ROE proceedings. Doing so would violate the substance of the Court’s April 14, 2017 order and would violate the legal standard required by the Federal Power Act. On February 4, 2025, the MISO transmission owners submitted a petition for review with the Court requesting review of the October 17, 2024 MISO ROE order on remand and a December 19, 2024 notice of denial of rehearing. The petition requests review of FERC’s decision to retroactively backdate the MISO transmission owners’ base ROE to the date of an earlier order that FERC abandoned when it issued Order No. 132
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569, treat an underlying unlawful complaint as if it were legitimate, and order eight years of interest as part of the directed refunds. On August 21, 2025, the NETOs submitted a brief in support of the MISO transmission owners with the Court. Final briefs in the Court proceeding were submitted on January 26, 2026 and oral argument is scheduled for March 17, 2026. Given the significant uncertainty regarding the applicability of the FERC order in the MISO transmission owners’ two complaint cases to the NETOs’ pending four complaint cases due to the complex differences between the cases, Eversource concluded that there is no reasonable basis for a change to the reserve or recognized ROEs for any of the complaints or subsequent periods at this time and Eversource cannot reasonably estimate any potential range of loss for any of the four complaint proceedings at this time. The resolution of these proceedings could have a material impact on the financial condition, results of operations, and cash flows. Eversource, CL&P, NSTAR Electric and PSNH currently record revenues at the 10.57 percent base ROE and incentive cap at 11.74 percent established in the October 16, 2014 FERC order. A change of 10 basis points to the base ROE used to establish the reserves would impact Eversource’s after-tax earnings by an average of approximately $3 million for each of the four 15-month complaint periods. F. Litigation and Legal Proceedings Eversource, including CL&P, NSTAR Electric and PSNH, are involved in legal, tax and regulatory proceedings regarding matters arising in the ordinary course of business, which involve management's assessment to determine the probability of whether a loss will occur and, if probable, its best estimate of probable loss. The Company records and discloses losses when these losses are probable and reasonably estimable, and discloses matters when losses are probable but not estimable or when losses are reasonably possible. Legal costs related to the defense of loss contingencies are expensed as incurred. G. Offshore Wind Sale and Contingent Liability On July 9, 2024, Eversource completed the sale of its 50 percent ownership share of Sunrise Wind to Ørsted for adjusted proceeds of $152 million. Ørsted paid Eversource $118 million at the closing of the sale transaction and remaining proceeds of $34 million will be paid after onshore construction is completed and certain other construction milestones are achieved. With completion of the sale, Eversource does not have any ongoing financial obligations associated with Sunrise Wind. On September 30, 2024, Eversource completed the sale of its 50 percent ownership share in the South Fork Wind and Revolution Wind projects to GIP for adjusted gross proceeds of $745 million, which were received at closing. As part of the sale, Eversource and GIP agreed to make certain post-closing purchase price adjustment payments that will impact the final purchase price. The post-closing purchase price adjustment payments include cost sharing obligations that require Eversource to share equally in GIP’s funding obligations up to an effective cap of approximately $240 million of incremental capital expenditure overruns incurred during the construction phase for Revolution Wind, after which Eversource will have responsibility for GIP’s obligations for any additional capital expenditure overruns in excess of this amount. The purchase price is also subject to post-closing adjustments as a result of final project economics, which includes Eversource’s obligation to maintain GIP’s internal rate of return through the construction period for each project as specified in the agreement. For Revolution Wind, purchase price adjustment payments are expected to be completed in late 2026. South Fork Wind has achieved commercial operation, and Eversource made a purchase price adjustment payment related to this project in June 2025. In January 2026, disputes with respect to this purchase price adjustment and all matters relating to South Fork Wind have now been resolved with no material impacts. Upon the completion of the sales in 2024, Eversource recorded a contingent liability of $365.0 million, reflecting its estimate of the future obligations under the terms of the sale to GIP. The total sales proceeds were compared to the carrying value of the investments, including the estimate of liability for post-closing adjustment payments to GIP, and Eversource recognized an aggregate after-tax loss on the sales of its offshore wind investments of $524 million, which included a net $60 million increase in income tax expense including an increase in the valuation allowance for unused capital losses, in 2024. In the third quarter of 2025, Eversource received an updated report from GIP on the construction status of Revolution Wind, which included revised projections of total construction costs. The revised cost projections reflected known and quantifiable cost increases, including those associated with the impacts of damage to the wind turbine installation vessel, insurance costs, tariff impacts, and costs incurred as a result of the stop-work order for Revolution Wind received on August 22, 2025 from the Bureau of Ocean Energy Management that halted all offshore wind construction activities through September 22, 2025. Based on those developments, Eversource recognized a pre-tax charge of $284.0 million in the third quarter of 2025 as a result of the aggregate impact of these items to increase the liability for purchase price adjustments associated with the offshore wind projects. Payments made in 2025 reduced the contingent liability and are reflected within investing activities on the statement of cash flows. These payments included cost overruns for the Revolution Wind project paid to GIP, insurance payments, and the purchase price adjustment payment related to the South Fork Wind project paid to GIP. Eversource continually evaluates the contingent liability and will reassess the balance as new information becomes available. Based on most recent updates from GIP on the construction status of Revolution Wind, factoring in estimated costs incurred as a result of a second stop-work order for Revolution Wind received on December 22, 2025 and removed on January 12, 2026, revised insurance costs, and other information currently available, Eversource believes that the contingent liability balance as of December 31, 2025 is a reasonable estimate to cover this contingent liability for purchase price adjustments. As of December 31, 2025, the contingent liability totaled $448.2 million and is recorded as a current liability on Eversource’s balance sheet, based upon the timing of expected payments to GIP. The contingent liability totaled $365.0 million as of December 31, 2024. 133
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Eversource relies on information that it receives from the project owners for the construction-related, delay-related, and insurance-related costs of Revolution Wind. Eversource uses its judgment to adjust, as needed, its expected obligations to GIP while construction of Revolution Wind is completed. New information or future developments that arise as the construction of Revolution Wind progresses will necessitate a reassessment of the estimated liability to GIP. The Company reviews available projections of total construction costs, including the latest cost estimates and project timeline, to determine if any changes to this liability are warranted. It is reasonably possible that as additional updated cost estimates become available, and if additional cost overruns materialize or other adverse changes in facts, regulations and circumstances occur, it could result in additional losses and increases to the offshore wind contingent liability, which could be material. The Company will continue to monitor developments and evaluate potential exposures related to this contingency and will revise its estimated liability as additional information becomes available. Contingencies are evaluated using the best information available at the time the financial statements are published, and this assessment involves judgments and assumptions about future events. Factors that could increase the obligation to GIP include construction cost overruns for Revolution Wind as well as the timing and extent of construction delays, which would impact the economics associated with the purchase price adjustment, and the eligibility for federal investment tax credits for Revolution Wind at a value lower than assumed and included in the purchase price. The purchase price of Revolution Wind included the sales value related to a 40 percent level of federal investment tax credits. A change in the expected value or qualification of investment tax credit adders could result in a significant loss in a future period. Total net proceeds could also be adjusted for a benefit due to Eversource if there are lower operation costs or higher availability of the projects through the period that is four years following the commercial operation of Revolution Wind. 2023 Impairment of Offshore Wind Investments: In 2023, Eversource recorded pre-tax other-than-temporary impairment charges of $2.17 billion ($1.95 billion after-tax) in connection with the process to divest its offshore wind investments. 14. LEASES Eversource, including CL&P, NSTAR Electric and PSNH, has entered into lease agreements as a lessee for the use of land, office space, service centers, vehicles, information technology, and equipment. These lease agreements are classified as either finance or operating leases and the liability and right-of- use asset are recognized on the balance sheet at lease commencement. Leases with an initial term of 12 months or less are not recorded on the balance sheet and are recognized as lease expense on a straight-line basis over the lease term. Eversource determines whether or not a contract contains a lease based on whether or not it provides Eversource with the use of a specifically identified asset for a period of time, as well as both the right to direct the use of that asset and receive the significant economic benefits of the asset. Eversource has elected the practical expedient to not separate non-lease components from lease components and instead to account for both as a single lease component, with the exception of the information technology asset class where the lease and non-lease components are separated. The provisions of Eversource, CL&P, NSTAR Electric and PSNH lease agreements contain renewal options. The renewal options range from one year to twenty years. The renewal period is included in the measurement of the lease liability if it is reasonably certain that Eversource will exercise these renewal options. For leases entered into or modified after the January 1, 2019 implementation date of the leases standard under Topic 842, the discount rate utilized for classification and measurement purposes as of the inception date of the lease is based on each company's collateralized incremental interest rate to borrow over a comparable term for an individual lease because the rate implicit in the lease is not determinable. CL&P and PSNH entered into certain contracts for the purchase of energy that qualify as leases. These contracts do not have minimum lease payments and therefore are not recognized as a lease liability on the balance sheet and are not reflected in the future minimum lease payments table below. Expense related to these contracts is included as variable lease cost in the table below. The expense and long-term obligation for these contracts are also included in Note 13B, "Commitments and Contingencies - Long-Term Contractual Arrangements," to the financial statements. In 2024, these contracts at PSNH were terminated. The components of lease cost, prior to amounts capitalized, are as follows: Eversource For the Years Ended December 31, (Millions of Dollars) 2025 2024 2023 Finance Lease Cost: Amortization of Right-of-use-Assets $ 9.5 $ 6.4 $ 4.8 Interest on Lease Liabilities 2.9 2.7 2.0 Total Finance Lease Cost 12.4 9.1 6.8 Operating Lease Cost 13.0 15.2 11.4 Variable Lease Cost 18.6 18.3 69.2 Total Lease Cost $ 44.0 $ 42.6 87.4 134
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For the Years Ended December 31, 2025 2024 2023 (Millions of Dollars) CL&P NSTARElectric PSNH CL&P NSTARElectric PSNH CL&P NSTARElectric PSNH Finance Lease Cost: Amortization of Right-of-use-Assets $ 2.0 $ 0.2 $ 0.1 $ 1.7 $ 0.2 $ — $ — $ 0.2 $ — Interest on Lease Liabilities 0.9 0.6 — 0.8 0.6 — — 0.6 — Total Finance Lease Cost 2.9 0.8 0.1 2.5 0.8 — — 0.8 — Operating Lease Cost 2.8 5.1 1.9 2.6 5.3 1.8 0.7 3.0 0.4 Variable Lease Cost 18.6 — — 18.9 — (0.6) 21.9 — 47.3 Total Lease Cost $ 24.3 $ 5.9 $ 2.0 $ 24.0 $ 6.1 $ 1.2 $ 22.6 $ 3.8 $ 47.7 Operating lease cost, net of the capitalized portion, is included in Operations and Maintenance (or Purchased Power, Purchased Natural Gas and Transmission expense for transmission leases) on the statements of income. Amortization of finance lease assets is included in Depreciation on the statements of income. Interest expense on finance leases is included in Interest Expense on the statements of income. Supplemental balance sheet information related to leases is as follows: As of December 31, 2025 As of December 31, 2024 (Millions of Dollars) Balance Sheet Classification Eversource CL&P NSTARElectric PSNH Eversource CL&P NSTARElectric PSNH Operating Leases: Right-of-use-Assets, Net Other Long-Term Assets $ 47.4 $ 6.1 $ 27.2 $ 1.5 $ 56.1 $ 7.7 $ 29.4 $ 3.3 Operating Lease Liabilities Current Portion Other Current Liabilities $ 10.0 $ 2.3 $ 3.9 $ 1.5 $ 10.4 $ 2.2 $ 3.7 $ 1.7 Long-Term Other Long-TermLiabilities 37.4 3.8 23.3 — 45.7 5.5 25.7 1.6 Total Operating Lease Liabilities $ 47.4 $ 6.1 $ 27.2 $ 1.5 $ 56.1 $ 7.7 $ 29.4 $ 3.3 Finance Leases: Right-of-use-Assets, Net Property, Plant andEquipment, Net $ 76.6 $ 14.6 $ 2.6 $ 0.6 $ 61.9 $ 16.6 $ 2.8 $ — Finance Lease Liabilities Current Portion Other Current Liabilities $ 24.5 $ 1.6 $ — $ 0.1 $ 5.6 $ 1.5 $ — $ — Long-Term Other Long-TermLiabilities 57.2 14.0 4.9 0.4 62.1 15.6 4.9 — Total Finance Lease Liabilities $ 81.7 $ 15.6 $ 4.9 $ 0.5 $ 67.7 $ 17.1 $ 4.9 $ — The finance lease payments that NSTAR Electric will make over the next twelve months are entirely interest-related, due to escalating payments. As such, none of the finance lease payments over the next twelve months will reduce the finance lease liability. As of December 31, 2024, the operating lease balances attributable to the Aquarion water distribution business were classified as Assets Held for Sale on the Eversource balance sheet. As of December 31, 2025, these assets were reclassified as Other Long-Term Assets on the Eversource balance sheet. For further information, see Note 24, “Assets Held for Sale.” Other information related to leases is as follows: As of December 31, 2025 2024 Eversource CL&P NSTAR Electric PSNH Eversource CL&P NSTAR Electric PSNH Weighted-Average Remaining Lease Term(Years): Operating Leases 9 3 12 2 9 4 12 2 Finance Leases 9 7 16 4 12 8 17 — Weighted-Average Discount Rate(Percentage): Operating Leases 4.1 % 5.3 % 4.2 % 5.1 % 4.1 % 5.2 % 4.2 % 5.2 % Finance Leases 3.5 % 5.3 % 2.9 % 4.6 % 3.3 % 5.3 % 2.9 % — % 135
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(Millions of Dollars) Eversource CL&P NSTAR Electric PSNH For the Year Ended December 31, 2025 Cash Paid for Amounts Included in the Measurement of Lease Liabilities: Operating Cash Flows from Operating Leases $ 12.8 $ 2.8 $ 5.0 $ 1.9 Operating Cash Flows from Finance Leases 2.8 0.9 0.7 — Financing Cash Flows from Finance Leases 5.7 1.5 — 0.2 Supplemental Non-Cash Information on Lease Liabilities: Right-of-use-Assets Obtained in Exchange for New Operating Lease Liabilities 1.4 0.8 0.1 0.1 Right-of-use-Assets Obtained in Exchange for New Finance Lease Liabilities 19.7 — — 0.7 (Millions of Dollars) Eversource CL&P NSTAR Electric PSNH For the Year Ended December 31, 2024 Cash Paid for Amounts Included in the Measurement of Lease Liabilities: Operating Cash Flows from Operating Leases $ 14.5 $ 2.5 $ 4.9 $ 1.8 Operating Cash Flows from Finance Leases 2.6 0.7 0.7 — Financing Cash Flows from Finance Leases 5.2 1.2 — — Supplemental Non-Cash Information on Lease Liabilities: Right-of-use-Assets Obtained in Exchange for New Operating Lease Liabilities 15.3 7.8 5.7 0.3 Right-of-use-Assets Obtained in Exchange for New Finance Lease Liabilities 0.3 — — — (Millions of Dollars) Eversource CL&P NSTAR Electric PSNH For the Year Ended December 31, 2023 Cash Paid for Amounts Included in the Measurement of Lease Liabilities: Operating Cash Flows from Operating Leases $ 10.5 $ 0.7 $ 2.5 $ 0.4 Operating Cash Flows from Finance Leases 2.0 — 0.6 — Financing Cash Flows from Finance Leases 3.9 — — — Supplemental Non-Cash Information on Lease Liabilities: Right-of-use-Assets Obtained in Exchange for New Operating Lease Liabilities 12.8 0.6 7.0 5.0 Right-of-use-Assets Obtained in Exchange for New Finance Lease Liabilities 18.5 18.3 — — As of December 31, 2025, there are no lease agreements for Eversource, CL&P, NSTAR Electric or PSNH which have been executed but have yet to commence and have not been recorded as right-of-use assets. Future minimum lease payments, excluding variable costs, under long-term leases, as of December 31, 2025 are as follows: Operating Leases Finance Leases (Millions of Dollars) Eversource CL&P NSTAR Electric PSNH Eversource CL&P NSTAR Electric PSNH Year Ending December 31, 2026 $ 11.5 $ 2.6 $ 5.0 $ 1.5 $ 27.9 $ 2.4 $ 0.7 0.2 2027 7.1 2.0 2.8 0.1 8.2 2.5 0.7 0.2 2028 6.8 1.9 2.8 — 7.5 2.6 0.7 0.2 2029 4.7 0.1 2.5 — 7.3 2.6 0.7 — 2030 4.3 — 2.5 — 7.3 2.6 0.7 — Thereafter 22.0 0.1 19.6 0.1 43.1 6.2 9.6 — Future lease payments 56.4 6.7 35.2 1.7 101.3 18.9 13.1 0.6 Less amount representing interest 9.0 0.6 8.0 0.2 19.6 3.3 8.2 0.1 Present value of future minimum lease payments $ 47.4 $ 6.1 $ 27.2 $ 1.5 $ 81.7 $ 15.6 $ 4.9 $ 0.5 136
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15. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each of the following financial instruments: Preferred Stock, Long-Term Debt and Rate Reduction Bonds: The fair value of CL&P's and NSTAR Electric's preferred stock is based upon pricing models that incorporate interest rates and other market factors, valuations or trades of similar securities and cash flow projections. The fair value of long- term debt and RRB debt securities is based upon pricing models that incorporate quoted market prices for those issues or similar issues adjusted for market conditions, credit ratings of the respective companies and treasury benchmark yields. The fair values provided in the table below are classified as Level 2 within the fair value hierarchy. Carrying amounts and estimated fair values are as follows: Eversource CL&P NSTAR Electric PSNH (Millions of Dollars) CarryingAmount Fair Value CarryingAmount FairValue CarryingAmount FairValue CarryingAmount FairValue As of December 31, 2025: Preferred Stock Not Subject to Mandatory Redemption $ 155.6 $ 126.1 $ 116.2 $ 92.9 $ 43.0 $ 33.2 $ — $ — Long-Term Debt 28,265.4 27,055.5 5,110.1 4,844.7 5,945.6 5,752.6 2,031.3 1,874.8 Rate Reduction Bonds 324.1 320.2 — — — — 324.1 320.2 As of December 31, 2024: Preferred Stock Not Subject to Mandatory Redemption $ 155.6 $ 123.8 $ 116.2 $ 90.3 $ 43.0 $ 33.5 $ — $ — Long-Term Debt 26,704.8 24,791.4 5,111.1 4,705.8 5,094.9 4,759.4 1,732.1 1,529.7 Rate Reduction Bonds 367.3 352.1 — — — — 367.3 352.1 Derivative Instruments and Marketable Securities: Derivative instruments and investments in marketable securities are carried at fair value. For further information, see Note 4, "Derivative Instruments," and Note 5, "Marketable Securities," to the financial statements. See Note 1H, "Summary of Significant Accounting Policies – Fair Value Measurements," for the fair value measurement policy and the fair value hierarchy. 16. ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) The changes in accumulated other comprehensive income/(loss) by component, net of tax, are as follows: For the Year Ended December 31, 2025 For the Year Ended December 31, 2024 Eversource (Millions of Dollars) QualifiedCash Flow HedgingInstruments Defined BenefitPlans Total QualifiedCash Flow HedgingInstruments Defined BenefitPlans Total Balance as of January 1st $ (0.4) $ (26.1) $ (26.5) $ (0.4) $ (33.3) $ (33.7) OCI Before Reclassifications — 0.5 0.5 — (2.5) (2.5) Amounts Reclassified from AOCI — 5.5 5.5 — 9.7 9.7 Net OCI — 6.0 6.0 — 7.2 7.2 Balance as of December 31st $ (0.4) $ (20.1) $ (20.5) $ (0.4) $ (26.1) $ (26.5) Defined benefit plan OCI amounts before reclassifications relate to actuarial gains and losses that arose during the year and were recognized in AOCI. The unamortized actuarial gains and losses and prior service costs on the defined benefit plans are amortized from AOCI into Other Income, Net over the average future employee service period, and are reflected in amounts reclassified from AOCI. The related tax effects of the defined benefit plan OCI amounts before reclassifications recognized in AOCI was a net deferred tax liability of $0.1 million in 2025 and were net deferred tax assets of $0.4 million and $4.9 million in 2024 and 2023, respectively. 137
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The following table sets forth the amounts reclassified from AOCI by component and the impacted line item on the statements of income: Amounts Reclassified from AOCI Eversource(Millions of Dollars) For the Years Ended December 31, Statements of IncomeLine Item Impacted2025 2024 2023 Unrealized Loss on Marketable Securities — — (1.6) Other Income, Net Tax Effect — — 0.4 Income Tax Expense Unrealized Loss on Marketable Securities, Net of Tax — — (1.2) Defined Benefit Plan Costs: Amortization of Actuarial Losses (4.2) (6.8) (7.0) Other Income, Net Amortization of Prior Service Cost — (0.3) (0.3) Other Income, Net Settlement Losses (3.3) (4.3) (12.4) Other Income, Net Total Defined Benefit Plan Costs (7.5) (11.4) (19.7) Tax Effect 2.0 1.7 6.4 Income Tax Expense Defined Benefit Plan Costs, Net of Tax (5.5) (9.7) (13.3) Total Amounts Reclassified from AOCI, Net of Tax $ (5.5) $ (9.7) $ (14.5) These amounts are included in the computation of net periodic Pension, SERP and PBOP costs. See Note 1L, "Summary of Significant Accounting Policies – Other Income, Net" and Note 11A, "Employee Benefits – Pension Benefits and Postretirement Benefits Other Than Pension," for further information. 17. DIVIDEND RESTRICTIONS Eversource parent's ability to pay dividends may be affected by certain state statutes, the ability of its subsidiaries to pay common dividends and the leverage restriction tied to its consolidated total indebtedness to total capitalization ratio requirement in its revolving credit agreements. Pursuant to the joint revolving credit agreement of Eversource, CL&P, PSNH, NSTAR Gas, Yankee Gas, EGMA and Aquarion Water Company of Connecticut, and to the NSTAR Electric revolving credit agreement, Eversource is required to maintain consolidated total indebtedness to total capitalization ratio of no greater than 70 percent at the end of each fiscal quarter and each other company is required to maintain consolidated total indebtedness to total capitalization ratio of no greater than 65 percent at the end of each fiscal quarter. As of December 31, 2025, all companies were in compliance with such covenant and in compliance with all such provisions of the revolving credit agreements that may restrict the payment of dividends as of December 31, 2025. The Retained Earnings balances subject to dividend restrictions were $4.50 billion for Eversource, $2.93 billion for CL&P, $3.32 billion for NSTAR Electric and $903.0 million for PSNH as of December 31, 2025. CL&P, NSTAR Electric and PSNH are subject to Section 305 of the Federal Power Act that makes it unlawful for a public utility to make or pay a dividend from any funds "properly included in its capital account." Management believes that this Federal Power Act restriction, as applied to CL&P, NSTAR Electric and PSNH, would not be construed or applied by the FERC to prohibit the payment of dividends from retained earnings for lawful and legitimate business purposes. In addition, certain state statutes may impose additional limitations on such companies and, including but not limited to, on NSTAR Gas, Yankee Gas, EGMA, and Aquarion’s operating companies. Such state law restrictions do not restrict the payment of dividends from retained earnings or net income. 18. COMMON SHARES The following table sets forth the Eversource parent common shares and the shares of common stock of CL&P, NSTAR Electric and PSNH that were authorized and issued, as well as the respective per share par values: Shares Par Value Authorized as of December31, 2025 and 2024 Issued as of December 31, 2025 2024 Eversource $ 5 410,000,000 382,854,501 375,724,367 CL&P $ 10 24,500,000 6,035,205 6,035,205 NSTAR Electric $ 1 100,000,000 200 200 PSNH $ 1 100,000,000 301 301 Common Share Issuances: On May 30, 2025, Eversource entered into an equity distribution agreement pursuant to which it may offer and sell up to $1.2 billion of its common shares from time to time through an “at-the-market” (ATM) equity offering program. Eversource may issue and sell its common shares through its sales agents during the term of this agreement. Shares were offered in transactions on the New York Stock Exchange, in the over-the-counter market, through negotiated transactions or otherwise. Sales may be made at either market prices prevailing at the time of sale, at prices related to such prevailing market prices or at negotiated prices. In 2025, Eversource issued 7,130,134 common shares, which resulted in proceeds of $465.4 million, net of issuance costs. Eversource used the net proceeds received for general corporate purposes. (1) (1) (1) (1) 138
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On May 11, 2022, Eversource entered into an equity distribution agreement pursuant to which it could offer and sell up to $1.2 billion of its common shares from time to time through an ATM equity offering program. In 2024, Eversource issued 15,740,294 common shares, which resulted in proceeds of $989.4 million, net of issuance costs. Eversource used the net proceeds received for general corporate purposes. Eversource completed the program in October 2024. Treasury Shares: As of December 31, 2025 and 2024, there were 7,437,621 and 9,116,315 Eversource common shares held as treasury shares, respectively. As of December 31, 2025 and 2024, there were 375,416,880 and 366,608,052 Eversource common shares outstanding, respectively. Eversource issues treasury shares to satisfy awards under the Company's incentive plans, shares issued under the dividend reinvestment and share purchase plan, and matching contributions under the Eversource 401k Plan. The issuance of treasury shares represents a non-cash transaction, as the treasury shares were used to fulfill Eversource's obligations that require the issuance of common shares. 19. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION The CL&P and NSTAR Electric preferred stock is not subject to mandatory redemption and is presented as a noncontrolling interest of a subsidiary in Eversource's financial statements. CL&P is authorized to issue up to 9,000,000 shares of preferred stock, par value $50 per share, and NSTAR Electric is authorized to issue 2,890,000 shares of preferred stock, par value $100 per share. Holders of preferred stock of CL&P and NSTAR Electric are entitled to receive cumulative dividends in preference to any payment of dividends on the common stock. Upon liquidation, holders of preferred stock of CL&P and NSTAR Electric are entitled to receive a liquidation preference before any distribution to holders of common stock in an amount equal to the par value of the preferred stock plus accrued and unpaid dividends. If the net assets were to be insufficient to pay the liquidation preference in full, then the net assets would be distributed ratably to all holders of preferred stock. The preferred stock of CL&P and NSTAR Electric is subject to optional redemption by the CL&P and NSTAR Electric Boards of Directors at any time. Details of preferred stock not subject to mandatory redemption are as follows (in millions, except in redemption price and shares): Redemption PricePer Share Shares Outstanding as of December 31, As of December 31, Series 2025 2024 2025 2024 CL&P $1.90 Series of 1947 $ 52.50 163,912 163,912 $ 8.2 $ 8.2 $2.00 Series of 1947 $ 54.00 336,088 336,088 16.8 16.8 $2.04 Series of 1949 $ 52.00 100,000 100,000 5.0 5.0 $2.20 Series of 1949 $ 52.50 200,000 200,000 10.0 10.0 3.90% Series of 1949 $ 50.50 160,000 160,000 8.0 8.0 $2.06 Series E of 1954 $ 51.00 200,000 200,000 10.0 10.0 $2.09 Series F of 1955 $ 51.00 100,000 100,000 5.0 5.0 4.50% Series of 1956 $ 50.75 104,000 104,000 5.2 5.2 4.96% Series of 1958 $ 50.50 100,000 100,000 5.0 5.0 4.50% Series of 1963 $ 50.50 160,000 160,000 8.0 8.0 5.28% Series of 1967 $ 51.43 200,000 200,000 10.0 10.0 $3.24 Series G of 1968 $ 51.84 300,000 300,000 15.0 15.0 6.56% Series of 1968 $ 51.44 200,000 200,000 10.0 10.0 Total CL&P 2,324,000 2,324,000 116.2 116.2 NSTAR Electric 4.25% Series of 1956 $ 103.625 180,000 180,000 18.0 18.0 4.78% Series of 1958 $ 102.80 250,000 250,000 25.0 25.0 Total NSTAR Electric 430,000 430,000 43.0 43.0 Fair Value Adjustment due to Merger with NSTAR (3.6) (3.6) Total Eversource - Noncontrolling Interest - Preferred Stock of Subsidiaries $ 155.6 $ 155.6 20. COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS Dividends on the preferred stock of CL&P and NSTAR Electric totaled $7.5 million for each of the years ended December 31, 2025, 2024 and 2023. These dividends were presented as Net Income Attributable to Noncontrolling Interests on the Eversource statements of income. Noncontrolling Interest – Preferred Stock of Subsidiaries on the Eversource balance sheets totaled $155.6 million as of December 31, 2025 and 2024. On the Eversource balance sheets, Common Shareholders' Equity was fully attributable to Eversource parent and Noncontrolling Interest – Preferred Stock of Subsidiaries was fully attributable to the noncontrolling interest. For the years ended December 31, 2025, 2024 and 2023, there was no change in ownership of the common equity of CL&P and NSTAR Electric. 139
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21. EARNINGS/(LOSS) PER SHARE Basic earnings/(loss) per share is computed based upon the weighted average number of common shares outstanding during each period. Diluted earnings/(loss) per share is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect of certain share-based compensation awards as if they were converted into outstanding common shares. The dilutive effect of unvested RSU and performance share awards is calculated using the treasury stock method. RSU and performance share awards are included in basic weighted average common shares outstanding as of the date that all necessary vesting conditions have been satisfied. For the years ended December 31, 2025, 2024 and 2023, there were no antidilutive share awards excluded from the computation of diluted EPS. The following table sets forth the components of basic and diluted earnings per share: Eversource (Millions of Dollars, except share information) For the Years Ended December 31, 2025 2024 2023 Net Income/(Loss) Attributable to Common Shareholders $ 1,692.4 $ 811.7 $ (442.2) Weighted Average Common Shares Outstanding: Basic 370,852,601 357,482,965 349,580,638 Dilutive Effect 406,663 296,443 259,843 Diluted 371,259,264 357,779,408 349,840,481 Basic Earnings/(Loss) Per Common Share $ 4.56 $ 2.27 $ (1.27) Diluted Earnings/(Loss) Per Common Share $ 4.56 $ 2.27 $ (1.26) 22. REVENUES Revenue is recognized when promised goods or services (referred to as performance obligations) are transferred to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. A five-step model is used for recognizing and measuring revenue from contracts with customers, which includes identifying the contract with the customer, identifying the performance obligations promised within the contract, determining the transaction price (the amount of consideration to which the company expects to be entitled), allocating the transaction price to the performance obligations and recognizing revenue when (or as) the performance obligation is satisfied. The following tables present operating revenues disaggregated by revenue source: For the Year Ended December 31, 2025 Eversource (Millions of Dollars) ElectricDistribution Natural GasDistribution ElectricTransmission WaterDistribution Other Eliminations Total Revenues from Contracts with Customers Retail Tariff Sales Residential $ 5,215.5 $ 1,474.9 $ — $ 167.8 $ — $ — $ 6,858.2 Commercial 3,273.4 716.3 — 71.1 — (8.9) 4,051.9 Industrial 421.6 210.0 — 4.8 — (26.1) 610.3 Total Retail Tariff Sales Revenues 8,910.5 2,401.2 — 243.7 — (35.0) 11,520.4 Wholesale Transmission Revenues — — 2,452.1 — — (1,786.8) 665.3 Wholesale Market Sales Revenues 1,004.7 184.0 — 4.4 — — 1,193.1 Other Revenues from Contracts with Customers 88.3 5.8 14.4 2.6 1,732.7 (1,729.5) 114.3 Total Revenues from Contracts with Customers 10,003.5 2,591.0 2,466.5 250.7 1,732.7 (3,551.3) 13,493.1 Alternative Revenue Programs 17.2 40.8 (183.7) (15.0) — 171.2 30.5 Other Revenues 18.9 3.0 0.5 1.2 — — 23.6 Total Operating Revenues $ 10,039.6 $ 2,634.8 $ 2,283.3 $ 236.9 $ 1,732.7 $ (3,380.1) $ 13,547.2 140
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For the Year Ended December 31, 2024 Eversource(Millions of Dollars) Electric Distribution Natural Gas Distribution Electric Transmission Water Distribution Other Eliminations Total Revenues from Contracts with Customers Retail Tariff Sales Residential $ 4,904.8 $ 1,129.1 $ — $ 150.4 $ — $ — $ 6,184.3 Commercial 2,973.3 588.0 — 70.3 — (7.7) 3,623.9 Industrial 389.0 172.5 — 4.7 — (22.4) 543.8 Total Retail Tariff Sales Revenues 8,267.1 1,889.6 — 225.4 — (30.1) 10,352.0 Wholesale Transmission Revenues — — 2,032.4 — — (1,529.3) 503.1 Wholesale Market Sales Revenues 658.9 161.9 — 4.2 — — 825.0 Other Revenues from Contracts with Customers 92.2 5.1 13.9 3.8 1,701.3 (1,694.6) 121.7 Total Revenues from Contracts with Customers 9,018.2 2,056.6 2,046.3 233.4 1,701.3 (3,254.0) 11,801.8 Alternative Revenue Programs 28.7 44.5 74.2 (5.3) — (67.2) 74.9 Other Revenues 19.6 2.8 0.5 1.2 — — 24.1 Total Operating Revenues $ 9,066.5 $ 2,103.9 $ 2,121.0 $ 229.3 $ 1,701.3 $ (3,321.2) $ 11,900.8 For the Year Ended December 31, 2023 Eversource(Millions of Dollars) ElectricDistribution Natural GasDistribution ElectricTransmission WaterDistribution Other Eliminations Total Revenues from Contracts with Customers Retail Tariff Sales Residential $ 5,054.2 $ 1,145.4 $ — $ 144.7 $ — $ — $ 6,344.3 Commercial 2,893.2 637.7 — 69.8 — (4.8) 3,595.9 Industrial 352.4 186.8 — 4.5 — (19.7) 524.0 Total Retail Tariff Sales Revenues 8,299.8 1,969.9 — 219.0 — (24.5) 10,464.2 Wholesale Transmission Revenues — — 1,777.5 — — (1,310.5) 467.0 Wholesale Market Sales Revenues 625.0 206.7 — 3.9 — — 835.6 Other Revenues from Contracts with Customers 82.6 5.6 18.9 8.1 1,636.6 (1,628.0) 123.8 Total Revenues from Contracts with Customers 9,007.4 2,182.2 1,796.4 231.0 1,636.6 (2,963.0) 11,890.6 Alternative Revenue Programs (54.3) 35.5 118.9 0.4 — (106.5) (6.0) Other Revenues 20.4 4.0 0.6 1.1 — — 26.1 Total Operating Revenues $ 8,973.5 $ 2,221.7 $ 1,915.9 $ 232.5 $ 1,636.6 $ (3,069.5) $ 11,910.7 For the Years Ended December 31, 2025 2024 2023 (Millions of Dollars) CL&P NSTARElectric PSNH CL&P NSTARElectric PSNH CL&P NSTARElectric PSNH Revenues from Contracts with Customers Retail Tariff Sales Residential $ 2,716.1 $ 1,802.6 $ 696.8 $ 2,493.7 $ 1,771.8 $ 639.3 $ 2,597.8 $ 1,691.0 $ 765.4 Commercial 1,263.9 1,650.0 361.7 1,164.8 1,466.7 343.6 1,082.1 1,442.3 369.6 Industrial 175.4 143.3 102.9 164.2 118.1 106.7 137.2 123.2 92.0 Total Retail Tariff Sales Revenues 4,155.4 3,595.9 1,161.4 3,822.7 3,356.6 1,089.6 3,817.1 3,256.5 1,227.0 Wholesale Transmission Revenues 1,037.8 901.1 513.2 870.8 794.1 367.5 794.7 692.0 290.8 Wholesale Market Sales Revenues 801.3 169.6 33.8 491.9 131.1 35.9 429.1 131.8 64.1 Other Revenues from Contracts with Customers 36.1 46.5 22.5 36.7 50.2 21.2 36.7 49.1 18.1 Total Revenues from Contracts with Customers 6,030.6 4,713.1 1,730.9 5,222.1 4,332.0 1,514.2 5,077.6 4,129.4 1,600.0 Alternative Revenue Programs (79.2) (4.9) (82.4) 45.4 36.7 20.8 66.8 (52.0) 49.8 Other Revenues 6.8 9.7 2.9 9.0 8.5 2.6 9.6 8.4 3.0 Eliminations (717.2) (731.3) (275.0) (661.5) (656.3) (243.1) (575.2) (570.3) (204.9) Total Operating Revenues $ 5,241.0 $ 3,986.6 $ 1,376.4 $ 4,615.0 $ 3,720.9 $ 1,294.5 $ 4,578.8 $ 3,515.5 $ 1,447.9 Retail Tariff Sales: Regulated utilities provide products and services to their regulated customers under rates, pricing, payment terms and conditions of service, regulated by each state regulatory agency. The arrangement whereby a utility provides commodity service to a customer for a price approved by the respective state regulatory commission is referred to as a tariff sale contract, and the tariff governs all aspects of the provision of regulated services by utilities. The majority of revenue for Eversource, CL&P, NSTAR Electric and PSNH is derived from regulated retail tariff sales for the sale and distribution of electricity, natural gas and water to residential, commercial and industrial retail customers. 141
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The utility's performance obligation for the regulated tariff sales is to provide electricity, natural gas or water to the customer as demanded. The promise to provide the commodity represents a single performance obligation, as it is a promise to transfer a series of distinct goods or services that are substantially the same and that have the same pattern of transfer to the customer. Revenue is recognized over time as the customer simultaneously receives and consumes the benefits provided by the utility, and the utility satisfies its performance obligation. Revenue is recognized based on the output method as there is a directly observable output to the customer (electricity, natural gas or water units delivered to the customer and immediately consumed). Each Eversource utility is entitled to be compensated for performance completed to date (service taken by the customer) until service is terminated. In regulated tariff sales, the transaction prices are the rates approved by the respective state regulatory commissions. In general, rates can only be changed through formal proceedings with the state regulatory commissions. These rates are designed to recover the costs to provide service to customers and include a return on investment. Regulatory commission-approved tracking mechanisms are included in these rates and are also used to recover, on a fully- reconciling basis, certain costs, such as the procurement of energy supply, state mandated energy purchase agreements, retail transmission charges, energy efficiency program costs, net metering for distributed generation, and restructuring and stranded costs, among others. These tracking mechanisms result in rates being changed periodically to ensure recovery of actual costs incurred and the refund of any overcollection of costs. Electric customers may elect to purchase electricity from each Eversource electric utility or may contract separately with a competitive third-party supplier. Certain eligible natural gas customers may elect to purchase natural gas from each Eversource natural gas utility or may contract separately with a gas supply operator. Revenue is not recorded for the sale of the electricity or the natural gas commodity to customers who have contracted separately with these suppliers, only the delivery to a customer, as the utility is acting as an agent on behalf of the supplier. Wholesale Transmission Revenues: The Eversource electric transmission-owning companies (CL&P, NSTAR Electric and PSNH) each own and maintain transmission facilities that are part of an interstate power transmission grid over which electricity is transmitted throughout New England. CL&P, NSTAR Electric and PSNH, as well as most other New England utilities, are parties to a series of agreements that provide for coordinated planning and operation of the region's transmission facilities and the rules by which they acquire transmission services. The Eversource electric transmission-owning companies have a combination of FERC-approved regional and local formula rates that are designed to work in tandem to recover all their transmission costs. These rates are part of the ISO-NE Tariff. Regional rates recover the costs of higher voltage transmission facilities that benefit the region and are collected from all New England transmission customers, including the Eversource distribution businesses. Eversource's local rates generally recover the costs of transmission facilities that do not provide a benefit to the region, and are collected from Eversource's distribution businesses and other transmission customers. The distribution businesses of Eversource, in turn, recover the FERC approved charges from retail customers through annual tracking mechanisms, which are retail tariff sales. The utility's performance obligation for regulated wholesale transmission sales is to provide transmission services to the customer as demanded. The promise to provide transmission service represents a single performance obligation. The transaction prices are the transmission rate formulas as defined by the ISO-NE Tariff and are regulated and established by FERC. Wholesale transmission revenue is recognized over time as the performance obligation is completed, which occurs as transmission services are provided to customers. The revenue is recognized based on the output method. Each Eversource utility is entitled to be compensated for performance completed to date (e.g., use of the transmission system by the customer). Wholesale Market Sales Revenues: Wholesale market sales transactions include sales of energy and energy-related products into the ISO-NE wholesale electricity market, sales of natural gas to third-party marketers, and the sale of RECs to various counterparties. ISO-NE oversees the region's wholesale electricity market and administers the transactions and terms and conditions, including payment terms, which are established in the ISO-NE tariff, between the buyers and sellers in the market. Pricing is set by the wholesale market. The wholesale transactions in the ISO-NE market occur on a day- ahead basis or a real-time basis (daily) and are, therefore, short-term. Transactions are tracked and reported by ISO-NE net by the hour, which is the net hourly position of energy sales and purchases by each market participant. The performance obligation for ISO-NE energy transactions is defined to be the net by hour transaction. Revenue is recognized when the performance obligation for these energy sales transactions is satisfied, which is when the sale occurs and the energy is transferred to the customer. For sales of natural gas, transportation, and natural gas pipeline capacity to third-party marketers, revenue is recognized when the performance obligation is satisfied at the point in time the sale occurs and the natural gas or related product is transferred to the marketer. RECs are sold to various counterparties, and revenue is recognized when the performance obligation is satisfied upon transfer of title to the customer through the New England Power Pool Generation Information System. Wholesale transactions also include the sale of CL&P’s, NSTAR Electric’s and PSNH’s transmission rights associated with their proportionate equity ownership share in the transmission lines of the Hydro-Québec system in Canada. Other Revenues from Contracts with Customers: Other revenues from contracts with customers primarily include property rentals that are not deemed leases. These revenues are generally recognized on a straight-line basis over time as the service is provided to the customer. Other revenues also include revenues from Eversource's service company, which is eliminated in consolidation. Alternative Revenue Programs: In accordance with accounting guidance for rate-regulated operations, certain of Eversource's utilities' rate making mechanisms qualify as alternative revenue programs (ARPs) if they meet specified criteria, in which case revenues may be recognized prior to billing based on allowed levels of collection in rates. Eversource's utility companies recognize revenue and record a regulatory asset or liability once the condition or event allowing for the automatic adjustment of future rates occurs. ARP revenues include both the recognition of the deferral adjustment to ARP revenues, when the regulator-specified condition or event allowing for additional billing or refund has occurred, and an equal and offsetting reversal of the ARP deferral to revenues as those amounts are reflected in the price of service in subsequent periods. 142
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Eversource’s ARPs include the revenue decoupling mechanism, the annual reconciliation adjustment to transmission formula rates, and certain capital tracker mechanisms. Certain Eversource electric, natural gas and water companies, including CL&P and NSTAR Electric, have revenue decoupling mechanisms approved by a regulatory commission (decoupled companies). Decoupled companies’ distribution revenues are not directly based on sales volumes. The decoupled companies reconcile their annual base distribution rate recovery to pre-established levels of baseline distribution delivery service revenues, with any difference between the allowed level of distribution revenue and the actual amount realized adjusted through subsequent rates. The transmission formula rates provide for the annual reconciliation and recovery or refund of estimated costs to actual costs. The financial impacts of differences between actual and estimated costs are deferred for future recovery from, or refund to, transmission customers. This transmission deferral reconciles billed transmission revenues to the revenue requirement for our transmission businesses. Other Revenues: Other Revenues include certain fees charged to customers that are not considered revenue from contracts with customers. Other revenues also include lease revenues under lessor accounting guidance of $3.1 million ($0.5 million at CL&P and $1.8 million at NSTAR Electric), $2.5 million ($0.5 million at CL&P and $1.2 million at NSTAR Electric), and $4.6 million, ($0.7 million at CL&P and $2.5 million at NSTAR Electric) for the years ended December 31, 2025, 2024 and 2023, respectively. Intercompany Eliminations: Intercompany eliminations are primarily related to the Eversource electric transmission revenues that are derived from ISO- NE regional transmission charges to the distribution businesses of CL&P, NSTAR Electric and PSNH that recover the costs of the wholesale transmission business, and revenues from Eversource's service company. Intercompany revenues and expenses between the Eversource wholesale transmission businesses and the Eversource distribution businesses and from Eversource's service company are eliminated in consolidation and included in "Eliminations" in the tables above. Receivables: Receivables, Net on the balance sheet primarily includes trade receivables from retail customers and customers related to wholesale transmission contracts, wholesale market sales, sales of RECs, and property rentals. In general, retail tariff customers and wholesale transmission customers are billed monthly, and the payment terms are generally due and payable upon receipt of the bill. Unbilled Revenues: Unbilled Revenues on the balance sheet represent estimated amounts due from retail customers for electricity, natural gas or water delivered to customers but not yet billed. The utility company has satisfied its performance obligation and the customer has received and consumed the commodity as of the balance sheet date, and therefore, the utility company records revenue for those services in the period the services were provided. Only the passage of time is required before the company is entitled to payment for the satisfaction of the performance obligation. Payment from customers is due monthly as services are rendered and amounts are billed. Actual amounts billed to customers when meter readings become available may vary from the estimated amount. Unbilled revenues are recognized by allocating estimated unbilled sales volumes to the respective customer classes, and then applying an estimated rate by customer class to those sales volumes. Unbilled revenue estimates reflect seasonality, weather, customer usage patterns, customer rates in effect for customer classes, and the timing of customer billing. The companies that have a decoupling mechanism record a regulatory deferral to reflect the actual allowed amount of revenue associated with their respective decoupled distribution rate design. Practical Expedients: Eversource has elected practical expedients in the accounting guidance that allow the company to record revenue in the amount that the company has a right to invoice, if that amount corresponds directly with the value to the customer of the company's performance to date, and not to disclose related unsatisfied performance obligations. Retail and wholesale transmission tariff sales fall into this category, as these sales are recognized as revenue in the period the utility provides the service and completes the performance obligation, which is the same as the monthly amount billed to customers. There are no other material revenue streams for which Eversource has unsatisfied performance obligations. 23. SEGMENT INFORMATION Eversource is organized into the Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution reportable segments and Other based on a combination of factors, including the characteristics of each segments' services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates. The Electric Distribution segment consists of the rate-regulated distribution businesses of CL&P, NSTAR Electric and PSNH, and includes the results of NSTAR Electric's solar power facilities. The Electric Transmission segment consists of the rate-regulated electric transmission businesses of CL&P, NSTAR Electric and PSNH. The Natural Gas Distribution segment consists of the rate-regulated businesses of Yankee Gas, NSTAR Gas and EGMA. The Water Distribution segment consists of the rate-regulated business of Aquarion. These reportable segments represent substantially all of Eversource's total consolidated revenues. Revenues from the sale of electricity, natural gas and water primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer. Eversource's reportable segments are determined based upon the level at which Eversource's chief operating decision maker assesses performance and makes decisions about the allocation of company resources. The chief operating decision maker uses the net income of each reportable segment to evaluate return generated from assets and decide how to reinvest profits and allocate resources, to monitor budget-to-actual results, in the planning and forecasting process, in determining compensation achievement, and in benchmarking to Eversource’s peers. Eversource’s chief operating decision maker is its chief executive officer. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. 143
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The remainder of Eversource's operations is presented as Other in the tables below and primarily consists of 1) the equity in earnings of Eversource parent from its subsidiaries and intercompany interest income, both of which are eliminated in consolidation, and interest expense related to the debt of Eversource parent, 2) the revenues and expenses of Eversource Service, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, 4) the results of other unregulated subsidiaries, which are not part of its core business, and 5) Eversource parent's equity ownership interests that are not consolidated, which primarily included the offshore wind investments until sale of the three offshore wind projects in 2024 and a natural gas pipeline owned by Enbridge, Inc. In the ordinary course of business, Yankee Gas, NSTAR Gas and EGMA purchase natural gas transmission services from the Enbridge, Inc. natural gas pipeline project described above. These affiliate transaction costs total $77.7 million annually and are classified as Purchased Power, Purchased Natural Gas and Transmission on the Eversource statements of income. Each of Eversource's subsidiaries, including CL&P, NSTAR Electric and PSNH, has one reportable segment. Cash flows used for investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized and deferred portions of pension and PBOP income/expense. Eversource's segment information is as follows: For the Year Ended December 31, 2025 Eversource(Millions of Dollars) Electric Distribution Natural Gas Distribution Electric Transmission Water Distribution Other Eliminations Total Operating Revenues $ 10,039.6 $ 2,634.8 $ 2,283.3 $ 236.9 $ 1,732.7 $ (3,380.1) $ 13,547.2 Depreciation and Amortization (1,435.1) (279.7) (437.1) (46.8) (220.1) 14.3 (2,404.5) Operations and Maintenance Operations, Excluding Storm Costs (432.8) (181.5) (152.0) Corporate Shared Services (443.4) (114.2) (77.0) Storm Costs (89.2) — — Employee Benefits (266.6) (89.3) (58.6) Uncollectible Expense (167.2) (74.3) — Other (170.8) (46.6) (79.7) Total Operations and Maintenance (1,570.0) (505.9) (367.3) (95.6) (1,285.2) 1,750.2 (2,073.8) Purchased Power, Purchased Natural Gas andTransmission, Other Taxes and Energy Efficiency (6,048.0) (1,314.4) (302.2) (27.4) (3.9) 1,615.6 (6,080.3) Operating Income 986.5 534.8 1,176.7 67.1 223.5 — 2,988.6 Interest Expense (386.3) (119.4) (171.6) (30.8) (701.2) 166.0 (1,243.3) Loss on Offshore Wind — — — — (284.0) — (284.0) Interest Income 98.2 26.8 0.4 0.1 166.0 (166.0) 125.5 Other Income, Net 155.9 30.5 40.9 6.1 1,943.5 (1,923.5) 253.4 Income Tax (Expense)/Benefit (182.6) (112.2) (266.8) 1.7 419.6 — (140.3) Net Income 671.7 360.5 779.6 44.2 1,767.4 (1,923.5) 1,699.9 Net Income Attributable to Noncontrolling Interests (4.6) — (2.9) — — — (7.5) Net Income Attributable to Common Shareholders $ 667.1 $ 360.5 $ 776.7 $ 44.2 $ 1,767.4 $ (1,923.5) $ 1,692.4 Total Assets (as of) $ 34,858.1 $ 10,865.5 $ 17,193.9 $ 2,977.6 $ 29,743.3 $ (31,851.7) $ 63,786.7 Cash Flows Used for Investments in Plant $ 1,872.6 $ 834.6 $ 1,094.0 $ 165.3 $ 192.2 $ — $ 4,158.7 (1) (2) 144
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For the Year Ended December 31, 2024 Eversource(Millions of Dollars) Electric Distribution Natural Gas Distribution Electric Transmission Water Distribution Other Eliminations Total Operating Revenues $ 9,066.5 $ 2,103.9 $ 2,121.0 $ 229.3 $ 1,701.3 $ (3,321.2) $ 11,900.8 Depreciation and Amortization (934.7) (216.6) (405.1) (32.3) (198.7) 11.0 (1,776.4) Operations and Maintenance Operations, Excluding Storm Costs (447.3) (180.9) (135.1) Corporate Shared Services (457.1) (106.1) (74.6) Storm Costs (76.8) — — Employee Benefits (202.5) (76.9) (52.7) Uncollectible Expense (182.8) (48.4) — Other (135.9) (29.2) (71.1) Total Operations and Maintenance (1,502.4) (441.5) (333.5) (98.7) (1,350.5) 1,713.7 (2,012.9) Purchased Power, Purchased Natural Gas andTransmission, Other Taxes and Energy Efficiency (5,685.3) (1,007.1) (276.0) (26.3) (7.6) 1,596.5 (5,405.8) Loss on Pending Sale of Aquarion — — — (297.0) — — (297.0) Operating Income/(Loss) 944.1 438.7 1,106.4 (225.0) 144.5 — 2,408.7 Interest Expense (359.1) (99.2) (172.4) (36.2) (662.7) 218.3 (1,111.3) Loss on Offshore Wind — — — — (464.0) — (464.0) Interest Income 114.6 23.2 0.3 0.1 218.3 (218.3) 138.2 Other Income, Net 134.7 22.4 50.5 7.2 1,416.9 (1,359.4) 272.3 Income Tax (Expense)/Benefit (198.0) (94.1) (257.3) 0.2 124.5 — (424.7) Net Income/(Loss) 636.3 291.0 727.5 (253.7) 777.5 (1,359.4) 819.2 Net Income Attributable to Noncontrolling Interests (4.6) — (2.9) — — — (7.5) Net Income/(Loss) Attributable to Common Shareholders $ 631.7 $ 291.0 $ 724.6 $ (253.7) $ 777.5 $ (1,359.4) $ 811.7 Total Assets (as of) $ 32,031.9 $ 9,786.7 $ 16,070.9 $ 2,515.8 $ 29,041.1 $ (29,851.9) $ 59,594.5 Cash Flows Used for Investments in Plant $ 1,807.4 $ 934.5 $ 1,343.3 $ 161.8 $ 233.5 $ — $ 4,480.5 For the Year Ended December 31, 2023 Eversource(Millions of Dollars) Electric Distribution Natural Gas Distribution Electric Transmission Water Distribution Other Eliminations Total Operating Revenues $ 8,973.5 $ 2,221.7 $ 1,915.9 $ 232.5 $ 1,636.6 $ (3,069.5) $ 11,910.7 Depreciation and Amortization (18.2) (214.2) (371.2) (56.0) (158.8) 2.7 (815.7) Operations and Maintenance Operations, Excluding Storm Costs (418.2) (172.8) (124.7) Corporate Shared Services (397.2) (103.0) (62.5) Storm Costs (71.1) — (1.3) Employee Benefits (175.6) (76.6) (46.1) Uncollectible Expense (161.9) (64.8) — Other (167.9) (27.5) (57.4) Total Operations and Maintenance (1,391.9) (444.7) (292.0) (93.2) (1,325.6) 1,651.7 (1,895.7) Purchased Power, Purchased Natural Gas andTransmission, Other Taxes and Energy Efficiency (6,712.7) (1,217.9) (258.5) (23.9) (4.2) 1,417.2 (6,800.0) Operating Income 850.7 344.9 994.2 59.4 148.0 2.1 2,399.3 Interest Expense (291.7) (85.7) (163.7) (38.5) (425.3) 149.5 (855.4) Loss on Offshore Wind — — — — (2,167.0) — (2,167.0) Interest Income 74.5 18.2 0.4 — 150.6 (149.5) 94.2 Other Income/(Loss), Net 136.2 20.4 41.2 5.9 (261.8) 312.0 253.9 Income Tax (Expense)/Benefit (157.1) (73.0) (225.8) 6.3 289.9 — (159.7) Net Income/(Loss) 612.6 224.8 646.3 33.1 (2,265.6) 314.1 (434.7) Net Income Attributable to Noncontrolling Interests (4.6) — (2.9) — — — (7.5) Net Income/(Loss) Attributable to Common Shareholders $ 608.0 $ 224.8 $ 643.4 $ 33.1 $ (2,265.6) $ 314.1 $ (442.2) Cash Flows Used for Investments in Plant $ 1,668.1 $ 844.1 $ 1,406.3 $ 167.0 $ 251.3 $ — $ 4,336.8 (1) (2) (1) (2) 145
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The significant expense categories and amounts align with the segment-level information that is regularly provided to the chief operating decision maker. Costs of the operations organization include labor and overtime, outside services, vehicles, vegetation management, employee expenses, fees and payments, regulatory assessments, and materials, partially offset by reimbursements. Corporate shared services include corporate centralized functions. Costs within these corporate functions primarily include labor, services by vendors, fees and payments, insurance, and regulatory assessments. Other includes information technology system depreciation at Eversource Service charged to the operating businesses, as well as storm funding, capitalization and various other corporate costs. The segment-level operating expense for information technology system depreciation is eliminated and reflected in depreciation in Eversource’s consolidation. For the water distribution segment, the chief operating decision maker is provided with total operations and maintenance expense information to manage its operations. Operations and maintenance expenses primarily include employee costs, benefits, and outside services. Other segment line items for the electric distribution, electric transmission and natural gas distribution segments primarily include purchased power, purchased natural gas and transmission, taxes other than income taxes including property, payroll-related and Connecticut gross earnings taxes, and energy efficiency program expenses. Other segment line items for the water distribution business primarily include taxes other than income taxes. 24. ASSETS HELD FOR SALE In December 2024, Eversource obtained approval from its Board of Trustees to sell the Aquarion water distribution business. On January 27, 2025, Eversource entered into a definitive agreement to sell Aquarion to the Aquarion Water Authority (AWA), a quasi-public corporation and political subdivision of the State of Connecticut and a standalone, newly created water authority alongside the South Central Connecticut Regional Water Authority. In June 2024, a Connecticut law chartered AWA and enabled it to acquire, own and operate Aquarion as a not-for-profit water authority. Subject to certain closing adjustments, the aggregate enterprise value of the sale is approximately $2.4 billion in cash, which included approximately $1.6 billion for the equity and $800 million of net debt that will either be extinguished at closing or transferred to the buyer. The sale requires approval by PURA and the DPU, as well as other approvals pursuant to the Hart-Scott-Rodino Antitrust Improvements Act, for which the relevant waiting period has expired, as well as other customary closing conditions. Regulatory approvals in New Hampshire and Maine were received. Eversource plans to use the net proceeds from sale to pay down parent company debt. On November 19, 2025, PURA denied the application to approve the sale, finding that the transaction did not meet managerial suitability and responsibility requirements due to concerns with governance and oversight structure over Aquarion and its consumer advocate. On December 2, 2025, the denial was appealed to the Connecticut Superior Court. On January 15, 2026, the Court issued its decision, sustaining the appeal and remanding back to PURA, finding that PURA acted illegally in denying the application as those disputed governance elements were mandated under Connecticut law. The Court upheld that operational aspects of the consumer advocate were within PURA’s statutory authority and regulatory discretion. A final decision is expected by PURA on March 25, 2026. The assets and liabilities of the Aquarion water distribution business had previously met the criteria to be classified as held for sale as of December 31, 2024 and were classified separately as current or long-term assets and liabilities held for sale on the Eversource balance sheet. As Eversource had concluded this was the sale of a business, all goodwill held by the water distribution reporting unit was included in the carrying amount of the business and was also classified within assets held for sale at that time. Aquarion’s long-term debt was expected to be repaid by Eversource upon closing and was therefore excluded from liabilities held for sale. Assets and liabilities classified as held for sale are measured at the lower of carrying amount or fair value less costs to sell. Closing of the transaction includes the finalization of working capital and other closing adjustments as well as final closing costs, which could result in a loss recorded at the time of sale. The water distribution business did not meet the criteria to be presented as a discontinued operation. In the fourth quarter of 2024, upon classifying the assets and liabilities as held for sale, Eversource concluded that the likely sale of Aquarion at a loss resulted in the requirement to test water distribution goodwill for impairment. Eversource performed an impairment test by comparing the fair value of the business to its carrying value and recorded a goodwill impairment of $297 million, as the estimated fair value of the business based on the anticipated sale was less than the carrying value. The fair value included future cash outflows of approximately $140 million of estimated income taxes as a result of the transaction. The goodwill impairment charge is presented separately within Operating Income on the Eversource statement of income for the year ended December 31, 2024. Based on PURA’s November 19, 2025 denial of the sale and the uncertainty of the ultimate outcome, the Aquarion water distribution business no longer met the criteria to be classified as held for sale and its assets and liabilities were reclassified as held and used on the balance sheet as of December 31, 2025. The reclassification to held and used did not result in an adjustment to Aquarion’s carrying values. (1) (2) 146
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As of December 31, 2024, the major classes of Aquarion’s assets and liabilities presented in current and long-term Assets Held for Sale and Liabilities Held for Sale on the Eversource balance sheet, which are included in the Water Distribution reportable segment, were as follows: (Millions of Dollars) Restricted Cash $ 5.8 Receivables, Net 14.4 Unbilled Revenues 11.5 Prepayments and Other Current Assets 24.6 Total Current Assets Held for Sale $ 56.3 Property, Plant and Equipment, Net $ 1,885.2 Regulatory Assets 51.2 Goodwill 662.5 Other Long-Term Assets 12.2 Total Long-Term Assets Held for Sale $ 2,611.1 Accounts Payable $ 24.2 Other Current Liabilities 28.4 Total Current Liabilities Held for Sale $ 52.6 Regulatory Liabilities $ 132.2 Other Long-Term Liabilities 266.7 Total Long-Term Liabilities Held for Sale $ 398.9 For the years ended December 31, 2024 and 2023, pre-tax income associated with the held for sale water distribution business (excluding the goodwill impairment recognized in 2024) was $43.1 million and $26.8 million, respectively. 25. GOODWILL In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. The following table presents Eversource’s goodwill by reportable segment: (Millions of Dollars) Electric Distribution Electric Transmission Natural Gas Distribution Water Distribution Total Balance as of January 1, 2024 $ 2,543.6 $ 576.8 $ 451.0 $ 960.7 $ 4,532.1 Sale of Water Unregulated Business and WaterAcquisition, net — — — (1.2) (1.2) Water Goodwill Impairment — — — (297.0) (297.0) Water Goodwill Reclassified as Held for Sale — — — (662.5) (662.5) Balance as of December 31, 2024 $ 2,543.6 $ 576.8 $ 451.0 $ — $ 3,571.4 Measurement Period Adjustment — — — (0.1) (0.1) Water Goodwill Reclassified from Held for Sale — — — 662.5 662.5 Balance as of December 31, 2025 $ 2,543.6 $ 576.8 $ 451.0 $ 662.4 $ 4,233.8 In 2024, Eversource completed the sale of its unregulated water business resulting in a reduction to goodwill of $5.4 million and completed a water acquisition resulting in the addition of $4.2 million of goodwill. Goodwill is not amortized but is subject to an assessment for impairment at least annually and more frequently if indicators of impairment arise that would more likely than not reduce the fair value of Eversource’s reporting units below their carrying amounts. Eversource's reporting units for the purpose of testing goodwill are Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution. These reporting units are consistent with the operating segments underlying the reportable segments identified in Note 23, "Segment Information," to the financial statements. In assessing goodwill for impairment, an entity is permitted to first assess qualitatively whether it is more likely than not that goodwill impairment exists as of the annual impairment test date. If after performing the qualitative assessment it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying value (including goodwill), then a quantitative goodwill impairment test is performed. A quantitative impairment test is required only if it is concluded that it is more likely than not that a reporting unit’s carrying value may not be recoverable. The quantitative assessment compares the estimated fair value of a reporting unit to its carrying amount, and to the extent the carrying amount exceeds the fair value, an impairment of goodwill is recognized for the excess up to the amount of goodwill allocated to the reporting unit. A resulting write-down, if any, would be charged to Operating Expenses. 147
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In the fourth quarter of 2024, Eversource concluded that the likely sale of Aquarion at a loss resulted in the requirement to perform an interim goodwill impairment test for Water Distribution goodwill. Eversource compared the estimated fair value of the business from the anticipated transaction to its carrying value. Assumptions used in the valuation were the future cash flows from the sale, including approximately $140 million of estimated income tax impacts as a result of the transaction. Based on the interim impairment test as of December 31, 2024, Eversource recorded a goodwill impairment of $297.0 million to write down the carrying value of the Water Distribution reporting unit to its estimated fair value. The goodwill impairment charge is presented separately within Operating Income on the Eversource statement of income for the year ended December 31, 2024. The remaining goodwill held by the Water Distribution reporting unit was reclassified to Assets Held for Sale on the Eversource balance sheet as of December 31, 2024 and became part of the water distribution disposal group. Eversource completed its annual goodwill impairment assessment for the Electric Distribution, Electric Transmission and Natural Gas Distribution reporting units as of October 1, 2025 and determined it was more likely than not that their fair value exceeded carrying value and no impairment existed. The annual goodwill assessment included a qualitative evaluation of multiple factors that impact the fair value of the reporting units, including general, macroeconomic and market conditions, and entity-specific assumptions that affect the future cash flows of the reporting units. Key considerations include discount rates, utility sector market performance and merger transaction multiples, the Company's share price and credit ratings, analyst reports, financial performance, cost and risk factors, internal estimates and projections of future cash flows and net income, long-term strategy, the timing and outcome of rate cases, and recent regulatory and legislative proceedings. As of October 1, 2025, the goodwill of the Water Distribution reporting unit was classified within Assets Held for Sale, and the disposal group was carried at fair value less cost to sell. Based on PURA’s November 19, 2025 denial of the Aquarion sale and the uncertainty of the ultimate outcome, the Aquarion water distribution business no longer met the criteria to be classified as held for sale. The goodwill held by the Water Distribution reporting unit of $662.5 million that was previously classified within Assets Held for Sale has been reclassified to Goodwill on the Eversource balance sheet as of December 31, 2025. In the fourth quarter of 2025, Eversource performed a goodwill impairment test for Water Distribution goodwill and determined that no impairment existed. 148
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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure No events that would be described in response to this item have occurred with respect to Eversource, CL&P, NSTAR Electric or PSNH. Item 9A. Controls and Procedures Management, on behalf of Eversource, CL&P, NSTAR Electric and PSNH, is responsible for the preparation, integrity, and fair presentation of the accompanying Financial Statements and other sections of this combined Annual Report on Form 10-K. Eversource's internal controls over financial reporting were audited by Deloitte & Touche LLP. Management, on behalf of Eversource, CL&P, NSTAR Electric and PSNH, is responsible for establishing and maintaining adequate internal controls over financial reporting. The internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment. Under the supervision and with the participation of the principal executive officer and principal financial officer, an evaluation of the effectiveness of internal controls over financial reporting was conducted based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting at Eversource, CL&P, NSTAR Electric and PSNH were effective as of December 31, 2025. Management, on behalf of Eversource, CL&P, NSTAR Electric and PSNH, evaluated the design and operation of the disclosure controls and procedures as of December 31, 2025 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Securities Exchange Act of 1934 and the rules and regulations of the SEC. This evaluation was made under management's supervision and with management's participation, including the principal executive officer and principal financial officer as of the end of the period covered by this Annual Report on Form 10-K. There are inherent limitations of disclosure controls and procedures, including the possibility of human error and the circumventing or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. The principal executive officer and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of Eversource, CL&P, NSTAR Electric and PSNH are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures. There have been no changes in internal controls over financial reporting for Eversource, CL&P, NSTAR Electric and PSNH during the quarter ended December 31, 2025 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. Item 9B. Other Information During the quarter ended December 31, 2025, none of the Company’s directors or officers adopted, modified, or terminated a “Rule 10b5-1 trading arrangement” or a “non-Rule 10b5-1 trading arrangement,” as such terms are defined under Item 408 of Regulation S-K. 149
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PART III Item 10. Directors, Executive Officers and Corporate Governance Eversource Energy The information required by this Item 10 for Eversource Energy is incorporated herein by reference to certain information contained in the sections captioned “Election of Trustees,” and “Governance of Eversource Energy” plus related subsections, of Eversource Energy’s definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 27, 2026. Information concerning executive officers of Eversource Energy required by this Item 10 is reported under a separate caption entitled “Information About Our Executive Officers” in Part I of this report. CL&P, NSTAR Electric and PSNH Certain information required by this Item 10 is omitted for CL&P, NSTAR Electric and PSNH pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly Owned Subsidiaries. Item 11. Executive Compensation Eversource Energy The information required by this Item 11 for Eversource Energy is incorporated herein by reference to certain information contained in Eversource Energy's definitive proxy statement for solicitation of proxies, which is expected to be filed with the SEC on or about March 27, 2026, under the sections captioned “Compensation Discussion and Analysis,” plus related subsections, and “Compensation Committee Report,” plus related subsections following such Report. CL&P, NSTAR Electric and PSNH Certain information required by this Item 11 has been omitted for CL&P, NSTAR Electric and PSNH pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Eversource Energy In addition to the information below under "Securities Authorized for Issuance Under Equity Compensation Plans," incorporated herein by reference is the information contained in the sections "Securities Ownership of Certain Beneficial Owners" and "Common Share Ownership of Trustees and Management" of Eversource Energy's definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 27, 2026. CL&P, NSTAR Electric and PSNH Certain information required by this Item 12 has been omitted for CL&P, NSTAR Electric and PSNH pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries. SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS The following table sets forth the number of Eversource Energy common shares issuable under Eversource Energy equity compensation plans, as well as their weighted exercise price, as of December 31, 2025, in accordance with the rules of the SEC: Plan Category Number of securities to beissued upon exercise ofoutstanding options,warrants and rights Weighted-average exerciseprice of outstanding options,warrants and rights Number of securitiesremaining available forfuture issuance under equitycompensation plans(excluding securitiesreflected in column ) Equity compensation plans approved by security holders 1,749,624 $— 3,051,466 Equity compensation plans not approved by security holders — — — Total 1,749,624 $— 3,051,466 (1) Includes 731,181 common shares for distribution in respect of restricted share units, and 1,018,443 performance shares issuable at target, all pursuant to the terms of our Incentive Plans. (2) The weighted-average exercise price does not take into account restricted share units or performance shares, which have no exercise price. (3) As of December 31, 2025, there were no equity compensation plans not approved by security holders. (1) (2) (1) (3)
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For information regarding our Incentive Plans, see Note 11C, "Employee Benefits - Share Based Payments," to the financial statements. Item 13. Certain Relationships and Related Transactions, and Director Independence Eversource Energy Incorporated herein by reference is the information contained in the sections captioned "Trustee Independence" and "Related Person Transactions" of Eversource Energy's definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 27, 2026. CL&P, NSTAR Electric and PSNH Certain information required by this Item 13 has been omitted for CL&P, NSTAR Electric and PSNH pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries. Item 14. Principal Accountant Fees and Services Eversource Energy Incorporated herein by reference is the information contained in the section "Relationship with Principal Independent Registered Public Accounting Firm" of Eversource Energy's definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 27, 2026. CL&P, NSTAR Electric and PSNH Pre-Approval of Services Provided by Principal Auditors None of CL&P, NSTAR Electric and PSNH is subject to the audit committee requirements of the SEC, the national securities exchanges or the national securities associations. CL&P, NSTAR Electric and PSNH obtain audit services from the independent auditor engaged by the Audit Committee of Eversource Energy's Board of Trustees. Eversource Energy's Audit Committee has established policies and procedures regarding the pre-approval of services provided by the principal auditors. Those policies and procedures delegate pre-approval of services to the Eversource Energy Audit Committee Chair provided that such offices are held by Trustees who are "independent" within the meaning of the Sarbanes-Oxley Act of 2002 and that all such pre- approvals are presented to the Eversource Energy Audit Committee at the next regularly scheduled meeting of the Committee. The following relates to fees and services for the entire Eversource Energy system, including Eversource Energy, CL&P, NSTAR Electric and PSNH. Fees Billed By Principal Independent Registered Public Accounting Firm The aggregate fees billed to the Company and its subsidiaries by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, the Deloitte Entities), for the years ended December 31, 2025 and 2024 totaled $7,048,414 and $7,454,414, respectively. In addition, affiliates of Deloitte & Touche LLP as noted below provide other accounting services to the Company. Audit and Non-Audit Fees 2025 2024 Audit Fees $ 5,711,000 $ 5,984,500 Audit Related Fees 1,335,500 1,386,000 All Other Fees 1,914 83,914 TOTAL $ 7,048,414 $ 7,454,414 Audit Fees consisted of fees related to the audits of financial statements of Eversource Energy and its subsidiaries in the Annual Report on Form 10-K, reviews of financial statements in the Combined Quarterly reports on Form 10-Q of Eversource Energy and its subsidiaries, consultations with management, regulatory and compliance filings, system conversion quality assurance, out of pocket expenses, and audits of internal controls over financial reporting for the years ended December 31, 2025 and 2024. Audit Related Fees were incurred for procedures performed in the ordinary course of business in support of Eversource’s ATM equity offering program, certain regulatory filings, comfort letters, consents, and other costs related to registration statements and financials for the years ended December 31, 2025 and 2024. All Other Fees for the years ended December 31, 2025 and 2024 related to an annual license for access to an accounting standards research tool. All Other Fees for the year ended December 31, 2024 also related to a system pre-implementation control review. The Audit Committee pre-approves all auditing services and permitted audit-related or other services (including the fees and terms thereof) to be performed for us by our independent registered public accounting firm, subject to the de minimis exceptions for non-audit services described in (1) (2) (3) (1) (2) (3) 151
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Section 10A(i)(1)(B) of the Securities Exchange Act of 1934, which are approved by the Audit Committee prior to the completion of the audit. The Audit Committee may form and delegate its authority to subcommittees consisting of one or more members when appropriate, including the authority to grant pre-approvals of audit and permitted non-audit services, provided that decisions of such subcommittees to grant pre-approvals are presented to the full Audit Committee at its next scheduled meeting. During 2025, all services described above were pre-approved by the Audit Committee or its Chair. The Audit Committee has considered whether the provision by the Deloitte Entities of the non-audit services described above was allowed under Rule 2- 01(c)(4) of Regulation S-X and was compatible with maintaining the independence of the registered public accountants and has concluded that the Deloitte Entities were and are independent of us in all respects. 152
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PART IV Item 15. Exhibits and Financial Statement Schedules (a) 1.Financial Statements: The financial statements filed as part of this Annual Report on Form 10-K are set forth under Item 8, "FinancialStatements and Supplementary Data." 2.Schedules I. Financial Information of Registrant: Eversource Energy (Parent) Balance Sheets as of December 31, 2025 and 2024 S-1 Eversource Energy (Parent) Statements of Income for the Years EndedDecember 31, 2025, 2024 and 2023 S-2 Eversource Energy (Parent) Statements of Comprehensive Income for the Years EndedDecember 31, 2025, 2024 and 2023 S-2 Eversource Energy (Parent) Statements of Cash Flows for the Years EndedDecember 31, 2025, 2024 and 2023 S-3 II. Valuation and Qualifying Accounts and Reserves for Eversource, CL&P, NSTAR Electric and PSNHfor 2025, 2024 and 2023 S-4 All other schedules of the companies for which inclusion is required in the applicable regulations of the SEC arepermitted to be omitted under the related instructions or are not applicable, and therefore have been omitted. 3. Exhibit Index E-1 Item 16. Form 10-K Summary Not applicable. 153
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SCHEDULE I EVERSOURCE ENERGY (PARENT) FINANCIAL INFORMATION OF REGISTRANT BALANCE SHEETS AS OF DECEMBER 31, 2025 AND 2024 (Thousands of Dollars) 2025 2024 ASSETS Current Assets: Cash $ 200 $ 1,083 Accounts Receivable from Subsidiaries 215,193 100,320 Notes Receivable from Subsidiaries 1,592,100 2,051,400 Prepayments and Other Current Assets, Including Assets Held for Sale 57,002 96,313 Total Current Assets 1,864,495 2,249,116 Deferred Debits and Other Assets: Investments in Subsidiary Companies, at Equity 21,413,181 20,080,215 Notes Receivable from Subsidiaries 2,296,500 2,296,500 Accumulated Deferred Income Taxes 100,941 113,718 Goodwill 3,550,070 3,231,811 Long-Term Assets Held for Sale — 335,393 Other Long-Term Assets 26,700 24,582 Total Deferred Debits and Other Assets 27,387,392 26,082,219 Total Assets $ 29,251,887 $ 28,331,335 LIABILITIES AND CAPITALIZATION Current Liabilities: Notes Payable $ 1,280,000 $ 1,538,011 Long-Term Debt - Current Portion 1,002,439 600,000 Accounts Payable to Subsidiaries 43,698 45,326 Accrued Interest 169,516 168,748 Other Current Liabilities 97,176 57,923 Total Current Liabilities 2,592,829 2,410,008 Deferred Credits and Other Liabilities: Long-Term Liabilities Held for Sale — 15,028 Other Long-Term Liabilities 115,299 137,656 Total Deferred Credits and Other Liabilities 115,299 152,684 Long-Term Debt 10,346,488 10,729,256 Common Shareholders' Equity: Common Shares 1,914,273 1,878,622 Capital Surplus, Paid in 9,937,878 9,428,905 Retained Earnings 4,504,983 3,929,141 Accumulated Other Comprehensive Loss (20,507) (26,472) Treasury Stock (139,356) (170,809) Common Shareholders' Equity 16,197,271 15,039,387 Total Liabilities and Capitalization $ 29,251,887 $ 28,331,335 See the Combined Notes to Financial Statements in this Annual Report on Form 10-K for a description of significant accounting matters related to Eversource parent, including the sale status of Aquarion as described in Note 24, “Assets Held for Sale,” Eversource common shares information as described in Note 18, "Common Shares," material obligations and guarantees as described in Note 13, "Commitments and Contingencies," and debt agreements as described in Note 8, "Short-Term Debt," and Note 9, "Long-Term Debt." S-1
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SCHEDULE I EVERSOURCE ENERGY (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF INCOME/(LOSS) FOR THE YEARS ENDED DECEMBER 31, 2025, 2024 AND 2023 (Thousands of Dollars, Except Share Information) 2025 2024 2023 Operating Revenues $ 2,067 $ 4,442 $ 840 Operating Expenses: Acquisition and Integration Costs Allowed for Recovery (82,346) — — Other 10,458 20 12,769 Loss on Pending Sale of Aquarion — 297,000 — Total Operating Expenses (71,888) 297,020 12,769 Operating Income/(Loss) 73,955 (292,578) (11,929) Interest Expense 548,723 549,511 397,281 Other Income, Net: Equity in Earnings/(Losses) of Subsidiaries 1,923,453 1,359,297 (312,040) Other, Net 166,600 214,444 188,003 Other Income/(Loss), Net 2,090,053 1,573,741 (124,037) Income/(Loss) Before Income Tax Benefit 1,615,285 731,652 (533,247) Income Tax Benefit (77,087) (80,001) (91,007) Net Income/(Loss) $ 1,692,372 $ 811,653 $ (442,240) Basic Earnings/(Loss) per Common Share $ 4.56 $ 2.27 $ (1.27) Diluted Earnings/(Loss) per Common Share $ 4.56 $ 2.27 $ (1.26) Weighted Average Common Shares Outstanding: Basic 370,852,601 357,482,965 349,580,638 Diluted 371,259,264 357,779,408 349,840,481 STATEMENTS OF COMPREHENSIVE INCOME/(LOSS) (Thousands of Dollars) 2025 2024 2023 Net Income/(Loss) $ 1,692,372 $ 811,653 $ (442,240) Other Comprehensive Income, Net of Tax: Qualified Cash Flow Hedging Instruments 20 20 20 Changes in Unrealized Gains on Marketable Securities — — 1,252 Changes in Funded Status of Pension, SERP and PBOP Benefit Plans 5,945 7,245 4,412 Other Comprehensive Income, Net of Tax 5,965 7,265 5,684 Comprehensive Income/(Loss) $ 1,698,337 $ 818,918 $ (436,556) See the Combined Notes to Financial Statements in this Annual Report on Form 10-K for a description of significant accounting matters related to Eversource parent, including the sale status of Aquarion as described in Note 24, “Assets Held for Sale,” Eversource common shares information as described in Note 18, "Common Shares," material obligations and guarantees as described in Note 13, "Commitments and Contingencies," and debt agreements as described in Note 8, "Short-Term Debt," and Note 9, "Long-Term Debt." S-2
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SCHEDULE I EVERSOURCE ENERGY (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2025, 2024 and 2023 (Thousands of Dollars) 2025 2024 2023 Operating Activities: Net Income/(Loss) $ 1,692,372 $ 811,653 $ (442,240) Adjustments to Reconcile Net Income/(Loss) to Net Cash Flows Provided by Operating Activities: Equity in (Earnings)/Losses of Subsidiaries (1,923,453) (1,359,297) 312,040 Cash Dividends Received from Subsidiaries 1,340,500 1,273,700 1,027,400 Deferred Income Taxes 12,098 (99,692) (22,256) Loss on Pending Sale of Aquarion — 297,000 — Other 88,966 57,469 (12,834) Changes in Current Assets and Liabilities: Accounts Receivables from Subsidiaries (32,527) (40,129) (6,853) Accounts Receivable from EGMA for Acquisition and Integration Costs Allowed for Recovery (82,346) — — Taxes Receivable/Accrued, Net 86,083 22,464 (80,968) Accounts Payable to Subsidiaries (1,628) 7,275 4,521 Other Current Assets and Liabilities, Net (4,322) 58,572 35,357 Net Cash Flows Provided by Operating Activities 1,175,743 1,029,015 814,167 Investing Activities: Capital Contributions to Subsidiaries (755,000) (2,026,500) (1,369,700) Return of Capital from Subsidiaries 11,000 17,000 438,000 Increase/(Decrease) in Notes Receivable from Subsidiaries 459,300 201,500 (1,578,100) Other Investing Activities — — 147,567 Net Cash Flows Used in Investing Activities (284,700) (1,808,000) (2,362,233) Financing Activities: Issuance of Common Shares, Net of Issuance Costs 465,389 989,447 — Cash Dividends on Common Shares (1,093,074) (1,001,488) (918,995) Issuance of Long-Term Debt 600,000 2,400,000 3,350,000 Retirement of Long-Term Debt (600,000) (1,350,000) (1,200,000) (Decrease)/Increase in Notes Payable (258,011) (233,894) 329,705 Other Financing Activities (6,241) (24,539) (13,076) Net Cash Flows (Used in)/Provided by Financing Activities (891,937) 779,526 1,547,634 Net (Decrease)/Increase in Cash and Restricted Cash (894) 541 (432) Cash and Restricted Cash - Beginning of Year 1,156 615 1,047 Cash and Restricted Cash - End of Year $ 262 $ 1,156 $ 615 Supplemental Cash Flow Information: Cash Paid/(Received) During the Year for: Interest $ 541,910 $ 483,101 $ 366,645 Income Taxes $ (171,114) $ 443 $ 23,984 See the Combined Notes to Financial Statements in this Annual Report on Form 10-K for a description of significant accounting matters related to Eversource parent, including the sale status of Aquarion as described in Note 24, “Assets Held for Sale,” Eversource common shares information as described in Note 18, "Common Shares," material obligations and guarantees as described in Note 13, "Commitments and Contingencies," and debt agreements as described in Note 8, "Short-Term Debt," and Note 9, "Long-Term Debt." S-3
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SCHEDULE II EVERSOURCE ENERGY AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEARS ENDED DECEMBER 31, 2025, 2024 AND 2023 (Thousands of Dollars) Column A Column B Column C Column D Column E Additions (1) (2) Description: Balance as ofBeginning of Year Charged to Costsand Expenses Charged to OtherAccounts -Describe (a) Deductions -Describe (b) Balance as of Endof Year Eversource: Reserves Deducted from Assets - Reserves for Uncollectible Accounts: 2025 $ 556,164 $ 101,141 $ 120,006 $ 196,772 $ 580,539 2024 554,455 74,069 119,659 192,019 556,164 2023 486,297 72,468 158,205 162,515 554,455 CL&P: Reserves Deducted from Assets - Reserves for Uncollectible Accounts: 2025 $ 279,108 $ 17,949 $ 43,110 $ 81,653 $ 258,514 2024 296,030 17,190 46,840 80,952 279,108 2023 225,320 11,675 126,360 67,325 296,030 NSTAR Electric: Reserves Deducted from Assets - Reserves for Uncollectible Accounts: 2025 $ 114,910 $ 41,430 $ 37,050 $ 60,829 $ 132,561 2024 97,026 33,607 37,653 53,376 114,910 2023 94,958 22,791 17,488 38,211 97,026 PSNH: Reserves Deducted from Assets - Reserves for Uncollectible Accounts: 2025 $ 14,090 $ 11,973 $ 7,193 $ 9,709 $ 23,547 2024 14,322 4,688 5,131 10,051 14,090 2023 29,236 3,989 (8,735) 10,168 14,322 (a) Amounts relate to uncollectible accounts receivables reserved for that are not charged to bad debt expense. CL&P, NSTAR Electric, NSTAR Gas, EGMA and Yankee Gas are allowed to recover in rates, amounts associated with certain uncollectible hardship accounts receivable. CL&P, NSTAR Electric, PSNH, NSTAR Gas and EGMA are also allowed to recover uncollectible energy supply costs through regulatory tracking mechanisms. (b) Amounts written off, net of recoveries. S-4
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EXHIBIT INDEX Each document described below is incorporated by reference by the registrant(s) listed to the files identified, unless designated with a (*), which exhibits are filed herewith. Management contracts and compensation plans or arrangements are designated with a (+). Exhibit Number Description 3. Articles of Incorporation and By-Laws (A) Eversource Energy 3.1 Declaration of Trust of Eversource Energy, as amended through May 1, 2025 (Exhibit 3.1, Eversource Energy Current Report on Form 8-K filed on May 1, 2025, File No. 001-05324) (B) The Connecticut Light and Power Company 3.1 Amended and Restated Certificate of Incorporation (Exhibit 3(i), CL&P Current Report on Form 8-K filed on January 9, 2012, File No. 000-00404) 3.2 By-laws of CL&P, as amended and restated effective September 29, 2014 (Exhibit 3.1, CL&P Current Report on Form 8-K filed on October 2, 2014, File No. 000-00404) (C) NSTAR Electric Company 3.1 Restated Articles of Organization of NSTAR Electric Company, fka Boston Edison Company (Exhibit 3.1, NSTAR Electric Quarterly Report on Form 10-Q for the Quarter Ended June 30, 1994 filed on August 12, 1994, File No. 001-02301) 3.2 Bylaws of NSTAR Electric Company, as amended and restated effective September 29, 2014 (Exhibit 3.1, NSTAR Electric Current Report on Form 8-K filed on October 2, 2014, File No. 000-02301) (D) Public Service Company of New Hampshire 3.1 Articles of Incorporation, as amended to May 16, 1991 (Exhibit 3.3.1, PSNH Annual Report on Form 10-K filed on March 25, 1994, File No. 001-06392) 3.2 By-laws of PSNH, as in effect June 27, 2008 (Exhibit 3, PSNH Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2008 filed on August 7, 2008, File No. 001-06392) 4. Instruments defining the rights of security holders, including indentures (A) Eversource Energy 4.1 Indenture between Eversource Energy and The Bank of New York as Trustee dated as of April 1, 2002 (Exhibit A-3, Eversource Energy 35-CERT filed on April 16, 2002, File No. 070-09535) 4.1.1 Seventh Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of March 1, 2016, relating to $250 million of Senior Notes, Series J, due 2026 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed on March 15, 2016, File No. 001-05324) 4.1.2 Tenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of January 1, 2018, relating to $450 million of Senior Notes, Series M, Due 2028 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed on January 12, 2018, File No. 001-05324) 4.1.3 Eleventh Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of December 1, 2018, relating to $400 million of Senior Notes, Series N, Due 2023 and $500 million of Senior Notes, Series O, Due 2029 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed on December 18, 2018, File No. 001-05324) E-1
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4.1.4 Twelfth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of January 1, 2020, relating to $650 million of Senior Notes, Series P, Due 2050 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed on January 16, 2020, File No. 001-05324) 4.1.5 Thirteenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of August 1, 2020, relating to $300 million aggregate principal amount of Senior Notes, Series Q, Due 2025 and $600 million aggregate principal amount of Senior Notes, Series R, Due 2030 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed on August 20, 2020, File No. 001-05324) 4.1.6 Fourteenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of March 1, 2021, relating to $350 million aggregate principal amount of Senior Notes, Series S, Due 2031 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed on March 16, 2021, File No. 001- 05324) 4.1.7 Fifteenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of August 1, 2021, relating to $350 million aggregate principal amount of Floating Rate Senior Notes, Series T and $300 million aggregate principal amount of Senior Notes, Series U, Due 2026 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed on August 13, 2021, File No. 001-05324) 4.1.8 Sixteenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of February 1, 2022, relating to $650 million aggregate principal amount of Senior Notes, Series V, Due 2027 and $650 million aggregate principal amount of Senior Notes, Series W, Due 2032 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed on February 25, 2022, File No. 001-05324) 4.1.9 Seventeenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of June 1, 2022, relating to $900 million aggregate principal amount of Senior Notes, Series X, Due 2024 and $600 million aggregate principal amount of Senior Notes, Series Y, Due 2027 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed on June 27, 2022, File No. 001-05324) 4.1.10 Eighteenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of March 1, 2023, relating to $1.3 billion aggregate principal amount of Senior Notes, Series Z, Due 2028 (Exhibit 4.1, Eversource Energy Current Report on Form 8 ‑ K filed on March 6, 2023, File No. 001- 05324) 4.1.11 Nineteenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of May 1, 2023, relating to $450 million aggregate principal amount of Senior Notes, Series AA, Due 2026 and $800 million aggregate principal amount of Senior Notes, Series BB, Due 2033 (Exhibit 4.3, Eversource Energy Current Report on Form 8 ‑ K filed on May 11, 2023, File No. 001-05324) 4.1.12 Twentieth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of November 1, 2023, relating to $800 million aggregate principal amount of Senior Notes, Series CC, Due 2029 (Exhibit 4.1, Eversource Energy Current Report on Form 8 ‑ K filed on November 13, 2023, File No. 001-05324) 4.1.13 Twenty-First Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of January 1, 2024, relating to $350 million aggregate principal amount of Senior Notes, Series DD, Due 2027 and $650 million aggregate principal amount of Senior Notes, Series EE, Due 2034 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed on January 19, 2024, File No. 001-05324) 4.1.14 Twenty-Second Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of April 1, 2024, relating to $700 million aggregate principal amount of Senior Notes, Series FF, Due 2031 and $700 million aggregate principal amount of Senior Notes, Series GG, Due 2034 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed on April 18, 2024, File No. 001-05324) 4.1.15 Twenty-Third Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of October 1, 2025, relating to $600 million aggregate principal amount of Senior Notes, Series HH, Due 2030 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed on October 17, 2025, File No. 001-05324) E-2
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4.2 Eversource Energy Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (Exhibit 4.3, Eversource Energy Annual Report on Form 10-K filed on February 27, 2020, File No. 001-05324) (B) The Connecticut Light and Power Company 4.1 Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, Trustee, dated as of May 1, 1921 (Composite including all twenty-four amendments to May 1, 1967) (Exhibit 4.1, Eversource 10-K filed on February 26, 2018, File No. 000-00404) 4.1.1 Series B Supplemental Indenture between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2004 (Exhibit 99.5, CL&P Current Report on Form 8-K filed on September 22, 2004, File No. 000-00404) 4.2 Composite Indenture of Mortgage and Deed of Trust between CL&P and Deutsche Bank Trust Company Americas f/k/a Bankers Trust Company, dated as of May 1, 1921, as amended and supplemented by seventy-three supplemental mortgages to and including Supplemental Mortgage dated as of April 1, 2005 (Exhibit 99.5, CL&P Current Report on Form 8-K filed on April 13, 2005, File No. 000-00404) 4.2.1 Supplemental Indenture (2005 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of April 1, 2005 (Exhibit 99.2, CL&P Current Report on Form 8-K filed on April 13, 2005, File No. 000-00404) 4.2.2 Supplemental Indenture (2006 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of June 1, 2006 (Exhibit 99.2, CL&P Current Report on Form 8-K filed on June 7, 2006, File No. 000-00404) 4.2.3 Supplemental Indenture (2007 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of March 1, 2007 (Exhibit 99.2, CL&P Current Report on Form 8-K filed on March 29, 2007, File No. 000-00404) 4.2.4 Supplemental Indenture (2007 Series D Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2007 (Exhibit 4, CL&P Current Report on Form 8-K filed on September 19, 2007, File No. 000-00404) 4.2.5 Supplemental Indenture (2014 Series A Bond) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of April 1, 2014 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on April 29, 2014, File No. 000-00404) 4.2.6 Supplemental Indenture (2015 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of May 1, 2015 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on May 26, 2015, File No. 000-00404) 4.2.7 Supplemental Indenture (2015 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of November 1, 2015 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on December 4, 2015, File No. 000-00404) 4.2.8 Supplemental Indenture (2017 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of March 1, 2017 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on March 16, 2017, File No. 000-00404) 4.2.9 Supplemental Indenture (2014 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of August 1, 2017 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on August 23, 2017, File No. 000-00404) 4.2.10 Supplemental Indenture (2018 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of March 1, 2018 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on April 2, 2018, File No. 000-00404) 4.2.11 Supplemental Indenture (2018 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of March 1, 2019 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on April 4, 2019, File No. 000-00404) E-3
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4.2.12 Supplemental Indenture (2017 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2019 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on September 23, 2019, File No. 000-00404) 4.2.13 Supplemental Indenture (2021 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of June 1, 2021 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on July 2, 2021, File No. 000-00404) 4.2.14 Supplemental Indenture (2023 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of January 1, 2023 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on January 10, 2023, File No. 000-00404) 4.2.15 Supplemental Indenture (2023 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of July 1, 2023 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on July 6, 2023, File No. 000-00404) 4.2.16 Supplemental Indenture (2024 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of January 1, 2024 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on January 23, 2024, File No. 000-00404) 4.2.17 Supplemental Indenture (2024 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of August 1, 2024 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on August 13, 2024, File No. 000-00404) 4.2.18 Supplemental Indenture (2025 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of January 1, 2025 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on January 13, 2025, File No. 000-00404) 4.3 CL&P Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (Exhibit 4.4, Eversource Energy Annual Report on Form 10-K filed on February 27, 2020, File No. 001-05324) (C) NSTAR Electric Company 4.1 Indenture between Boston Edison Company and the Bank of New York (as successor to Bank of Montreal Trust Company) (Exhibit 4.1, 2017 Eversource Energy Annual Report on Form 10-K filed on February 26, 2018, File No. 001-05324) 4.1.1 A Form of 5.75% Debenture Due March 15, 2036 (Exhibit 99.2, Boston Edison Company Current Report on Form 8 ‑ K filed on March 17, 2006, File No. 001-02301) 4.1.2 A Form of 5.50% Debenture Due March 15, 2040 (Exhibit 99.2, NSTAR Electric Company Current Report on Form 8 ‑ K filed on March 15, 2010, File No. 001-02301) 4.1.3 A Form of 4.40% Debenture Due 2044 (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed on March 13, 2014, File No. 001-02301) 4.1.4 A Form of 2.70% Debenture due 2026 (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed on May, 31, 2016, File No. 001-02301) 4.1.5 Form of 3.20% Debenture due May 15, 2027 (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed on May 18, 2017 File No. 001-02301) 4.1.6 Form of 3.25% Debenture due May 15, 2029 (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed on May 23, 2019, File No. 001-02301) 4.1.7 Form of 3.95% Debenture due April 1, 2030 (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed on March 26, 2020, File No. 001-02301) 4.1.8 Form of 3.10% Debenture due June 1, 2051 (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed on June 2, 2021, File No. 001-02301) 4.1.9 Form of 1.95% Debenture due August 15, 2031 (Exhibit 4.1, NSTAR Electric Company Current Report on Form 8- K filed on August 23, 2021, File No. 001-02301) 4.1.10 Form of 4.55% Debenture due June 1, 2052 (Exhibit 4.1, NSTAR Electric Company Current Report on Form 8-K filed on May 17, 2022, File No. 001-02301)
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4.1.11 Form of 4.95% Debenture due September 15, 2052 (Exhibit 4.1, NSTAR Electric Company Current Report on Form 8-K filed on September 15, 2022, File No. 001-02301) 4.1.12 Form of 5.60% Debenture due October 1, 2028 (Exhibit 4.1, NSTAR Electric Company Current Report on Form 8- K filed on September 25, 2023, File No. 001-02301) 4.1.13 Form of 5.40% Debenture due 2034 (Exhibit 4.1, NSTAR Electric Company Current Report on Form 8 ‑ K filed on May 22, 2024, File No. 001-02301) 4.1.14 Form of 4.85% Debenture due 2030 (Exhibit 4.1, NSTAR Electric Company Current Report on Form 8 ‑ K filed on February 26, 2025, File No. 001-02301) 4.1.15 Form of 5.20% Debenture due 2035 (Exhibit 4.2, NSTAR Electric Company Current Report on Form 8 ‑ K filed on February 26, 2025, File No. 001-02301) 4.2 Second Amended and Restated Credit Agreement, dated as of October 15, 2021, by and among NSTAR Electric Company and the Banks named therein, pursuant to which Barclays Bank PLC serves as Administrative Agent and Swing Line Lender (Exhibit 10.13, Eversource Energy Annual Report on Form 10-K filed on February 17, 2022, File No. 001-05324) 4.2.1 First Amendment to Second Amended and Restated Credit Agreement and Extension Agreement, dated October 17, 2022, by and between NSTAR Electric Company and the Banks named therein, pursuant to which Barclays Bank PLC serves as Administrative Agent and Swing Line Lender (Exhibit 4.1, Eversource Energy Quarterly Report on Form 10-Q filed on November 4, 2022, File No. 001-05324) 4.2.2 Second Amendment to Second Amended and Restated Credit Agreement, dated October 11, 2024, by and between NSTAR Electric Company and the Banks named therein, pursuant to which Barclays Bank PLC serves as Administrative Agent and Swing Line Lender (Exhibit 4, Eversource Energy Quarterly Report on Form 10-Q filed on November 6, 2024, File No. 001-05324) 4.3 Indenture between NSTAR Electric Company, as successor to Western Massachusetts Electric Company (WMECO), and The Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.2, WMECO Current Report on Form 8-K filed on October 8, 2003, File No. 000-07624) 4.3.1 Second Supplemental Indenture between NSTAR Electric Company, as successor to WMECO, and The Bank of New York, as Trustee dated as of September 1, 2004 (Exhibit 4.1, WMECO Current Report on Form 8-K filed on September 27, 2004, File No. 000-07624) 4.3.2 Fourth Supplemental Indenture between NSTAR Electric Company, as successor to WMECO, and The Bank of New York Trust, as Trustee, dated as of August 1, 2007 (Exhibit 4.1, WMECO Current Report on Form 8-K filed on August 20, 2007, File No. 000-07624) 4.3.3 Eighth Supplemental Indenture between NSTAR Electric Company, as successor to WMECO, and The Bank of New York Trust Company, N.A., as Trustee, dated as of June 1, 2016 (Exhibit 4.1, WMECO Current Report on Form 8-K filed on June 29, 2016, File No. 000-07624) 4.4 NSTAR Electric Company Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (Exhibit 4.4, Eversource Energy Annual Report on Form 10-K filed on February 27, 2020, File No. 001-05324) (D) Public Service Company of New Hampshire 4.1 First Mortgage Indenture between PSNH and First Fidelity Bank, National Association, New Jersey, now First Union National Bank, Trustee, dated as of August 15, 1978 (Composite including all amendments effective June 1, 2011) (included as Schedule C to the Eighteenth Supplemental Indenture filed as Exhibit 4.1 to PSNH Current Report on Form 8-K filed on June 2, 2011, File No. 001-06392) 4.1.1 Fourteenth Supplemental Indenture between PSNH and Wachovia Bank, National Association successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee dated as of October 1, 2005 (Exhibit 99.2, PSNH Current Report on Form 8-K filed on October 6, 2005, File No. 001-06392) 4.1.2 Twenty-Second Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of June 1, 2019 (Exhibit 4.1, PSNH Current Report on Form 8-K filed on July 3, 2019, File No. 001-06392) E-5
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4.1.3 Twenty-Third Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of August 1, 2020 (Exhibit 4.1, PSNH Current Report on Form 8-K filed on August 31, 2020, File No. 001-06392) 4.1.4 Twenty-Fourth Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of June 1, 2021 (Exhibit 4.1, PSNH Current Report on Form 8-K filed on June 21, 2021, File No. 001-06392) 4.1.5 Twenty-Fifth Supplemental Indenture, between PSNH and U.S. Bank Trust Company, National Association, as Trustee dated as of January 1, 2023 (Exhibit 4.1, PSNH Current Report on Form 8-K filed on January 11, 2023, File No. 001-06392) 4.1.6 Twenty-Sixth Supplemental Indenture, between PSNH and U.S. Bank Trust Company, National Association, as Trustee dated as of September 1, 2023 (Exhibit 4.1, PSNH Current Report on Form 8-K filed on September 25, 2023, File No. 001-06392) 4.1.7 Twenty-Seventh Supplemental Indenture, between PSNH and U.S. Bank Trust Company, National Association, as Trustee dated as of April 1, 2024 (Exhibit 4.3, PSNH Current Report on Form 8-K filed on April 1, 2024, File No. 001-06392) 4.1.8 Twenty-Eighth Supplemental Indenture, between PSNH and U.S. Bank Trust Company, National Association, as Trustee dated as of June 1, 2025 (Exhibit 4.1, PSNH Current Report on Form 8-K filed on June 24, 2025, File No. 001-06392) 4.2 Series A Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001 (Exhibit 4.3.5, 2001 Eversource Energy Annual Report on Form 10-K filed on March 22, 2002, File No. 001-05324) (F) Eversource Energy, The Connecticut Light and Power Company and Public Service Company of New Hampshire 4.1 Second Amended and Restated Credit Agreement, dated as of October 15, 2021, by and among Eversource, Aquarion Water Company of Connecticut, NSTAR Gas, CL&P, PSNH, Yankee Gas and EGMA and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent and Swing Line Lender (Exhibit 10.12, Eversource Energy Annual Report on Form 10-K filed on February 17, 2022, File No. 001-05324) 4.1.1 First Amendment to Second Amended and Restated Credit Agreement and Extension Agreement, dated October 17, 2022, by and among Eversource, Aquarion Water Company of Connecticut, NSTAR Gas, CL&P, PSNH, Yankee Gas and EGMA and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent and Swing Line Lender (Exhibit 4, Eversource Energy Quarterly Report on Form 10-Q filed on November 4, 2022, File No. 001-05324) 4.1.2 Second Amendment to Second Amended and Restated Credit Agreement and Extension Agreement, dated November 29, 2023, by and among Eversource, Aquarion Water Company of Connecticut, NSTAR Gas, CL&P, PSNH, Yankee Gas and EGMA and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent and Swing Line Lender (Exhibit 4.1.2, Eversource Energy Annual Report on Form 10-K filed on February 14, 2024, File No. 001-05324) 4.1.3 Third Amendment to Second Amended and Restated Credit Agreement, dated October 11, 2024, by and among Eversource Energy, Aquarion Water Company of Connecticut, NSTAR Gas Company, The Connecticut Light and Power Company, Public Service Company of New Hampshire, Yankee Gas Services Company and Eversource Gas Company of Massachusetts and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent and Swing Line Lender (Exhibit 4, Eversource Energy Quarterly Report on Form 10-Q filed on November 6, 2024, File No. 001-05324) 10. Material Contracts (A) Eversource Energy 10.1 Lease between The Rocky River Realty Company and Eversource Energy Service Company, dated as of July 1, 2008 (Exhibit 10.1, Eversource Energy Annual Report on Form 10-K filed on February 26, 2018, File No. 001-05324) *+10.2 Eversource Energy Board of Trustees’ Compensation Arrangement Summary E-6
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+10.3 Eversource Supplemental Executive Retirement Program, as amended to include the Eversource Supplemental Cash Balance Pension Plan, effective January 1, 2025 (Exhibit 10.1, Eversource Energy Current Report on Form 8-K filed on December 6, 2024, File No. 001-05324) +10.4 Eversource Energy Deferred Compensation Plan for Executives effective as of January 1, 2014 (Exhibit 10.6, Eversource Energy Annual Report on Form 10-K filed on February 26, 2016, File No. 001-05324) +10.4.1 Amendment No 1 to the Eversource Deferred Compensation Plan effective February 7, 2018 (Exhibit 10.6.1, Eversource Energy Annual Report on Form 10-K filed on February 27, 2020, File No. 001-05324) +10.5 NSTAR Excess Benefit Plan, effective August 25, 1999 (Exhibit 10.1, NSTAR Annual Report on Form 10-K/A filed on September 29, 2000, File No. 001-14768) +10.5.1 NSTAR Excess Benefit Plan, incorporating the NSTAR 409A Excess Benefit Plan, as amended and restated effective January 1, 2008, dated December 24, 2008 (Exhibit 10.1.1, NSTAR Annual Report on Form 10-K filed on February 9, 2009, File No. 001-14768) +10.6 Amended and Restated Change in Control Agreement by and between Joseph R. Nolan, Jr. and NSTAR, dated November 15, 2007 (Exhibit 10.13, NSTAR Annual Report on Form 10-K filed on February 11, 2008, File No. 001-14768) +10.7 Amended and Restated Change in Control Agreement by and between Senior Vice President and NSTAR, dated November 15, 2007 (Exhibit 10.15, NSTAR Annual Report on Form 10-K filed on February 11, 2008, File No. 001-14768) (B) Eversource Energy, The Connecticut Light and Power Company, NSTAR Electric Company and Public Service Company of New Hampshire 10.1 Amended and Restated Form of Service Contract between each of Eversource Energy, CL&P, NSTAR Electric Company and Eversource Energy Service Company dated as of January 1, 2014. (Exhibit 10.1, Eversource Energy Annual Report on Form 10-K filed on February 25, 2014, File No. 001-05324) 10.2 Transmission Operating Agreement between the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc. dated as of February 1, 2005 (Exhibit 10.29, Eversource Energy Annual Report on Form 10-K filed on March 17, 2005, File No. 001-05324) 10.2.1 Rate Design and Funds Disbursement Agreement among the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc., effective June 30, 2006 (Exhibit 10.22.1, Eversource Energy Annual Report on Form 10-K filed on March 1, 2007, File No. 001-05324) 10.3 Eversource Energy's Third Amended and Restated Tax Allocation Agreement dated as of April 10, 2012, (Exhibit 10.1, Eversource Energy Quarterly Report on Form 10-Q for Quarter Ended June 30, 2012 filed on August 7, 2012, File No. 001- 05324) +10.4 Amended and Restated Incentive Plan Effective January 1, 2009 (Exhibit 10.3, Eversource Energy Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324) +10.5 2018 Eversource Energy Incentive Plan (Exhibit 99.2, Eversource Energy Current Report on Form 8-K dated May 3, 2018, File No. 001-05324) 10.5.1 Amendment Number 1 to the 2018 Eversource Incentive Plan, effective May 3, 2023 (Appendix A to the Eversource Energy Definitive Proxy Statement for the 2023 Eversource Energy Annual Meeting of Shareholders, dated March 24, 2023, File No. 001-05324) +10.6 Trust under Supplemental Executive Retirement Plan dated May 2, 1994 (Exhibit 10.33, Eversource Energy Annual Report on Form 10-K filed on March 21, 2003, File No. 001-05324) +10.6.1 First Amendment to Trust Under Supplemental Executive Retirement Plan, effective as of December 10, 2002 (Exhibit 10 (B) 10.19.1, Eversource Energy Annual Report on Form 10-K filed on March 12, 2004, File No. 001- 05324) E-7
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+10.6.2 Second Amendment to Trust Under Supplemental Executive Retirement Plan, effective as of November 12, 2008 (Exhibit 10.12.2, Eversource Energy Annual Report on Form 10-K filed on February 27, 2009, File No. 001- 05324) +10.7 Amended and Restated Employment Agreement with Gregory B. Butler, effective January 1, 2009 (Exhibit 10.7, Eversource Energy Annual Report on Form 10-K filed on February 27, 2009, File No. 001-05324) (C) Eversource Energy, The Connecticut Light and Power Company, Public Service Company of New Hampshire and NSTAR Electric Company 10.1 Eversource Energy Service Company Transmission and Ancillary Service Wholesale Revenue Allocation Methodology among The Connecticut Light and Power Company, NSTAR Electric Company, Public Service Company of New Hampshire, Holyoke Water Power Company and Holyoke Power and Electric Company Trustee dated as of January 1, 2008 (Exhibit 10.1, Eversource Energy Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2008 filed on May 9, 2008, File No. 001-05324) *19. Insider Trading Policy *21. Subsidiaries of the Registrant *23. Consents of Independent Registered Public Accounting Firm *31. Rule 13a - 14(a)/15 d - 14(a) Certifications (A) Eversource Energy 31 Certification by the Chairman of the Board, President and Chief Executive Officer of Eversource Energy pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 31.1 Certification by the Chief Financial Officer of Eversource Energy pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (B) The Connecticut Light and Power Company 31 Certification by the Chairman and Chief Executive Officer of CL&P pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 31.1 Certification by the Chief Financial Officer of CL&P pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (C) NSTAR Electric Company 31 Certification by the Chairman of NSTAR Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 31.1 Certification by the Chief Financial Officer of NSTAR Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (D) Public Service Company of New Hampshire 31 Certification by the Chairman of PSNH pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 31.1 Certification by the Chief Financial Officer of PSNH pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 *32 18 U.S.C. Section 1350 Certifications (A) Eversource Energy 32 Certification by the Chairman of the Board, President and Chief Executive Officer and the Chief Financial Officer of Eversource Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (B) The Connecticut Light and Power Company 32 Certification by the Chairman and Chief Executive Officer and the Chief Financial Officer of CL&P pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 E-8
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(C) NSTAR Electric Company 32 Certification by the Chairman and the Chief Financial Officer of NSTAR Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (D) Public Service Company of New Hampshire 32 Certification by the Chairman and the Chief Financial Officer of PSNH pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 *97 Clawback Policy *101.INS Inline XBRL Instance Document - the instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document *101.SCH Inline XBRL Taxonomy Extension Schema *101.CAL Inline XBRL Taxonomy Extension Calculation *101.DEF Inline XBRL Taxonomy Extension Definition *101.LAB Inline XBRL Taxonomy Extension Labels *101.PRE Inline XBRL Taxonomy Extension Presentation *104 The cover page from the Annual Report on Form 10-K for the year ended December 31, 2025, formatted in Inline XBRL E-9
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EVERSOURCE ENERGY SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. EVERSOURCE ENERGY February 17, 2026 By: /s/ Jay S. Buth Jay S. Buth Vice President, Controller and Chief Accounting Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. POWER OF ATTORNEY Each person whose signature appears below constitutes and appoints Gregory B. Butler, John M. Moreira and Jay S. Buth and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Signature Title Date /s/ Joseph R. Nolan, Jr. Chairman of the Board, President and February 17, 2026 Joseph R. Nolan, Jr. Chief Executive Officer (Principal Executive Officer) /s/ John M. Moreira Executive Vice President, Chief Financial Officer February 17, 2026 John M. Moreira and Treasurer (Principal Financial Officer) /s/ Jay S. Buth Vice President, Controller February 17, 2026 Jay S. Buth and Chief Accounting Officer /s/ Cotton M. Cleveland Trustee February 17, 2026 Cotton M. Cleveland /s/ Linda Dorcena Forry Trustee February 17, 2026 Linda Dorcena Forry /s/ Gregory M. Jones Trustee February 17, 2026 Gregory M. Jones /s/ Loretta D. Keane Trustee February 17, 2026 Loretta D. Keane E-10
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Signature Title Date /s/ John Y. Kim Trustee February 17, 2026 John Y. Kim /s/ David H. Long Trustee February 17, 2026 David H. Long /s/ W. Robert Mudge Trustee February 17, 2026 W. Robert Mudge /s/ Daniel J. Nova Trustee February 17, 2026 Daniel J. Nova /s/ Frederica M. Williams Trustee February 17, 2026 Frederica M. Williams E-11
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THE CONNECTICUT LIGHT AND POWER COMPANY SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. THE CONNECTICUT LIGHT AND POWER COMPANY February 17, 2026 By: /s/ Jay S. Buth Jay S. Buth Vice President, Controller and Chief Accounting Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. POWER OF ATTORNEY Each person whose signature appears below constitutes and appoints Gregory B. Butler, John M. Moreira and Jay S. Buth and each of them, his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Signature Title Date /s/ Paul Chodak III Chairman and Chief Executive Officer February 17, 2026 Paul Chodak III and a Director (Principal Executive Officer) /s/ John M. Moreira Executive Vice President, Chief Financial Officer February 17, 2026 John M. Moreira and Treasurer and a Director (Principal Financial Officer) /s/ Gregory B. Butler Executive Vice President and General Counsel February 17, 2026 Gregory B. Butler and a Director /s/ Jay S. Buth Vice President, Controller February 17, 2026 Jay S. Buth and Chief Accounting Officer /s/ Penelope M. Conner Director February 17, 2026 Penelope M. Conner /s/ Chandler J. Howard Director February 17, 2026 Chandler J. Howard /s/ Patrick J. McGrath Director February 17, 2026 Patrick J. McGrath /s/ Ian G. Nicholson Director February 17, 2026 Ian G. Nicholson
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E-12
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NSTAR ELECTRIC COMPANY SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. NSTAR ELECTRIC COMPANY February 17, 2026 By: /s/ Jay S. Buth Jay S. Buth Vice President, Controller and Chief Accounting Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. POWER OF ATTORNEY Each person whose signature appears below constitutes and appoints Gregory B. Butler, John M. Moreira and Jay S. Buth and each of them, his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Signature Title Date /s/ Joseph R. Nolan, Jr. Chairman and a Director February 17, 2026 Joseph R. Nolan, Jr. (Principal Executive Officer) /s/ Paul Chodak III Chief Executive Officer and a Director February 17, 2026 Paul Chodak III /s/ John M. Moreira Executive Vice President, Chief Financial Officer February 17, 2026 John M. Moreira and Treasurer and a Director (Principal Financial Officer) /s/ Gregory B. Butler Executive Vice President and General Counsel February 17, 2026 Gregory B. Butler and a Director /s/ Jay S. Buth Vice President, Controller February 17, 2026 Jay S. Buth and Chief Accounting Officer E-13
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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE February 17, 2026 By: /s/ Jay S. Buth Jay S. Buth Vice President, Controller and Chief Accounting Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. POWER OF ATTORNEY Each person whose signature appears below constitutes and appoints Gregory B. Butler, John M. Moreira and Jay S. Buth and each of them, his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Signature Title Date /s/ Joseph R. Nolan, Jr. Chairman and a Director February 17, 2026 Joseph R. Nolan, Jr. (Principal Executive Officer) /s/ Paul Chodak III Chief Executive Officer and a Director February 17, 2026 Paul Chodak III /s/ John M. Moreira Executive Vice President, Chief Financial Officer February 17, 2026 John M. Moreira and Treasurer and a Director (Principal Financial Officer) /s/ Gregory B. Butler Executive Vice President and General Counsel February 17, 2026 Gregory B. Butler and a Director /s/ Jay S. Buth Vice President, Controller February 17, 2026 Jay S. Buth and Chief Accounting Officer E-14
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Exhibit 10.2 SUMMARY OF TRUSTEE COMPENSATION ARRANGEMENTS The Compensation Committee periodically reviews the compensation of our non-employee Trustees and, when it deems appropriate and upon consultation with the Committee’s independent compensation consultant, recommends adjustments to be approved by the Board of Trustees. The Compensation Committee recommends to the Board compensation for the Trustees based on competitive market practices for both the total value of compensation and the allocation of cash and equity. The Committee uses data obtained from similarly sized utility and general industry companies as guidelines for setting Trustee compensation. The level of Trustee compensation recommended by the Committee and approved by the Board enables us to attract Trustees who have a broad range of backgrounds and experiences. Each non-employee Trustee serving on January 1 receives a grant under the Company’s Incentive Plan, effective on the tenth business day of such year, consisting of the number of restricted stock units (RSUs) resulting from dividing $175,000 by the average closing price of our common shares as reported on the NYSE for the 10 trading days immediately preceding such date and rounding the resulting amount to the nearest whole RSU. RSUs generally vest on the next business day following the grant. Non-employee Trustees may elect distribution of up to 100 percent of the common shares issuable in respect of such RSUs immediately upon vesting of their RSU grant, subject to satisfaction of the Trustee share ownership guidelines. The distribution of all common shares entitled to be received upon vesting, but not distributed immediately, is deferred until the tenth business day of January of the year following retirement from Board service. Any individual who is elected to serve as a Trustee after January 1 of any calendar year receives an RSU grant prorated from the date of such election and granted on the first business day of the month following such election. 2025 Trustee Compensation Compensation Element Amount Annual Cash Retainer $125,000 Annual Stock Retainer $175,000 Board and Committee Attendance FeesNone Annual Lead Trustee Retainer $35,000 Annual Committee Chair Retainer $25,000 Audit Committee $20,000 Compensation Committee $20,000 Governance, Environmental and Social Responsibility Committee $20,000 Finance and Risk Management Committee Annual cash retainers of $125,000 per Trustee, additional Lead Trustee and Committee Chair cash retainers, and annual RSU grants for service on the Board for 2025 were paid based on the amounts described above. The share ownership guidelines set forth in the Company’s Corporate Governance Guidelines require each Trustee to attain ownership of a number of common shares equal to a market value of at least five-times the then current annual cash compensation retainer for service on the Board. Trustees are required to hold all shares awarded as annual stock compensation retainers until the guidelines have been met. Prior to the year earned, each Trustee may irrevocably elect to defer receipt of all or a portion of their cash compensation. Deferred funds are credited with deemed earnings on various deemed investments as permitted by the Company's Deferred Compensation Plan. Deferred cash compensation is payable either in a lump sum or in installments in accordance with the Trustee’s prior election. There were no above- market earnings in deferred compensation value during 2025, as the terms of the Deferred Compensation Plan provide for market-based investments, including Company common shares. Our Incentive Plan places a limit on the amount of total annual compensation that can be paid to any Trustee. When applicable, we pay travel-related expenses for spouses of Trustees who attend Board functions, but we do not pay tax gross-up payments in connection with any taxes on such expenses, nor do we pay pension benefits to our non-employee Trustees.
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Exhibit 19 Eversource Energy Insider Trading Policy Introduction Eversource Energy and its subsidiaries (collectively, the “Company”) has adopted this Insider Trading Policy (the “Policy”) tohelp its Trustees, officers and employees comply with applicable securities laws. The Policy relates to transactions in theCompany’s common shares, including the trading of shares to and from those held in the Eversource 401k Plan (allcollectively referred to in this Policy as “Company Securities”), and except for specific exempt purchases discussed below.This Policy has been adopted to also promote compliance with applicable securities laws and Company policy, both of whichprohibit persons who are aware of material, non-public information about the Company from trading in Company Securitiesor providing material non-public information to other persons who may trade in Company Securities on the basis of thatinformation. The Policy also acts to help preserve the reputation and integrity of Eversource Energy and all persons affiliatedwith the Company. Persons Subject to the PolicyThe provisions of the Policy relating to the prohibition on disclosure of material non-public information apply to all Insiders,as that term is defined below, not just Trustees and officers, as well as members of an Insider’s household and entitiescontrolled by a person covered by this Policy (“Related Persons,” as further defined below). Certain portions of the Policyrelating to trading in Company Securities apply only to Company Trustees and senior executives as noted. Relevant Definitions Insider: Any person who possesses material, non-public information is considered an “Insider” as to that information.Insiders can include Company Trustees, officers, employees, independent contractors and those persons in a specialrelationship with the Company, such as Company auditors, consultants or counsel. Material Information: Information is considered “material” if a reasonable investor would consider that informationimportant in making a decision to buy, sell or hold securities. Any information that could be expected to affect the Company’sstock price, whether positively or negatively, should be considered material. There is no bright line standard for assessingmateriality; rather, materiality is based on an assessment of all of the facts and circumstances. The following are examples ofpotentially material information: • Unpublished financial results or earnings projections;• Changes in dividend policy or payments;• Pending or proposed merger, acquisition or tender offer;• Pending or proposed acquisition or disposition of significant assets;• Pending or threatened significant litigation, or the resolution of such litigation;• Rating agency decisions, or issuance of a credit watch or change in Company outlook;• Pending or threatened labor disputes, including strikes or lockouts;• Undisclosed material data, cyber or other security breach;• Changes in key management. The above list is for illustrative purposes only; there are many other types of information that may be considered “material”depending on facts and circumstances. Non-public Information: Information that has not been disclosed to the public is generally considered non-publicinformation. In order for information to be considered public, it must be widely disseminated in a manner making it generallyavailable to investors. Information that is disseminated through established newswire services (such as Dow Jones, Reuters orthe Associated Press) or through public disclosure documents filed with the U.S. Securities and Exchange Commission(“SEC”) is generally considered widely disseminated to the public. Related Persons: Persons related to an Insider, including an Insider’s spouse, as well as anyone else who lives in the Insider’shousehold; partnerships of which an Insider is a general partner; trusts of which an Insider is a trustee; estates of which anInsider is an executor or administrator; and other equivalent legal entities that an Insider controls. Insiders are responsible forthe transactions of these Related Persons, and therefore Insiders should make Related Persons aware of the need to conferwith the Insider before trading in Company Securities.
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Specific Guidance Non-Disclosure of Material, Nonpublic InformationMaterial, non-public information relating to the Company must not be disclosed to anyone, except to persons within theCompany or third party agents of the Company (such as auditors, investing banking advisors or legal counsel) whosepositions require them to have the information, and only after appropriate action, such as the signing of a non-disclosureagreement, has been taken to protect the information. Violations of insider trading laws and this Policy can result indisciplinary action, up to and including termination of employment with the Company, as well as substantial civil fines andeven imprisonment. Prohibited Trading in Company SecuritiesNo Insider may purchase or sell Company Securities, or recommend that another person purchase or sell Company Securities,when he or she has knowledge of material information concerning the Company that has not been disclosed to the public.Gifts, charitable donations and other contributions of Company Securities are also subject to this Policy, as are hedges orpledges of Company Securities and sales and purchases within the Company’s 401k Plan. Hedges and pledges of CompanySecurities by officers and Trustees are prohibited at all times. This Policy does not apply, however, to purchases of CompanySecurities resulting from an employee’s previously determined periodic contribution of money to the Company’s 401k Planpursuant to a previously made payroll deduction election, reinvested dividends, transactions effected pursuant to pre-existingRule 10b5-1 Plans, or sales required to meet current tax withholding requirements on vesting stock compensation. If anInsider is uncertain as to whether or not he or she is in possession of material, non-public information, the Insider must refrainfrom any purchase or sale of Company Securities and seek advice from the Company’s Legal Department. All Companymanagers are responsible for communicating directly with the Legal Department when a question exists as to whether anyemployee should be counseled on restrictions in trading Company Securities because the employee may be in possession ofconfidential, undisclosed material information. Pre-Clearance ProceduresEversource Energy Trustees and officers (VP level and above), including Related Persons, may not directly or indirectly,purchase or sell, or otherwise make any transfer, gift, pledge or loan of, any Company Securities (other than those noted in theprevious section relating to 401k Plan contributions, dividend reinvestments, transactions effected pursuant to pre-existing10b5-1 Plans, and sales required to meet current tax withholding requirements on vesting stock compensation) without firstobtaining approval in advance. A request for pre-clearance must be made by email addressed to the Company’s ExecutiveVice President and General Counsel and the Executive Vice President and Corporate Secretary prior to entering into anytransaction. The request will be evaluated to determine whether the proposed transaction is consistent with applicablesecurities laws and the Company’s policies, including compliance with the Company’s share ownership guidelines, prior toand following the proposed transaction. Contact Eversource Energy’s Director of Compensation at 860-665-5500 for furtherinformation on share ownership guidelines. Other details setting forth trading requirements in Company Securities aredescribed in the periodic communications from the Legal Department. Quarterly or Event Specific Trading RestrictionsAll purchases, sales and gifts of Company Securities by Trustees and officers (except for the specific exempt purchases notedabove), must occur within a prescribed time period, or “open window.” Open windows to transact in Company Securities willgenerally begin one business day after the release of Company earnings for the current period and will generally remain openfor up to 30 calendar days from that date. The Company reserves the right to suspend or close the window at any time. Section 16 Reporting PersonsCompany Trustees and certain Company officers (“Section 16 Reporting Persons”) are subject to additional tradingrestrictions and requirements under SEC rules. The Company officers that are subject to the additional rules set forth belowconsist of the CEO, all Executive Vice Presidents, and the Vice President, Controller and Chief Accounting Officer. Section 16 Reports (Forms 3, 4 and 5)Section 16 Reporting Persons are required by Section 16(a) of the Securities Exchange Act of 1934 to report to the SEC theirinitial beneficial ownership of Company Securities on Form 3 within 10 days of becoming a Reporting Person and allsubsequent changes in ownership on Form 4, no later than two business days after the transaction. Under new SEC rules, gifts(a disposition for no consideration) must now be reported on Form 4 within two business days of the transaction. A gift maynot be reported on a year-end Form 5. The Legal Department will assist Section 16 Reporting Persons in preparing and filingthe required Section 16 reports with 2
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the SEC; however, Section 16 Reporting Persons retain responsibility for informing the Legal Department of transactions inCompany Securities. Section 16 Reporting Persons are also subject to Rule 144 under the Securities Act of 1933 and are required to file Form 144(before making an open market sale of Company Securities) when the amount to be sold in any three-month period exceeds5,000 common shares or has an aggregate sales price greater than $50,000. Form 144 notifies the SEC of the intent to sellCompany Securities, and it must be filed electronically. Form 144 is generally prepared by a broker and is in addition to theSection 16 reports described above. Section 16 Reporting Persons must also refrain from making a non-exempt purchase of Company Securities within sixmonths of having sold Company Securities and from making a non-exempt sale of Company Securities within six months ofhaving purchased Company Securities. Rule 10b5-1 PlansTrustees and certain Company officers and employees are frequently in possession of material, non-public information andthus would often be prevented from trading in Company Securities. As such, the Company has authorized the entry into pre-existing written plans, contracts, instructions, or arrangements under Rule 10b5-1 under the Securities Exchange Act of 1934(a "10b5-1 Plan") that meet the following requirements: (1) the 10b5-1 Plan or any revisions or amendments to an existing 10b5-1 Plan is entered into during open windowperiods and is approved by either the Company’s Executive Vice President and General Counsel or ExecutiveVice President and Corporate Secretary;(2) the 10b5-1 Plan provides that no trades may occur thereunder until expiration of the applicable cooling-off periodspecified in Rule 10b5-1(c)(ii)(B), and that no trades occur until after that time.◦. For Trustees and officers, the cooling-off period ends on the later of (x) ninety days after adoption or certainmodifications of the 10b5-1 Plan; or (y) two business days following disclosure of the Company's financialresults in a Form 10-Q or Form 10-K for the quarter during which the 10b5-1 Plan was adopted.◦. For all other persons, the cooling-off period ends 30 days after adoption or modification of the 10b5-1 Plan.◦. The required cooling-off periods will apply to the entry into a new 10b5-1 Plan and any amendments orrevisions to an existing 10b5-1 Plan;(3) the 10b5-1 Plan is entered into in good faith by the Insider, and not as part of a plan or scheme to evade theprohibitions of Rule 10b5-1, at a time when the Insider is not in possession of material non-public informationabout the Company; and, if the Insider is a Trustee or officer, the 10b5-1 Plan must include representations by theInsider certifying to that effect;(4) the 10b5-1 Plan explicitly specifies the security or securities to be purchased or sold, the number of shares, theprices and/or dates of transactions, or other formula(s) describing such transactions, or the 10b5-1 Plan gives athird party the discretionary authority to execute such purchases and sales, outside the control of the Insider, solong as such third party does not possess any material non-public information about the Company; and(5) the 10b5-1 Plan is the only outstanding 10b5-1 Plan entered into by the Insider (subject to the extremely limitedexceptions described in Rule 10b5-1). If you are considering entering into, modifying or terminating a 10b5-1 Plan or have any questions regarding 10b5-1 Plans,please contact the Company’s Executive Vice President and General Counsel or Executive Vice President and CorporateSecretary. A new SEC rule requires the Company to disclose in its Annual Reports on Form 10-K and Quarterly Reports on Form 10-Qthe adoption, modification, or termination of 10b5-1 Plans by Trustees and officers who are Section 16 Reporting Persons.This disclosure must describe each plan’s material terms (other than pricing terms), including the name and title of the Trusteeor officer; the date the plan was adopted, modified, or terminated; the plan’s duration; and the total amount of securities to bepurchased or sold under the plan. You should consult your own legal and tax advisors before entering into, or modifying or terminating, any 10b5-1 Plan. Atrading plan, contract, instruction or arrangement will not qualify as an approved 10b5-1 Plan without the prior review andapproval of the Company’s Executive Vice President and General Counsel or Executive Vice President and CorporateSecretary as described above. Contact Eversource Energy’s Director of Compensation at 860-665-5500 for furtherinformation regarding 10b5-1 Plans. 3
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Any questions regarding the specific requirements affecting Section 16 Reporting Persons, should be directed to theCompany’s Legal Department. Revision History Update to Material Information list to include cyber breach 02/19/2019 Administrative changes 07/26/2021 Revised to reflect changes to Rule 10b5-1 05/3/2023 4
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Exhibit 21 Subsidiaries of the Registrants as of February 17, 2026 State of Incorporation The Connecticut Light and Power Company CT Connecticut Yankee Atomic Power Company CT Eversource Energy Service Company CT Eversource Energy Transmission Ventures, Inc. CT Eversource Gas Transmission LLC MA Eversource Gas Transmission II LLC MA Eversource LNG Service Company LLC MA Northern Pass Transmission LLC NH Renewable Properties, Inc. NH Eversource Holdco Corporation MA Eversource TEI LLC DE Eversource Investment LLC MA Eversource Investment Service Company LLC MA Aquarion Company DE Aquarion Water Company CT Abenaki Water Co., Inc. NH Aquarion Water Company of Connecticut CT Aquarion Water Company of Massachusetts, Inc. MA Aquarion Water Capital of Massachusetts, Inc. DE Aquarion Water Company of New Hampshire, Inc. NH The Torrington Water Company CT Aquarion Management Services Company DE New England Service Company CT HWP Company MA North Atlantic Energy Corporation NH North Atlantic Energy Service Corporation NH Northeast Nuclear Energy Company CT NSTAR Electric Company MA Harbor Electric Energy Company MA Public Service Company of New Hampshire NH Properties, Inc. NH PSNH Funding LLC 3 DE The Rocky River Realty Company CT Yankee Atomic Electric Company MA (1) (2) (3) (4) (2) (3) (2) (3) (4)
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Yankee Energy System, Inc. CT Eversource Gas Company of Massachusetts MA Hopkinton LNG Corp. MA NSTAR Gas Company MA Yankee Gas Services Company CT YES Clean Hydrogen LLC DE (1) The names of some of our subsidiaries which, if considered in the aggregate as a single subsidiary, would not constitute a “significant subsidiary,” have been omitted in accordance with Item 601(b) (21)(ii) of Regulation S-K. (2) SEC Registrant. (3) This entity is doing business as Eversource Energy. (4) For The Connecticut Light and Power Company, NSTAR Electric Company and Public Service Company of New Hampshire, investments in Connecticut Yankee Atomic Power Company and Yankee Atomic Electric Company are accounted for under the equity method. (3) (3) (3)
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Exhibit 23 CONSENTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in Registration Statement Nos. 333-286362 and 333-278423 on Form S-3 and RegistrationStatement Nos. 333-142724, 333-224605, 333-231116, and 333-274943 on Form S-8 of our reports dated February 17, 2026, relating to the consolidated financial statements and the financial statement schedules of Eversource Energy and subsidiaries, and the effectiveness ofEversource Energy and subsidiaries' internal control over financial reporting, appearing in this Annual Report on Form 10-K of EversourceEnergy for the year ended December 31, 2025. We also consent to the incorporation by reference in Registration Statement No. 333-286362-01 on Form S-3 of our report datedFebruary 17, 2026, relating to the financial statements and the financial statement schedule of The Connecticut Light and Power Companyappearing in this Annual Report on Form 10-K of The Connecticut Light and Power Company for the year ended December 31, 2025. We also consent to the incorporation by reference in Registration Statement No. 333-286362-03 on Form S-3 of our report datedFebruary 17, 2026, relating to the consolidated financial statements and the financial statement schedule of NSTAR Electric Company andsubsidiary appearing in this Annual Report on Form 10-K of NSTAR Electric Company for the year ended December 31, 2025. We also consent to the incorporation by reference in Registration Statement No. 333-286362-02 on Form S-3 of our report datedFebruary 17, 2026, relating to the consolidated financial statements and the financial statement schedule of Public Service Company ofNew Hampshire and subsidiaries appearing in this Annual Report on Form 10-K of Public Service Company of New Hampshire for theyear ended December 31, 2025. /s/ Deloitte & Touche LLP Hartford, Connecticut February 17, 2026
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Exhibit 31 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Joseph R. Nolan, Jr., certify that: 1. I have reviewed this Annual Report on Form 10-K of Eversource Energy (the registrant); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: February 17, 2026 /s/ Joseph R. Nolan, Jr. Joseph R. Nolan, Jr. Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)
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Exhibit 31.1 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, John M. Moreira, certify that: 1. I have reviewed this Annual Report on Form 10-K of Eversource Energy (the registrant); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: February 17, 2026 /s/ John M. Moreira John M. Moreira Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
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Exhibit 32 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with this Annual Report on Form 10-K of Eversource Energy (the registrant) for the period ending December 31, 2025 as filed with the Securities and Exchange Commission (the Report), we, Joseph R. Nolan, Jr., Chairman of the Board, President and Chief Executive Officer of the registrant, and John M. Moreira, Executive Vice President, Chief Financial Officer and Treasurer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that: 1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the registrant. /s/ Joseph R. Nolan, Jr. Joseph R. Nolan, Jr. Chairman of the Board, President and Chief Executive Officer /s/ John M. Moreira John M. Moreira Executive Vice President, Chief Financial Officer and Treasurer Date: February 17, 2026
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Exhibit 31 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Paul Chodak III, certify that: 1. I have reviewed this Annual Report on Form 10-K of The Connecticut Light and Power Company (the registrant); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: February 17, 2026 /s/ Paul Chodak III Paul Chodak III Chairman and Chief Executive Officer (Principal Executive Officer)
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Exhibit 31.1 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, John M. Moreira, certify that: 1. I have reviewed this Annual Report on Form 10-K of The Connecticut Light and Power Company (the registrant); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: February 17, 2026 /s/ John M. Moreira John M. Moreira Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
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Exhibit 32 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with this Annual Report on Form 10-K of The Connecticut Light and Power Company (the registrant) for the period ending December 31, 2025 as filed with the Securities and Exchange Commission (the Report), we, Paul Chodak III, Chairman and Chief Executive Officer of the registrant, and John M. Moreira, Executive Vice President, Chief Financial Officer and Treasurer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that: 1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the registrant. /s/ Paul Chodak III Paul Chodak III Chairman and Chief Executive Officer /s/ John M. Moreira John M. Moreira Executive Vice President, Chief Financial Officer and Treasurer Date: February 17, 2026
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Exhibit 31 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Joseph R. Nolan, Jr., certify that: 1. I have reviewed this Annual Report on Form 10-K of NSTAR Electric Company (the registrant); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: February 17, 2026 /s/ Joseph R. Nolan, Jr. Joseph R. Nolan, Jr. Chairman (Principal Executive Officer)
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Exhibit 31.1 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, John M. Moreira, certify that: 1. I have reviewed this Annual Report on Form 10-K of NSTAR Electric Company (the registrant); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: February 17, 2026 /s/ John M. Moreira John M. Moreira Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
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Exhibit 32 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with this Annual Report on Form 10-K of NSTAR Electric Company (the registrant) for the period ending December 31, 2025 as filed with the Securities and Exchange Commission (the Report), we, Joseph R. Nolan, Jr., Chairman of the registrant, and John M. Moreira, Executive Vice President, Chief Financial Officer and Treasurer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that: 1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the registrant. /s/ Joseph R. Nolan, Jr. Joseph R. Nolan, Jr. Chairman /s/ John M. Moreira John M. Moreira Executive Vice President, Chief Financial Officer and Treasurer Date: February 17, 2026
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Exhibit 31 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Joseph R. Nolan, Jr., certify that: 1. I have reviewed this Annual Report on Form 10-K of Public Service Company of New Hampshire (the registrant); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: February 17, 2026 /s/ Joseph R. Nolan, Jr. Joseph R. Nolan, Jr. Chairman (Principal Executive Officer)
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Exhibit 31.1 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, John M. Moreira, certify that: 1. I have reviewed this Annual Report on Form 10-K of Public Service Company of New Hampshire (the registrant); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: February 17, 2026 /s/ John M. Moreira John M. Moreira Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
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Exhibit 32 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with this Annual Report on Form 10-K of Public Service Company of New Hampshire (the registrant) for the period ending December 31, 2025 as filed with the Securities and Exchange Commission (the Report), we, Joseph R. Nolan, Jr., Chairman of the registrant, and John M. Moreira, Executive Vice President, Chief Financial Officer and Treasurer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that: 1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the registrant. /s/ Joseph R. Nolan, Jr. Joseph R. Nolan, Jr. Chairman /s/ John M. Moreira John M. Moreira Executive Vice President, Chief Financial Officer and Treasurer Date: February 17, 2026
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Exhibit 97 Eversource EnergyExecutive Clawback Policy The Board of Trustees (the Board) of Eversource Energy (the Company), in order to continue to maintain the bestinterests of the Company and its shareholders, is adopting this revised Clawback Policy (the Policy), whichprovides for the recovery of erroneously awarded incentive-based compensation in the event of an AccountingRestatement (as defined below). This Policy is designed to comply with, and shall be interpreted to be consistentwith, Section 10D of the Securities and Exchange Act of 1934, as amended (the Exchange Act), Rule 10D-1promulgated under the Exchange Act (Rule 10D-1), and Section 303A.14 of the New York Stock Exchange(NYSE) Listed Company Manual (Listing Standards). 1. Administration: Except as specifically set forth herein, this Policy shall be administered by the Board’sCompensation Committee (except as otherwise provided for herein, referred to as the Administrator). TheAdministrator is authorized to interpret and construe this Policy and to make all determinations necessary,appropriate or advisable for the administration of this Policy. Any determinations made by theAdministrator shall be final and binding on all affected individuals and need not be uniform with respectto each individual covered by the Policy. In the administration of this Policy, the Administrator isauthorized to consult with the Board’s Audit Committee or other Committee(s), as may be necessary orappropriate, as to matters within the scope of such other Committee(s)’ responsibility and authority.Subject to any limitation at applicable law, the Administrator may authorize and empower any officer,employee or advisor of the Company to take any and all actions necessary or appropriate to carry out thepurpose and intent of this Policy other than with respect to any recovery under this Policy involving suchofficer or employee. 2. Definitions: As used in this Policy, the following definitions apply:• Accounting Restatement means an accounting restatement of the Company’s financialstatements due to the Company’s material noncompliance with any financial reportingrequirement under the securities laws, including any required accounting restatement to correctan error in previously issued financial statements that is material to the previously issuedfinancial statements, or that would result in a material misstatement if the error were corrected inthe current period or left uncorrected in the current period.• Applicable Period means the three completed fiscal years immediately preceding the date onwhich the Company is required to prepare an Accounting Restatement, as well as any transitionperiod that results from a change in the Company’s fiscal year within or immediately followingthose three completed years, except that a transition period that comprises a period of at leastnine months shall count as a completed fiscal year. The “date on which the Company is requiredto prepare an Accounting Restatement” is the earlier to occur of (a) the date the Board, aCommittee or any officer or officers of the Company authorized to take such action if Boardaction is not required concludes or reasonably should have concluded that the Company isrequired to prepare an Accounting Restatement or (b) the date a court, regulator or other legallyauthorized body directs the Company to prepare an Accounting Restatement, in each caseregardless of if or when the restated financial statements are filed.• Covered Executives means the Company’s current and former executive officers and theCompany’s Chief Accounting Officer, as determined by the 1
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Administrator in accordance with the definition of executive officer set forth in Rule 10D-1 andthe Listing Standards.• Erroneously Awarded Compensation means the amount of Incentive-Based Compensation (asdefined below) received during the Applicable Period that exceeds the amount of incentive-based compensation that otherwise would have been received had it been determined based onthe Accounting Restatement, computed on a pre-tax basis.• Financial Reporting Measure is any measure that is determined and presented in accordancewith the accounting principles used in preparing the Company’s financial statements, and anymeasure that is derived wholly or in part from such measure. Financial Reporting Measuresinclude but are not limited to the following (and any measures derived from the following):Company stock price; total shareholder return (TSR); revenues; net income; profitability of oneor more reportable segments; financial ratios (e.g., accounts receivable turnover and inventoryturnover rates); earnings before interest, taxes, depreciation and amortization (EBITDA); fundsfrom operations and adjusted funds from operations; liquidity measures (e.g., working capital,operating cash flow); return measures (e.g., return on invested capital, return on assets); earningmeasures (e.g., earnings per share); revenue per user, or average revenue per user, where revenueis subject to an Accounting Restatement; cost per employee, where cost is subject to anAccounting Restatement; any of such financial reporting measures relative to a peer group,where the Company’s financial reporting measure is subject to an Accounting Restatement; andtax basis income. A Financial Reporting Measure need not be presented within the Company’sfinancial statements or included in a filing with the Securities and Exchange Commission.• Incentive-Based Compensation means any compensation that is granted, earned or vestedbased wholly or in part upon the attainment of a Financial Reporting Measure. Incentive-BasedCompensation is received for purposes of this Policy in the Company’s fiscal period duringwhich the Financial Reporting Measure specified in the Incentive-Based Compensation award isattained, even if the payment or grant of such Incentive-Based Compensation occurs after theend of that period. 3. Covered Executives; Incentive-Based Compensation: This Policy applies to Incentive-BasedCompensation received by a Covered Executive (a) after beginning services as a Covered Executive; (b) ifthat person served as a Covered Executive at any time during the performance period for such Incentive-Based Compensation; and (c) while the Company had a listed class of securities on a national securitiesexchange. Recovery of Incentive-Based Compensation is not required (1) with respect to any suchcompensation received while an individual was serving in a non-executive capacity prior to becoming anexecutive officer of the Company or (2) from any individual who is an executive officer on the date onwhich the Company is required to prepare an Accounting Restatement but who was not an executiveofficer of the Company at any time during the performance period for which the incentive-basedcompensation is received. 4. Required Recoupment of Erroneously Awarded Compensation in the Event of an AccountingRestatement: In the event the Company is required to issue an Accounting Restatement, the Companyshall promptly recoup the amount of any Erroneously Awarded Compensation received by each CoveredExecutive during the Applicable Period. The Administrator shall give notice to each Covered Executive ofthe Accounting Restatement, which shall contain a demand for payment and the amount of ErroneouslyAwarded Compensation to be repaid. Covered Executives shall also 2
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reimburse the Company for any expenses incurred, including reasonable attorneys’ fees. 5. Erroneously Awarded Compensation Subject to Recovery: The amount of Erroneously AwardedCompensation subject to recovery under the Policy, as determined by the Administrator, is the amount ofIncentive-Based Compensation received by the Covered Executive that exceeds the amount of Incentive-Based Compensation that would have been received by the Covered Executive had it been determinedbased on the restated amounts. Erroneously Awarded Compensation shall be computed by theAdministrator without regard to any taxes paid by the Covered Executive in respect of the ErroneouslyAwarded Compensation. For Incentive-Based Compensation based on stock price or TSR: (a) theAdministrator shall determine the amount of Erroneously Awarded Compensation based on a reasonableestimate of the effect of the Accounting Restatement on the stock price or TSR upon which the Incentive-Based Compensation was received; and (b) the Company shall maintain documentation of thedetermination of that reasonable estimate and provide such documentation to the NYSE. 6. Method of Recoupment: Subject to the provisions set forth in this Policy, the Administrator shalldetermine, in its sole discretion, the timing and method for promptly recouping Erroneously AwardedCompensation hereunder, which may include, without limitation (a) seeking reimbursement of all or partof any cash or equity-based award; (b) cancelling prior cash or equity-based awards, whether vested orunvested or paid or unpaid; (c) forfeiture of deferred compensation, subject to compliance with Section409A of the Internal Revenue Code and the regulations promulgated thereunder; and (d) any other methodauthorized by applicable law or contract. Subject to compliance with applicable law, the Administratormay effect recovery under this Policy from any amount otherwise payable from the Company to theCovered Executive, including amounts payable to such individual under any otherwise applicableCompany plan or program, including base salary, bonuses or commissions and compensation previouslydeferred by the Covered Executive. Each Covered Executive, by accepting or being deemed to haveaccepted Incentive-Based Compensation, agrees to cooperate fully with the Administrator, and to causeany and all permitted transferees of the Covered Executive to cooperate fully with the Administrator toeffectuate any forfeiture or disgorgement required hereunder. Neither the Administrator nor the Companynor any other person, other than the Covered Executive and his or her permitted transferees, if any, will beresponsible for any adverse tax or other consequences to a Covered Officer or his or her permittedtransferees, if any, that may arise as a result of the application of this Policy. The Company is authorizedand directed pursuant to this Policy to recoup Erroneously Awarded Compensation in compliance withthis Policy and to do so reasonably promptly, unless the Administrator has determined that recoverywould be impracticable solely for the following reasons, and subject to the following procedural anddisclosure requirements:• The direct expense paid to a third party to assist in enforcing the Policy would exceed the amount to berecovered. Before concluding that it would be impracticable to recover any amount of ErroneouslyAwarded Compensation based on expense of enforcement, the Administrator must make a reasonableattempt to recover such erroneously awarded compensation, document such reasonable attempt(s) torecover, and provide that documentation to the NYSE.• Recovery would violate home country law where the law was adopted prior to November 28, 2022.Before concluding that it would be impracticable to recovery any Erroneously Awarded Compensationbased on violation of home country law, the 3
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Administrator must satisfy the applicable opinion and disclosure requirements of Rule 10D-1 and theListing Standards; or• Recovery would likely cause an otherwise tax qualified retirement plan, under which benefits arebroadly available to employees of the Company, to fail to meet the requirements of 26 U.S.C. 401(a)(13) or 26 U.S.C. 411(a) and regulations thereunder. 7. No Indemnification of Covered Executives: Notwithstanding the terms of any indemnification orinsurance policy or any contractual arrangement with any Covered Executive that may be interpreted tothe contrary, the Company shall not indemnify any Covered Executives against the loss of anyErroneously Awarded Compensation, or any costs related thereto, including any payment orreimbursement for the cost of third party insurance purchased by any Covered Executive to fund potentialclawback obligations under this Policy. 8. Administrator Indemnification: Members of the Administrator, other Committees, and the Board shallnot be personally liable for any action, determination or interpretation made in good faith with respect tothis Policy and shall be fully indemnified by the Company to the fullest extent under applicable law andCompany policy with respect to any such action, determination or interpretation. The foregoing sentenceshall not limit any other rights to indemnification of the members of the Board or its Committees underapplicable law or Company policy. 9. Effective Date: This Policy shall be effective as of December 1, 2023 (the “Effective Date”) and shallapply to Incentive Compensation received by a Covered Executive on or after October 2, 2023. Allclawback policy provisions contained in the Company’s Incentive Plan as described in the Company’s2023 proxy statement not inconsistent with this Policy shall remain in full force and effect. 10.Amendment; Termination: The Administrator may amend, modify, supplement, rescind or replace all orany portion of this Policy at any time and from time to time in its discretion, and shall amend this Policyas it deems necessary to comply with applicable law or any rules or standards adopted by regulatorybodies or national securities exchanges on which the Company’s securities are listed. 11.Other Recoupment Rights; Company Claims: The Administrator intends that this Policy shall beapplied to the fullest extent of the law. Any right of recoupment under this Policy is in addition to, and notin lieu of, any other remedies or rights of recoupment that may be available to the Company underapplicable law or pursuant to the terms of any similar policy in any employment agreement, equity awardagreement, or similar agreement and any other legal remedies available to the Company. Nothingcontained in this Policy, and no recoupment or recovery as contemplated by this Policy, shall limit anyclaims, damages or other legal remedies the Company or any of its affiliates may have against a CoveredExecutive arising out of or resulting from an Accounting Restatement or any other actions or omissions bythe Covered Executives that violate this Policy. 12.Successors: This Policy shall be binding and enforceable against all Covered Executives and theirbeneficiaries, heirs, executors, administrators or other legal representatives. 4
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13.Exhibit Filing Requirement: A copy of this Policy and any amendments thereto shall be posted on theCompany’s website and filed as an exhibit to the Company’s annual report on Form 10-K. 5