EVERSOURCE ENERGY (ES) Business

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.

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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.

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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:

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

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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.

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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

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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.

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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.

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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.

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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

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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.

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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.

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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.

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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.

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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.

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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.