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Item 7. Management’s Discussion and Analysis

2026-02-17 compared with 2025-02-14 · 549 added, 473 removed, 720 unchanged (59% of the section changed)

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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 on the sales and impairments of the offshore wind equity method investments, a loss on the pending sale of the Aquarion water distribution business, a loss on the disposition of land that was initially acquired to construct the Northern Pass Transmission project and was subsequently abandoned, and certain transaction and transition costs.

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.

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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 on the offshore wind equity method investments, the loss on the pending sale of the Aquarion water distribution business, the loss on the disposition of land associated with an abandoned project, and transaction and transition costs are not indicative of our ongoing costs and performance.

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.

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Earnings Overview and Future Outlook:

• We earned $811.7 million, or $2.27 per share, in 2024, compared with a loss of $442.2 million, or $1.26 per share, in 2023.

Our 2024 results include an aggregate, net after-tax loss on the sales of our offshore wind investments of $524.0 million, or $1.47 per share, and an after-tax loss resulting from the expected sale of Aquarion of $298.3 million, or $0.83 per share.

Our 2023 results included after-tax impairment charges on our offshore wind investments of $1.95 billion, or $5.58 per share.

Our 2023 results also included after-tax land abandonment and other charges of $6.9 million, or $0.02 per share.

Excluding these charges, our non-GAAP earnings were $1.63 billion, or $4.57 per share, in 2024, compared with non-GAAP earnings of $1.52 billion, or $4.34 per share, in 2023.

• 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.

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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 $607.2 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.

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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.

Strategic Developments:

• On January 27, 2025, Eversource entered into a definitive agreement to sell Aquarion.

Subject to certain closing adjustments, the aggregate enterprise value of the sale is approximately $2.4 billion in cash, which includes approximately $1.6 billion for the equity and $800 million of net debt that will be extinguished at closing.

The sale is subject to regulatory and other approvals and is expected to close in late 2025.

Eversource plans to use the net proceeds from the pending sale to pay down parent company debt.

• In the third quarter of 2024, Eversource completed the sale of its 50 percent ownership share in the Sunrise Wind project to Ørsted for adjusted proceeds of $152 million and 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.

Eversource recognized an aggregate net after-tax loss on the sales of its offshore wind investments of $524 million.

Eversource recorded a contingent liability of $365 million, reflecting its estimate of the future obligations under the GIP sale terms, which include an expected cost overrun sharing obligation, expected obligation to maintain GIP’s internal rate of return, and obligation for other future costs.

Eversource does not have any ongoing financial obligations associated with Sunrise Wind.

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.

Earnings Overview

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Non-GAAP Earnings $ 1,767.4 $ 4.76 $ 1,634.0 $ 4.57 $ 1,517.7 $ 4.34

Losses on Offshore Wind Investments (after-tax) (1)

Losses on Offshore Wind (after-tax) (1)

(75.0) (0.20) (524.0) (1.47) (1,953.0) (5.58)

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— — — — (6.9) (0.02)

Transaction and Transition Costs (after-tax) (4)

— — — — (15.0) (0.04)

Net Income/(Loss) Attributable to Common Shareholders (GAAP) $ 1,692.4 $ 4.56 $ 811.7 $ 2.27 $ (442.2) $ (1.26)

(1) In 2024, we recorded a loss on the sales of our offshore wind equity method investments.

(1) 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 "Business Development and Capital Expenditures – Offshore Wind Business" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations .

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 .

(2) 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 – Pending Sale of Aquarion" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations .

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 .

(3) The 2023 charges primarily include a loss on the disposition of abandoned land intended to be used for the cancelled Northern Pass Transmission project.

(4) Transaction costs in 2022 primarily include costs associated with the transition of systems as a result of our purchase of the assets of Columbia Gas of Massachusetts (CMA) on October 9, 2020 and integrating the CMA assets onto Eversource’s systems.

The impact of higher shares outstanding resulted in $0.17 earnings per share dilution in 2025, as compared to 2024.

Regulated Companies:

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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 $23.7 million in 2024, as compared to 2023, due primarily to higher revenues from base distribution rate increases at NSTAR Electric effective January 1, 2024 and at PSNH effective August 1, 2024 and from CL&P's capital tracking mechanism due to increased electric system improvements, and an increase in interest income primarily on regulatory deferrals.

Those earnings increases were partially offset by higher operations and maintenance expense primarily driven by higher employee benefit costs, higher interest expense, higher depreciation expense, the absence of a prior year benefit at PSNH related to the establishment of a new regulatory tracking mechanism that allowed for the recovery of previously incurred operating expenses associated with poles acquired on May 1, 2023, higher property tax expense, and a higher effective tax rate.

Our electric transmission segment earnings increased $81.2 million in 2024, as compared to 2023, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure and the impact of the annual rate reconciliation filing with FERC, partially offset by a higher effective tax rate.

Our natural gas distribution segment earnings increased $66.2 million in 2024, as compared to 2023, due primarily to higher revenues from base distribution rate increases effective November 1, 2024 at EGMA and effective November 1, 2024 and November 1, 2023 at NSTAR Gas and capital tracking mechanisms due to continued investments in natural gas infrastructure.

Earnings also benefited from lower operations and maintenance expense, the absence of a prior year unfavorable regulatory adjustment resulting from NSTAR Gas’ GSEP reconciliation filing, and a lower effective tax rate.

Those earnings increases were partially offset by higher depreciation expense, higher interest expense, and higher property tax expense.

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.

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 impairment charge and transaction costs associated with the expected sale, water distribution segment earnings increased $11.5 million in 2024, as compared to 2023, due primarily to an after-tax benefit of $11.6 million recorded in 2024 to recognize the impacts of the Aquarion Water Company of Connecticut’s rate case decision from PURA.

The impacts of PURA’s rate case decision on March 15, 2023 were recorded beginning in March 2024 as a result of the State of Connecticut Superior Court’s decision on the rate case appeal on March 25, 2024.

The impacts primarily include a reduction to depreciation expense to reflect lower depreciation rates ordered by PURA in its final decision, partially offset by lower authorized revenues.

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 $1.37 billion in 2024, as compared to 2023, due primarily to the loss on the sale of Eversource parent’s offshore wind investments in 2024, which resulted in an after-tax charge of $524.0 million, as compared to an impairment charge on these investments in 2023 of $1.95 billion.

Results for 2023 also include a loss on the disposition of land that was initially acquired to construct the Northern Pass Transmission project and was subsequently abandoned and other charges recorded of $6.9 million.

Excluding these charges, Eversource parent and other companies earnings decreased by $66.3 million due primarily to higher interest expense and the absence of a benefit in 2023 from the liquidation of Eversource parent’s equity method investment in a renewable energy fund, partially offset by the absence of a charitable contribution made in 2023 with a portion of the proceeds from the liquidation, and a lower effective tax rate.

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

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.

Sources and Uses of Cash:

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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 plus a return on the equity and debt used to finance the investments.

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 $1.64 billion, $291.7 million and $112.0 million at Eversource, NSTAR Electric and PSNH, respectively, as of December 31, 2024.

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, 2024, $1.40 billion of Eversource's long-term debt, including $600.0 million at Eversource parent, $400.0 million at CL&P and $250.0 million at NSTAR Electric, matures within the next 12 months.

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.

Eversource is currently in the process of selling its Aquarion water distribution business.

For information regarding the pending sale and use of proceeds, see "Business Development and Capital Expenditures - Pending Sale of Aquarion" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations .

Cash totaled $135.4 million as of December 31, 2025, compared with $26.7 million as of December 31, 2024.

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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, which terminates on October 11, 2029.

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 re volving 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, which terminates on October 11, 2029, that serves to backstop NSTAR Electric's $650 million commercial paper program.

NSTAR Electric is also a party to a five-year $650 million revolving credit facility.

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:

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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.

As a result of the CL&P long-term debt issuance in January 2024, $207.3 million of commercial paper borrowings under the Eversource parent commercial paper program were reclassified to Long-Term Debt on Eversource parent’s balance sheet as of December 31, 2023.

Intercompany Borrowings:

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Intercompany loans from Eversource parent to its subsidiaries are eliminated in consolidation on Eversource's balance sheets.

As of December 31, 2024, there were intercompany loans from Eversource parent to CL&P of $280.0 million and to PSNH of $131.1 million.

As of December 31, 2023, there were intercompany loans from Eversource parent to CL&P of $457.0 million and to PSNH of $233.0 million.

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.

As a result of the CL&P long-term debt issuance in January 2024, $207.3 million of CL&P’s intercompany borrowings were reclassified to Long-Term Debt on CL&P’s balance sheet as of December 31, 2023.

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 July 24, 2024, PURA approved CL&P’s request for authorization to issue up to $1.00 billion in long-term debt through December 31, 2025.

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 January 28, 2025, Yankee Gas submitted an application to PURA requesting authorization to issue up to $360 million in long-term debt through December 31, 2026.

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:

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CL&P 2025 Series A First Mortgage Bonds 4.95 % 400.0 January 2025 January 2030 Repaid short-term debt, paid capital expenditures and working capital

CL&P Series B First Mortgage Bonds 4.95 % 300.0 August 2024 August 2034 Repaid Series D Bonds, repaid short-term debt, and working capital

CL&P Series D First Mortgage Bonds 7.875 % (139.8) October 2024 October 2024 Paid at maturity

CL&P 2025 Series A First Mortgage Bonds 4.95 % 400.0 January 2025 January 2030 Repaid short-term debt, paid capital expenditures and working capital

NSTAR Electric Debentures 5.40 % 600.0 May 2024 June 2034 Repaid short-term debt, paid capital expenditures and working capital

PSNH Series X First Mortgage Bonds 5.35 % 300.0 April 2024 October 2033 Repaid short-term debt, paid capital expenditures and working capital

Eversource Parent Series DD Senior Notes 5.00 % 350.0 January 2024 January 2027 Repaid short-term debt

Eversource Parent Series EE Senior Notes 5.50 % 650.0 January 2024 January 2034 Repaid short-term debt

Eversource Parent Series FF Senior Notes 5.85 % 700.0 April 2024 April 2031 Repaid Series X Senior Notes and Aquarion’s 2014 Senior Notes at maturity and short-term debt

Eversource Parent Series GG Senior Notes 5.95 % 700.0 April 2024 July 2034 Repaid Series X Senior Notes and Aquarion’s 2014 Senior Notes at maturity and short-term debt

Eversource Parent Series X Senior Notes 4.20 % (900.0) June 2024 June 2024 Paid at maturity

Eversource Parent Series L Senior Notes 2.90 % (450.0) October 2024 October 2024 Paid at maturity

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 working capital

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 working capital

NSTAR Electric Debentures 5.20 % 300.0 October 2025 March 2035 Repaid short-term debt, paid capital expenditures and 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 expenditures and 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

NSTAR Gas Series W First Mortgage Bonds 5.29 % 160.0 June 2024 June 2029 Repaid short-term debt, paid capital expenditures and general corporate purposes

NSTAR Gas Series X First Mortgage Bonds 5.48 % 40.0 June 2024 June 2034 Repaid short-term debt, paid capital expenditures and general corporate purposes

Yankee Gas Series W First Mortgage Bonds 5.50 % 90.0 July 2024 July 2029 Repaid short-term debt, paid capital expenditures, working capital and repaid Series P bonds at maturity

Yankee Gas Series X First Mortgage Bonds 5.74 % 90.0 July 2024 July 2034 Repaid short-term debt, paid capital expenditures, working capital and repaid Series P bonds at maturity

Yankee Gas Series P First Mortgage Bonds 2.23 % (100.0) October 2024 October 2024 Paid at maturity

EGMA Series E First Mortgage Bonds 5.17 % 100.0 October 2024 November 2034 Refinanced existing indebtedness, paid capital expenditures and general corporate purposes

Aquarion Senior Notes 4.00 % (360.0) August 2024 August 2024 Paid at maturity

Aquarion Water Company of Connecticut Senior Notes 5.57 % 70.0 August 2024 September 2034 Repaid short-term debt, paid capital expenditures and general corporate purposes

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.

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 expenditures and working capital

NSTAR Gas Series Z First Mortgage Bonds 5.30 % 20.0 June 2025 June 2035 Repaid short-term debt, paid capital expenditures and 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 working capital

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 working capital

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 expenditures and working capital

Rate Reduction Bonds:

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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.

Common Share Issuances:

Eversource had 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 “at-the-market” (ATM) equity offering program.

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.

In 2023, no shares were issued under this agreement.

Eversource completed the program in October 2024.

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 the timing of cash payments made on our accounts payable, a $108.8 million increase due to income tax refunds received in 2024 as compared to income tax payments made in 2023, an improvement in regulatory under-recoveries driven primarily by the timing of collections for the CL&P non-bypassable FMCC and other regulatory tracking mechanisms partially offset by the unfavorable impact in the timing of collections for energy supply costs, a $20.7 million decrease in cost of removal expenditures, a $12.4 million decrease in cash payments to vendors for storm costs, and the timing of other working capital items.

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.

These favorable impacts were partially offset by the timing of cash collections on our accounts receivable.

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 2023, we paid cash dividends of $919.0 million and issued non-cash dividends of $23.4 million in the form of treasury shares, totaling dividends of $942.4 million, or $2.70 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.

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Current Outlook Current Outlook Current Outlook

Eversource Parent BBB+ Stable Baa2 Negative BBB Stable

CL&P A- Stable A3 Negative A- Stable

NSTAR Electric A- Stable A2 Negative A- Stable

PSNH A- Stable A3 Stable A- Stable

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

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:

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Current Outlook Current Outlook Current Outlook

Eversource Parent BBB Stable Baa2 Negative BBB Stable

CL&P A Stable A1 Negative A+ Stable

NSTAR Electric A- Stable A2 Negative A Stable

PSNH A Stable A1 Stable A+ Stable

In June 2024, Moody’s revised the outlook from stable to negative for CL&P citing a weaker financial profile and a challenging Connecticut regulatory environment.

In December 2024, S&P downgraded the ratings for Eversource parent and its subsidiaries primarily due to S&P's negative assessment of the Connecticut regulatory construct for Eversource’s Connecticut utilities.

These credit ratings and outlook changes reflect higher regulatory risk in Connecticut with the regulatory construct and adverse regulatory developments, including recent rate orders and the passage of Senate Bill 7, negatively impacting the credit quality of Eversource and its subsidiaries.

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

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The Massachusetts Energy Facilities Siting Board approved the project on June 28, 2024.

Additional required environmental permits are expected to be approved by the end of 2025, as well as a license from the MA DEP expected to be approved by the end of the second quarter of 2026.

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.

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The remaining transmission and distribution circuits will be placed in-service throughout 2030 and into 2031.

The total project cost is approximately $1.84 billion, with $1.38 billion allocated for transmission and $460 million for distribution.

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.

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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.

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Load growth and other reflects growth in our service territory, including improvements of acquisitions, installation of new services, and interconnections of systems.

Pending Sale of Aquarion:

In early 2024, Eversource initiated an exploratory assessment of the potential sale of the Aquarion water distribution business.

In December 2024, final bids were received, and 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.

The sale is subject to approval by PURA, DPU and the NHPUC, as well as other approvals pursuant to the Hart-Scott-Rodino Antitrust Improvements Act as well as other customary closing conditions.

The sale is expected to close in late 2025.

Eversource plans to use the net proceeds from the pending sale to pay down parent company debt.

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.

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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.

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.

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:

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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.

The projected capital expenditures reflect a reduction in planned capital expenditures for Connecticut’s electric and natural gas distribution businesses due to regulatory policies in Connecticut that discourage investment, including ensuring the timely recovery of costs and the ability to earn a fair return.

The continuing pattern of adverse regulatory outcomes for Connecticut utilities and associated credit downgrades from our credit rating agencies necessitated a reduction to Connecticut’s electric and natural gas distribution projected capital expenditures.

These capital reductions do not impact Eversource’s commitment to safety, reliability, or critical staffing structure.

Projected capital expenditures for the water distribution business of $130 million are expected until the time of sale in late 2025 and have been factored into the water business impairment recorded as of December 31, 2024.

Offshore Wind Business:

Eversource’s previous offshore wind business included 50 percent ownership interests in each of North East Offshore and South Fork Class B Member, LLC.

During 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 through a 100 percent ownership in South Fork Wind Holdings, LLC Class A interests.

On May 25, 2023, Eversource announced that it had completed a strategic review of its offshore wind investments and determined that it would pursue the sale of its offshore wind investments.

On September 7, 2023, Eversource completed the sale of its 50 percent interest in an uncommitted lease area consisting of approximately 175,000 developable acres located 25 miles off the south coast of Massachusetts to Ørsted for $625 million in an all-cash transaction.

In September of 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.

As of December 31, 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 from 2025 to 2027.

As of December 31, 2024, the tax equity interest in South Fork Wind totaled $22.2 million.

On January 24, 2024, Eversource entered into an agreement with Ørsted to sell Eversource’s 50 percent share of Sunrise Wind, subject to certain conditions and regulatory approvals.

On April 18, 2024, Eversource and Ørsted executed an equity and asset purchase agreement and on July 9, 2024, Eversource completed the sale of its 50 percent ownership share of Sunrise Wind to Ørsted.

In accordance with the equity and asset purchase agreement and after adjustment for a reduction in capital spending compared to forecasted amounts, adjusted proceeds totaled $152 million.

Ørsted paid Eversource $118 million at the closing of the sale transaction, which was used to repay parent company debt.

Remaining proceeds of $34 million will be paid after onshore construction is completed and certain other construction milestones are achieved.

The remaining expected proceeds have been recorded in Other Long-Term Assets on Eversource’s balance sheet as of December 31, 2024.

Eversource recorded a pre-tax gain on the sale of Sunrise Wind of $377 million in 2024.

With completion of the sale, Eversource does not have any ongoing financial obligations associated with Sunrise Wind.

On February 13, 2024, Eversource executed an agreement to sell its 50 percent interests in the South Fork Wind and Revolution Wind projects to Global Infrastructure Partners (GIP) for an initial gross purchase price of approximately $1.1 billion.

The initial purchase price was subject to adjustment based on, among other things, the progress, timing and the construction cost of Revolution Wind, including changes in actual versus forecasted capital spending between signing the agreement and closing of the transaction.

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.

Adjusted gross proceeds from the sale were approximately $375 million lower than the previously estimated purchase price.

This reduction reflects approximately $150 million resulting from lower capital spending between signing the agreement and closing, and approximately $225 million related to the final terms of the sale transaction, primarily due to the delay of the commercial operations date of Revolution Wind.

Proceeds from the transaction were used to repay parent company debt.

As part of the Revolution Wind and South Fork Wind sale, Eversource and GIP agreed to make certain post-closing purchase price adjustment payments, which could further impact the final purchase price.

The post-closing purchase price adjustment payments include cost sharing obligations that require Eversource to share equally with GIP 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.

Post-closing purchase price adjustment payments will be made following the commercial operation date of Revolution Wind.

South Fork Wind has achieved commercial operation, and Eversource is in the process of finalizing the construction cost post-close purchase price adjustment payment related to this project, which is not expected to be material.

Upon the completion of both sale transactions in 2024, the total proceeds were compared to the carrying value of the investments, including an estimate of liability for post-closing adjustment payments to GIP, and Eversource recognized an aggregate, net after-tax loss on the sales of its offshore wind investments of $524 million.

The aggregate, net after-tax loss is comprised of (1) the lower proceeds related to final terms of the sale transaction to GIP of approximately $225 million related to non-construction costs for the Revolution Wind and South Fork Wind projects, primarily due to a purchase price reduction of $150 million resulting from the delay of the commercial operations date of Revolution Wind, (2) recently identified forecasted construction costs as a result of a delay in the anticipated commercial operation date related to Revolution Wind of approximately $350 million, which includes an estimate for the anticipated post-closing adjustment to GIP related to Eversource’s expected cost overrun sharing obligation, and (3) approximately $326 million, which includes an estimate for the anticipated post-closing adjustment related to Eversource’s expected obligations to GIP as a result of final economics of the Revolution Wind and South Fork Wind projects and other future costs, as well as a net $60 million increase in income tax expense including an increase in the valuation allowance for unused capital losses.

These losses were partially offset by the $377 million gain on the sale of Sunrise Wind.

Upon sale, Eversource recorded a contingent liability of $365 million, reflecting its estimate of the future obligations under the GIP sale terms, which include the expected cost overrun sharing obligation, expected obligation to maintain GIP’s internal rate of return, and obligation for other future costs.

The majority of this liability is expected to be settled upon the completion of the Revolution Wind project.

The long-term portion of the liability of $350 million is recorded in Other Long-Term Liabilities, and $15 million is recorded in Other Current Liabilities on Eversource’s balance sheet as of December 31, 2024.

Contingencies are evaluated using the best information available at the time the financial statements are prepared, and this assessment involves judgments and assumptions about future events.

Factors that could increase the post-closing adjustment payments owed to GIP include the ultimate cost of construction and extent of cost overruns for Revolution Wind, delays in construction, which would impact the economics associated with the purchase price adjustment, and Revolution Wind’s eligibility for federal investment tax credits at a lower value than assumed and included in the purchase price.

The purchase price included the sales value related to a 40 percent level of federal investment tax credits, 10 percent of which is the energy community investment tax credit (ITC) adder included in the Inflation Reduction Act of approximately $170 million related to Revolution Wind.

Although management believes the ITC adder value is realizable, there is some uncertainty at this time as to whether those ITC adders can be achieved, and management continues to evaluate the project’s qualifications and to monitor guidance issued by the United States Treasury Department.

A change in the expected value or qualification of ITC adders could result in a significant loss in a future period.

New information or future developments that arise as construction progresses and as cost estimates are reviewed and revised will require a reassessment of the estimated liability for the post-closing adjustment payments.

The Company is currently aware that construction of the offshore foundations, offshore substation and turbine tower installations could result in increased cost overruns in the future.

Only preliminary construction cost projections are available for these cost overruns, and there is insufficient updated information at this point in order for Eversource to change its estimate with reasonably estimable information.

Eversource will continue to assess the potential exposure and adjust the liability as needed.

It is expected that updated costs estimates will become available in the first half of 2025, and adverse changes in facts and circumstances could result in additional losses that could be material.

The Company believes it is reasonably possible that there is an additional loss in excess of the liability recorded, but management cannot reasonably estimate a range of loss beyond the $365 million recorded at this time.

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.

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.

Eversource has entered into separate construction management agreements to manage Sunrise Wind’s and Revolution Wind’s onshore electric substation construction through completion.

In this role, Eversource will be solely a service provider to Sunrise Wind and Revolution Wind.

2023 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.

During 2023, in connection with the process to divest its offshore wind business, Eversource identified indicators for impairment in both the second and fourth quarters of 2023.

In each impairment assessment, 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.

The completion of the strategic review in the second quarter of 2023 resulted in Eversource recording a pre-tax other-than-temporary impairment charge of $401 million ($331 million after-tax) to reflect the investment at estimated fair value based on the expected sales price at that time.

This established a new cost basis in the investments.

Negative developments in the fourth quarter of 2023, including a lower expected sales price, additional projected construction cost increases, and the October 2023 OREC pricing denial for Sunrise Wind, resulted in Eversource conducting an impairment evaluation and recognizing an additional pre-tax other-than-temporary impairment charge of $1.77 billion ($1.62 billion after-tax) and establishing a new cost basis in the investments as of December 31, 2023.

The Eversource statement of income for the year ended 2023 reflects a total pre-tax other-than-temporary impairment charge of $2.17 billion ($1.95 billion after-tax) in its offshore wind investments.

The impairment charges were non-cash charges and did not impact Eversource’s cash position at the time of the impairment.

Eversource’s offshore wind investments did not meet the criteria to qualify for presentation as a discontinued operation.

The 2023 impairment evaluations involved judgments in developing the estimates and timing of the future cash flows arising from the expected sales price of Eversource’s 50 percent interest in the wind projects, including expected sales value from investment tax credit adder amounts, less estimated costs to sell, and uncertainties related to the Sunrise Wind re-bid process in New York’s offshore wind solicitation in 2024.

Additional assumptions in the fourth quarter 2023 assessment included revised projected construction costs and estimated project cost overruns, management’s assumption that the Sunrise Wind project would ultimately be abandoned, estimated termination costs, salvage values of Sunrise Wind assets, and the value of the tax equity ownership interest.

The assumptions used in the discounted cash flow analyses were subject to inherent uncertainties and subjectivity.

All significant inputs into the impairment evaluations were Level 3 fair value measurements.

A summary of the significant estimates and assumptions included in the 2023 impairment charges is as follows:

Second Quarter 2023

Fourth Quarter 2023

(Millions of Dollars)

Lower expected sales proceeds across all three wind projects

$ 401 $ 525 $ 926

Expected cost overruns not recovered in the sales price

Loss of sales value from the sale price offered by GIP, including loss of ITC adders value, cancellation costs and other impacts assuming Sunrise Wind project is abandoned

Impairment Charges, pre-tax 401 1,766 2,167

Tax Benefit (70) (144) (214)

Impairment Charges, after-tax $ 331 $ 1,622 1,953

A summary of the carrying value by investee and by project as of December 31, 2023 is as follows:

Investments Expected to be Disposed of Investment to be Held

North East Offshore South Fork Class B Member, LLC

South Fork Wind Holdings, LLC Class A

Total Offshore Wind Investments

(Millions of Dollars) Sunrise Wind Revolution Wind

Carrying Value as of December 31, 2023, before

Impairment Charge $ 699 $ 799 $ 299 $ 485 $ 2,282

Fourth Quarter 2023 Impairment Charge (1,218) (544) — (4) (1,766)

Carrying Value as of December 31, 2023 $ (519) $ 255 $ 299 $ 481 $ 516

During 2024, Eversource sold its interest in the North East Offshore and South Fork Class B, Member LLC equity method investments and recognized an aggregate, net after-tax loss on the sale of its offshore wind investments of $524 million.

Capital contributions in the offshore wind investments, 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 sale of the investments in 2024, and proceeds received from the 2023 sale of the unused lease area and from 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.

FERC Regulatory Matters

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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, for the NETOs, which FERC concludes are of average financial risk, the preliminary just and reasonable base ROE is 10.41 percent and the preliminary incentive cap on total ROE is 13.08 percent.

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.

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569-A and reaffirmed the methodology previously adopted in Opinion No.

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.

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.

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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 was 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.

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.

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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.

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PURA is conducting the proceeding in two phases.

On January 25, 2023, PURA staff issued a proposal outlining a suggested portfolio of PBR elements for further exploration and potential implementation in the second phase of the proceeding.

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 with final decisions expected in 2025.

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 outlines 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 which concentrates on performance mechanisms in a PBR framework.

The proposal suggests the development of performance incentive mechanisms, reported metrics and scorecards.

These straw proposals are not authoritative and additional technical sessions, hearings and testimony will continue prior to a final decision, which will not be applied until the time of CL&P’s next distribution rate case.

PURA is expected to issue updated straw proposals in the first and second reopener dockets in the first quarter of 2025.

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.

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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.

PURA established a partial procedural schedule with hearings scheduled in the third quarter of 2025.

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.

Although we cannot predict the ultimate outcome of this matter, we continue to believe these deferred storm restoration costs were prudently incurred and are probable of recovery.

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 April 17, 2024, PURA issued an interim decision in CL&P’s Rate Adjustment Mechanisms (RAM) filing and approved rates for six RAM components, with rates effective July 1, 2024 through April 30, 2025.

The rate approvals include the recovery of NBFMCC and SBC net underrecoveries as of December 31, 2023 of $264.9 million and $86.2 million, respectively, and the recovery of expected net costs of $388.5 million for the NBFMCC and $254.4 million for the SBC for the period July 1, 2024 through April 30, 2025.

The NBFMCC rate adjustment is primarily driven by long-term nuclear power purchase agreements required by state policy (Millstone and Seabrook) and the SBC rate adjustment is primarily driven by costs associated with accounts receivable hardship customer protection and the new low-income discount rate effective December 2023.

On August 14, 2024, PURA issued a final decision that approved a further adjustment to the NBFMCC rate to include the recovery of incurred and deferred electric vehicle program costs from 2021 through May 31, 2024 of $44.4 million and expected electric vehicle program costs from June 1, 2024 through December 31, 2024 of $24.3 million.

The $44.4 million, plus $5.4 million in carrying costs, will be recovered over a 20-month period of September 1, 2024 through April 30, 2026, and the $24.3 million will be recovered over an eight-month period of September 1, 2024 through April 30, 2025.

In addition, PURA approved an incremental $3.5 million of 2024 Innovative Energy Solutions program costs and $1.5 million of Connecticut Green Bank program costs over an eight-month period of September 1, 2024 through April 30, 2025.

These amounts are included in the “Public Benefits” portion of the customer bills in Connecticut.

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, which CL&P estimated at $766.4 million for capital costs and operating expenses.

In CL&P’s view, the final decision does not provide a reasonable path for cost recovery and delays implementation by at least a year during the pendency of the cost recovery proceeding.

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.

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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 by May 14, 2024, and rebuttal testimony by May 29, 2024.

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.

Written exceptions to the proposed final decision were filed on October 31, 2024, and oral arguments were presented on November 7, 2024.

CL&P’s written exceptions focused on three main aspects of the proposed decision, which include (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 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 January 3, 2025, PURA stated it will evaluate the merits of CL&P’s petition for reconsideration.

Under state law, PURA is expected to issue its decision within 90 days of January 3, 2025.

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’s rate application requested approval of a distribution rate increase of $209 million, which included a base distribution rate increase of $274 million, partially offset by a reduction of $65 million in the combined Gas System Improvements and System Expansion Reconciliation rates.

In addition, Yankee Gas requested approval to implement a rate credit of $37.4 million to offset the PGA rate for non-firm margin credits over one year beginning November 1, 2025.

As part of the rate case, Yankee Gas proposed to implement a multi-year performance-based rate making plan with a four-year initial term from November 1, 2025 to October 31, 2029 that would adjust rates annually and includes performance metrics.

A final decision by PURA is expected in October 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.

Aquarion Water Company of Connecticut Distribution 2022 Rate Case:

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The decision allows an authorized regulatory ROE of 8.70 percent.

On March 30, 2023, AWC-CT filed an appeal on the decision and requested a stay of the decision with the State of Connecticut Superior Court.

On April 5, 2023, the Court temporarily granted AWC-CT’s request to stay and on May 25, 2023 granted a permanent stay of certain orders affecting base rates, which would keep existing rates in place until the appeal is completed.

The stay included the condition that AWC-CT place any revenue received from customers above the rates and amounts authorized in the March 15, 2023 decision in a separate, interest bearing account until further order.

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 March 28, 2024, AWC-CT filed an appeal of the Connecticut Superior Court decision to the Connecticut Appellate Court, and that appeal was subsequently transferred to the Connecticut Supreme Court for review.

A ruling on the appeal is pending.

On April 18, 2024, PURA initiated a docket to address the matters on remand.

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On September 13, 2024, AWC-CT filed an appeal of PURA’s July 31, 2024 final decision to the Connecticut Superior Court.

A ruling on the appeal is pending.

As a result of the State of Connecticut Superior Court’s March 2024 decision on the appeal, AWC-CT recorded the impacts of the PURA rate case decision from the effective date of the order on March 15, 2023 through December 31, 2024.

The impacts primarily include a reduction to depreciation expense to reflect lower depreciation rates ordered by PURA in its final decision, partially offset by lower authorized revenues.

These adjustments resulted in an after-tax benefit of $11.6 million in 2024.

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:

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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 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 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 CIP Filing:

On December 30, 2022, the DPU approved a provisional system planning tariff for the recovery of costs associated with a capital investment project (CIP) proposal submitted by NSTAR Electric for one of six geographic study areas in its service territory in accordance with DPU’s directives.

The DPU established a new, provisional framework for planning and funding upgrades to the electric power system to foster development and interconnection of distributed energy facilities.

Under the DPU program, NSTAR Electric has filed infrastructure upgrade proposals to be built within a four-year construction timeframe that allocate the costs of interconnection upgrades between the interconnecting distributed generation facility and distribution customers based on a technical analysis of capacity benefits.

Payments made by the distributed generation facility will be applied against the total capital investment made by NSTAR Electric and NSTAR Electric will earn a return on the net investment.

The amount allocated to distribution customers will be recovered through a reconciling mechanism, the Provisional System Planning Tariff.

The DPU approved the first of these provisional system planning projects, the Marion-Fairhaven group study area, which will enable 141 MW of distributed energy resources (DER) to be interconnected at a total estimated cost of $120 million.

Of the total $120 million, $66 million will be allocated to distribution customers, once the enabled distributed energy facilities capacity is fully subscribed by distributed energy facilities interconnecting customers.

Additionally, NSTAR Electric will proceed with construction of approximately $54 million of transmission upgrades necessary to improve local reliability and integrate distribution energy resources in the Marion-Fairhaven area and recover the amount through local transmission rates.

On June 4, 2024, the DPU approved four of the remaining five CIPs that were originally submitted by NSTAR Electric.

These included the Plainfield-Blandford CIP, which will enable 40 MW of DER to be interconnected at a total estimated distribution investment of $37 million, the Dartmouth-Westport CIP which enables 60 MW of DER for a total distribution investment of $58 million, the Plymouth CIP which enables 380 MW of DER for a total distribution investment of $152 million and the Cape Cod CIP which enables 296 MW of DER for a total distribution investment of $170 million.

Of the total $417 million for these four recently approved CIPs, $183 million will be allocated to distribution customers, once the enabled distributed energy facilities capacity is fully subscribed by distributed energy facilities interconnecting customers.

Additionally, NSTAR Electric will proceed with construction of approximately $64 million of transmission upgrades necessary to improve local reliability and integrate distribution energy resources in the four CIP areas and recover the amount through local transmission rates.

On January 27, 2025, NSTAR Electric filed a petition with the DPU to withdraw the sixth CIP project, Freetown, that was originally submitted.

NSTAR Electric’s Electric Sector Modernization Plan (ESMP) Filing :

On January 29, 2024, in accordance with Massachusetts state law, NSTAR Electric filed its ESMP with the DPU.

The law required each electric distribution company to develop and file a comprehensive distribution system plan to proactively upgrade the distribution system (and, where applicable, the associated transmission system) to:

(i) improve grid reliability, communications and resiliency;

(ii) enable increased, timely adoption of renewable energy and distributed energy resources;

(iii) promote energy storage and electrification technologies necessary to decarbonize the environment and economy;

(iv) prepare for future climate-driven impacts on the transmission and distribution systems;

(v) accommodate increased transportation electrification, increased building electrification and other potential future demands on distribution and, where applicable, the transmission system;

and (vi) minimize or mitigate impacts on Massachusetts ratepayers, thereby helping the state realize its statewide greenhouse gas emissions limits and sublimits under the law.

NSTAR Electric’s plan meets these requirements by providing a comprehensive view of all the investments required to build a safer, more reliable, more resilient electric distribution system to enable an affordable, equitable clean energy transition taking into account the needs of environmental justice communities.

For the five-year period from 2025 through 2029, the proposed incremental distribution capital investment is $608 million and the incremental distribution expense amount is $211 million.

On August 29, 2024, the DPU approved the overall ESMP for a five-year period commencing July 1, 2025.

On November 21, 2024, the DPU opened a second phase of the proceeding to consider a short-term ESMP-focused cost recovery mechanism and metrics.

In issuing the notice of proceeding, the DPU limited the review of investment in this docket and excluded NSTAR Electric’s ESMP proposals regarding the EV Phase II extension, low and moderate income solar and the new CIPs.

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.

NSTAR Electric filed its proposed tariff and testimony on December 18, 2024, and is currently in the discovery process, which will be followed by hearings and briefing with completion of the proceeding and final orders expected prior to the start of the plan in July 2025.

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 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.

EGMA Distribution Rates:

On November 4, 2024, EGMA submitted a revised filing for its first rate base reset for rates to be 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 is 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 will be 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 is $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 will be increased effective November 1, 2025 to incorporate the $62.2 million remaining revenue requirement.

On November 7, 2024, the DPU approved this filing.

Future of Gas Docket:

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 issued an order for this docket.

The DPU will 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.

The DPU intends to put policies and structures in place that would protect customers as Massachusetts works to decarbonize the building sector, which may involve subsequent dockets and regulatory proceedings and potentially recasting the role of LDCs in Massachusetts.

The DPU preserved customer choice for energy needs and encouraged further development of decarbonized alternatives, such as the networked geothermal systems that NSTAR Gas is piloting in Framingham, Massachusetts.

On December 29, 2023, Eversource and other LDCs sought formal clarity from the DPU to fully understand the resulting impact to their natural gas businesses and the associated timing of any impacts.

On April 2, 2024, the DPU issued an order responding to the request for clarification indicating that the LDCs shall implement the inclusion of a Non-Gas Pipeline Alternatives (NPA) analysis on all project authorizations effective immediately.

Existing NPA analysis processes will be used until such time a formal stakeholder-based NPA analysis framework is established and approved by the DPU.

Eversource, along with the other LDCs, have engaged a consultant to inform the development of the required NPA framework by conducting a stakeholder engagement process as mandated by the order.

Another component of the order is the submission of climate compliance plans every five years beginning April 1, 2025.

The climate compliance plan filings will 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.

The DPU also indicated that NSTAR Gas and EGMA are not required to provide climate compliance performance metrics in the next PBR filing, however would be expected to propose metrics at the latest in the next base distribution rate proceeding.

GHG emissions reporting was not changed from the order, however, effective November of 2024, reporting requirements have changed per the MA DEP and these requirements implement registration and GHG emissions reporting requirements for companies selling and distributing heating fuels to homes and businesses in Massachusetts, including suppliers of natural gas, fuel oil, and propane, and implement a reporting requirement for fuel storage facilities.

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.

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.

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:

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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.

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, and proposed to take effect August 1, 2025.

The temporary rates are subject to reconciliation based on the outcome of the permanent rate case back to the date when temporary rates took effect.

The permanent rate increase request includes $247 million in unrecovered storm costs to be recovered over a five-year period.

As part of the rate case, PSNH proposed to implement a performance-based rate making plan that would adjust rates annually over a four-year term, with a commitment to not file another rate case for at least four years.

The plan includes a revenue-cap formula adjusted for inflation, a supplemental capital adjustment formula to support PSNH’s planned capital infrastructure improvements, an exogenous events recovery mechanism, performance metrics and an earnings sharing mechanism, among others.

If the NHPUC approves the performance-based rate making plan as proposed, the previously established RRA and PPAM rate reconciling mechanisms and lost base revenues will be eliminated.

The NHPUC is permitted up to twelve months to investigate the proposed rates and issue a final order.

A decision by the NHPUC on permanent rates is expected by August 1, 2025.

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.

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

On April 10, 2024, the U.S.

Environmental Protection Agency announced the final regulation setting drinking water standards for six per- and polyfluoroalkyl substances (PFAS) compounds.

The regulation requires compliance under a phased approach in which systems will need to complete the initial monitoring requirements for each PFAS within three years, and when warranted, take steps to assure compliance within five years.

Beginning in 2027, systems will need to report results of initial monitoring and regular monitoring and issue public notifications for any monitoring and reporting violations.

Starting in 2029, systems must comply with all maximum contaminant levels (MCL) and provide public notification for MCL violations.

Eversource is currently evaluating the impacts to comply with the regulation for its water business.

On July 4, 2025, An Act to Provide for Reconciliation Pursuant to Title II of H.

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.

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.

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

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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, plus a return on investment.

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.

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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 were prudently incurred, meet the criteria for cost recovery and are probable of recovery.

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.

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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, 2024, the discount rates used to determine the funded status 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.

As of December 31, 2023, the discount rates used were within a range of 4.9 percent to 5.0 percent for the Pension and SERP Plans, and 5.0 percent to 5.2 percent for the PBOP Plans.

The increase in the discount rates used to calculate the funded status resulted in a decrease to the Pension and SERP Plans’ projected benefit obligation of $332.9 million and a decrease to the PBOP Plans' projected benefit obligation of $39.8 million as of December 31, 2024.

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.

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The Eversource Service PBOP Plan is not subject to health care cost trends.

As of December 31, 2024, for the Aquarion PBOP Plan, the health care trend rate used to determine the funded status for pre-65 retirees is 7.5 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.

Cash Balance Interest Crediting Rate Assumption :

The Cash Balance Pension Plan is a new, additional obligation of the existing Pension Plan and the liability will begin to accrue benefits upon the effective date of January 1, 2025.

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.

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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 eleven years.

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.

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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, 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, therefore the change in their pension expense does not 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.

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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 2024 to 2025 is driven primarily by lower amortization of actuarial losses, partially offset by an increase in the service cost component, both of which were due in part to the impact of the new cash balance pension plan.

The increase in PBOP income from 2024 to 2025 is driven primarily by favorable expected return on assets due to a higher asset balance.

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 in an amount at least equal to the amount that will satisfy all federal funding requirements.

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 through tax deductible contributions to external trusts.

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.

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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, and $451 million to Natural Gas Distribution.

Goodwill allocated to Water Distribution of $663 million is classified as held for sale.

$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.

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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 performed the annual impairment assessment of goodwill as of October 1, 2024 for the Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution reporting units.

Our qualitative assessment included an 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.

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.

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.

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.

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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.

We did not identify any events or conditions that make it more likely than not that an impairment may have occurred at our other reporting units.

For these remaining reporting units, we believe that the fair value was substantially in excess of 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.

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:

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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 review 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.

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.

Equity Method Investments:

Investments in affiliates where we have the ability to exercise significant influence, but not control, over an investee are initially recognized as an equity method investment at cost.

Any differences between the cost of an investment and the amount of underlying equity in net assets of an investee are considered basis differences and are determined based upon the estimated fair values of the investee's identifiable assets and liabilities.

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.

During 2023, in connection with the process to divest its offshore wind business, Eversource identified indicators for impairment in both the second and fourth quarters of 2023.

The impairment evaluations involved judgments in developing the estimates and timing of future cash flows, including key judgments in determining the most likely outcome of the projects, the likelihood of realization of investment tax credit adders, and the likelihood of future spending amounts and cost overruns, as well as potential cancellation costs and salvage values of Sunrise Wind assets.

The assumptions used in the discounted cash flow analyses were subject to inherent uncertainties and subjectivity.

The use of different assumptions, estimates, or judgments with respect to the

estimation of future cash flows could have materially changed the impairment charges.

The impairment charges were non-cash charges and did not impact Eversource’s cash position at the time of the impairment.

Loss Contingencies:

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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 the third quarter of 2024, Eversource recorded a contingent liability of $365 million, reflecting its estimate of the future obligations under the GIP sale terms.

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, and obligation for other future costs, as well as the likelihood of realization of investment tax credit adders that were included in the purchase price.

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.

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.

Adverse changes in facts and circumstances could result in additional losses that could be material to 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:

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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:

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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.

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:

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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.

The fair value measurement guidance was also applied in estimating the fair value of preferred stock, long-term debt and RRBs.

Changes in fair value of our derivative contracts are recorded as Regulatory Assets or Liabilities, as we recover the costs of these contracts in rates charged to customers.

These valuations are sensitive to the prices of energy-related products in future years and assumptions made.

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 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.

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.

Valuations of derivative contracts also reflect our estimates of nonperformance risk, including credit risk.

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Interest Expense 1,243.3 1,111.3 132.0

Losses on Offshore Wind Investments 464.0 2,167.0 (1,703.0)

Losses on Offshore Wind 284.0 464.0 (180.0)

Other Income, Net 378.9 410.5 (31.6)

Income/(Loss) Before Income Tax Expense 1,243.9 (275.0) 1,518.9

Income Before Income Tax Expense 1,840.2 1,243.9 596.3

Income Tax Expense 140.3 424.7 (284.4)

Net Income/(Loss) 819.2 (434.7) 1,253.9

Net Income 1,699.9 819.2 880.7

Net Income Attributable to Noncontrolling Interests 7.5 7.5 —

Net Income/(Loss) Attributable to Common Shareholders $ 811.7 $ (442.2) $ 1,253.9

Net Income Attributable to Common Shareholders $ 1,692.4 $ 811.7 $ 880.7

Operating Revenues

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Sales Volumes (GWh) Percentage

Increase Sales Volumes (MMcf) Percentage

(Decrease) Sales Volumes (MMcf) Percentage

Increase Sales Volumes (MG) Percentage

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Base Distribution Revenues:

• Base electric distribution revenues increased $141.1 million due primarily to a base distribution rate increase at NSTAR Electric effective January 1, 2024 and a temporary base distribution rate increase at PSNH effective August 1, 2024.

• Base natural gas distribution revenues increased $49.2 million due primarily to base distribution rate increases effective November 1, 2024 at EGMA and effective November 1, 2024 and November 1, 2023 at NSTAR Gas.

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.

On December 26, 2023, the DPU approved a $104.9 million increase to NSTAR Electric’s base distribution rates effective January 1, 2024.

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, 2023, the DPU approved a $25.4 million increase to NSTAR Gas’ base distribution rates, of which, $15.5 million was associated with a base rate adjustment and the remainder for a prior period exogenous cost adjustment, for effect on November 1, 2023.

On October 30, 2024, the DPU approved a $12.7 million increase to NSTAR Gas’ base distribution rates effective November 1, 2024.

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.

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).

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:

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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.

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.

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Energy supply procurement $ (128.7) $ 231.7

CL&P NBFMCC 544.9 —

NSTAR Electric net metering 133.1 —

Stranded costs 127.1 —

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)

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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 and lower average supply-related sales volumes.

The decrease in energy supply procurement within natural gas distribution was driven by lower average prices, partially offset by higher average supply-related sales volumes.

The increase in CL&P’s NBFMCC revenues was driven by an increase in the retail Non-Bypassable Federally Mandated Congestion Charge (NBFMCC) rate.

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.

Effective January 1, 2023, CL&P reduced the average NBFMCC rate to a credit of $0.01524 per kWh.

The rate reduction returned to customers the net benefits of higher wholesale market sales received in the ISO-NE market for these energy contracts.

The average NBFMCC rate changed to $0.00000 per kWh effective July 1, 2023 and then to $0.00293 per kWh effective September 1, 2023.

As a result of the April 2024 interim decision in the 2024 CL&P RAM filing, the average NBFMCC rate increased to $0.03906 per kWh effective July 1, 2024.

As a result of the August final decision in the 2024 CL&P RAM filing, the average NBFMCC rate increased to $0.04290 per kWh effective September 1, 2024.

The rate increases primarily resulted from higher net costs associated with power purchase agreements with the Millstone and Seabrook nuclear power plants.

CL&P is required by regulation to purchase electric generation from Millstone and Seabrook under PURA-approved PPAs entered into in 2019.

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 $205.1 million due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure and the impact of the annual rate reconciliation filing with FERC.

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:

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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 higher long-term contractual energy-related costs that are recovered in the non-bypassable component of the FMCC mechanism at CL&P, higher net metering costs and an increase in long-term renewable contract costs at NSTAR Electric, partially offset by a decrease in long-term renewable energy purchase contract costs at PSNH.

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 decreased due primarily to a decrease in the retail cost deferral and lower average prices, partially offset by higher average purchased volumes.

The increase in transmission costs was primarily the result of 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 cost of transmission service compared to estimated amounts billed to 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).

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Employee-related expenses (including labor and benefits) $ 15.3

Uncollectible expense 14.9

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)

General costs (including vendor services in corporate areas, insurance, fees and assessments) 3.8

Storm-related costs (4.5)

Total Base Electric Distribution (Non-Tracked Costs) 42.2

Tracked Electric Costs (Electric Distribution and Electric Transmission) - Increase due primarily to higher transmission expense, increases in grid modernization and pension tracking mechanisms at NSTAR Electric, and higher uncollectible expense 98.0

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 expense s

Total Tracked Electric Costs 59.7

Total Electric Distribution and Electric Transmission 101.9

Natural Gas Distribution:

Base (Non-Tracked Costs) - Decrease due primarily to lower uncollectible expense (14.2)

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 employee compensation costs disallowed from rate base 11.9

Base (Non-Tracked Costs) 60.7

Tracked Costs 3.7

Total Natural Gas Distribution 64.4

Water Distribution 3.8

Eversource Parent and Other Companies - other operations and maintenance 26.8

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)

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Amortization expense also includes the amortization of cert ain costs as those costs are collected in rates.

The variance in Amortization is due primarily to the deferral adjustment of energy-related and other tracked costs at CL&P (included in the non-bypassable component of the FMCC mechanism), NSTAR Electric and PSNH, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs.

The CL&P non-bypassable FMCC retail rate increased in 2024 as compared to 2023, and the higher collections lowered the regulatory under-recovery deferral adjustment, resulting in an increase to amortization expense of $548.5 million.

Amortization expense also increased at NSTAR Electric as a result of an increase in storm costs recovered in rates and increased at PSNH due to the absence of a 2023 benefit related to the establishment of a new regulatory tracking mechanism that allowed for the recovery of previously incurred operating expenses associated with poles acquired from Consolidated Communications on May 1, 2023.

The establishment of the PPAM regulatory asset resulted in a pre-tax benefit of $16.9 million recorded in Amortization expense on the statement of income in 2023.

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 decreased due primarily to the deferral adjustment, partially offset by higher program spending.

Taxes Other Than Income Taxes expense increased due primarily to higher property taxes as a result of higher utility plant balances and higher Connecticut gross earnings taxes.

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.

Interest Expense increased due primarily to an increase in interest on long-term debt as a result of debt issuances ($220.7 million), higher interest on short-term notes payable due to increased borrowings ($16.0 million), an increase in interest expense on regulatory deferrals ($15.8 million), and higher amortization of debt discounts and premiums, net ($4.1 million), partially offset by an increase in capitalized AFUDC related to debt funds and other capitalized interest ($3.2 million), and a decrease in RRB interest expense ($1.4 million).

Losses on Offshore Wind Investments relates to the loss recorded on the 2024 sales of our equity method offshore wind investments and the impairment charge in 2023 resulting from the expected sales of these offshore wind investments.

See "Business Development and Capital Expenditures – Offshore Wind Business" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations for further information.

Other Income, Net increased due primarily to an increase in interest income primarily from regulatory deferrals ($44.0 million), an increase in equity in earnings related to Eversource’s equity method investments ($36.4 million), an increase in capitalized AFUDC related to equity funds ($19.7 million), investment income in 2024 compared to investment losses in 2023 driven by market volatility ($5.5 million) and a gain on the sale of an unregulated water business in 2024 ($4.4 million), partially offset by a decrease related to pension, SERP and PBOP non-service income components ($17.5 million).

The variance in Other Income, Net was also due to the absence in 2024 of a benefit in 2023 from the liquidation of Eversource’s equity method investment in a renewable energy fund in excess of its carrying value, partially offset by a charitable contribution made with a portion of the proceeds from the liquidation in 2023, as well as the absence in 2024 of a loss on the abandonment of land in 2023.

Income Tax Expense increased due primarily to higher pre-tax earnings ($319.0 million), a decrease in amortization of EDIT ($14.5 million), a higher share-based payment tax deficiency ($1.8 million), and an increase in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($28.3 million).

This was partially offset by a decrease in reserves ($9.0 million) primarily related to the loss on sales of Eversource’s offshore wind investments in 2024 compared to the impairment on these investments in 2023, lower state taxes ($49.3 million), and lower return to provision adjustments ($40.3 million).

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)

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)

Total Other Income, Net $ (31.6)

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 –

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Depreciation 432.7 406.5 26.2 446.0 407.7 38.3 168.0 154.1 13.9

Amortization of Regulatory Assets/(Liabilities), Net 104.5 (500.3) 604.8 130.9 16.1 114.8 136.1 (16.3) 152.4

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

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For the Years Ended December 31,

2024 2023 Increase Percentage

2025 2024 Increase/

(Decrease) Percentage Increase/(Decrease)

CL&P 20,351 20,151 200 1.0 %

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Operating Revenues:

Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased $36.2 million at CL&P and $205.4 million at NSTAR Electric and decreased $153.4 million at PSNH in 2024, as compared to 2023.

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 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 $35.8 million due primarily to a temporary base distribution rate increase effective August 1, 2024.

• PSNH's distribution revenues increased $59.9 million due primarily to base distribution rate increases effective August 1, 2024 and August 1, 2025.

Tracked Distribution Revenues:

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Energy supply procurement $ (44.1) $ (93.4) $ 8.8

CL&P NBFMCC 544.9 — —

NSTAR Electric net metering — 133.1 —

Stranded costs 6.6 77.7 42.8

Retail transmission 56.3 135.0 53.9

CL&P NBFMCC 153.3 — —

CL&P System Benefit Charge 94.6 — —

2 unchanged sentences

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, NSTAR Electric and PSNH was driven by lower average prices and lower average supply-related sales volumes.

The increase in CL&P’s NBFMCC revenues was driven by an increase in the retail Non-Bypassable Federally Mandated Congestion Charge (NBFMCC) rate.

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.