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Item 7. Management’s Discussion and Analysis

2025-02-14 compared with 2024-02-14 · 553 added, 522 removed, 640 unchanged (63% 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 the impairment charges for the offshore wind investments, a loss on the disposition of land that was initially acquired to construct the Northern Pass Transmission project and was subsequently abandoned, certain transaction and transition costs, and our earnings and EPS excluding charges at CL&P related to an October 2021 settlement agreement that included credits to customers and funding of various customer assistance initiatives and a 2021 storm performance penalty imposed on CL&P by PURA.

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.

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 impairment charges for the offshore wind investments, the loss on the disposition of land associated with an abandoned project, transaction and transition costs, and the CL&P October 2021 settlement agreement, and the 2021 storm performance penalty imposed on CL&P by PURA are not indicative of our ongoing costs and performance.

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 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 had a loss of $442.2 million, or $1.26 per share, in 2023, compared with earnings of $1.40 billion, or $4.05 per share, in 2022.

Our 2023 results include after-tax impairment charges of $1.95 billion, or $5.58 per share, recorded at Eversource parent to reflect our current estimate of the fair value of the offshore wind projects.

Our 2023 results also include after-tax land abandonment and other charges recorded at Eversource parent of $6.9 million, or $0.02 per share.

Our 2022 results include after-tax transaction and transition costs of $15.0 million, or $0.04 per share.

Excluding the offshore wind impairments and these other charges, our non-GAAP earnings were $1.52 billion, or $4.34 per share, in 2023, compared with $1.42 billion, or $4.09 per share, in 2022.

• We project that we will earn within a 2024 non-GAAP earning guidance range of between $4.50 per share and $4.67 per share, which excludes the impact of the expected sales of our 50 percent interests in three jointly-owned offshore wind projects and related transaction costs.

We also project that our long-term EPS growth rate through 2028 from our regulated utility businesses will be in a 5 to 7 percent range.

• 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 project that we will earn within a 2025 earning guidance range of between $4.67 per share and $4.82 per share.

We also project that our long-term EPS growth rate through 2029 will be in a 5 to 7 percent range, using 2024 non-GAAP EPS of $4.57 per share as the base year.

• Cash flows provided by operating activities totaled $2.16 billion in 2024, compared with $1.65 billion in 2023.

Investments in property, plant and equipment totaled $4.34 billion in 2023 and $3.44 billion in 2022.

• Cash and Cash Equivalents totaled $53.9 million as of December 31, 2023, compared with $374.6 million as of December 31, 2022.

Investments in property, plant and equipment totaled $4.48 billion in 2024, compared with $4.34 billion in 2023.

• Cash totaled $26.7 million as of December 31, 2024, compared with $53.9 million as of December 31, 2023.

Our available borrowing capacity under our commercial paper programs totaled $607.2 million as of December 31, 2024.

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On January 29, 2025, our Board of Trustees approved a common share dividend payment of $0.7525 per share, payable on March 31, 2025 to shareholders of record as of March 4, 2025.

• We project to make capital expenditures of $23.12 billion from 2024 through 2028, of which we expect $9.71 billion to be in our electric distribution segment, $5.44 billion to be in our natural gas distribution segment, $5.77 billion to be in our electric transmission segment, and $1.08 billion to be in our water distribution segment.

• We project to make capital expenditures of $24.17 billion from 2025 through 2029, of which we expect $10.22 billion to be in our electric distribution segment, $6.00 billion to be in our natural gas distribution segment, and $6.81 billion to be in our electric transmission segment.

We also project to invest $1.15 billion in information technology and facilities upgrades and enhancements.

• On February 13, 2024, we initiated an exploratory assessment of monetizing our water distribution business and are exploring the potential sale of the business.

Strategic Developments:

• On February 13, 2024, Eversource announced that it has executed an agreement to sell its existing 50 percent interests in the South Fork Wind and Revolution Wind projects to Global Infrastructure Partners (GIP).

As part of this transaction, Eversource expects to receive approximately $1.1 billion of cash proceeds upon closing, which includes the sales value related to the 10 percent energy community ITC adder of approximately $170 million related to Revolution Wind, and to exit these projects while retaining certain cost sharing obligations for the construction of Revolution Wind.

The purchase price is subject to future post-closing adjustment payments based on, among other things, the progress, timing and expense of construction at each project.

The cost sharing obligations provide that Eversource would share equally with GIP in GIP’s funding obligations for up to approximately $240 million of incremental capital expenditure overruns incurred during the construction phase for the Revolution Wind project, after which GIP’s obligations for any additional capital expenditure overruns would be shared equally by Eversource and Ørsted.

Additionally, Eversource’s financial exposure will be adjusted by certain purchase price adjustments to be made following commercial operation of the Revolution Wind project and closing of South Fork as a result of final project economics, which includes Eversource’s obligation to maintain GIP’s internal rate of return for each project as specified in the agreement.

Eversource currently expects that South Fork Wind will reach full commercial operation prior to closing of the sale with GIP and Eversource does not expect any material cost sharing or other purchase price adjustment payments for South Fork Wind.

Closing of the transaction is currently expected to occur in mid-2024.

• On January 24, 2024, Ørsted signed an agreement with Eversource to acquire Eversource’s 50 percent share of Sunrise Wind.

The sale is subject to the successful selection of Sunrise Wind in the ongoing New York fourth solicitation for offshore wind capacity, signing of an OREC contract with NYSERDA, finalization of sale agreements, receipt of final federal construction permits, and relevant regulatory approvals.

If Sunrise Wind is not successful in the solicitation, then the existing OREC contract for Sunrise Wind will be cancelled according to the state’s requirements, and Eversource and Ørsted’s joint venture for Sunrise Wind will remain in place.

In that scenario, Ørsted and Eversource would then assess their options in determining the best path forward for Sunrise Wind and its assets, which include the BOEM offshore lease area.

• On January 25, 2024, Eversource and Ørsted submitted a new proposal for Sunrise Wind in the New York fourth offshore wind solicitation.

• Four of South Fork Wind’s twelve turbines were installed and placed into service by January 1, 2024, meeting the project commercial operation date requirements under the power purchase agreement with LIPA.

All wind turbines are expected to be installed and placed into service by the end of March 2024.

• 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.

Earnings Overview

Consolidated:

Below is a summary of our earnings/(loss) by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net (Loss)/Income Attributable to Common Shareholders and diluted EPS.

Below is a summary of our earnings/(loss) by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income/(Loss) Attributable to Common Shareholders and diluted EPS.

For the Years Ended December 31,

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(Millions of Dollars, Except Per Share Amounts) Amount Per Share Amount Per Share Amount Per Share

Net (Loss)/Income Attributable to Common Shareholders (GAAP) $ (442.2) $ (1.26) $ 1,404.9 $ 4.05 $ 1,220.5 $ 3.54

Net Income/(Loss) Attributable to Common Shareholders (GAAP) $ 811.7 $ 2.27 $ (442.2) $ (1.26) $ 1,404.9 $ 4.05

Regulated Companies (Non-GAAP) $ 1,691.9 $ 4.73 $ 1,509.3 $ 4.31 $ 1,460.4 $ 4.21

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Non-GAAP Earnings $ 1,634.0 $ 4.57 $ 1,517.7 $ 4.34 $ 1,419.9 $ 4.09

Impairments of Offshore Wind Investments (after-tax) (1)

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

(524.0) (1.47) (1,953.0) (5.58) — —

Loss on Pending Sale of Aquarion (after-tax) (2)

(298.3) (0.83) — — — —

Land Abandonment Loss and Other Charges (after-tax) (3)

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— — — — (15.0) (0.04)

CL&P Settlement Impacts (after-tax) (4)

— — — — (86.1) (0.25)

Net (Loss)/Income Attributable to Common Shareholders (GAAP) $ (442.2) $ (1.26) $ 1,404.9 $ 4.05 $ 1,220.5 $ 3.54

(1) We recorded impairment charges resulting from the expected sales of our offshore wind investments and to reflect our current estimate of the fair value of the offshore wind projects.

Net Income/(Loss) Attributable to Common Shareholders (GAAP) $ 811.7 $ 2.27 $ (442.2) $ (1.26) $ 1,404.9 $ 4.05

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

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 .

(2) The 2023 charges primarily include a loss on the disposition of land.

The land was initially acquired to construct the Northern Pass Transmission project and was subsequently abandoned.

(3) Transaction costs in 2022 and 2021 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.

(4) The 2021 after-tax costs are associated with the October 1, 2021 CL&P settlement agreement approved by PURA that included credits to customers and funding of various customer assistance initiatives and a 2021 storm performance penalty imposed on CL&P by PURA.

(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 .

(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.

Regulated Companies:

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Net Income - Regulated Companies (GAAP) $ 1,393.6 $ 3.90 $ 1,509.3 $ 4.31 $ 1,460.4 $ 4.21

Electric Distribution, excluding CL&P Settlement Impacts

(Non-GAAP) $ 608.0 $ 1.74 $ 592.8 $ 1.71 $ 556.2 $ 1.61

Electric Distribution $ 631.7 $ 1.77 $ 608.0 $ 1.74 $ 592.8 $ 1.71

Electric Transmission 724.6 2.03 643.4 1.84 596.6 1.72

Natural Gas Distribution 291.0 0.81 224.8 0.64 234.2 0.67

Water Distribution 33.1 0.09 36.8 0.11 36.8 0.11

Water Distribution, excluding Loss on Pending Sale (Non-GAAP) 44.6 0.12 33.1 0.09 36.8 0.11

Net Income - Regulated Companies (Non-GAAP) $ 1,691.9 $ 4.73 $ 1,509.3 $ 4.31 $ 1,460.4 $ 4.21

CL&P Settlement Impacts (after-tax) — — — — (86.1) (0.25)

Loss on Pending Sale of Aquarion (after-tax) (298.3) (0.83) — — — —

Net Income - Regulated Companies (GAAP) $ 1,393.6 $ 3.90 $ 1,509.3 $ 4.31 $ 1,460.4 $ 4.21

Our electric distribution segment earnings increased $15.2 million in 2023, as compared to 2022, due primarily to a base distribution rate increase effective January 1, 2023 at NSTAR Electric, higher earnings from CL&P's capital tracking mechanism due to increased electric system improvements, an increase in interest income primarily on regulatory deferrals, the impact of a new regulatory tracking mechanism at PSNH that allows for the recovery of previously incurred operating expenses associated with poles acquired on May 1, 2023, and higher AFUDC equity income.

Those earnings increases were partially offset by higher operations and maintenance expense, higher interest expense, higher property and other tax expense, higher depreciation expense and lower pension income.

Our electric transmission segment earnings increased $46.8 million in 2023, as compared to 2022, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure and a lower effective tax rate.

Our natural gas distribution segment earnings decreased $9.4 million in 2023, as compared to 2022, due primarily to higher depreciation expense, higher interest expense, a higher effective tax rate, an unfavorable regulatory adjustment resulting from NSTAR Gas’ GSEP reconciliation filing, higher operations and maintenance expense arising primarily from higher uncollectible expense, and higher property tax expense.

Those earnings decreases were partially offset by higher earnings from capital tracking mechanisms due to continued investments in natural gas infrastructure, base distribution rate increases effective November 1, 2023 and November 1, 2022 at NSTAR Gas and effective November 1, 2022 at EGMA, and an increase in interest income primarily on regulatory deferrals.

Our water distribution segment earnings decreased $3.7 million in 2023, as compared to 2022, due primarily to higher depreciation, operations and maintenance expense and higher interest expense.

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 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.

Eversource Parent and Other Companies:

Eversource parent and other companies’ losses increased $1.90 billion in 2023, as compared to 2022, due primarily to the 2023 impairments of Eversource parent’s offshore wind investments, which resulted in a total after-tax charge of $1.95 billion, or $5.58 per share.

Earnings were also unfavorably impacted by higher interest expense and a loss on the disposition of land in 2023 that was initially acquired to construct the Northern Pass Transmission project and was subsequently abandoned.

Earnings benefited by a lower effective tax rate as a result of the ability to utilize tax credits and benefits in 2023, as well as a decrease in after-tax transaction and transition costs.

Additionally, 2023 earnings were favorably impacted from the liquidation of Eversource parent’s equity method investment in a renewable energy fund, partially offset by a charitable contribution made with a portion of the proceeds from the liquidation in 2023.

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.

Sources and Uses of Cash:

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The levels of short-term borrowing may vary significantly over the course of the year due to the impact of fluctuations in cash flows from operations (including timing of storm costs and regulatory recoveries), dividends paid, capital contributions received and the timing of long-term debt financings.

Eversource, CL&P, NSTAR Electric and PSNH each uses its available capital resources to fund its respective construction expenditures, meet debt requirements, pay operating costs, including storm-related costs, pay dividends, and fund other corporate obligations, such as pension contributions.

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.

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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.

In addition, Eversource uses its capital resources to fund investments in its offshore wind business, which are recognized as long-term assets.

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.

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, 2023, $1.95 billion of Eversource's long-term debt, including $1.35 billion at Eversource parent and $139.8 million at CL&P, matures within the next 12 months.

Eversource, with its solid credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt.

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.

Eversource, with its current credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt.

Eversource, CL&P, NSTAR Electric and PSNH will reduce their short-term borrowings with operating cash flows or with the issuance of new long-term debt, determined by considering capital requirements and maintenance of Eversource's credit rating and profile.

Cash and Cash Equivalents totaled $53.9 million as of December 31, 2023, compared with $374.6 million as of December 31, 2022.

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 $26.7 million as of December 31, 2024, compared with $53.9 million as of December 31, 2023.

Short-Term Debt - Commercial Paper Programs and Credit Agreements :

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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 13, 2028, and 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, which terminates on October 11, 2029, that 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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There were no borrowings outstanding on the revolving credit facilities as of December 31, 2024 or 2023.

CL&P and PSNH have uncommitted line of credit agreements totaling $375 million and $250 million, respectively, which will expire in 2024.

CL&P and PSNH have uncommitted line of credit agreements totaling $375 million and $250 million, respectively, all of which will expire in either May 2025, September 2025 or October 2025.

There are no borrowings outstanding on either the CL&P or PSNH uncommitted line of credit agreements as of December 31, 2024.

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 as Long-Term Debt on Eversource parent’s balance sheet as of December 31, 2023.

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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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, 2022, there were intercompany loans from Eversource parent to PSNH of $173.3 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.

Eversource parent charges interest on these intercompany loans at the same weighted-average interest rate as its commercial paper program.

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Availability under Long-Term Debt Issuance Authorizations:

On June 14, 2022, the DPU approved NSTAR Gas’ request for authorization to issue up to $325 million in long-term debt through December 31, 2024.

On November 30, 2022, the PURA approved CL&P's request for authorization to issue up to $1.15 billion in long-term debt through December 31, 2024.

As a result of CL&P’s January 2024 long-term debt issuance, CL&P has now fully utilized this authorization.

On June 7, 2023, PURA approved Yankee Gas’ request for authorization to issue up to $350 million in long-term debt through December 31, 2024.

On November 21, 2023, NSTAR Electric petitioned the DPU requesting authorization to issue up to $2.4 billion in long-term debt through December 31, 2026.

On February 8, 2024, the NHPUC approved PSNH’s request for authorization to issue up to $300 million in long-term debt through December 31, 2024.

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.

PSNH has utilized its long-term debt authorizations in place with NHPUC.

Long-Term Debt Issuances and Repayments:

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Repayment Information

CL&P 2023 Series A First Mortgage Bonds 5.25 % $ 500.0 January 2023 January 2053 Repaid 2013 Series A Bonds at maturity and short-term debt, and paid capital expenditures and working capital

CL&P 2013 Series A First Mortgage Bonds 2.50 % (400.0) January 2023 January 2023 Paid at maturity

CL&P 2023 Series B First Mortgage Bonds 4.90 % 300.0 July 2023 July 2033 Repaid short-term debt, paid capital expenditures and working capital

CL&P 2024 Series A First Mortgage Bonds 4.65 % $ 350.0 January 2024 January 2029 Repaid short-term debt, paid capital expenditures and working capital

NSTAR Electric 2023 Debentures 5.60 % 150.0 September 2023 October 2028 Repaid Series G Senior Notes at maturity and short-term debt and for general corporate purposes

NSTAR Electric 2013 Series G Senior Notes 3.88 % (80.0) November 2023 November 2023 Paid at maturity

PSNH Series W First Mortgage Bonds 5.15 % 300.0 January 2023 January 2053 Repaid short-term debt, paid capital expenditures and working capital

PSNH Series X First Mortgage Bonds 5.35 % 300.0 September 2023 October 2033 Repaid Series S Bonds at maturity and for general corporate purposes

PSNH Series S First Mortgage Bonds 3.50 % (325.0) November 2023 November 2023 Paid at maturity

Eversource Parent Series Z Senior Notes 5.45 % 750.0 March 2023 March 2028 Repaid Series F Senior Notes at maturity and short-term debt

Eversource Parent Series F Senior Notes 2.80 % (450.0) May 2023 May 2023 Paid at maturity

Eversource Parent Series Z Senior Notes 5.45 % 550.0 May 2023 March 2028 Repaid Series T Senior Notes and Series N Senior Notes at maturity and short-term debt

Eversource Parent Series AA Senior Notes 4.75 % 450.0 May 2023 May 2026 Repaid Series T Senior Notes and Series N Senior Notes at maturity and short-term debt

Eversource Parent Series BB Senior Notes 5.125 % 800.0 May 2023 May 2033 Repaid Series T Senior Notes and Series N Senior Notes at maturity and short-term debt

Eversource Parent Variable Rate Series T Senior Notes SOFR plus 0.25% (350.0) August 2023 August 2023 Paid at maturity

Eversource Parent Series CC Senior Notes 5.95 % 800.0 November 2023 February 2029 Repaid Series N Senior Notes at maturity and short-term debt

Eversource Parent Series N Senior Notes 3.80 % (400.0) December 2023 December 2023 Paid at maturity

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

Yankee Gas Series V First Mortgage Bonds 5.51 % 170.0 August 2023 August 2030 Repaid short-term debt and general corporate purposes

EGMA Series D First Mortgage Bonds 5.73 % 58.0 November 2023 November 2028 Repaid short-term debt, paid capital expenditures and working capital

Aquarion Water Company of Connecticut Senior Notes 5.89 % 50.0 September 2023 October 2043 Repaid existing indebtedness, paid capital expenditures and general corporate purposes

As a result of the CL&P and Eversource parent long-term debt issuances in January 2024, $139.8 million and $990.9 million, respectively, of current portion of long-term debt were reclassified as Long-Term Debt on CL&P’s and Eversource parent’s balance sheets as of December 31, 2023.

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

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.

Rate Reduction Bonds:

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PSNH paid $43.2 million of RRB principal payments in each of 2024 and 2023, and paid $14.9 million and $16.2 million of interest payments in 2024 and 2023, respectively.

Common Share Issuances and 2022 Equity Distribution Agreement:

On May 11, 2022, Eversource entered into an equity distribution agreement pursuant to which it may offer and sell up to $1.2 billion of its common shares from time to time through an “at-the-market” (ATM) equity offering program.

In 2023, no shares were issued under this agreement.

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.

In 2024, Eversource issued 15,740,294 common shares, which resulted in proceeds of $989.4 million, net of issuance costs.

Eversource used the net proceeds received for general corporate purposes.

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 $2.16 billion in 2024, compared with $1.65 billion in 2023.

Operating cash flows were unfavorably impacted by an increase in regulatory under-recoveries driven primarily by the timing of collections for the CL&P non-bypassable FMCC and other regulatory tracking mechanisms, the timing of cash payments made on our accounts payable, a $26.7 million increase in cash payments to vendors for storm costs, an $11.9 million increase in cost of removal expenditures, and the timing of other working capital items.

In 2023, CL&P increased the flow back to customers of net revenues generated by long-term state-approved energy contracts by providing these credits to customers through the non-bypassable FMCC retail rate.

The reduction in the CL&P non-bypassable FMCC retail rate decreased the regulatory over-recovery balance and created an under-recovery balance as of December 31, 2023 , which resulted in a decrease to amortization expense of $802.3 million in 2023, as compared to 2022, and is presented as a cash outflow in Amortization on the statement of cash

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.

The impacts of regulatory collections are included in both Regulatory Recoveries and Amortization on the statements of cash flows.

These unfavorable impacts were partially offset by the timing of cash collections on our accounts receivable, the absence in 2023 of $78.4 million of payments in 2022 related to withheld property taxes at our Massachusetts companies, a decrease of $76.3 million in pension contributions made in 2023 compared to 2022, the absence in 2023 of $72.0 million of customer credits distributed in 2022 at CL&P as a result of the October 2021 settlement agreement and the 2021 storm performance penalty for CL&P’s response to Tropical Storm Isaias, and a $38.7 million increase in operating cash flows due to lower income tax payments.

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.

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

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.

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.

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Investments in Property, Plant and Equipment on the statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized and deferred portions of pension and PBOP income/expense.

In 2023, investments for Eversource, CL&P, NSTAR Electric, and PSNH were $4.34 billion, $1.09 billion, $1.38 billion and $605.1 million, respectively.

In 2024, investments for Eversource, CL&P, NSTAR Electric, and PSNH were $4.48 billion, $978.5 million, $1.56 billion and $608.8 million, respectively.

Capital expenditures were primarily for continuing projects to maintain and improve infrastructure and operations, including enhancing reliability to the transmission and distribution systems.

Capital contributions in the offshore wind investments, including the 2023 contribution for the tax equity investment in South Fork Wind, are included in Investments in Unconsolidated Affiliates on the statements of cash flows.

Proceeds received from the sale of the uncommitted lease area of $625 million in 2023 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, are included in Proceeds from Unconsolidated Affiliates on the statement of cash flows.

Proceeds from the October 2023 distribution were used to pay down short-term debt.

Proceeds from Unconsolidated Affiliates also includes proceeds received from the liquidation of an equity method investment in a renewable energy investment fund of $147.6 million in 2023.

Contractual Obligations:

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Eversource $ 1,113.5 $ 1,044.2 $ 982.4 $ 872.3 $ 764.4 $ 6,793.6 $ 11,570.4

Our commitments to make payments in addition to these contractual obligations include other liabilities reflected on our balance sheets, future funding of our offshore wind equity method investments until the expected sales are completed, and guarantees of certain obligations primarily associated with our offshore wind investments.

The future funding and guarantee obligations associated with our offshore wind investments will be impacted by the expected sales of our offshore wind investments and related developments.

For information regarding our projected capital expenditures over the next five years, see "Business Development and Capital Expenditures - Projected Capital Expenditures" and for further information on the expected sales of our 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 .

Our commitments to make payments in addition to these contractual obligations include other liabilities reflected on our balance sheets, and guarantees of certain obligations primarily associated with construction of our previously owned offshore wind investments.

Credit Ratings:

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Current Outlook Current Outlook Current Outlook

Eversource Parent A- Watch Neg Baa2 Negative BBB Stable

CL&P A Watch Neg A3 Stable A- Stable

NSTAR Electric A Watch Neg A2 Negative A- Stable

PSNH A Watch Neg A3 Stable A- Stable

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

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+ Watch Neg Baa2 Negative BBB Stable

CL&P A+ Watch Neg A1 Stable A+ Stable

NSTAR Electric A Watch Neg A2 Negative A Stable

PSNH A+ Watch Neg A1 Stable A+ Stable

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.

Business Development and Capital Expenditures

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Electric Transmission Business:

Our consolidated electric transmission business capital expenditures increased by $240.8 million in 2023, as compared to 2022.

Our consolidated electric transmission business capital expenditures decreased by $120.0 million in 2024, as compared to 2023.

A summary of electric transmission capital expenditures by company is as follows:

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Total Electric Transmission $ 1,327.8 $ 1,447.8 $ 1,207.0

Our transmission projects are designed to improve the reliability of the electric grid, meet customer demand for power and increases in electrification of municipal infrastructure, strengthen the electric grid's resilience against extreme weather and other safety and security threats, and enable integration of increasing amounts of clean power generation from renewable sources, such as solar, battery storage, and offshore wind.

Our transmission projects are designed to improve the reliability of the electric grid, meet customer demand for power, and strengthen the electric grid's resilience against extreme weather and other safety and security threats.

In Connecticut, Massachusetts and New Hampshire, our transmission projects include transmission line upgrades, the installation of new transmission interconnection facilities, substations and lines, and transmission substation enhancements.

Greater Cambridge Energy Program:

The Greater Cambridge Energy Program will construct Eversource’s first underground transmission substation in Cambridge, Massachusetts, along with associated transmission and distribution lines.

The project will address the increased electric demand in the region, enhance the resiliency of the transmission system, and ensure a flexible grid to reliably serve customers.

The flexibility to transmit and distribute mixed energy sources will support the decarbonization and electrification goals of both the City of Cambridge and the state of Massachusetts.

The new 115/13.8-kV, 35,000 square foot substation will be located in an underground vault and includes three distribution power transformers supplying thirty-six distribution circuits.

The project also includes five underground duct banks housing eight new 115-kV transmission lines.

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

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.

The initial in-service date for the project is June 2029, which includes two 115-kV transmission lines and the transmission portion of the substation.

The first distribution circuits and substation distribution will be placed in-service by the end of 2029.

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

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

As of December 31, 2024, $100.1 million has been spent on the project, with $70 million for transmission and $30.1 million for distribution.

Distribution Business:

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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.

In the fourth quarter of 2024, upon classifying the assets and liabilities as held for sale, Eversource concluded that the likely sale of Aquarion at a loss resulted in the requirement to test water distribution goodwill for impairment.

Eversource performed an impairment test by comparing the fair value of the business to its carrying value and recorded a goodwill impairment of $297 million, as the estimated fair value of the business based on the anticipated sale was less than the carrying value.

The fair value included future cash outflows of approximately $140 million of estimated income taxes as a result of the transaction.

The goodwill impairment charge is presented separately within Operating Income on the Eversource statement of income for the year ended December 31, 2024.

Projected Capital Expenditures:

A summary of the projected capital expenditures for the regulated companies' electric transmission and for the total electric distribution, natural gas distribution and water distribution for 2024 through 2028, including information technology and facilities upgrades and enhancements on behalf of the regulated companies, is as follows:

A summary of the projected capital expenditures for the regulated companies' electric transmission and for the total electric distribution and natural gas distribution for 2025 through 2029, including information technology and facilities upgrades and enhancements on behalf of the regulated companies, is as follows:

(Millions of Dollars) 2025 2026 2027 2028 2029 2025 - 2029 Total

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3,059 3,395 3,327 3,217 3,215 16,213

Water Distribution 169 204 218 234 251 1,076

Information Technology and All Other 256 222 222 225 227 1,152

Total $ 4,721 $ 5,009 $ 4,912 $ 4,776 $ 4,754 $ 24,172

The projections do not include investments related to offshore wind projects.

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 offshore wind business includes 50 percent ownership interests in wind partnerships, which collectively hold the Revolution Wind, South Fork Wind and Sunrise Wind projects, and a tax equity investment in South Fork Wind.

The offshore wind projects are being developed and constructed through joint and equal partnerships with Ørsted.

As of December 31, 2023 and 2022, Eversource's total equity investment balance in its offshore wind business was $515.5 million and $1.95 billion, respectively.

Expected Sales of Offshore Wind Investments :

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 contribution of $528 million using the proceeds from the lease area sale to invest in a tax equity interest for South Fork Wind.

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.

As a result of this investment, Eversource expects to receive investment tax credits after the turbines are placed in service for South Fork Wind and meet the requirements to qualify for the ITC.

These credits will be utilized to reduce Eversource’s federal tax liability or generate tax refunds over the next 24 months.

All of South Fork Wind’s twelve turbines are expected to be installed and placed into service by the end of March 2024.

On January 24, 2024, Ørsted signed an agreement with Eversource to acquire Eversource’s 50 percent share of Sunrise Wind.

In that scenario, Ørsted and Eversource would then assess their options in determining the best path forward for Sunrise Wind and its assets, which include the BOEM offshore lease area.

If Sunrise Wind’s revised bid is successful in the new solicitation, Sunrise Wind would have 90 days to negotiate a new OREC agreement at the re-bid price.

In a successful re-bid, Ørsted would become the sole owner of Sunrise Wind, while Eversource would remain contracted to lead the project’s onshore construction.

If Sunrise Wind is successful in the re-bid, Ørsted would pay Eversource 50 percent of the negotiated purchase price upon closing the sale transaction, with the remaining 50 percent paid when onshore construction is completed and certain other milestones are achieved.

On January 25, 2024, Eversource and Ørsted submitted a new proposal for Sunrise Wind in the New York fourth offshore wind solicitation.

On February 13, 2024, Eversource announced that it has executed an agreement to sell its existing 50 percent interests in the South Fork Wind and Revolution Wind projects to Global Infrastructure Partners (GIP).

The purchase price is subject to future post-closing adjustment payments based on, among other things, the progress, timing and expense of construction at each project.

Factors that could result in Eversource’s total net proceeds from the transaction to be lower or higher include Revolution Wind’s eligibility for federal investment tax credits at other than the anticipated 40 percent level;

the ultimate cost of construction and extent of cost overruns for Revolution Wind;

delays in constructing Revolution Wind, which would impact the economics associated with the purchase price adjustment;

and 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 date of the Revolution Wind project.

Closing a transaction with GIP would be subject to customary conditions, including certain regulatory approvals under the Hart Scott Rodino Act and by the New York Public Service Commission and the FERC, as well as other conditions, among which is the completion and execution of the partnership agreements between GIP and Ørsted that will govern GIP’s new ownership interest in those projects following Eversource’s divestiture.

Closing of the transaction is currently expected to occur in mid-2024.

If closing of the sale is delayed, additional capital contributions made by Eversource would be recovered in the sales price.

Under the agreement, Eversource’s existing credit support obligations are expected to roll off for each project around the time that each project completes its expected capital spend.

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.

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.

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.

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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.

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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.

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.

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.

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

The 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.

Additional assumptions in the fourth quarter assessment included revised projected construction costs and estimated project cost overruns, 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 are subject to inherent uncertainties and subjectivity.

The use of different assumptions, estimates, or judgments with respect to the estimation of future cash flows could materially change the impairment charges.

The impairment evaluations were based on best information available at the impairment assessment dates.

New information from events or circumstances arising after the balance sheet date, such as the January 25, 2024 re-bid of Sunrise Wind in the New York solicitation, are not included in the December 31, 2023 impairment evaluation.

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.

The expected cash flows arising from the anticipated sales are a significant input in the impairment evaluation.

In the fourth quarter of 2023, project construction forecasts were updated, and these new forecasts reflected additional expenditures for construction and scheduling related pressures, including the availability and increased cost of installation vessels and supply chain cost increases related to foundation fabrication.

In determining the current fair value of the investments, these updated projections exceeded the previously estimated projections for construction expenditures, which resulted in a revised sales price that was significantly lower than the previous bid value.

Another significant assumption in the impairment evaluation includes the probability of payment of future cost overruns on the three wind projects through each project's respective commercial operation date, which would not be recovered in the expected sales price.

This assumption was based on construction projections updated in the fourth quarter of 2023 exceeding prior estimates.

An increase in expected cost overruns could result in a significant impairment in a future period.

Another key assumption in the impairment model of our offshore wind investments was investment tax credit (“ITC”) adders that were included in the Inflation Reduction Act and were a separate part of the sales price value offered by GIP.

An ITC adder is an additional 10 percent of credit value for ITC eligible costs and include two distinct qualifications related to either using domestic sourced materials (domestic content) or construction of an onshore substation in a designated community (energy community).

Similar to the base ITC of 30 percent of the eligible costs, any ITC adders generated would be used to reduce an owner’s federal tax liability and could be used to receive tax refunds from prior years as well.

Management believes there is a high likelihood that the 10 percent energy community ITC adder is realizable, and that ITC adder would amount to approximately $170 million of additional sales value related to Revolution Wind and that it would qualify for the ITC adder after it reaches commercial operation in 2025.

Although management believes the ITC adder value is realizable, there is some uncertainty at this time as to whether or not 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 impairment in a future period.

Another fourth quarter 2023 development included in the impairment evaluation is the key judgment regarding the probability of future cash inflows and outflows associated with the sale or abandonment of the Sunrise Wind project and the expected outcome of the New York fourth offshore wind solicitation in 2024.

In June 2023, Sunrise Wind filed a petition with the New York State Public Service Commission for an order authorizing NYSERDA to amend the Sunrise Wind OREC contract to increase the contract price to cover increased costs and inflation.

At that time, management expected the contract repricing would be successful given NYSERDA’s public support for pricing adjustments.

On October 12, 2023, the New York State Public Service Commission denied this petition.

Subsequent to the denial, on November 30, 2023, the general terms of an expedited offshore wind renewable energy solicitation in New York were released.

A primary condition for Sunrise Wind to participate in this new solicitation was to agree to terminate its existing OREC agreement.

As of December 31, 2023, Eversource and Ørsted were considering whether to submit a new bid for Sunrise Wind, the price at which a new bid would be made, and the probability of success in the new bidding process.

The December 31, 2023 impairment evaluation included management’s judgment of the likelihood of possible future scenarios that included the Sunrise Wind project continuing with its existing OREC contract, the project re-bidding and being selected in the new solicitation, the project re-bidding and not being selected, or the project not moving forward.

The unfavorable development of the October 2023 denial of the OREC pricing petition, management’s assessment of the likelihood of success in the competitive New York re-bidding process, and the increased costs to build the project, have resulted in management’s assumption that the Sunrise Wind project will ultimately be abandoned, and therefore, no sales value was modeled in the impairment evaluation.

Additionally, in the abandonment assumption, management has assumed the loss of contingent sales value associated with any related ITC adders and has estimated future cash outflows for Eversource’s share of cancellation costs required under Sunrise Wind’s supplier contracts, partially offset by expected salvage value and expected cost overruns not incurred in the case of abandonment that are included in the fourth quarter 2023 impairment charge.

An increase in expected cancellation costs could result in a significant impairment in a future period.

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

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

Management will continue to monitor and evaluate all facts and circumstances in the offshore wind sales process and the impact on its investment balance.

Adverse changes in facts and circumstances of estimates and timing of future cash flows and the factors described above could result in the recognition of additional, significant impairment charges that could be material to the financial statements.

The impairment charge was a non-cash charge and did not impact Eversource’s cash position.

Eversource will continue to make future cash expenditures for required cash contributions to its offshore wind investments up to the time of disposition of each of the offshore wind projects.

Capital contributions are expected until the sales are completed and changes in the timing and amounts of these contributions would be adjusted in the sales prices and therefore not result in an additional impairment charge.

Proceeds from the transactions will be used to pay off parent company debt.

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

Contracts, Permitting and Construction of Offshore Wind Projects:

The following table provides a summary of the Eversource and Ørsted major projects with announced contracts:

Wind Project State Servicing Size (MW) Term (Years) Price per MWh Pricing Terms Contract Status

Revolution Wind Rhode Island 400 20 $98.43 Fixed price contract;

no price escalation Approved

Revolution Wind Connecticut 304 20 $98.43 - $99.50

Fixed price contracts;

no price escalation Approved

South Fork Wind New York (LIPA) 90 20 $160.33 2 percent average price escalation Approved

South Fork Wind New York (LIPA) 40 20 $86.25 2 percent average price escalation Approved

The offshore wind projects require receipt of federal, state and local approvals necessary to construct and operate the projects.

The federal permitting process is led by BOEM, and state approvals are required from New York, Rhode Island and Massachusetts.

South Fork Wind and Revolution Wind have received all required approvals to start construction.

Significant delays in the siting and permitting process resulting from the timeline for obtaining approval from BOEM and the state and local agencies could adversely impact the timing of Sunrise Wind’s' in-service date.

Federal Siting and Permitting Process:

The federal siting and permitting process for each of our offshore wind projects commence with the filing of a Construction and Operations Plan (COP) application with BOEM.

BOEM provides a review schedule for the project’s COP approval and conducts environmental and technical reviews of the COP.

BOEM issues an Environmental Impact Statement (EIS) that assesses the environmental, social, and economic impacts of constructing the project and recommends measures to minimize impacts.

The Final EIS will inform BOEM in deciding whether to approve the project or to approve with modifications and BOEM will then issue its Record of Decision.

BOEM issues its final approval of the COP following the Record of Decision.

Revolution Wind and Sunrise Wind filed their COP applications with BOEM in March 2020 and September 2020, respectively.

For the Revolution Wind project, BOEM released its Draft EIS on September 2, 2022 and its Final EIS on July 17, 2023.

On August 21, 2023, BOEM issued its Record of Decision, which concluded BOEM’s environmental review of the project and identified the recommended configuration.

Final approval of the Revolution Wind project was received on November 20, 2023.

For the Sunrise Wind project, BOEM released its Draft EIS on December 16, 2022 and its Final EIS on December 15, 2023.

The Record of Decision is expected in the first quarter of 2024 and final approval of Sunrise Wind is expected in the second quarter of 2024.

South Fork Wind, Revolution Wind and Sunrise Wind are each designated as a “Covered Project” pursuant to Title 41 of the Fixing America’s Surface Transportation Act (FAST41) and a Major Infrastructure Project under Section 3(e) of Executive Order 13807, which provides greater federal attention on meeting the projects’ permitting timelines.

State and Local Siting and Permitting Process:

State permitting applications in Rhode Island for Revolution Wind and in New York for Sunrise Wind were filed in December 2020.

On July 8, 2022, the Rhode Island Energy Facilities Siting Board issued a Final Decision and Order approving the Revolution Wind project and granting a license to construct and operate.

On November 17, 2022, the New York Public Service Commission approved an order adopting a Joint Proposal filed by Sunrise Wind and granting a Certificate of Environmental Compatibility and Public Need.

On November 18, 2022, Sunrise Wind filed its Phase 1 Environmental Management and Construction Plan (EM&CP) with the New York Public Service Commission, which details the plans on limited onshore construction activities subject to state and local jurisdiction.

On March 27, 2023, Sunrise Wind filed its EM&CP for Phase 2, which covers the remainder of the project components.

On June 22, 2023, Sunrise Wind received approval of the Phase 1 EM&CP.

On July 13, 2023, the New York State Public Service Commission approved Sunrise Wind’s notice for authorization to proceed with construction for Phase 1.

On December 18, 2023, Sunrise Wind received approval of the Phase 2 EM&CP.

On November 9, 2022, the Towns of Brookhaven and Suffolk County executed the easements and other real estate rights necessary to construct the Sunrise Wind project.

On November 28, 2022, the Town of North Kingstown and the Quonset Development Corporation approved Revolution Wind’s real estate PILOT terms and the personal property PILOT agreement necessary to construct the Revolution Wind project.

Construction Process:

South Fork Wind received all required approvals to start construction and the project entered the construction phase in early 2022.

All major onshore construction activities, including the project’s underground onshore transmission line and the onshore interconnection facility located in East Hampton, New York are complete.

Offshore construction activities began in the fourth quarter of 2022, and installation of the subsea transmission cable, the monopile foundations and offshore substation was completed in 2023.

Installation of the project’s 11-megawatt wind turbines continued throughout 2023 and four of South Fork Wind’s twelve turbines were placed into service by January 1, 2024, meeting the project commercial operation date requirements under the power purchase agreement with LIPA.

All wind turbines are expected to be installed

and placed into service by the end of March 2024.

South Fork Wind faces several challenges and appeals of New York State and federal agency approvals, however we believe it is probable we will be able to overcome these challenges.

For Revolution Wind, on October 31, 2023, the joint venture made its final investment decision to advance to full onshore and offshore construction and installation, and major construction began in the fourth quarter of 2023 upon receipt of all necessary federal, state and local approvals.

For Sunrise Wind, once all necessary federal, state and local approvals are received and the joint venture has made its final investment decision, informed in part by the outcome of the New York fourth solicitation, then major construction is expected to begin.

Sunrise Wind has started limited onshore construction activities.

Projected In-Service Dates:

We expect the South Fork Wind project to be in-service by the end of March 2024 and the Revolution Wind project to be in-service in late 2025.

For Sunrise Wind, based on the updated BOEM permit schedule outlining when BOEM will complete its review of the COP, we currently expect an in-service date in 2026.

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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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 its 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 Court found that FERC’s development of the new return methodology was arbitrary and capricious due to FERC’s failure to offer a reasonable explanation for its decision to reintroduce the risk-premium financial model in its new methodology for calculating a just and reasonable return.

At this time, Eversource cannot predict how and when FERC will address the Court’s findings on the remand of the MISO FERC opinions or any potential associated impact on the NETOs’ four pending ROE complaint cases.

Given the significant uncertainty regarding the applicability of the FERC opinions in the MISO transmission owners’ two complaint cases to the NETOs’ pending four complaint cases, Eversource concluded that there is no reasonable basis for a change to the reserve or recognized ROEs for any of the complaint periods at this time.

As well, Eversource cannot reasonably estimate a range of loss for any of the four complaint proceedings at this time.

On October 17, 2024, FERC issued an order on the remand of the MISO ROE proceedings.

The order addressed the Court’s decision that the reintroduction of the risk-premium financial model in the ROE methodology was arbitrary and capricious by removing the risk-premium financial model from the ROE methodology.

The removal of the risk-premium financial model was the only revision to FERC’s ROE methodology and resulted in a two-model approach utilizing the two-step discounted cash flow model and the capital asset pricing model.

MISO 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.

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 November 13, 2024, the NETOs filed a supplemental brief in their four pending ROE proceedings to explain to FERC that it cannot apply the reasoning and methodologies of the MISO ROE case to the NETOs’ cases due to the entirely different set of facts in the MISO and NETOs ROE proceedings.

Doing so would violate the substance of the Court’s April 14, 2017 order and would violate the legal standard required by the Federal Power Act.

On February 4, 2025, the MISO transmission owners submitted a petition for review with the Court requesting review of the October 17, 2024 MISO ROE order on remand and a December 19, 2024 notice of denial of rehearing.

The petition requests review of FERC’s decision to retroactively backdate the MISO transmission owners’ base ROE to the date of an earlier order that FERC abandoned when it issued Order No.

569, treat an underlying unlawful complaint as if it were legitimate, and order eight years of interest as part of the directed refunds.

Given the significant uncertainty regarding the applicability of the FERC order in the MISO transmission owners’ two complaint cases to the NETOs’ pending four complaint cases due to the complex differences between the cases, Eversource concluded that there is no reasonable basis for a change to the reserve or recognized ROEs for any of the complaints or subsequent periods at this time and Eversource cannot reasonably estimate any potential range of loss for any of the four complaint proceedings at this time.

The resolution of these proceedings could have a material impact on the financial condition, results of operations, and cash flows.

Eversource, CL&P, NSTAR Electric and PSNH currently record revenues at the 10.57 percent base ROE and incentive cap at 11.74 percent established in the October 16, 2014 FERC order.

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Prospectively from the date of a final FERC order implementing a new base ROE, based off of estimated 2024 rate base, a change of 10 basis points to the base ROE would impact Eversource’s future annual after-tax earnings by approximately $6 million per year, and will increase slightly over time as we continue to invest in our transmission infrastructure.

FERC Notice of Proposed Rulemaking on Transmission Incentives:

On March 20, 2020, FERC issued a Notice of Proposed Rulemaking (NOPR) on transmission incentives.

The NOPR intends to revise FERC’s electric transmission incentive policies to reflect competing uses of transmission due to generation resource mix, technological innovation and shifts in load patterns.

FERC proposes to grant transmission incentives based on measurable project economics and reliability benefits to consumers rather than its current project risks and challenges framework.

On July 1, 2020, Eversource filed comments generally supporting the NOPR.

On April 15, 2021, FERC issued a Supplemental NOPR that proposes to eliminate the existing 50 basis point return on equity for utilities that have been participating in a regional transmission organization (RTO ROE incentive) for more than three years.

On June 25, 2021, the NETOs jointly filed comments strongly opposing FERC’s proposal.

On July 26, 2021, the NETOs filed Supplemental NOPR reply comments responding to various parties advocating for the elimination of the RTO Adder.

If FERC issues a final order eliminating the RTO ROE incentive as proposed in the Supplemental NOPR, the estimated annual impact (using 2023 estimated rate base) on Eversource's after-tax earnings is approximately $19.5 million.

The Supplemental NOPR contemplates an effective date 30 days from the final order.

At this time, Eversource cannot predict the ultimate outcome of these proceedings, including possible appellate review, and the resulting impact on its transmission incentives.

Transmission Rates and Other Transmission Rates-Related Proceedings:

CL&P, NSTAR Electric and PSNH transmission rates are calculated in accordance with a FERC-approved formula ratemaking framework and each utility is required to file an annual update on or before July 31st with resulting rates effective January 1st the following year.

The formula rate framework provides for an annual reconciliation of the prior calendar year actual costs incurred related to our transmission facilities, including an allowed ROE, plus forecasted information through the next rate period.

The annual update process includes formula rate protocols that provide disclosure of cost inputs, an opportunity for informal discovery procedures and a challenge process, which provides transparency to stakeholders.

From time to time, various matters are pending before FERC relating to transmission rates, incentives, interconnections and transmission planning.

Depending on the outcome, any of these matters could materially impact our results of operations and financial condition.

At this time, Eversource cannot predict the ultimate outcome of the matters currently pending before FERC, and the resulting impact on its transmission incentives or planning.

Regulatory Developments and Rate Matters

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Base Distribution Rates:

In Connecticut, electric, natural gas and water utilities serving more than seventy-five thousand customers are required to file a distribution rate case within four years of the last rate case.

In Connecticut, PURA is required to conduct a review and investigation of the financial and operating records of each electric, natural gas and water utility serving more than seventy-five thousand customers within four years of its last general rate hearing.

PURA can elect to convene a general rate hearing at an interval of less than four years unless prohibited from doing so by an agency decision or other law.

CL&P's and Yankee Gas' base distribution rates were each established in 2018 PURA-approved rate case settlement agreements.

On October 27, 2021, PURA approved a settlement agreement for CL&P that included a current base distribution rate freeze until no earlier than January 1, 2024.

The approval of the settlement agreement satisfied the Connecticut statute of rate review requirements that requires electric utilities to file a distribution rate case within four years of the last rate case.

On March 15, 2023, PURA issued a final decision that rejected Aquarion Water Company of Connecticut’s (AWC-CT) application with PURA to amend its existing rate schedules.

AWC-CT filed an appeal on the decision and on May 25, 2023, the State of Connecticut Superior Court granted a permanent stay of certain orders affecting base rates, which will keep existing rates in place until the appeal is completed.

For further information, see "Regulatory Developments and Rate Matters - Connecticut," below .

In Massachusetts, electric distribution companies are required to file distribution rate schedules every five years, and natural gas local distribution companies to file distribution rate schedules every 10 years, and those companies are limited to one settlement agreement in any 10-year period.

NSTAR Electric's base distribution rates were established in a November 2022 DPU-approved rate case.

NSTAR Gas' base distribution rates were established in an October 2020 DPU-approved rate case.

EGMA's base distribution rates were established in an October 2020 DPU-approved rate settlement agreement.

Aquarion is not required to initiate a rate review with the DPU.

Aquarion’s base distribution rates were established in a 2018 DPU-approved rate case.

In New Hampshire, PSNH's base distribution rates were established in a December 2020 NHPUC-approved rate case settlement agreement.

Aquarion's base distribution rates were established in a July 2022 NHPUC-approved rate case settlement agreement, with a single step adjustment approved on January 19, 2023.

Rates were effective March 1, 2023.

In New Hampshire, PSNH is not required to initiate a rate review with the NHPUC on any set timeframe, and the NHPUC has no obligation to hear any rate matter that it has investigated within a period of two years, though it may elect to do so at its discretion.

Rate Reconciling Mechanisms:

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Increases or decreases in energy supply retail rates result in corresponding fluctuations in both energy supply procurement revenues and purchased power or purchased natural gas expenses on the statements of income.

The electric and natural gas distribution companies also recover certain other costs in retail rates on a fully reconciling basis through regulatory commission-approved cost tracking mechanisms and, therefore, recovery of these costs has no impact on earnings.

Costs recovered through cost tracking mechanisms include, among others, electric retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for the Massachusetts utilities, pension and PBOP benefits, net metering for distributed generation, and solar-related programs.

The electric and natural gas distribution companies also recover certain other costs from customers in retail rates on a fully reconciling basis through regulatory commission-approved cost tracking mechanisms and therefore, recovery of these costs has no impact on earnings.

Costs recovered through cost tracking mechanisms include, among others, state mandated energy purchase agreements and other energy-related costs, electric retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for the Massachusetts utilities, pension and PBOP benefits, net metering for distributed generation, and solar-related programs.

The reconciliation filings compare the total actual costs allowed to revenue requirements related to these services and the difference between the costs incurred (or the rate recovery allowed) and the actual costs allowed is deferred and included, to be either recovered or refunded, in future customer rates.

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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, which would apply at the time of CL&P’s next distribution rate case.

The straw proposal is not authoritative and technical sessions are continuing prior to a final decision.

PURA is expected to issue a straw proposal in the second reopener focusing on performance incentive mechanisms (PIMs) in the first quarter of 2024.

The three reopener dockets continue to progress through the Phase 2 process.

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.

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.

CL&P Storm Filing:

On December 22, 2023, CL&P initiated a docket seeking a prudency review of approximately $634 million of catastrophic storm costs for twenty-four weather events from January 1, 2018 to December 31, 2021.

In the filing, CL&P requested PURA establish a rate to collect $50 million annually from customers from the date of the final decision in this proceeding.

This rate would be effective until the next distribution rate case and would replenish the under-collected storm reserve and reduce future carrying charges for customers.

CL&P Storm Filings:

On March 28, 2024, PURA established a prudency review proceeding for the purpose of receiving and reviewing evidence of the costs reported by CL&P in response to catastrophic storms and pre-staging events totaling approximately $634 million that occurred between January 1, 2018 and December 31, 2021.

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.

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.

CL&P Advanced Metering Infrastructure Filing:

On July 31, 2020, CL&P submitted to PURA its proposed $512 million Advanced Metering Infrastructure investment and implementation plan.

On August 17, 2021, PURA issued a Notice of Request for an Amended EDC Advanced Metering Infrastructure Proposal.

On November 8, 2021, CL&P submitted an Amended Proposal in response to this request with an updated schedule for the years 2022 through 2028, which included additional information as required by PURA.

As required, the plan includes a full deployment of advanced metering functionality and a composite business case in support of the Advanced Metering Infrastructure plan.

On January 3, 2024, PURA issued a final decision regarding CL&P’s Advanced Metering Infrastructure investment and implementation plan, which CL&P most recently estimated at $766.4 million for capital costs and one-time operating expenses.

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

In addition, the final decision modifies the prudence standard for recovery of costs expended on the project, improperly linking recovery to outcomes not known at the outset of the project.

On January 18, 2024, CL&P submitted a motion for reconsideration to PURA asking that the agency modify these aspects of the decision.

Termination of Park City Wind’s Power Purchase Agreement with CL&P :

On October 2, 2023, Park City Wind LLC and CL&P signed an agreement to terminate the Park City Wind offshore wind generation PPA, at the request of Park City Wind LLC.

The termination agreement was effective on October 13, 2023, the date of PURA approval.

In October 2023, Park City Wind LLC paid a termination payment of $12.9 million to CL&P resulting from the termination of the PPA, which CL&P will return to customers.

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.

In addition, in CL&P’s view, the final decision modifies the prudence standard for recovery of costs expended on the project, improperly linking recovery to outcomes not known at the outset of the project.

On January 18, 2024, CL&P submitted a motion for reconsideration to PURA, asking that the agency modify these aspects of the decision, which PURA subsequently denied on February 14, 2024.

On March 6, 2024, CL&P filed written comments citing four major problems associated with PURA’s guidelines for recovery of the costs of AMI implementation, which if not addressed, represent obstacles to AMI implementation in Connecticut.

On April 16, 2024, PURA issued a procedural order directing Eversource and inviting all parties and intervenors to submit pre-filed testimony pertaining to AMI by May 14, 2024, and rebuttal testimony by May 29, 2024.

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 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.

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.

Aquarion Water Company of Connecticut Distribution Rate Case:

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On March 15, 2023, PURA issued a final decision that rejected this request.

In this decision, PURA ordered a base distribution rate decrease of $2.0 million effective March 15, 2023.

In this decision, PURA ordered a decrease to total authorized revenues of $4.0 million effective March 15, 2023.

The decision allows an authorized regulatory ROE of 8.70 percent.

On March 30, 2023, AWC-CT filed an appeal on the decision 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 will keep existing rates in place until the appeal is completed.

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.

A hearing on the merits of the appeal was held on January 11, 2024.

A decision from the State of Connecticut Superior Court is pending.

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.

On July 31, 2024, PURA issued a final decision in this docket and increased AWC-CT’s approved revenue requirement by $0.1 million above the amount authorized in the March 15, 2023 decision.

Rates went into effect on July 31, 2024.

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

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.

Massachusetts:

NSTAR Electric Distribution Rates :

On November 30, 2022, the DPU issued its decision in the NSTAR Electric distribution rate case and approved a base distribution rate increase of $64 million effective January 1, 2023.

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.

NSTAR Electric submitted its first annual PBR Adjustment filing on September 15, 2023 and on December 26, 2023, the DPU approved a $104.9 million increase to base distribution rates effective January 1, 2024.

The base distribution rate increase was comprised of a $50.6 million inflation-based adjustment and a $54.3 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 September 16, 2024, NSTAR Electric submitted its annual PBR Adjustment filing for a $55.8 million increase to base distribution rates, for effect on January 1, 2025.

The requested base distribution rate increase is comprised of a $35.3 million inflation-based adjustment and a $20.5 million adjustment for capital additions based on the difference between the historical five-year average of total capital additions and the base capital revenue requirement.

On December 23, 2024, the DPU approved this filing.

NSTAR 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 :

Massachusetts state law requires the electric distribution companies to file a comprehensive distribution system plan by January 29, 2024, to proactively upgrade the distribution system (and, where applicable, the associated transmission system) to:

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;

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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.

On January 29, 2024, NSTAR Electric filed its ESMP with the DPU.

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 taking into account the needs of environmental justice communities.

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

The DPU must approve, approve with modification, or reject the ESMP filing within seven months after filing.

Termination of SouthCoast Wind’s Power Purchase Agreements with NSTAR Electric :

On August 28, 2023, SouthCoast Wind Energy LLC and NSTAR Electric signed agreements to terminate three SouthCoast Wind offshore wind generation PPAs, at the request of SouthCoast Wind Energy LLC.

The termination agreements were effective on September 29, 2023, the date of DPU approval.

In October 2023, SouthCoast Wind Energy, LLC paid a termination payment totaling $32.5 million to NSTAR Electric resulting from the termination of the PPAs, which NSTAR Electric will return to customers.

Termination of Commonwealth Wind’s Power Purchase Agreement with NSTAR Electric :

On July 13, 2023, Commonwealth Wind, LLC and NSTAR Electric signed an agreement to terminate the Commonwealth Wind offshore wind generation PPA, at the request of Commonwealth Wind, LLC.

The termination agreement was effective on August 23, 2023, the date of DPU approval.

In October 2023, Commonwealth Wind, LLC paid a termination payment of $25.9 million to NSTAR Electric, which NSTAR Electric will return to customers.

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.

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.

NSTAR Gas Distribution Rates:

NSTAR Gas’ PBR mechanism allows for an annual adjustment to base distribution rates for inflation and exogenous events.

NSTAR Gas submitted its third annual PBR Adjustment filing on September 15, 2023 and on October 30, 2023, the DPU approved a $25.4 million increase to 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 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.

New Hampshire:

PSNH Pole Acquisition Approval:

On November 18, 2022, the NHPUC issued a decision that approved a proposed purchase agreement between PSNH and Consolidated Communications, in which, PSNH would acquire both jointly-owned and solely-owned poles and pole assets.

The NHPUC also authorized PSNH to recover certain expenses associated with the operation and maintenance of the transferred poles, pole inspections, and vegetation management expenses through a new cost recovery mechanism, the PPAM, subject to consummation of the purchase agreement.

The purchase agreement was finalized on May 1, 2023 for a purchase price of $23.3 million.

Upon consummation of the purchase agreement, PSNH established a regulatory asset of $16.9 million for operation and maintenance expenses and vegetation management expenses associated with the purchased poles incurred from February 10, 2021 through April 30, 2023 that PSNH is authorized to collect through the PPAM regulatory tracking mechanism.

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

PSNH Energy Efficiency Plan :

On February 24, 2022, a state law was enacted that directed that the joint utility energy efficiency plan and programming framework in effect on January 1, 2021 be utilized going forward, including utility performance incentive payments, lost base revenue calculations, and Evaluation, Measurement, and Verification process.

Additionally, the law established a process for future plan proposals, including the 2024 through 2026 triennial plan, and includes a mechanism for future rate increases based on the consumer price index.

On November 30, 2023, the NHPUC approved a three-year joint utility energy efficiency plan for 2024 through 2026, of which, $158 million is the PSNH program budget over the next three years.

Additionally, on December 22, 2023, the NHPUC approved the annual LBR rate for 2024, allowing PSNH to recover approximately $14 million in revenue that would have been collected if not for the implementation of energy efficiency measures.

PSNH Distribution Rate Case :

On June 11, 2024, PSNH filed an application with the NHPUC for approval of a temporary annual base distribution rate increase.

On July 31, 2024, the NHPUC approved a settlement agreement that was reached by PSNH, New Hampshire Department of Energy, and the Office of the Consumer Advocate to implement a temporary annual base distribution rate increase of $61.2 million effective August 1, 2024.

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.

Legislative and Policy Matters

On June 29, 2023, Connecticut enacted Public Act No.

23-102 (Substitute Senate Bill No.

7) (the Act) that encompasses 40 sections.

The Act prohibits recovery in retail rates of certain costs incurred by utilities, including costs for consultants and outside counsel for rate cases, membership dues, and lobbying.

None of the rate-setting provisions will result in an immediate change to rates, as all will require some future process, primarily a general distribution rate proceeding before PURA.

The Act also makes prospective adjustments to the timing and procedures used in the retail rate setting process, including (1) requiring additional procedural steps to be satisfied for proposed settlements of cases;

(2) increasing the deadline to issue a final decision on an application from a water company to amend base rates from 200 days to 270 days;

(3) authorizing PURA to elect to evaluate if rates should be reduced on an interim basis if a utility earns an ROE that exceeds its authorized ROE by 50 basis points over a rolling 12-month period ending with the two most recent consecutive financial quarters (instead of the current standard of 100 basis points);

and (4) authorizing PURA to elect to convene a general rate hearing at an interval of less than four years unless prohibited from doing so by an agency decision or other law.

The Act is prospective, not retroactive and therefore, does not change obligations or rate provisions established by settlements implemented prior to the Act.

The Act also prohibits CL&P’s electric system improvements (ESI) capital tracking mechanism from being reauthorized in the next general distribution proceeding.

The ESI will therefore remain in place until base distribution rates are adjusted in CL&P’s next general distribution rate proceeding.

The Act also excludes storms and other emergencies affecting 70 percent or more of an electric distribution company’s customers from the 2020 law requiring credits for residential customers who are without power for 96 or more consecutive hours.

Lastly, the Act was amended by Public Act No.

23-204 (House Bill No.

6941) to require the Governor to designate the chairperson of PURA from among the sitting commissioners by June 30, 2023 and every two years thereafter;

and to delete the changes in Section 21 of the Act to the duties and powers of PURA commissioners.

Designation of the chairperson does not constitute a renomination for a full commission term, as otherwise provided by law.

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.

Critical Accounting Policies

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We have $2.10 billion of deferred storm costs that either have yet to be filed with the applicable regulatory commission, are pending regulatory approval, or are subject to prudency review as of December 31, 2024.

Tropical Storm Isaias resulted in deferred storm restoration costs of approximately $232 million at CL&P as of December 31, 2023.

Tropical Storm Isaias in August 2020 resulted in deferred storm restoration costs of approximately $232 million at CL&P as of December 31, 2024.

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.

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For each of these plans, several significant assumptions are used to determine the projected benefit obligation, funded status, and net periodic benefit expense/income.

These assumptions include the expected long-term rate of return on plan assets, discount rate, compensation/progression rate and mortality and retirement assumptions.

These assumptions include the expected long-term rate of return on plan assets, discount rate, compensation/progression rate, cash balance interest crediting rate and mortality and retirement assumptions.

We evaluate these assumptions annually and adjust them as necessary.

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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, 2023, the discount rates used to determine the funded status 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.

As of December 31, 2022, the discount rates used were within a range of 5.1 percent to 5.2 percent for the Pension and SERP Plans, and 5.2 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 $98.9 million and an increase to the PBOP Plans' projected benefit obligation of $12.0 million as of December 31, 2023.

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.

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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This assumption reflects the expected long-term salary growth rate, including consideration of the levels of increases built into collective bargaining agreements, and impacts the estimated benefits that Pension and SERP Plan participants will receive in the future.

As of December 31, 2023 and 2022, the compensation/progression rates used to determine the funded status were within a range of 3.5 percent to 4.0 percent.

As of December 31, 2024 and 2023, the compensation/progression rates used to determine the Pension and SERP Plan funded status were within a range of 3.5 percent to 4.0 percent.

Health Care Cost Assumptions :

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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 interest crediting rate assumption represents the long-term rate by which the Pension Plan’s cash balance accounts are expected to grow.

Actual interest on the cash balance accounts is based on the 30-year U.S.

Treasury securities rate in effect for September of the preceding year, with a minimum rate of 4 percent.

The cash balance interest crediting rate assumption used in determining the forecasted 2025 pension expense was 4.8 percent.

Actuarial Gains and Losses:

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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 seven 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 eleven 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 2024.

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Pension, SERP and PBOP expense/income is determined by our actuaries and consists of service cost and prior service cost/credit, interest cost based on the discounting of the obligations, amortization of actuarial gains and losses, and the expected return on plan assets.

For the Pension and SERP Plans, pre-tax net periodic benefit income was $108.4 million and $181.6 million for the years ended December 31, 2023 and 2022, respectively, and there was pre-tax net periodic benefit expense of $23.6 million for the year ended December 31, 2021.

For the Pension and SERP Plans, pre-tax net periodic benefit income was $76.8 million, $108.4 million and $181.6 million for the years ended December 31, 2024, 2023 and 2022, respectively.

For the PBOP Plans, pre-tax net periodic benefit income was $64.3 million, $57.3 million and $79.8 million for the years ended December 31, 2024, 2023 and 2022, respectively.

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We estimate that net periodic benefit income in 2025 for the Pension and SERP Plans will be approximately $93 million and for the PBOP Plans will be approximately $69 million.

The decrease in pension income from 2023 to 2024 is driven primarily by higher amortization of actuarial loss due to unrecognized actuarial loss arising in 2023, partially offset by the absence in 2024 of a 2023 SERP settlement charge and a decrease in the interest cost component due to a lower discount rate.

The increase in PBOP income from 2023 to 2024 is driven primarily by favorable expected return on assets due to a higher asset balance and a decrease in the interest cost component due to a lower discount rate.

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.

For the PBOP Plans, there is no amortization of actuarial loss in 2025.

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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.

Based on the current status of the Pension Plans and federal pension funding requirements, there is no minimum funding requirement for our Eversource Service Pension Plan in 2024 and we do not expect to make pension contributions in 2024.

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 2025 and we do not expect to make pension contributions in 2025.

It is our policy to fund the PBOP Plans annually through tax deductible contributions to external trusts.

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Pension Plans (excluding SERP Plans) PBOP Plans

Decrease in Plan Income Decrease in Plan Income

Decrease in Plan Income Decrease/(Increase) in Plan Income

(Millions of Dollars) For the Years Ended December 31, For the Years Ended December 31,

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Higher compensation rate 5.9 8.1 N/A N/A

We recorded goodwill on our balance sheet associated with previous mergers and acquisitions, all of which totaled $4.53 billion as of December 31, 2023.

We have identified our reporting units for purposes of allocating and testing goodwill as Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution.

Electric Distribution and Electric Transmission reporting units include carrying values for the respective components of CL&P, NSTAR Electric and PSNH.

The Natural Gas Distribution reporting unit includes the carrying values of NSTAR Gas, Yankee Gas and EGMA.

The Water Distribution reporting unit includes the Aquarion water utility businesses.

As of December 31, 2023, goodwill was allocated to the reporting units as follows:

$2.54 billion to Electric Distribution, $577 million to Electric Transmission, $451 million to Natural Gas Distribution and $961 million to Water Distribution.

Goodwill is recognized on our balance sheet from previous mergers and acquisitions to the extent that the consideration paid exceeded the net fair value of the identified assets and liabilities acquired in each business combination.

We are required to test goodwill balances for impairment at least annually by considering the fair values of the reporting units, which requires us to use estimates and judgments.

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Goodwill impairment is deemed to exist if the carrying amount of a reporting unit exceeds its estimated fair value.

If goodwill were deemed to be impaired, it would be written down in the current period to the extent of the impairment.

If goodwill were to be impaired, it would be written down in the current period to the extent of the impairment.

We have identified our reporting units for purposes of allocating and testing goodwill as Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution.

The Electric Distribution and Electric Transmission reporting units include carrying values for the respective components of CL&P, NSTAR Electric and PSNH.

The Natural Gas Distribution reporting unit includes the carrying values of NSTAR Gas, Yankee Gas and EGMA.

The Water Distribution reporting unit includes the Aquarion water utility businesses.

As of December 31, 2024, 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.

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.

A quantitative impairment test is required only if it is concluded that it is more likely than not that a reporting unit’s fair value is less than its carrying amount.

We performed an impairment assessment of goodwill as of October 1, 2023 for the Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution reporting units.

If we perform the qualitative assessment but determine it is more likely than not that a reporting unit’s fair value is less than its carrying amount, we perform a quantitative test to compare the fair value of the reporting unit to its carrying amount, including goodwill.

If the carrying amount of the reporting unit exceeds its fair value, we record an impairment loss as a reduction to goodwill and a charge to operating expenses, but the loss recognized would not exceed the total amount of goodwill allocated to the reporting unit.

We 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.

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.

The 2023 goodwill impairment assessment resulted in a conclusion that goodwill is not impaired.

We believe that the fair value of the reporting units was substantially in excess of carrying value.

In the fourth quarter of 2024, we concluded that the likely sale of Aquarion at a loss resulted in the requirement to perform an interim goodwill impairment test for Water Distribution goodwill.

We compared the estimated fair value of the business from the anticipated transaction to its carrying value.

Assumptions used in the valuation were the future cash flows from the sale, including the estimated income tax impacts as a result of the transaction.

Based on the interim impairment test, we recorded a goodwill impairment of $297 million to write down the carrying value of the water distribution reporting unit to its estimated fair value.

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.

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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 impairments occurred during the year 2023.

No significant impairments occurred during the year 2024.

Equity Method Investments:

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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.

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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.

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 estimate 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 are subject to inherent uncertainties and subjectivity.

The use of different assumptions, estimates, or judgments with respect to the estimation of future cash flows could materially change the impairment charges.

The impairment evaluations were based on best information available at the impairment assessment date.

Management will continue to monitor and evaluate all facts and circumstances in the offshore wind sales process and the impact on its investment balance.

See Note 6, “Investments in Unconsolidated Affiliates,” to the financial statements for further information on the impairments to Eversource’s offshore wind equity method investments carrying value.

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:

We make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information.

The assessment of loss contingencies involves judgments and assumptions about future events.

Our estimates are subject to revision in future periods based on actual costs or new information.

The amount recorded may differ from the actual expense incurred when the uncertainty is resolved.

Such difference would be a change in estimate and could have a significant impact on the financial statements.

Upon the sales of our offshore wind investments in 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.

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.

Accounting for Environmental Reserves:

Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated.

Increases to estimates of environmental liabilities could have an adverse impact on earnings.

We estimate these liabilities based on findings through various phases of the assessment, considering the most likely action plan from a variety of available remediation options (ranging from no action required to full site remediation and long-term monitoring), current site information from our site assessments, remediation estimates from third party engineering and remediation contractors, and our prior experience in remediating contaminated sites.

If a most likely action plan cannot yet be determined, we estimate the liability based on the low end of a range of possible action plans.

A significant portion of our environmental sites and reserve amounts relate to former MGP sites that were operated several decades ago and manufactured natural gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment, for which we may have potential liability.

Estimates are based on the expected remediation plan.

Our estimates are subject to revision in future periods based on actual costs or new information from other sources, including the level of contamination at the site, the extent of our responsibility or the extent of remediation required, recently enacted laws and regulations or a change in cost estimates.

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.

Accounting for Environmental Reserves:

Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated.

Increases to estimates of environmental liabilities could have an adverse impact on earnings.

If a most likely action plan cannot yet be determined, we estimate the liability based on the low end of a range of possible action plans.

Estimates are based on the expected remediation plan.

Fair Value Measurements:

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Taxes Other Than Income Taxes 997.9 940.4 57.5

Loss on Pending Sale of Aquarion 297.0 — 297.0

Total Operating Expenses 9,492.1 9,511.4 (19.3)

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Interest Expense 1,111.3 855.4 255.9

Impairments of Offshore Wind Investments 2,167.0 — 2,167.0

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

Other Income, Net 410.5 348.1 62.4

(Loss)/Income Before Income Tax Expense (275.0) 1,866.0 (2,141.0)

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

Income Tax Expense 424.7 159.7 265.0

Net (Loss)/Income (434.7) 1,412.4 (1,847.1)

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

Net Income Attributable to Noncontrolling Interests 7.5 7.5 —

Net (Loss)/Income Attributable to Common Shareholders $ (442.2) $ 1,404.9 $ (1,847.1)

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

Operating Revenues

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Sales Volumes (GWh) Percentage

Decrease Sales Volumes (MMcf) Percentage

Decrease Sales Volumes (MG) Percentage

Increase Sales Volumes (MMcf) Percentage

Increase Sales Volumes (MG) Percentage

2024 2023 2024 2023 2024 2023

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Base Distribution Revenues:

• Base electric distribution revenues increased $36.6 million due primarily to a base distribution rate increase at NSTAR Electric effective January 1, 2023.

• Base natural gas distribution revenues increased $18.5 million due primarily to base distribution rate increases effective November 1, 2023 and November 1, 2022 at NSTAR Gas and effective November 1, 2022 at EGMA.

• 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.

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

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.

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.

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).

Tracked Distribution Revenues:

Tracked distribution revenues consist of certain costs that are recovered from customers in retail rates through regulatory commission-approved cost tracking mechanisms and therefore, recovery of these costs has no impact on earnings.

Tracked distribution revenues consist of certain costs that are recovered from customers in retail rates on a fully reconciling basis through regulatory commission-approved cost tracking mechanisms and therefore, recovery of these costs has no impact on earnings.

Costs recovered through cost tracking mechanisms include, among others, energy supply and natural gas supply procurement, state mandated energy purchase agreements and other energy-related costs, electric retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for the Massachusetts utilities, pension and PBOP benefits, net metering for distributed generation, and solar-related programs.

Revenues from certain of these cost tracking mechanisms also include certain incentives earned, return on capital tracking mechanisms, and carrying charges that are billed in rates to customers, which do impact earnings.

Costs recovered through cost tracking mechanisms include, among others, energy supply and natural gas supply procurement and other energy-related costs, electric retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for the Massachusetts utilities, pension and PBOP benefits, net metering for distributed generation, and solar-related programs.

Tracked revenues also include wholesale market sales transactions, such as sales of energy and energy-related products into the ISO-NE wholesale electricity market, sales of natural gas to third party marketers, and the sale of RECs to various counterparties.

Customers have the choice to purchase electricity from each Eversource electric utility or from a competitive third party supplier.

Customers have the choice to purchase electricity from their Eversource electric utility or from a competitive third party supplier.

For customers who have contracted separately with these competitive suppliers, revenue is not recorded for the sale of the electricity commodity, as the utility is acting as an agent on behalf of the third party supplier.

For customers that choose to purchase electric generation from CL&P, NSTAR Electric or PSNH, each 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.

Certain eligible natural gas customers may elect to purchase natural gas from each Eversource natural gas utility or may contract separately with a

Certain eligible natural gas customers may elect to purchase natural gas from their Eversource natural gas utility or may contract separately with a

gas supply operator.

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operators, only the delivery to a customer, as the utility is acting as an agent on behalf of the gas supply operator.

Tracked distribution revenues increased/(decreased) in 2023, as compared to 2022, due primarily to the following:

The variance in tracked distribution revenues in 2024, as compared to 2023 is due primarily to the following:

(Millions of Dollars) Electric Distribution Natural Gas Distribution

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Energy supply procurement $ (1,239.6) $ (165.2)

CL&P FMCC (330.1) —

CL&P NBFMCC 544.9 —

NSTAR Electric net metering 133.1 —

Stranded costs 127.1 —

Retail transmission 98.9 —

Energy efficiency 2.3 38.1

CL&P System Benefit Charge 88.4 —

Other distribution tracking mechanisms 159.2 44.0

Wholesale Market Sales Revenue 33.9 (44.8)

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

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

Fluctuations in retail transmission revenues are driven by the recovery of the costs of our wholesale transmission business, such as those billed by ISO-NE and Local and Regional Network Service charges.

For further information, see " Purchased Power, Purchased Natural Gas and Transmission " expense below.

The decrease in CL&P’s FMCC revenues was driven by a decrease in the retail Non-Bypassable Federally Mandated Congestion Charge (NBFMCC) rate, which reflects the impact of returning net benefits of higher wholesale market sales received in the ISO-NE market for long-term state approved energy contracts at CL&P, which are then credited back to customers through the retail NBFMCC rate.

CL&P’s average NBFMCC rate in effect from January 1, 2022 through April 30, 2022 was $0.01423 per kWh and from May 1 through August 31, 2022 was $0.01251 per kWh.

As a result of the CL&P RAM proceeding in Docket No.

22-01-03, CL&P reduced the average NBFMCC rate effective September 1, 2022 from $0.01251 per kWh to $0.00000 per kWh.

As part of a November 2022 rate relief plan, CL&P further reduced the average NBFMCC rate effective January 1, 2023 to a credit of $0.01524 per kWh.

These rate reductions returned to customers the net revenues generated by long-term state-approved energy contracts with the Millstone and Seabrook nuclear power plants.

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

As a result of the 2023 CL&P RAM decision, the average NBFMCC rate changed to $0.00293 per kWh effective September 1, 2023.

The decrease in electric distribution wholesale market sales revenue was due primarily to lower average electricity market prices received for wholesale sales at CL&P, NSTAR Electric and PSNH.

ISO-NE average market prices received for CL&P’s wholesale sales decreased to an average price of $36.60 per MWh in 2023, as compared to $82.88 per MWh in 2022, driven primarily by lower 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 that CL&P entered into in 2019, as required by regulation.

CL&P sells the energy purchased from Millstone and Seabrook into the wholesale market and uses the proceeds from the energy sales to offset the contract costs.

The net sales or net cost amount is refunded to, or recovered from, customers in the non-bypassable component of the CL&P FMCC rate.

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 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.

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.

Electric Transmission Revenues :

Electric transmission revenues increased $107.2 million due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure.

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.

Other Revenues and Eliminations:

Other revenues primarily include the revenues of Eversource's service company, most of which are eliminated in consolidation.

Eliminations are also primarily related to the Eversource electric transmission revenues that are derived from ISO-NE regional transmission charges to the distribution businesses of CL&P, NSTAR Electric and PSNH that recover the costs of the wholesale transmission business in rates charged to their customers.

Eliminations are also related to the Eversource electric transmission revenues that are derived from ISO-NE regional transmission charges to the distribution businesses of CL&P, NSTAR Electric and PSNH that recover the costs of the wholesale transmission business in rates charged to their customers.

Purchased Power, Purchased Natural Gas and Transmission expense includes costs associated with providing electric generation service

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The variance in energy supply procurement costs is offset in Operating Revenues (tracked energy supply procurement revenues).

The decrease in other electric distributions costs was primarily the result of a decrease in long-term renewable contract costs and lower net metering costs at NSTAR Electric, partially offset by higher long-term contractual energy-related costs at CL&P that are recovered in the non-bypassable component of the FMCC mechanism, and by higher net metering costs at PSNH.

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.

Costs at the natural gas distribution segment relate to supply procurement costs for retail customers.

Total natural gas costs decreased due primarily to lower average prices and lower average purchased supply volumes, partially offset by an increase in the retail cost deferral.

The decrease in transmission costs was primarily the result of a decrease in the retail transmission cost deferral, which reflects the actual cost of transmission service compared to estimated amounts billed to customers and a decrease in costs billed by ISO-NE that support regional grid investments.

These decreases were partially offset by an increase in Local Network Service charges, which reflect the cost of transmission service provided by Eversource over our local transmission network.

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.

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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Base Electric Distribution (Non-Tracked Costs):

Shared corporate costs (including IT system depreciation at Eversource Service) $ 41.4

Storm costs 13.3

Employee-related expenses (including labor and benefits) $ 22.7

Uncollectible expense 14.9

Shared corporate costs (including IT system depreciation at Eversource Service) 11.2

Operations-related expenses (including vegetation management, vendor services, vehicles and materials) 6.3

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

Absence in 2023 of energy assistance program as part of CL&P rate relief plan (10.0)

Employee-related expenses, including labor and benefits (9.2)

Operations-related expenses (including vegetation management, vendor services and vehicles) (7.8)

Storm-related costs (4.5)

Total Base Electric Distribution (Non-Tracked Costs) 54.4

Tracked Electric Costs (Electric Distribution and Electric Transmission) - Increase due primarily to higher uncollectible expense and higher funding of NSTAR Electric storm reserve as part of January 1, 2023 rate change, partially offset by lower pension tracking mechanism at NSTAR Electric 44.7

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

Total Electric Distribution and Electric Transmission 152.4

Natural Gas Distribution:

Base (Non-Tracked Costs) - Increase due primarily to higher uncollectible expense and shared corporate costs, partially offset by lower employee-related expenses 6.5

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

Tracked Costs 11.0

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Water Distribution 3.8

Parent and Other Companies and Eliminations:

Eversource Parent and Other Companies - other operations and maintenance 26.8

Transaction and Transition Costs (17.8)

Eliminations (62.6)

Total Operations and Maintenance $ 117.2

Depreciation expense increased due primarily to higher net plant in service balances, partially offset by a decrease in approved depreciation rates as part of the rate case decision effective January 1, 2023 at NSTAR Electric.

Depreciation expense increased due primarily to higher net plant in service balances.

Amortization expense includes the deferral of energy-related costs and other costs that are included in certain regulatory commission-approved cost tracking mechanisms.

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These costs are recovered from customers in rates and have no impact on earnings.

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

Amortization decreased 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 decrease in the CL&P FMCC mechanism was driven primarily by the November 2022 rate relief plan, which reduced the non-bypassable FMCC rate effective January 1, 2023.

The decrease was also driven by the impact of a new regulatory tracking mechanism at PSNH that allows for the recovery of operating expenses associated with poles acquired from Consolidated Communications on May 1, 2023.

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 decrease was partially offset by the amortization of historical exogenous property taxes that were approved for recovery effective January 1, 2023 at NSTAR Electric and effective November 1, 2022 at NSTAR Gas and EGMA, and an unfavorable regulatory adjustment resulting from NSTAR Gas’ GSEP reconciliation filing that resulted in an increase to amortization expense of $9.0 million recorded in 2023 .

Energy Efficiency Programs expense increased due primarily to the deferral adjustment and the timing of the recovery of energy efficiency costs at NSTAR Gas and EGMA, partially offset by a decrease at NSTAR Electric.

The deferral adjustment reflects the actual costs of energy efficiency programs compared to the amounts billed to customers.

The costs for the majority of the state energy policy initiatives and expanded energy efficiency programs are recovered from customers in rates and have no impact on earnings.

Taxes Other Than Income Taxes expense increased due primarily to higher employment-related taxes based on the timing of payroll pay periods, higher property taxes as a result of higher assessments and higher utility plant balances, and higher Connecticut gross earnings taxes.

Interest Expense increased due primarily to an increase in interest on long-term debt as a result of new debt issuances ($200.3 million), an increase in interest on short-term notes payable ($43.8 million), higher amortization of debt discounts and premiums, net ($2.7 million), and an increase in interest expense on regulatory deferrals ($1.3 million), partially offset by an increase in capitalized AFUDC related to debt funds and other capitalized interest ($63.1 million), and a decrease in RRB interest expense ($1.3 million).

Impairments of Offshore Wind Investments relates to impairment charges in the second and fourth quarters of 2023 associated with Eversource’s offshore wind equity method investments resulting from the expected sale of the 50 percent interests in three jointly-owned offshore wind projects.

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

Other Income, Net increased due primarily to an increase in interest income primarily from regulatory deferrals ($43.7 million) and an increase in capitalized AFUDC related to equity funds ($30.8 million), partially offset by a decrease related to pension, SERP and PBOP non-service income components ($86.9 million), a loss on the disposition of land in 2023 compared to gains on the sales of property in 2022 ($9.0 million), a decrease in equity in earnings related to Eversource’s equity method investments ($7.4 million), and investment losses in 2023 compared to investment income in 2022 driven by market volatility ($6.8 million).

Other Income, Net also increased due to 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.

Income Tax Expense decreased due primarily to lower pre-tax earnings ($449.6 million), lower state taxes ($3.4 million), a decrease in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($7.4 million), an increase in amortization of EDIT ($2.4 million), and lower return to provision adjustments ($66.7 million), partially offset by lower share-based payment excess tax benefits ($2.6 million), and an increase in reserves ($233.0 million) primarily related to the impairment of Eversource’s offshore wind investment valuation allowance reserve of $224.0 million and $8.8 million relating to an uncertain tax position.

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.

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).

RESULTS OF OPERATIONS –

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Depreciation 406.5 376.9 29.6 407.7 372.6 35.1 154.1 140.4 13.7

Amortization of Regulatory (Liabilities)/Assets, Net (500.3) 335.6 (835.9) 16.1 83.9 (67.8) (16.3) 42.9 (59.2)

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

Energy Efficiency Programs 171.7 133.5 38.2 263.4 325.6 (62.2) 42.9 39.6 3.3

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For the Years Ended December 31,

2023 2022 Decrease Percentage

2024 2023 Increase Percentage

CL&P 20,151 19,577 574 2.9 %

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Operating Revenues:

Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, decreased $238.9 million at CL&P, $67.6 million at NSTAR Electric, and $26.9 million at PSNH in 2023, as compared to 2022.

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.

Base Distribution Revenues:

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• NSTAR Electric's distribution revenues increased $105.3 million due primarily to a base distribution rate increase effective January 1, 2024.

• PSNH's distribution revenues decreased $0.8 million due primarily to a decrease in sales volumes as a result of milder weather in 2023 compared to 2022, partially offset by a base distribution rate increase effective August 1, 2022.

• PSNH's distribution revenues increased $35.8 million due primarily to a temporary base distribution rate increase effective August 1, 2024.

Tracked Distribution Revenues:

Costs recovered through cost tracking mechanisms include, among others, energy supply procurement, state mandated energy purchase agreements and other energy-related costs, retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for NSTAR Electric, pension and PBOP benefits, net metering for distributed generation, and solar-related programs.

Costs recovered through cost tracking mechanisms include, among others, energy supply procurement and other energy-related costs, retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for NSTAR Electric, pension and PBOP benefits, net metering for distributed generation, and solar-related programs.

Tracked revenues also include wholesale market sales transactions, such as sales of energy and energy-related products into the ISO-NE wholesale electricity market and the sale of RECs to various counterparties.

Customers have the choice to purchase electricity from each Eversource electric utility or from a competitive third party supplier.

Customers have the choice to purchase electricity from their Eversource electric utility or from a competitive third party supplier.

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 $ (710.5) $ (253.9) $ (275.2)

CL&P FMCC (330.1) — —

CL&P NBFMCC 544.9 — —

NSTAR Electric net metering — 133.1 —

Stranded costs 6.6 77.7 42.8

Retail transmission (9.8) 60.2 48.5

CL&P System Benefit Charge 88.4 — —

Other distribution tracking mechanisms 69.7 77.2 12.3

Wholesale Market Sales Revenue 62.8 (0.7) (28.2)

The increase in energy supply procurement at CL&P and NSTAR Electric was driven by higher average prices, partially offset by lower average supply-related sales volumes.

The decrease in energy supply procurement at PSNH was driven by lower average supply-related sales volumes, partially offset by higher average prices.

For further information, see " Purchased Power and Transmission " expense below.

CL&P’s average NBFMCC rate in effect from January 1, 2022 through April 30, 2022 was $0.01423 per kWh and from May 1 through August 31, 2022 was $0.01251 per kWh.

As a result of the CL&P RAM proceeding in Docket No.

22-01-03, CL&P reduced the average NBFMCC rate effective September 1, 2022 from $0.01251 per kWh to $0.00000 per kWh.

As part of a November 2022 rate relief plan, CL&P further reduced the average NBFMCC rate effective January 1, 2023 to a credit of $0.01524 per kWh.

These rate reductions returned to customers the net revenues generated by long-term state-approved energy contracts with the Millstone and Seabrook nuclear power plants.

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

As a result of the 2023 CL&P RAM decision, the average NBFMCC rate changed to $0.00293 per kWh effective September 1, 2023.

The decrease in wholesale market sales revenue was due primarily to lower average electricity market prices received for wholesale sales at CL&P, NSTAR Electric and PSNH.

CL&P’s volumes sold into the market were primarily from the sale of output generated by the Millstone PPA and Seabrook PPA that CL&P entered into in 2019, as required by regulation.

CL&P sells the energy purchased from Millstone and Seabrook into the wholesale market and uses the proceeds from the energy sales to offset the contract costs.

The net sales or net cost amount is refunded to, or recovered from, customers in the non-bypassable component of the CL&P FMCC rate.

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.