CONNECTICUT LIGHT & POWER CO

Current report

• cyber events or breaches, including acts of war or terrorism, affecting our systems or the systems of third parties on which we rely,

Current report

•unauthorized access to, and the misappropriation of, confidential and proprietary Company, customer, employee, financial or system operating information,

Current report

•adverse publicity, which can harm our reputation, influence legislative and regulatory bodies, and result in unfavorable outcomes,

Current report

•breakdown, failure of, or damage to operating equipment, information technology systems, or processes of our transmission and distribution systems,

Current report

•We earned $606.8 million, or $1.61 per share, in the first quarter of 2026, compared with $550.8 million, or $1.50 per share, in the first quarter of 2025. Our first quarter 2026 results include an after-tax charge of $43.9 million, or $0.12 per share, resulting from FERC’s March 19, 2026 order in the NETO ROE complaint proceedings, which was recorded within the Transmission segment. Excluding this charge, our non-GAAP earnings were $650.7 million, or $1.73 per share in the first quarter of 2026.

Current report

•We revised 2026 non-GAAP earnings guidance to be in the range of $4.57 per share and $4.72 per share taking into account the impact of the prospective reduction to the transmission ROE resulting from the March 19, 2026 FERC order and the potential Aquarion sale. We also expect that our cumulative long-term earnings per share growth rate will be within the range of 5 to 7 percent through 2030, using the adjusted 2026 non-GAAP earnings guidance mid-point of $4.65 per share as the base year. We expect annual earnings growth towards the upper half of the long-term guidance by 2028.

Current report

•On March 19, 2026, FERC issued an order in the NETO ROE proceedings, attempting to resolve all four pending complaints dating back to 2011. In the decision, FERC applied a revised ROE methodology and found the NETOs’ then-existing base ROE of 11.14 percent was unjust and unreasonable and established a replacement base ROE of 9.57 percent, with an incentive cap of 12.09 percent, for the first complaint period (October 1, 2011 through December 31, 2012), and prospectively effective October 16, 2014. FERC directed the NETOs to issue refunds with interest for applicable refund periods, subsequently extended the refund deadline to May 20, 2027, and dismissed the remaining complaints. As a result of the FERC decision, we determined that a loss is probable and estimated a range of reasonably possible pre-tax losses of $60.4 million to $932 million. We recorded a current regulatory liability of $60.4 million (pre-tax) as of March 31, 2026, which represents the low end of the range as no amount within this range is considered a better estimate. The NETOs have filed a request for rehearing with FERC. Eversource and Avangrid have filed a joint motion requesting a stay of the retroactive refund obligation applicable to the period October 16, 2014 through March 19, 2026 with the U.S. Court of Appeals for the D.C. Circuit Court. While we continue to challenge the March 19, 2026 FERC decision, we cannot predict the ultimate outcome of these proceedings.

Current report

•On April 30, 2026, the NETOs submitted a Federal Power Act Section 205 filing to FERC proposing a replacement base ROE of 11.39 percent, resulting in a cap of 12.89 percent including incentives, based on current market data utilizing FERC’s revised ROE methodology. The NETOs requested an effective date of June 30, 2026. FERC has 60 days to act on the rate proposal and can suspend the proposed rate change for up to five months after the initial 60-day notice. If a settlement is not reached among the parties to the FERC proceeding, Eversource would begin billing the proposed ROE by December 2026 on a subject-to-refund basis after the completion of a hearing on the matter.

Current report

•On March 25, 2026, PURA approved the sale of the Aquarion water business to the Aquarion Water Authority following remand from the Connecticut Superior Court. The closing of the transaction remains subject to appeals, regulatory processes, and customary closing conditions.

Current report

(1) In the first quarter of 2026, we recorded a pre-tax charge of $60.4 million as a result of the March 19, 2026 FERC decision in the FERC base ROE complaints. The charge reflects estimated refunds associated with the fifteen-month first complaint period, including interest accrued through March 31, 2026. For further information, see the “FERC Regulatory Matters” section included in this Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Current report

Our electric transmission segment earnings decreased $19.0 million in the first quarter of 2026, as compared to the first quarter of 2025, due primarily to the $43.9 million after-tax charge for the March 19, 2026 FERC decision in the FERC base ROE complaints. Excluding this charge, our electric transmission segment earnings increased $24.9 million in the first quarter of 2026, as compared to the first quarter of 2025, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure andhigher non-refundable transmission revenues, partially offset by higher interest expense.

Current report

Eversource Parent and Other Companies: Eversource parent and other companies losses increased by $19.1 million in the first quarter of 2026, as compared to the first quarter of 2025, due primarily to higher income tax expense and higher interest expense.

Current report

Cash totaled $270.2 million as of March 31, 2026, compared with $135.4 million as of December 31, 2025.

Current report

(1)The Eversource Parent Series A Junior Subordinated Notes bear interest at a fixed rate of 6.10 percent per year from August 15, 2026 to August 14, 2031. Thereafter, the interest rate resets every five years, commencing on August 15, 2031, at a rate per year equal to the five-year U.S. Treasury Rate plus a spread of 2.521 percent.

Current report

(2) The Eversource Parent Series B Junior Subordinated Notes bear interest at a fixed rate of 6.35 percent per year from August 15, 2026 to August 14, 2036. Thereafter, the interest rate resets every five years, commencing on August 15, 2036, at a rate per year equal to the five-year U.S. Treasury Rate plus a spread of 2.325 percent.

Current report

For our offshore wind contingent liability, payments made in the first quarter of 2026 reduced the liability and were reflected within investing activities on the statement of cash flows. Payments related to cost overruns for the Revolution Wind project paid to GIP.

Current report

Credit Ratings: On February 23, 2026, the junior subordinated debt of Eversource parent was assigned new ratings from S&P of BBB-, Moody’s of Baa3 and Fitch of BB+.

Current report

On November 19, 2025, PURA denied the application to approve the sale, finding that the transaction did not meet managerial suitability and responsibility requirements due to concerns with governance and oversight structure over Aquarion and its consumer advocate. On December 2, 2025, the denial was appealed to the Connecticut Superior Court. On January 15, 2026, the Court issued its decision, sustaining the appeal and remanding back to PURA, finding that PURA acted illegally in denying the application as those disputed governance elements were mandated under Connecticut law. The Court upheld that operational aspects of the consumer advocate were within PURA’s statutory authority and regulatory discretion.

Current report

On March 25, 2026, upon remand from the Connecticut Superior Court, PURA reversed its November 2025 decision and approved the sale of Aquarion to AWA. As conditions of PURA’s approval, prior to closing, Eversource will contribute $10 million into a rate stabilization fund for the future benefit of Aquarion customers and will return to customers revenues collected and held in escrow related to the 2022 rate case appeal.

Current report

Despite PURA approval of the transaction, legal opposition, including the potential for appeals, introduces significant uncertainty regarding the ultimate timing and consummation of the sale. As a result, the Company cannot assert that the sale of Aquarion is probable and concluded that the held‑for‑sale criteria were not met as of March 31, 2026. Closing of the transaction remains subject to finalization of working capital and other transaction-related adjustments and final closing costs, which could result in a loss recognized either upon meeting held for sale classification and measurement or at the time of sale.

Current report

On March 19, 2026, FERC issued Opinion No. 594 in the NETO ROE proceedings, attempting to resolve all four pending complaints dating back to 2011 and respond to the D.C. Circuit Court’s April 14, 2017 decision vacating FERC’s prior decision in the first complaint, which found that the FERC had failed to (1) make an explicit, reasoned finding that the then-existing 11.14 percent base ROE was unjust and unreasonable before imposing a replacement ROE, and (2) adequately justify placing the ROE at the midpoint of the upper half of the zone of reasonableness. In Opinion No. 594, FERC applied a revised ROE methodology that it believes is consistent with its 2024 ROE Order on remand to the Midcontinent ISO (MISO) transmission owners, to satisfy the first step in the FERC process to revise the ROE in a Section 206 proceeding by finding the NETOs’ base ROE of 11.14 percent is unjust and unreasonable. FERC then found the just and reasonable replacement base ROE to be 9.57 percent with an incentive cap of 12.09 percent for the first complaint period (October 1, 2011 – December 31, 2012) and applied this same ROE prospectively, effective October 16, 2014, the date of the first complaint order vacated by the D.C. Circuit Court. FERC directed the NETOs to issue refunds with interest for the applicable refund periods. This decision decreases the allowed base ROE of 10.57 percent with an incentive cap of 11.74 percent to a base ROE of 9.57 percent with an incentive cap of 12.09 percent. The second, third and fourth NETO ROE complaints were dismissed as part of the decision and FERC did not direct any refunds for the periods associated with those proceedings.

Current report

On April 14, 2026, FERC granted an extension of the refund deadline to May 20, 2027. On April 14, 2026, Eversource and Avangrid filed a joint motion requesting a stay of the retroactive refund obligation applicable to the period October 16, 2014 through March 19, 2026 (retroactive refund period) with the D.C. Circuit Court.

Current report

On April 20, 2026, the NETOs submitted to FERC a request for rehearing of Opinion No. 594 to reconsider its decision by highlighting several deficiencies including but not limited to the unlawful retroactive refund period with interest extended beyond the 15-month statutory relief authority granted in Section 206(b) of the Federal Power Act, the FERC not proving that the previously approved 11.14 percent base ROE was unjust and unreasonable as remanded by the D.C. Circuit Court, the flawed methodologies applied in setting the replacement 9.57 percent base ROE, failing to comply with the requirement for FERC to use data that is relevant to the current period at the time of the decision for the NETOs’ going forward ROE, and procedural issues related to overlapping complaints.

Current report

On April 30, 2026, the NETOs submitted a Federal Power Act Section 205 filing to FERC, which is a formal request by a public utility to change the ROE rate prospectively and requires the utility to prove the proposed change is just and reasonable. The NETOs proposed a replacement ROE of 11.39 percent, resulting in a cap of 12.89 percent including incentives, which is based on current market data utilizing FERC’s ROE methodology from Opinion No. 594. The NETOs requested an effective date of June 30, 2026. FERC has 60 days to act on the rate proposal and can suspend the proposed rate change for up to five months after the initial 60-day notice. If a settlement is not reached among the parties to the FERC proceeding, Eversource would begin billing the proposed ROE by December 2026 on a subject-to-refund basis after the completion of a hearing on the matter.

Current report

As a result of the March 19, 2026 FERC decision, Eversource has determined that a loss is probable and that a range of loss is reasonably estimable. Based on Eversource’s current evaluation of the relevant facts and circumstances, the Company has estimated a range of reasonably possible pre-tax losses of $60.4 million to $932 million, which includes a range of interest of $28.8 million to $256 million, as of March 31, 2026. The low end of the estimated range of loss reflects estimated refunds associated with the fifteen-month first complaint period, including interest. The high end of the estimated range of loss includes the refunds associated with the first complaint period, as well as estimated refunds for the retroactive refund period from October 16, 2014 through March 19, 2026, including interest, in the pre-tax amount of approximately $871 million. The range of loss estimates use the 9.57 percent replacement ROE and incentive cap of 12.09 percent prescribed in the March 19, 2026 FERC decision. Based on Eversource’s legal assessment of the Federal Power Act and the legal and regulatory deficiencies underlying this decision as identified in the rehearing request, including that the retroactive application is inconsistent with the statutory limitations under the Federal Power Act, Eversource does not believe that refunds at the high end of the range for the retroactive period are probable. Eversource continues to challenge the March 19, 2026 FERC decision, but cannot predict the ultimate outcome of these proceedings.

Current report

The Company has recorded a current regulatory liability for revenues subject to refund of $60.4 million (pre-tax) as of March 31, 2026, which represents the low end of the range, as no amount within this range is considered a better estimate. The liability recorded reflects the difference between the billed 10.57 percent base ROE and the new 9.57 percent base ROE for the first complaint period, including interest. The liability consists of $28.7 million, $24.2 million and $7.5 million for CL&P, NSTAR Electric and PSNH, respectively, of which $13.7 million, $11.5 million and $3.6 million is accrued interest, respectively, as of March 31, 2026. The revenues subject to refund were recorded as a reduction to Operating Revenues and the accrued interest was recorded as an increase to Interest Expense in the statements of income. Eversource does not have any other reserves recorded for the other complaint periods, as these remaining complaints were dismissed.

Current report

The Company’s estimates are based on currently available information; however, it is reasonably possible that the ultimate resolution of this matter may result in a loss in excess of the amount accrued, and such additional losses could have a material impact on the financial condition, results of operations, and cash flows in a future period.

Current report

The reduction in the base ROE from 10.57 percent to 9.57 percent is expected to lower Eversource's future annual after-tax earnings by approximately $70 million, estimated using 2025 rate base, and would increase over time as we continue to invest in our transmission infrastructure. The change in the related specific transmission incentive adders would partially offset the reduced annual after-tax earnings by approximately $5 million.

Current report

On May 4, 2026, PURA issued a notice of proceeding to consider whether the issuance of rate reduction bonds for the securitization of approved storm costs is in the best interest of rate payers. A timeline in this proceeding has not yet been established.

Current report

Aquarion Water Company of Connecticut Distribution 2026 Rate Case: On March 2, 2026, Aquarion Water Company of Connecticut (AWC-CT) filed an application with PURA to amend its existing rate schedules to address an operating revenue deficiency. AWC-CT’s rate application requested approval of an increase to authorized revenues of $87.6 million for the rate year beginning November 25, 2026, comprised of a proposed base rate increase of $61.4 million inclusive of capital projects placed into service between 2022 and June 2026 and a surcharge revenue requirement of $26.2 million inclusive of capital additions between July 2026 and June 2027. On April 21, 2026, PURA issued correspondence in this proceeding revising the application date to April 8, 2026 and establishing a procedural schedule for the docket. Proposed and final decisions are expected from PURA on November 17, 2026 and December 23, 2026, respectively.

Current report

Massachusetts 2026 Winter Bill Relief Program: In February 2026, NSTAR Electric, NSTAR Gas and EGMA implemented a winter electric and natural gas bill relief program, as approved by the DPU. Under this program, in February and March 2026, Massachusetts residential electric customers received an aggregate bill reduction of approximately 25 percent, a portion of which was funded by the Commonwealth of Massachusetts, and residential natural gas customers received an aggregate bill reduction of approximately 10 percent. These bill credits were deferred and will be recovered between April and December 2026 for electric customers and between May and October 2026 for natural gas customers. No carrying charges will be collected. The bill relief program results in delayed collections from customers, impacting the timing of cash flows. Proceeds of $84.1 million were received by NSTAR Electric from the Commonwealth of Massachusetts in January 2026 and reduced regulatory assets recorded on its balance sheet in the first quarter of 2026.

Current report

Massachusetts: On March 16, 2026, Massachusetts Governor Healey signed Executive Order No. 654, which establishes a statewide plan to expand energy supply, affordability, and reliability. The order sets targets of ten GW of new energy resources and five GW of energy storage online or under development by 2035. Resources includes solar, wind, storage, nuclear, geothermal, natural gas, and demand‑side resources such as energy efficiency, virtual power plants, and managed EV charging. The order directs state agencies to streamline permitting, reform interconnection and procurement processes, diversify fuel supply, and strengthen grid resilience to ensure Massachusetts can meet projected load growth while keeping energy affordable and reliable. It directs the DPU to require electric distribution companies to accelerate interconnection, implement flexible interconnection and cost-recovery mechanisms, and advance time-of-use rates and distributed energy resources. The order also promotes coordination with utilities to streamline solar and storage deployment and modernize grid infrastructure. For natural gas, it underscores the continued role of existing infrastructure, while requiring evaluation of gas supply and storage capacity and delivery capabilities to promote energy affordability and reliability.

Current report

New Hampshire: On April 15, 2026, New Hampshire enacted legislation authorizing electric utilities to recover certain storm‑related costs through securitization, subject to approval by the NHPUC. Under the legislation, eligible storm costs include prudently incurred costs associated with storm preparation, emergency response, and system restoration activities, as well as related financing and transaction costs. Recovery through securitization would occur pursuant to one or more NHPUC finance orders issued following a utility petition and hearing process. If approved, securitized costs would be recovered over a defined period through customer charges designed to provide timely recovery of principal, interest, and associated expenses, generally at interest rates lower than PSNH’s authorized return on equity. This legislation provides a potential alternative to traditional storm cost recovery mechanisms and is intended to mitigate the near‑term cash flow and customer bill impacts of significant storm events. While the legislation does not affect the recovery of storm costs previously incurred, it may influence the manner and timing of recovery of qualifying storm costs incurred in future periods.

Current report

Base Distribution Revenues: Base distribution rates are the approved, regulated charges to recover the utility’s cost of service, including operations and building and maintaining infrastructure, that allow utilities to recover investments and earn a reasonable return. Base distribution rates are established in base rate proceedings and approved by state regulators. Fluctuations in base distribution revenues impact earnings. Base distribution revenues include the impact of the revenue decoupling mechanism, which qualifies as an alternative revenue program (ARP). The increase at Electric Distribution is due primarily to base distribution rate increases at NSTAR Electric effective January 1, 2026 and at PSNH effective August 1, 2025. The increase at Natural Gas Distribution is due primarily to base distribution rate increases effective November 1, 2025 at Yankee Gas, at NSTAR Gas and at EGMA.

Current report

•electric retail transmission charges;

Current report

•state-mandated charges incurred in furtherance of grid reliability, affordability, clean energy and other energy policy directives from the state, such as energy purchase agreements required by legislation and regulation and other energy-related costs, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), hardship and low income programs, net metering for distributed generation, and additionally for NSTAR Electric solar-related programs; and

Current report

Operating Revenues do not directly correlate to charges on a customer’s bill and cannot be used to determine the percentage of a customer’s bill that contributes to various charges or programs. Differences between total company operating revenues and rates on a customer’s bill can arise due to customer class allocations and rate design, application of regulatory accounting, and other factors. For customers who have contracted with competitive third-party suppliers or gas supply operators, revenue is not recorded for the sale of the electricity or natural gas commodity, which, for those customers, represents a significant portion of a bill but is not reflected in total company operating revenues.

Current report

The CL&P SBC retail rates in effect in the first quarter of 2026 were lower than those in the first quarter of 2025. These lower collections resulted in a corresponding decrease to amortization expense of $37.4 million for the CL&P SBC deferral adjustment.

Current report

Interest Expense increased for thethree month period due to the following:

Current report

Other Income, Net increased for thethree month period due to the following:

Previous report

• cyberattacks or breaches, including those resulting in the compromise of the confidentiality of our proprietary information and the personal information of our customers,

Previous report

•We earned $367.5 million, or $0.99 per share, in the third quarter of 2025, compared with a loss of $118.1 million, or $0.33 per share, in the third quarter of 2024. We earned $1.27 billion, or $3.44 per share, in the first nine months of 2025, compared with $739.1 million, or $2.08 per share, in the first nine months of 2024.

Previous report

•Our 2025 results include an aggregate net after-tax charge resulting from our previous offshore wind investments of $75.0 million, or $0.20 per share. Our 2024 results include an after-tax loss on the sale of our offshore wind investments of $524.0 million, or $1.48 per share for the nine month period. These 2025 and 2024 charges were recorded within Eversource Parent and Other Companies. Excluding these charges, our 2025 non-GAAP earnings were $442.5 million, or $1.19 per share, in the third quarter of 2025 and $1.35 billion, or $3.64 per share, in the first nine months of 2025, and our 2024 non-GAAP earnings were $405.9 million, or $1.13 per share, in the third quarter of 2024 and $1.26 billion, or $3.56 per share, in the first nine months of 2024.

Previous report

•We narrowed our projection to earn within a 2025 non-GAAP earnings guidance range of between $4.72 per share and $4.80 per share excluding the impact of the net charge resulting from our previous offshore wind investments, compared to the previous guidance range of $4.67 per share to $4.82 per share. We also reaffirmed our projection that our expected 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.

Previous report

•On November 5, 2025, PURA issued a final decision in the Yankee Gas distribution rate case that included a distribution rate increase of $95.7 million ($82.2 million including a previously recorded non-firm margin rate credit), effective November 1, 2025. The final decision also established an authorized net regulatory ROE of 9.32 percent and a 53 percent common equity ratio for Yankee Gas’ capital structure.

Previous report

•On July 25, 2025, the NHPUC issued its decision in the PSNH distribution rate case and approved a permanent rate increase of $100.7 million, effective August 1, 2025, inclusive of the temporary rate increase that went into effect in August 2024. The order established an authorized regulatory ROE of 9.5 percent with a 50 percent common equity ratio for PSNH’s capital structure. The NHPUC approved an alternative regulatory framework that authorizes formulaic annual revenue adjustments on August 1st of 2026, 2027 and 2028. PSNH is required to file its next base distribution rate case for effect in June 2029 and committed not to file its next distribution rate case until 2029. The alternative regulatory framework calculates the annual revenue adjustment using a productivity factor and an adjustment for inflation to provide PSNH with increased revenue for operations, and also contains an exogenous events recovery mechanism, a performance metric, and an earnings sharing mechanism.

Previous report

(1)In the third quarter of 2025, we recorded a pre-tax charge of $284 million associated with increasing our offshore wind contingent liability for expected future payments under the terms of the 2024 sale agreement with GIP for the South Fork Wind and Revolution Wind projects, offset by expected tax benefits from the offshore wind sale of $209 million. In the third quarter of 2024, we recorded a pre-tax loss on the sales of our offshore wind investments of $464.0 million and a $60 million increase in income tax expense, resulting in an after-tax loss of $524.0 million. For further information, see the “Offshore Wind Contingent Liability” section below included in this Management's Discussion and Analysis of Financial Condition and Results of Operations.

Previous report

Those earnings increases were partially offset by higher property tax expense, higher interest expense, higher depreciation expense, lower net interest income on regulatory deferrals, and higher operations and maintenance expense.

Previous report

Our electric transmission segment earnings increased $10.6 million and $52.4 million in the third quarter and the first nine months of 2025, respectively, as compared to the third quarter and the first nine months of 2024, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure. Earnings in the nine month period also benefited from lower interest expense.

Previous report

Eversource Parent and Other Companies: Eversource parent and other companies’ losses decreased by $448.3 million and $380.1 million in the third quarter and the first nine months of 2025, respectively, as compared to the third quarter and the first nine months of 2024, due primarily to an after-tax charge of $524.0 million recorded in the third quarter of 2024 resulting from the sale of Eversource parent’s offshore wind investments, as compared to an aggregate net after-tax charge of $75.0 million recorded in the third quarter of 2025 resulting from an increase to the offshore wind contingent liability, net of tax benefits associated with the tax losses on the sales of its offshore wind investments.

Previous report

Excluding these charges, Eversource parent and other companies earnings decreased by $0.7 million and losses increased by $68.9 million in the third quarter and the first nine months of 2025, respectively, due primarily to higher interest expense due to the absence in 2025 of capitalized interest as a result of the sale of our offshore wind projects in the third quarter of 2024 and higher interest costs from short-term debt, partially offset by a lower effective rate resulting from the recognition of state tax benefits and certain tax credits as a result of the 2024 tax return to provision process in the third quarter of 2025.

Previous report

Offshore Wind Contingent Liability: Eversource recorded a contingent liability relating to expected future payments to GIP as part of the September 30, 2024 sale of the South Fork Wind and Revolution Wind projects. As part of the definitive agreement with GIP, Eversource is responsible for certain post-closing purchase price adjustments. This obligation included an expected cost overrun sharing obligation, an expected obligation to maintain GIP’s internal rate of return, and an obligation for other future costs.

Previous report

In the third quarter of 2025, Eversource received an updated report from GIP on the construction status of Revolution Wind, which included revised projections of total construction costs. The revised cost projections reflected known and quantifiable cost increases, including those associated with the impacts of damage to the wind turbine installation vessel, insurance costs, tariff impacts, and costs incurred as a result of the stop-work order for Revolution Wind received on August 22, 2025 from the Bureau of Ocean Energy Management that halted all offshore wind construction activities through September 22, 2025. Based on these developments and information currently available, in the third quarter of 2025 Eversource recognized a pre-tax charge of $284 million as a result of the aggregate impact of these items, to increase the liability for purchase price adjustments associated with the offshore wind projects. As of September 30, 2025 and December 31, 2024, the contingent liability totaled $507.7 million and $365 million, respectively.

Previous report

Eversource relies on information that it receives from the project owners for both the final completed cost of South Fork Wind and construction-related costs of Revolution Wind. Eversource uses its judgment to adjust, as needed, its expected obligations to GIP while construction of Revolution Wind is completed, which continues to be expected in the second half of 2026.

Previous report

New information or future developments that arise as the construction of Revolution Wind progresses will necessitate a reassessment of the estimated liability related to the obligations to GIP. The Company reviews available projections of total construction costs, including the latest cost estimates and project timeline, to determine if any changes to this liability are warranted.

Previous report

It is reasonably possible that as additional updated cost estimates become available, and if additional cost overruns materialize or other adverse changes in facts, regulations and circumstances occur, it could result in additional losses and increases to the offshore wind contingent liability, which could be material. The Company will continue to monitor developments and evaluate potential exposures related to this contingency and will revise its estimated liability as additional information becomes available.

Previous report

Contingencies are evaluated using the best information available at the time the financial statements are published, and this assessment involves judgments and assumptions about future events. Factors that could increase the obligation to GIP include construction cost overruns for Revolution Wind as well as the extent of construction delays, which would impact the economics associated with the purchase price adjustment, and the eligibility for federal investment tax credits for Revolution Wind at a lower value than assumed and included in the purchase price. The purchase price of Revolution Wind included the sales value related to a 40 percent level of federal investment tax credits. A change in the expected value or qualification of investment tax credit adders could result in a significant loss in a future period.

Previous report

As a result of the increase to the offshore wind contingent liability, Eversource recognized an aggregate, net after-tax charge of $75.0 million, or $0.20 per share, in the third quarter of 2025. This charge consists of the pre-tax $284 million increase to the offshore wind contingent liability, offset by $209 million of tax benefits associated with tax losses on the sale of the South Fork Wind and Revolution Wind projects that Eversource expects to realize.

Previous report

2024 Loss Recorded Upon Sale of Offshore Wind Investments: The three and nine months ended September 30, 2024 statements of income include a loss resulting from the sale of Eversource’s offshore wind investments. On July 9, 2024, Eversource completed the sale of its 50 percent ownership share of Sunrise Wind to Ørsted. On September 30, 2024, Eversource completed the sale of its 50 percent ownership share in the South Fork Wind and Revolution Wind projects to GIP. Upon the completion of both of these sale transactions, 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 after-tax loss on the sale of its offshore wind investments of $524 million, which included a net $60 million increase in income tax expense including an increase in the valuation allowance for unused capital losses, in the third quarter of 2024.

Previous report

Eversource is currently in the process of selling its Aquarion water distribution business. For information regarding the pending sale and expected 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.

Previous report

Cash and cash equivalents totaled $259.3 million as of September 30, 2025, compared with $26.7 million as of December 31, 2024.

Previous report

As a result of the Eversource parent long-term debt issuance in October 2025, $595.0 million of current portion of long-term debt was reclassified to Long-Term Debt on Eversource parent’s balance sheet as of September 30, 2025. As a result of the NSTAR Electric long-term debt issuance in October 2025, $305.4 million of current portion of long-term debt was reclassified to Long-Term Debt on NSTAR Electric’s balance sheet as of September 30, 2025.

Previous report

Payments made in 2025 related to Eversource’s offshore wind contingent obligation, which include a purchase price adjustment payment related to the South Fork Wind project, are reflected in investing activities on the statement of cash flows.

Previous report

Credit Ratings: On September 15, 2025, Fitch revised the outlook from stable to watch negative for Eversource parent, CL&P, NSTAR Electric and PSNH due to the stop-work order for the Revolution Wind project.

Previous report

The assets and liabilities of the Aquarion water distribution business met the criteria to be classified as held for sale and have been classified separately as current or long-term assets and liabilities held for sale on the Eversource balance sheets as of September 30, 2025 and December 31, 2024. Closing of the transaction will include the finalization of working capital and other closing adjustments as well as final closing costs, which could result in a loss recorded at the time of sale. For further information, see Note 18, “Assets Held for Sale.”

Previous report

All amounts associated with the first complaint period have been refunded. Eversource has recorded a reserve of $39.1 million (pre-tax and excluding interest) for the second complaint period as of both September 30, 2025 and December 31, 2024. This reserve represents the difference between the billed rates during the second complaint period and a 10.57 percent base ROE and 11.74 percent incentive cap. The reserve consisted of $21.4 million for CL&P, $14.6 million for NSTAR Electric and $3.1 million for PSNH as of both September 30, 2025 and December 31, 2024.

Previous report

On October 16, 2018, FERC issued an order on all four complaints describing how it intends to address the issues that were remanded by the Court. FERC proposed a new framework to determine (1) whether an existing ROE is unjust and unreasonable and, if so, (2) how to calculate a replacement ROE. Initial briefs were filed by the NETOs, Complainants and FERC Trial Staff on January 11, 2019 and reply briefs were filed on March 8, 2019. The NETOs' brief was supportive of the overall ROE methodology determined in the October 16, 2018 order provided the FERC does not change the proposed methodology or alter its implementation in a manner that has a material impact on the results.

Previous report

If the results of the illustrative calculations were included in a final FERC order for each of the complaint periods, then a 10.41 percent base ROE and a 13.08 percent incentive cap would not have a significant impact on our financial statements for all of the complaint periods. These preliminary calculations are not binding and do not represent what we believe to be the most likely outcome of a final FERC order.

Previous report

On November 21, 2019, FERC issued Opinion No. 569 affecting the two pending transmission ROE complaints against the Midcontinent ISO (MISO) transmission owners, in which FERC adopted a new methodology for determining base ROEs. Various parties sought rehearing. On December 23, 2019, the NETOs filed supplementary materials in the NETOs' four pending cases to respond to this new methodology because of the uncertainty of the applicability to the NETOs' cases. On May 21, 2020, the FERC issued its order in Opinion No. 569-A on the rehearing of the MISO transmission owners' cases, in which FERC again changed its methodology for determining the MISO transmission owners' base ROEs. On November 19, 2020, the FERC issued Opinion No. 569-B denying rehearing of Opinion No. 569-A and reaffirmed the methodology previously adopted in Opinion No. 569-A. The new methodology differs significantly from the methodology proposed by FERC in its October 16, 2018 order to determine the NETOs' base ROEs in their four pending cases. FERC Opinion Nos. 569-A and 569-B were appealed to the Court. On August 9, 2022, the Court issued its decision vacating MISO ROE FERC Opinion Nos. 569, 569-A and 569-B and remanded to FERC to reopen the proceedings. The Court found that FERC’s development of the new return methodology was arbitrary and capricious due to FERC’s failure to offer a reasonable explanation for its decision to reintroduce the risk-premium financial model in its new methodology for calculating a just and reasonable return.

Previous report

On October 17, 2024, FERC issued an order on the remand of the MISO ROE proceedings. The order addressed the Court’s decision that the reintroduction of the risk-premium financial model in the ROE methodology was arbitrary and capricious by removing the risk-premium financial model from the ROE methodology. The removal of the risk-premium financial model was the only revision to FERC’s ROE methodology and resulted in a two-model approach utilizing the two-step discounted cash flow model and the capital asset pricing model. MISO transmission owners were directed to provide refunds for the period November 12, 2013 to February 11, 2015 (the first MISO ROE complaint refund period) and for the period from September 28, 2016 (the date of FERC’s order on the first MISO ROE complaint) to October 17, 2024 by December 1, 2025. The order also stated that FERC does not preclude the use of the risk-premium financial model in future proceedings if the parties can demonstrate that FERC’s stated concerns around the inclusion of the model have been addressed. On March 25, 2025, FERC issued an order addressing arguments raised on rehearing, sustaining the result, and denying rehearing.

Previous report

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.

Previous report

On February 4, 2025, the MISO transmission owners submitted a petition for review with the Court requesting review of the October 17, 2024 MISO ROE order on remand and a December 19, 2024 notice of denial of rehearing. The petition requests review of FERC’s decision to retroactively backdate the MISO transmission owners’ base ROE to the date of an earlier order that FERC abandoned when it issued Order No. 569, treat an underlying unlawful complaint as if it were legitimate, and order eight years of interest as part of the directed refunds. On August 21,

Previous report

2025, the NETOs submitted a brief in support of the MISO transmission owners with the Court. Final briefs in the Court proceeding are due January 26, 2026.

Previous report

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.

Previous report

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.

Previous report

A change of 10 basis points to the base ROE used to establish the reserves would impact Eversource’s after-tax earnings by an average of approximately $3 million for each of the four 15-month complaint periods. Prospectively from the date of a final FERC order implementing a new base ROE, based off of estimated 2025 rate base, a change of 10 basis points to the base ROE would impact Eversource’s future annual after-tax earnings by approximately $7 million per year, and will increase slightly over time as we continue to invest in our transmission infrastructure.

Previous report

CL&P Performance Based Rate Making: On May 26, 2021, in accordance with an October 2020 Connecticut law, PURA opened a proceeding to begin to evaluate and eventually implement performance-based regulation (PBR) for electric distribution companies. PURA is conducting the proceeding in two phases. On April 26, 2023, PURA issued a final decision on the first phase and identified various objectives to guide PBR development and evaluate adoption of a PBR framework. The decision commenced Phase 2 by initiating three reopener dockets focused on revenue adjustment mechanisms, performance metrics, and integrated distribution system planning.

Previous report

On November 16, 2023, PURA issued a straw proposal in the first reopener that focused on revenue adjustment mechanisms. The proposal outlined potential additions and reforms to the current revenue adjustment mechanisms, such as multi-year rate plans, earnings sharing mechanisms and the revenue decoupling mechanism. On March 14, 2024, PURA issued a straw proposal in the second reopener docket that concentrated on performance mechanisms in a PBR framework. The proposal suggested the development of performance incentive mechanisms, reported metrics and scorecards. On February 27, 2025, PURA issued revised straw proposals for both the first and second reopener dockets, resulting in some edits to the previous proposals based on participant feedback. On April 4, 2025, PURA issued a straw proposal in the third reopener docket that focused on the establishment of integrated distribution system planning under a PBR framework.

Previous report

On July 14, 2025, PURA issued proposed final decisions in the first two reopener dockets. The proposed final decision in the first reopener docket adopted a PBR framework inclusive of a multi-year rate plan with an attrition relief mechanism that uses a revenue-cap formula approach to adjust revenues based on a variety of factors including inflation, a productivity factor, a customer dividend percentage, an exogenous cost factor and a capital funding mechanism, as well as an earnings sharing mechanism and a revenue decoupling mechanism for implementation in CL&P’s next distribution rate case. The multi-year rate plan has a stay out period of four years, but certain situations, such as deteriorating financial condition, exceeding authorized return, falling interest rates, or excess storm costs, could trigger the initiation of a new rate amendment proceeding during the multi-year rate plan. The proposed final decision in the second reopener docket established reporting parameters, including the commencement of scorecards and reported metrics and the development of company specific performance incentive mechanisms. Results of scorecards and reported metrics are proposed to be reported annually to PURA, beginning March 1, 2026. Company specific performance incentive mechanisms will be implemented in CL&P’s next rate case proceeding.

Previous report

On August 8, 2025, PURA issued a proposed final decision in the third reopener docket, adopting the contents and reporting process for an integrated distribution system plan (IDSP) under a PBR framework. The IDSP report will document the grid planning process for available distribution system capacity and system needs, including the development, operation, and evolution of the electrical distribution grid. The IDSP report will include CL&P’s planned investments over a four-year plan period and long-term capital investment strategy, and will be utilized by PURA in determining the amount of allowable capital additions within a multi-year rate plan included in the calculation of the capital funding mechanism adopted in the first reopener docket. The draft decision requires CL&P to submit a comprehensive IDSP filing every four years in alignment with the submittal of a rate amendment application and to also submit an annual IDSP filing to report on IDSP investments throughout the four-year period.

Current report — wording carried from elsewhere

We do not provide a reconciliation of guidance from non-GAAP recurring EPS to the most directly comparable GAAP measure of EPS because we are not able to predict with reasonable certainty the amount or nature of all items that will be included in our Net Income Attributable to Common Shareholders or non-GAAP recurring earnings for the year ending December 31, 2026. These items are uncertain, depend on many factors and could have a material impact on our Net Income Attributable to Common Shareholders and non-GAAP recurring earnings for the year ending December 31, 2026, and therefore cannot be made available without unreasonable effort.

Current report — wording carried from elsewhere

PURA issued a final decision in the Yankee Gas distribution rate case on November 5, 2025 that was subsequently updated on March 11, 2026, that included a distribution rate increase of $86.7 million, effective November 1, 2025. The approved revenue requirement includes a previously recorded rate credit of $37.4 million plus carrying charges for non-firm margin credits over three years beginning November 1, 2025. Excluding the rate credit, the distribution rate increase totaled $100.1 million.

Current report — wording carried from elsewhere

•energy supply and natural gas supply procurement;

Current report — wording carried from elsewhere

•other delivery costs, such as certain capital tracking mechanisms for infrastructure improvements, and additionally for the Massachusetts utilities, pension and PBOP benefits.

Current report — wording carried from elsewhere

Revenues from certain of these cost tracking mechanisms also include certain incentives earned, return on capital tracking mechanisms, and carrying charges that are billed in rates to customers, which do impact earnings. Tracked revenues also include wholesale market sales transactions, such as sales of energy and energy-related products into the ISO-NE wholesale electricity market, sales of natural gas to third-party marketers, and the sale of RECs to various counterparties.

Previous report — wording carried elsewhere

•On May 30, 2025, we entered into an equity distribution agreement pursuant to which we may offer and sell up to $1.2 billion of our common shares from time to time through an ATM equity offering program. In the first nine months of 2025, we issued 7,130,134 common shares, which resulted in proceeds of $465.4 million, net of issuance costs.

Previous report — wording carried elsewhere

The increase in other electric distribution costs for the nine month period is due primarily to an increase in the long-term renewable energy purchase contract cost deferral and in net metering costs at NSTAR Electric, higher long-term contractual energy-related costs that are recovered in the non-bypassable component of the FMCC mechanism at CL&P, and higher net metering costs at PSNH.

Previous report — wording carried elsewhere

Income Tax Expense decreased for the three month period due primarily to a decrease in reserves ($384.5 million), a decrease in return to provision adjustments ($23.4 million), and a decrease in amortization of EDIT ($4.9 million), partially offset by higher pre-tax earnings ($44.5 million), higher state taxes ($65.6 million), and an increase in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($29.1 million).