Eversource's utility companies are subject to rate regulation that is based on cost recovery and meets the criteria for application of accounting guidance for rate-regulated operations, which considers the effect of regulation on the timing of the recognition of certain revenues and expenses. The regulated companies' financial statements reflect the effects of the rate-making process. The rates charged to the customers of Eversource's regulated companies are designed to collect each company's costs to provide service, including a return on investment.

The application of accounting guidance for rate-regulated enterprises results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. Regulatory liabilities represent either revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.

Management believes it is probable that each of the regulated companies will recover its respective investments in long-lived assets and the regulatory assets that have been recorded. If management were to determine that it could no longer apply the accounting guidance applicable to rate-regulated enterprises, or if management could not conclude it is probable that costs would be recovered from customers in future rates, the applicable costs would be charged to net income in the period in which the determination is made.


	As of December 31,
	2025								2024
(Millions of Dollars)	Eversource		CL&P		NSTAR Electric		PSNH		Eversource		CL&P		NSTAR Electric		PSNH
Storm Costs, Net	$	1,959.3	$	991.3	$	499.6	$	468.4	$	2,039.4	$	971.1	$	609.8	$	458.5
Regulatory Tracking Mechanisms	1,573.8		206.5		705.6		93.2		1,781.6		507.7		650.0		162.8
Income Taxes, Net	1,044.5		546.1		161.5		23.3		968.4		521.0		145.4		20.7
Benefit Costs	992.8		173.7		300.0		61.7		967.4		168.8		293.6		65.6
Derivative Contracts	753.2		0.1		753.1		—		57.2		57.2		—		—
Securitized Stranded Costs	306.1		—		—		306.1		349.3		—		—		349.3
Cost of Removal	262.5		—		8.1		—		198.4		—		8.5		—
Goodwill-related	230.4		—		197.8		—		247.2		—		212.3		—
Asset Retirement Obligations	162.8		44.2		84.6		5.4		150.2		41.2		78.3		5.1
Environmental Remediation Costs	136.1		—		—		—		116.2		—		—		—
EGMA Acquisition and Integration Costs	82.3		—		—		—		—		—		—		—
Other Regulatory Assets	189.9		19.5		92.0		3.0		195.4		58.5		109.2		3.7
Total Regulatory Assets	7,693.7		1,981.4		2,802.3		961.1		7,070.7		2,325.5		2,107.1		1,065.7
Less: Current Portion	1,975.1		265.2		978.8		119.9		2,189.7		638.5		902.8		173.3
Total Long-Term Regulatory Assets	$	5,718.6	$	1,716.2	$	1,823.5	$	841.2	$	4,881.0	$	1,687.0	$	1,204.3	$	892.4

Storm Costs, Net: The storm cost deferrals relate to costs incurred for storm events at CL&P, NSTAR Electric and PSNH that each company expects to recover from customers. A storm must meet certain criteria to qualify for deferral and recovery with the criteria specific to each state jurisdiction and utility company. Once a storm qualifies for recovery, all qualifying expenses incurred during storm restoration efforts are deferred and recovered from customers. Costs for storms that do not meet the specific criteria are expensed as incurred. In addition to storm restoration costs, CL&P and PSNH are each allowed to recover pre-staging storm costs. Management believes storm costs deferred were prudently incurred and meet the criteria for specific cost recovery in Connecticut, Massachusetts and New Hampshire, and that recovery from customers is probable through the applicable regulatory recovery processes. For CL&P, under the current regulatory construct, the unamortized regulatory asset balance earns a return once authorized for recovery in rates. NSTAR Electric recovers a carrying charge on its deferred storm cost regulatory asset balance. PSNH earns a return on the regulatory asset balance.

Multiple tropical and severe storms over the past several years have caused extensive damage to Eversource’s electric distribution systems resulting in significant numbers and durations of customer outages, along with significant pre-staging costs. Storms in 2025 that qualified for future recovery resulted in deferred storm restoration costs and pre-staging costs totaling $129 million at Eversource, including $82 million at CL&P, $25 million at NSTAR Electric, and $22 million at PSNH. Management believes that all of these storm costs were prudently incurred and meet the criteria for specific cost recovery. Of Eversource’s total deferred storm costs, $2.06 billion either have yet to be filed with the applicable regulatory commission, are pending regulatory approval, or are subject to prudency review (including $1.19 billion at CL&P, $409 million at NSTAR Electric and $456 million at PSNH) as of December 31, 2025. These storm cost totals exclude storm funding amounts that are collected in rates, which are recorded as a reduction to the deferred storm cost regulatory asset balance. CL&P, NSTAR Electric and PSNH are seeking approval of their deferred storm restoration costs through the applicable regulatory recovery process.

CL&P Storm Filings: On March 28, 2024, PURA established a prudency review proceeding for the purpose of receiving and reviewing evidence of the costs reported by CL&P in response to catastrophic storms and pre-staging events totaling approximately $634 million that occurred between January 1, 2018 and December 31, 2021. On December 31, 2024, CL&P filed a supplement to its March 2024 prudency review application to request that PURA evaluate the prudence of its costs for nine additional catastrophic storms and two additional pre-staging events for the period January 1, 2022 through January 31, 2023 totaling approximately $173 million. On July 10, 2025, CL&P filed a second supplement to its March 2024 prudency review application to request that PURA evaluate the prudence of its costs for ten additional catastrophic storms for the period February 1, 2023 through December 31, 2023 totaling approximately $171 million. On July 25, 2025, CL&P filed a third supplement in this application to include carrying charges calculated at the weighted average cost of capital on the deferred storm costs totaling $246 million, which reflects CL&P’s actual financing costs on the unpaid storm costs from the date the deferred storm costs first began to accrue through May 2025. These carrying charges have not been deferred on the balance sheet. On December 13, 2025, PURA opened a new proceeding for the prudency determination of CL&P’s 2018 to 2023 storm costs either by a settled or litigated process and a separate future docket will be needed to consider CL&P’s application to issue rate reduction bonds for the securitization of approved storm costs. A final decision is expected on or about July 29, 2026. Although we cannot predict the ultimate outcome of these storm proceedings, we continue to believe these deferred storm restoration costs were prudently incurred and are probable of recovery.

CL&P’s storm events include the August 4, 2020 Tropical Storm Isaias, which resulted in deferred storm restoration costs of approximately $232 million at CL&P as of December 31, 2025. Although in 2021 PURA found that CL&P’s performance in its preparation for, and response to, Tropical Storm Isaias fell below applicable performance standards in certain instances, CL&P believes it presented in its 2023 storm filing credible evidence demonstrating there is no reasonably close causal connection between the alleged sub-standard performance and the storm costs incurred. While it is possible that some amount of storm costs may be disallowed by PURA, any such amount cannot be estimated at this time. CL&P continues to believe that these storm restoration costs associated with Tropical Storm Isaias were prudently incurred and meet the criteria for cost recovery.

Regulatory Tracking Mechanisms: The regulated companies' approved rates are designed to recover costs incurred to provide service to customers. The regulated companies recover certain of their costs on a fully-reconciling basis through regulatory commission-approved tracking mechanisms. The differences between the costs incurred (or the rate recovery allowed) and the actual revenues are recorded as regulatory assets (for undercollections) or as regulatory liabilities (for overcollections) to be included in future customer rates each year. Carrying charges are recovered in rates on all material regulatory tracking mechanisms.

The electric and natural gas distribution companies recover, on a fully reconciling basis, the costs associated with the procurement of energy and natural gas supply, state mandated energy purchase agreements and other energy-related costs, electric transmission related costs from FERC-approved transmission tariffs, energy efficiency programs, low income assistance programs, certain uncollectible accounts receivable for hardship customers, restructuring and stranded costs as a result of deregulation (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for the Massachusetts utilities, pension and PBOP benefits, net metering for distributed generation, and solar-related programs.

CL&P, NSTAR Electric, Yankee Gas, NSTAR Gas, EGMA and the Aquarion Water Company of Connecticut each have a regulatory commission approved revenue decoupling mechanism. Distribution revenues are decoupled from customer sales volumes, where applicable, which breaks the relationship between sales volumes and revenues. Each company reconciles its annual base distribution rate recovery amount to the pre-established levels of baseline distribution delivery service revenues. Any difference between the allowed level of distribution revenue and the actual amount realized during a 12-month period is adjusted through rates in the following period.

Income Taxes, Net: The tax effect of temporary book-tax differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income, including those differences relating to uncertain tax positions) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and accounting guidance for income taxes. Differences in income taxes between the accounting guidance and the rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets. As these assets are offset by deferred income tax liabilities, no carrying charge is collected. The amortization period of these assets varies depending on the nature and/or remaining life of the underlying assets and liabilities. For further information regarding income taxes, see Note 12, "Income Taxes," to the financial statements.

Benefit Costs: Deferred benefit costs represent unrecognized actuarial losses and gains and unrecognized prior service costs and credits attributable to Eversource's Pension, SERP and PBOP Plans. The regulated companies record actuarial losses and gains and prior service costs and credits arising at the December 31st remeasurement date of the funded status of the benefit plans as a regulatory asset or regulatory liability in lieu of a charge to Accumulated Other Comprehensive Income/(Loss), reflecting ultimate recovery from customers through rates. The regulatory asset or regulatory liability is amortized with the recognition of actuarial losses and gains and prior service costs and credits to net periodic benefit expense/income over the estimated average future employee service period using the corridor approach. Regulatory accounting is also applied to the portions of Eversource's service company costs that support the regulated companies, as these amounts are also recoverable. As these regulatory assets or regulatory liabilities do not represent a cash outlay for the regulated companies, no carrying charge is recovered from customers. See Note 11A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pension," for further information on regulatory benefit plan amounts arising and amortized during the year.

Eversource, CL&P, NSTAR Electric, and PSNH recover benefit costs related to their distribution and transmission operations from customers in rates as allowed by their applicable regulatory commissions. NSTAR Electric, NSTAR Gas and EGMA recover qualified pension and PBOP expenses related to their distribution operations through a rate reconciling mechanism that fully tracks the change in net pension and PBOP expenses each year. The electric transmission companies' rates provide for an annual true-up of estimated to actual costs, which include pension and PBOP expenses as allowed by FERC.

Derivative Contracts: For the regulated companies, regulatory assets (for losses) or regulatory liabilities (for gains) are recorded to offset the fair value of derivative contracts used to purchase energy and energy-related products that will be recovered from or refunded to customers in future rates. These regulatory assets and liabilities are excluded from rate base and contract costs are being recovered in energy supply rates over the duration of the contracts. See Note 4, "Derivative Instruments," to the financial statements for further information on these contracts.

Securitized Stranded Costs: In 2018, a subsidiary of PSNH issued $635.7 million of securitized RRBs to finance PSNH's unrecovered remaining costs associated with the divestiture of its generation assets. Securitized regulatory assets, which are not earning an equity return, are being recovered over the amortization period of the associated RRBs. The PSNH RRBs are expected to be repaid by February 1, 2033. For further information, see Note 10, "Rate Reduction Bonds and Variable Interest Entities," to the financial statements.

Cost of Removal: Eversource's regulated companies currently recover amounts in rates for future costs of removal of plant assets over the lives of the assets. The estimated cost to remove utility assets from service is recognized as a component of depreciation expense, and the cumulative amount collected from customers but not yet expended is recognized as a regulatory liability. Expended removal costs that exceed amounts collected from customers are recognized as regulatory assets, as they are probable of recovery in future rates.

Asset Retirement Obligations: The costs associated with the depreciation of the regulated companies' ARO assets and accretion of the ARO liabilities are recorded as regulatory assets in accordance with regulatory accounting guidance. The regulated companies' ARO assets, regulatory assets, and ARO liabilities offset and are excluded from rate base. These costs are being recovered over the life of the underlying property, plant and equipment.

EGMA Acquisition and Integration Costs: As part of a DPU-approved settlement agreement on December 1, 2025, acquisition-related and integration costs incurred from the October 2020 acquisition of Columbia Gas of Massachusetts (now Eversource Gas Company of Massachusetts) are allowed for recovery over a 10-year period beginning at the time EGMA’s next base distribution rate change becomes in effect. These regulatory assets are being carried with no return.

Other Regulatory Assets: Other Regulatory Assets primarily include certain uncollectible accounts receivable for hardship customers, contractual obligations associated with the spent nuclear fuel storage costs of the CYAPC, YAEC and MYAPC decommissioned nuclear power facilities, removal costs incurred that exceed amounts collected from customers, electric vehicle program costs, certain exogenous property taxes and merger-related costs allowed for recovery, losses associated with the reacquisition or redemption of long-term debt, and various other items.

Regulatory Costs in Other Long-Term Assets: Eversource's regulated companies had $244.2 million (including $127.1 million for CL&P, $51.0 million for NSTAR Electric and $5.4 million for PSNH) and $221.0 million (including $116.3 million for CL&P, $41.1 million for NSTAR Electric and $4.5 million for PSNH) of additional regulatory costs not yet specifically approved as of December 31, 2025 and 2024, respectively, that were included in Other Long-Term Assets on the balance sheets. These amounts will be reclassified to Regulatory Assets upon approval by the applicable regulatory agency. Based on regulatory policies or past precedent on similar costs, management believes it is probable that these costs will ultimately be approved and recovered from customers in rates. As of December 31, 2025 and 2024, these regulatory costs included $123.2 million (including $57.0 million for CL&P and $34.0 million for NSTAR Electric) and $92.5 million (including $47.2 million for CL&P and $24.4 million for NSTAR Electric), respectively, of deferred uncollectible hardship costs.


	As of December 31,
	2025								2024
(Millions of Dollars)	Eversource		CL&P		NSTAR Electric		PSNH		Eversource		CL&P		NSTAR Electric		PSNH
EDIT due to Tax Cuts and Jobs Act of 2017	$	2,423.4	$	933.3	$	847.9	$	319.8	$	2,442.7	$	956.6	$	877.6	$	330.6
Regulatory Tracking Mechanisms	1,186.6		457.3		535.2		111.2		702.4		180.3		413.6		114.4
Cost of Removal	867.1		275.1		479.4		45.5		684.1		212.8		451.3		20.1
Deferred Portion of Non-Service Income Components of Pension, SERP and PBOP	509.4		72.8		252.5		48.5		427.1		61.6		211.6		42.6
AFUDC - Transmission	179.4		72.0		107.4		—		154.8		65.1		89.7		—
Derivative Contract	91.0		—		91.0		—		—		—		—		—
Benefit Costs	80.4		8.8		24.5		6.8		69.3		4.5		21.4		3.9
Other Regulatory Liabilities	200.8		43.3		15.0		4.0		184.5		39.1		14.2		4.5
Total Regulatory Liabilities	5,538.1		1,862.6		2,352.9		535.8		4,664.9		1,520.0		2,079.4		516.1
Less: Current Portion	1,264.6		417.5		650.8		118.4		632.3		124.1		436.3		121.1
Total Long-Term Regulatory Liabilities	$	4,273.5	$	1,445.1	$	1,702.1	$	417.4	$	4,032.6	$	1,395.9	$	1,643.1	$	395.0

EDIT due to Tax Cuts and Jobs Act of 2017: Pursuant to the Tax Cuts and Jobs Act of 2017, Eversource had remeasured its existing deferred federal income tax balances to reflect the decrease in the U.S. federal corporate income tax rate from 35 percent to 21 percent. The remeasurement resulted in provisional regulated excess accumulated deferred income tax (excess ADIT or EDIT) liabilities that will benefit customers in future periods and were recognized as regulatory liabilities on the balance sheet. EDIT liabilities related to property, plant, and equipment are subject to IRS normalization rules and will be returned to customers using the same timing as the remaining useful lives of the underlying assets that gave rise to the ADIT liabilities. Eversource's regulated companies are in the process of refunding the EDIT liabilities to customers based on orders issued by applicable state and federal regulatory commissions.

Deferred Portion of Non-Service Income Components of Pension, SERP and PBOP: Regulatory liabilities were recorded for the deferred portion of the non-service related components of net periodic benefit expense/(income) for the Pension, SERP and PBOP Plans. These regulatory liabilities will be amortized over the remaining useful lives of the various classes of utility property, plant and equipment.

FERC ROE Complaints: As of December 31, 2025 and 2024, Eversource has a reserve established for the second ROE complaint period in the pending FERC ROE complaint proceedings, which was recorded as a regulatory liability and is reflected within Regulatory Tracking Mechanisms in the table above. The cumulative pre-tax reserve (excluding interest) as of December 31, 2025 and 2024 totaled $39.1 million for Eversource (including $21.4 million for CL&P, $14.6 million for NSTAR Electric and $3.1 million for PSNH). See Note 13E, "Commitments and Contingencies – FERC ROE Complaints," for further information on developments in the pending ROE complaint proceedings.

CL&P State Bonding Proceeds: On July 1, 2025, Connecticut enacted Public Act No. 25-173 (Senate Bill No. 4) (the Act). The Act authorizes the State of Connecticut to issue up to $125 million in new general obligation bonds for each fiscal year 2026 and 2027 to reduce costs of hardship protection measures charged to retail customers, of which 67 percent of each issuance will be allocated to CL&P, and $30 million for fiscal year 2026 and $20 million for fiscal year 2027 in new general obligation bonds to fund the electric vehicle charging program, of which 80 percent of each issuance will be allocated to CL&P.

On September 19, 2025, CL&P received $107.8 million in general obligation bond proceeds from the State of Connecticut, which represent reimbursement of incurred costs that were previously recognized as regulatory assets on CL&P’s balance sheets. The proceeds received for the reimbursement of hardship costs and for electric vehicle charging program costs were credited against the System Benefits Charge (SBC) and Non-Bypassable Federally Mandated Congestion Charge (NBFMCC) regulatory deferrals on CL&P’s balance sheet as of December 31, 2025. The proceeds from the state bond funding are presented as a cash inflow in Regulatory Recoveries within operating activities on CL&P’s statement of cash flows.

Yankee Gas Distribution Rate Case: On November 12, 2024, Yankee Gas filed an application with PURA to amend its existing distribution rates for effect on November 1, 2025. Yankee Gas had subsequently amended its rate application to request approval of a distribution rate increase of $193 million. On September 22, 2025, PURA issued a proposed final (draft) decision in Yankee Gas’s distribution rate case that included a distribution rate increase of $55.6 million, effective November 1, 2025.

On November 5, 2025, PURA issued a final decision in the Yankee Gas distribution rate case that included a distribution rate increase of $82.2 million and a total distribution revenue requirement of $802.2 million, effective November 1, 2025. The approved revenue requirement includes a previously recorded rate credit of $37.4 million plus carrying charges for non-firm margin credits over three years beginning November 1, 2025. Excluding the rate credit, the distribution rate increase totaled $95.7 million. The final decision also established an authorized net regulatory ROE of 9.32 percent, adopting a 9.48 percent ROE net of certain reductions totaling 16 basis points, and a 53 percent common equity ratio for Yankee Gas’ capital structure. PURA declined to approve the multi-year performance-based rate making plan that would adjust rates annually as proposed by Yankee Gas. PURA also implemented an annual cap on contemporaneous cost recovery of aging infrastructure replacement spending in the Distribution Integrity Management Program (DIMP) rate tracking mechanism of $139.9 million, in which spending above the annual cap will be deferred for recovery until the next distribution rate case. The final decision resulted in a net pre-tax loss to earnings of $8.5 million in the fourth quarter of 2025, primarily for the write off of certain capitalized employee compensation costs that were disallowed from rate base. Yankee Gas filed motions to request PURA reconsider the disallowances of these capitalized costs, certain computational errors, and other issues identified in its final decision. On December 15, 2025, PURA issued a notice of reconsideration to reconsider the final decision. A final decision on the reconsideration is expected from PURA by March 15, 2026.

NSTAR Electric Distribution Rates: NSTAR Electric’s performance based regulation (PBR) mechanism allows for an annual adjustment to base distribution rates for inflation, exogenous events and future capital additions based on a historical five-year average of total capital additions. On September 15, 2025, NSTAR Electric submitted its annual PBR Adjustment filing for a $55.1 million increase to base distribution rates and a total base distribution revenue requirement of $1.34 billion for effect on January 1, 2026. The requested base distribution rate increase is comprised of a $25.2 million inflation-based adjustment and a $29.9 million K-bar adjustment for capital additions based on the difference between the historical five-year average of total capital additions and the base capital revenue requirement. On December 30, 2025, the DPU approved this filing.

On September 16, 2024, NSTAR Electric submitted its annual PBR Adjustment filing for a $55.8 million increase to base distribution rates, for effect on January 1, 2025. The requested base distribution rate increase is comprised of a $35.3 million inflation-based adjustment and a $20.5 million adjustment for capital additions based on the difference between the historical five-year average of total capital additions and the base capital revenue requirement. On December 23, 2024, the DPU approved this filing.

NSTAR Gas Distribution Rates: NSTAR Gas’ PBR mechanism allows for an annual adjustment to base distribution rates for inflation and exogenous events. On June 16, 2025, NSTAR Gas submitted its annual PBR Adjustment filing for rates to be effective on November 1, 2025. On September 11, 2025, NSTAR Gas updated its filing to request approval of a $162.6 million increase to base distribution rates and a total base distribution revenue requirement of $447.7 million. The base distribution rate increase is comprised of a $10.3 million inflation-based adjustment and, in accordance with the DPU’s final decision in the 2020 NSTAR Gas rate case, a $152.3 million rate-base reset to incorporate capital additions for the period 2021 through 2024, which includes the transfer of GSEP revenues totaling $107.3 million into base rates, as well as other non-GSEP plant additions totaling $45.0 million.

On October 29, 2025, the DPU issued a decision determining that NSTAR Gas was not eligible to increase its distribution rates for the rate base reset because it did not achieve certain performance metrics under its PBR plan, and did not allow the base rate increase of $45.0 million for the incorporation of non-GSEP plant additions into base rates. The decision stated that those investments could be considered for inclusion in base distribution rates in NSTAR Gas’s next base rate proceeding. The DPU did allow NSTAR Gas to transfer its GSEP revenues through 2024 of $107.3 million for recovery through base distribution rates effective November 1, 2025. The DPU approved the base distribution rate increase of $10.3 million for the inflation-based adjustment. The DPU also approved NSTAR Gas’ mitigation proposal, in which NSTAR Gas paused recovery of the Gas System Enhancement Adjustment Factor (GSEAF) and reduced the current GSEAF to zero on November 1, 2025 in order to align this decrease with the base rate increase and to mitigate November 1, 2025 bill impacts to customers. NSTAR Gas will begin to recover the remaining 2025 GSEP revenue requirement on May 1, 2026 over 18 months. On November 4, 2025, NSTAR Gas filed a motion requesting the DPU to reconsider its decision denying the rate base reset citing legal concerns and arguing that the decision will ultimately result in higher costs for customers. NSTAR Gas also notified the DPU of its intention to file a base distribution rate case.

On December 30, 2025, NSTAR Gas and the Massachusetts Office of the Attorney General reached a joint settlement agreement that allowed for the reinstatement of the rate base reset of $45.0 million increase to base distribution rates effective January 1, 2026, for NSTAR Gas to not petition for a rate case with new rates effective December 1, 2026, and for continuation of NSTAR Gas’ PBR program through November 1, 2030. The settlement agreement also required NSTAR Gas to provide a credit to customers of $10.2 million over a ten-month period beginning January 2026 as penalty for its failure to meet three performance metrics as required for eligibility for the rate base reset, pay a $2 million concession to the Office of the Attorney General to fund customer energy assistance programs, waive recovery of certain carrying charges, delay recovery of $53 million of capital pipeline investments until the next rate case, and provide bill stabilization credit deferrals. The DPU approved the settlement agreement on January 16, 2026. The settlement agreement resulted in a pre-tax charge to earnings of $12.2 million in the fourth quarter of 2025.

NSTAR Electric and EGMA Settlement: On November 3, 2025, EGMA, NSTAR Electric, and the Massachusetts Office of the Attorney General reached a joint settlement agreement that resolved outstanding issues in multiple open Pension Adjustment Mechanism (PAM) dockets and open Resiliency Tree Work (RTW) dockets at NSTAR Electric and allows recovery of transaction and integration costs related to Eversource’s acquisition of EGMA. Certain PAM and RTW collections are being refunded to NSTAR Electric’s customers over a one-year period beginning January 1, 2026 and the transaction and integration costs of $82.3 million will be collected from EGMA customers over a ten-year period from the time of the next EGMA rate case. The settlement agreement was approved by the DPU on December 1, 2025. The settlement resulted in a net pre-tax benefit to earnings of $64.8 million on the Eversource income statement in the fourth quarter of 2025 ($82.3 million benefit at Eversource Parent and Other Companies for the allowed recovery of previously expensed acquisition-related and integration costs and $17.5 million charge at NSTAR Electric) and a net increase to regulatory assets on the Eversource balance sheet.

EGMA Distribution Rates: On November 4, 2024, EGMA submitted a revised filing for its first rate base reset for rates effective November 1, 2024, in accordance with an October 7, 2020 EGMA Rate Settlement Agreement approved by the DPU. The compliance filing was ordered by the DPU on October 31, 2024. The rate base reset occurring on November 1, 2024 adjusted distribution rates to account for capital additions (including the roll-in of GSEP capital additions), depreciation expense, property taxes, and return on rate base for capital additions placed into service through December 31, 2023. The total revenue requirement calculated for the first rate base reset was an increase to base distribution rates of $147.8 million, of which $34.0 million is associated with GSEP investments through December 31, 2023. Under the terms of the Rate Settlement Agreement, EGMA applied a cap on the revenue change effective November 1, 2024, and the amount in excess of the cap was deferred for recovery through the Local Distribution Adjustment Clause (LDAC) on May 1, 2025, including carrying charges. After adjusting for the cap, the increase to base distribution rates was $85.6 million effective November 1, 2024 (of which $8.8 million is offset by a reduction in the GSEP revenue requirement and GSEP rate also taking effect on November 1, 2024 for a net distribution rate change on November 1, 2024 of $76.8 million). Base distribution rates increased effective November 1, 2025 to incorporate the $62.2 million remaining revenue requirement. On November 7, 2024, the DPU approved this filing.

PSNH Distribution Rate Case: On June 11, 2024, PSNH filed an application with the NHPUC for approval of a temporary annual base distribution rate increase. On July 31, 2024, the NHPUC approved a settlement agreement that was reached by PSNH, New Hampshire Department of Energy, and the Office of the Consumer Advocate to implement a temporary annual base distribution rate increase of $61.2 million effective August 1, 2024. Temporary rates were in effect until permanent rates were approved and took effect August 1, 2025.

Also on June 11, 2024, PSNH filed an application with the NHPUC to request an increase in permanent base distribution rates of $181.9 million, which is inclusive of the temporary rate increase. Throughout the course of the proceeding, PSNH amended the requested revenue requirement to account for developments in the case, and arrived at a final proposed rate increase of $103 million, which primarily reflects the removal of deferred storm costs that will be addressed in a separate proceeding. On July 25, 2025, the NHPUC issued its decision on permanent rates and approved a permanent rate increase of $100.7 million, effective August 1, 2025, inclusive of the temporary rate increase referenced above. The total base distribution revenue requirement effective August 1, 2025 is $519 million. The order also established an authorized regulatory ROE of 9.5 percent with a 50 percent common equity ratio for PSNH’s capital structure.

This revenue requirement also contains an alternative regulation revenue requirement adjustment. This adjustment was part of the NHPUC’s alternative regulatory framework that the NHPUC adopted as an alternative to PSNH’s proposed performance-based regulation plan. The alternative regulatory framework authorizes formulaic annual revenue adjustments on August 1st of 2026, 2027 and 2028. PSNH is required to file its next base distribution rate case for effect in June 2029 and committed not to file its next distribution rate case until 2029. The alternative regulatory framework calculates the annual revenue adjustment using a productivity factor and an adjustment for inflation to provide PSNH with increased revenue for operations. The framework also contains an exogenous events recovery mechanism for certain unforeseen events out of PSNH’s control and exceeding a specified threshold, a performance metric, and an earnings sharing mechanism where PSNH would have to return 75 percent of all revenue back to customers that exceeds 25 basis points more than the authorized ROE of 9.5 percent. Consistent with PSNH’s proposal, lost base revenues for both net metering and energy efficiency were eliminated effective August 1, 2025.

To the extent permanent rates exceed the level of temporary rates, the difference will reconcile back to the date that the temporary rates took effect and the company recovers the difference over a twelve-month term. On August 11, 2025, PSNH filed its recoupment calculation, and on September 10, 2025, the NHPUC issued an order that the recoupment is $9.1 million and will be collected through the RRA regulatory tracking mechanism over a one-year period.

As part of the decision, unrecovered storm costs of $247 million were removed from the rate proceeding for consideration in a separate proceeding. Approval of the ultimate amount of storm costs to be recovered is subject to a separate prudency review that was filed in March of 2024 and is being considered by the NHPUC in a separate dedicated docket, which is at this time complete and awaiting the issuance of an order. Approved storm costs in excess of the amount approved in base rates will be recovered through the Regulatory Reconciliation Adjustment (RRA) regulatory tracking mechanism. The NHPUC increased the level of storm costs recovered in base rates from $12 million to $19 million.

On January 30, 2026, the New Hampshire Department of Energy filed a notice of appeal with the New Hampshire Supreme Court challenging certain aspects of the PSNH distribution rate case. The appeal raises issues regarding the lawfulness of the Company’s alternative regulatory framework, the adequacy of the NHPUC’s findings supporting the approved revenue requirement, and whether the NHPUC sufficiently addressed required regulatory factors in its final order. The Department of Energy contends that additional findings were necessary to support the final determinations. On February 6, 2026, the Office of the Consumer Advocate filed a notice of cross-appeal with the New Hampshire Supreme Court challenging other aspects of the rate case decision. The NHPUC, as the deciding agency, is afforded the highest level of deference by the New Hampshire Supreme Court, and therefore the Department of Energy and the Office of Consumer Advocate will have a very high burden to meet to be successful on appeal. Eversource is currently evaluating the appeals and will respond consistent with applicable legal and regulatory processes.