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REGULATORY ACCOUNTING | 12 Months Ended
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Dec. 31, 2024
Regulated Operations [Abstract] |
REGULATORY ACCOUNTING | REGULATORY ACCOUNTING 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, plus 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. Regulatory Assets: The components of regulatory assets were as follows:
| As of December 31,
| 2024 |  | 2023
(Millions of Dollars) | Eversource |  | CL&P |  | NSTAR Electric |  | PSNH |  | Eversource |  | CL&P |  | NSTAR Electric |  | PSNH
Storm Costs, Net | $ | 2,039.4 |  |  | $ | 971.1 |  |  | $ | 609.8 |  |  | $ | 458.5 |  |  | $ | 1,785.9 |  |  | $ | 896.6 |  |  | $ | 609.1 |  |  | $ | 280.2 |
Regulatory Tracking Mechanisms | 1,781.6 |  |  | 507.7 |  |  | 650.0 |  |  | 162.8 |  |  | 1,319.2 |  |  | 354.5 |  |  | 482.9 |  |  | 182.2 |
Benefit Costs | 967.4 |  |  | 168.8 |  |  | 293.6 |  |  | 65.6 |  |  | 1,117.3 |  |  | 197.4 |  |  | 336.7 |  |  | 79.3 |
Income Taxes, Net | 968.4 |  |  | 521.0 |  |  | 145.4 |  |  | 20.7 |  |  | 912.4 |  |  | 512.6 |  |  | 128.6 |  |  | 16.4 |
Securitized Stranded Costs | 349.3 |  |  | — |  |  | — |  |  | 349.3 |  |  | 392.5 |  |  | — |  |  | — |  |  | 392.5 |
Goodwill-related | 247.2 |  |  | — |  |  | 212.3 |  |  | — |  |  | 264.1 |  |  | — |  |  | 226.7 |  |  | — |
Asset Retirement Obligations | 150.2 |  |  | 41.2 |  |  | 78.3 |  |  | 5.1 |  |  | 137.9 |  |  | 38.5 |  |  | 72.3 |  |  | 4.7 |
Derivative Liabilities | 57.2 |  |  | 57.2 |  |  | — |  |  | — |  |  | 120.9 |  |  | 120.9 |  |  | — |  |  | — |
Other Regulatory Assets | 510.0 |  |  | 58.5 |  |  | 117.7 |  |  | 3.7 |  |  | 339.0 |  |  | 22.7 |  |  | 101.6 |  |  | 8.0 |
Total Regulatory Assets | 7,070.7 |  |  | 2,325.5 |  |  | 2,107.1 |  |  | 1,065.7 |  |  | 6,389.2 |  |  | 2,143.2 |  |  | 1,957.9 |  |  | 963.3 |
Less: Current Portion | 2,189.7 |  |  | 638.5 |  |  | 902.8 |  |  | 173.3 |  |  | 1,674.2 |  |  | 480.4 |  |  | 676.1 |  |  | 189.5 |
Total Long-Term Regulatory Assets | $ | 4,881.0 |  |  | $ | 1,687.0 |  |  | $ | 1,204.3 |  |  | $ | 892.4 |  |  | $ | 4,715.0 |  |  | $ | 1,662.8 |  |  | $ | 1,281.8 |  |  | $ | 773.8 |
As of December 31, 2024, the Regulatory Assets attributable to the Aquarion water distribution business have been reclassified to Assets Held for Sale on the Eversource balance sheet. As of December 31, 2023, these balances were recorded within Regulatory Assets on the Eversource balance sheet. For further information, see Note 24, “Assets Held for Sale.” 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 all 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. Each electric utility company either recovers a carrying charge on its deferred storm cost regulatory asset balance or the regulatory asset balance is included in rate base. 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 2024 that qualified for future recovery resulted in deferred storm restoration costs and pre-staging costs totaling $410 million at Eversource, including $134 million at CL&P, $85 million at NSTAR Electric, and $191 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, $2.10 billion either have yet to be filed with the applicable regulatory commission, are pending regulatory approval, or are subject to prudency review (including $1.12 billion at CL&P, $551 million at NSTAR Electric and $440 million at PSNH) as of December 31, 2024. 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. As part of CL&P’s October 1, 2021 settlement agreement, CL&P agreed to freeze its current base distribution rates (including storm costs) until no earlier than January 1, 2024. 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. 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’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, 2024. 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. 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. 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. 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. Goodwill-related: The goodwill regulatory asset originated from a 1999 transaction, and the DPU allowed its recovery in NSTAR Electric and NSTAR Gas rates. This regulatory asset is currently being amortized and recovered from customers in rates without a carrying charge over a 40-year period, and as of December 31, 2024, there were 15 years of amortization remaining. 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. Derivative Liabilities: Regulatory assets are recorded as an offset to derivative liabilities and relate to the fair value of contracts used to purchase energy and energy-related products that will be recovered from customers in future rates. These assets are excluded from rate base and are being recovered as the actual settlements occur over the duration of the contracts. See Note 4, "Derivative Instruments," to the financial statements for further information on these contracts. Other Regulatory Assets: Other Regulatory Assets primarily include environmental remediation costs, 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 $221.0 million (including $116.3 million for CL&P, $41.1 million for NSTAR Electric and $4.5 million for PSNH) and $241.7 million (including $166.7 million for CL&P, $21.9 million for NSTAR Electric and $1.2 million for PSNH) of additional regulatory costs not yet specifically approved as of December 31, 2024 and 2023, 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, 2024 and 2023, these regulatory costs included $92.5 million (including $47.2 million for CL&P and $24.4 million for NSTAR Electric) and $82.1 million (including $64.0 million for CL&P and $7.3 million for NSTAR Electric), respectively, of deferred uncollectible hardship costs. Equity Return on Regulatory Assets: For rate-making purposes, the regulated companies recover the carrying costs related to their regulatory assets. For certain regulatory assets, the carrying cost recovered includes an equity return component. This equity return is not recorded on the balance sheets. The equity return for PSNH was $22.5 million and $10.2 million as of December 31, 2024 and 2023, respectively. These carrying costs will be recovered from customers in future rates. Regulatory Liabilities: The components of regulatory liabilities were as follows:
| As of December 31,
| 2024 |  | 2023
(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 | $ | 2,442.7 |  |  | $ | 956.6 |  |  | $ | 877.6 |  |  | $ | 330.6 |  |  | $ | 2,548.6 |  |  | $ | 969.2 |  |  | $ | 905.1 |  |  | $ | 339.3 |
Regulatory Tracking Mechanisms | 702.4 |  |  | 180.3 |  |  | 413.6 |  |  | 114.4 |  |  | 668.3 |  |  | 154.0 |  |  | 347.2 |  |  | 114.4 |
Cost of Removal | 684.1 |  |  | 212.8 |  |  | 451.3 |  |  | 20.1 |  |  | 666.6 |  |  | 157.9 |  |  | 420.9 |  |  | 16.2 |
Deferred Portion of Non-Service Income Components of Pension, SERP and PBOP | 427.1 |  |  | 61.6 |  |  | 211.6 |  |  | 42.6 |  |  | 354.0 |  |  | 49.9 |  |  | 175.9 |  |  | 36.6 |
AFUDC - Transmission | 154.8 |  |  | 65.1 |  |  | 89.7 |  |  | — |  |  | 124.3 |  |  | 56.1 |  |  | 68.2 |  |  | — |
Benefit Costs | 69.3 |  |  | 4.5 |  |  | 21.4 |  |  | 3.9 |  |  | 51.0 |  |  | 0.6 |  |  | 22.2 |  |  | — |
Other Regulatory Liabilities | 184.5 |  |  | 39.1 |  |  | 14.2 |  |  | 4.5 |  |  | 201.9 |  |  | 30.4 |  |  | 13.9 |  |  | 4.6 |
Total Regulatory Liabilities | 4,664.9 |  |  | 1,520.0 |  |  | 2,079.4 |  |  | 516.1 |  |  | 4,614.7 |  |  | 1,418.1 |  |  | 1,953.4 |  |  | 511.1 |
Less: Current Portion | 632.3 |  |  | 124.1 |  |  | 436.3 |  |  | 121.1 |  |  | 591.8 |  |  | 102.2 |  |  | 368.1 |  |  | 117.5 |
Total Long-Term Regulatory Liabilities | $ | 4,032.6 |  |  | $ | 1,395.9 |  |  | $ | 1,643.1 |  |  | $ | 395.0 |  |  | $ | 4,022.9 |  |  | $ | 1,315.9 |  |  | $ | 1,585.3 |  |  | $ | 393.6 |
As of December 31, 2024, the Regulatory Liabilities attributable to the Aquarion water distribution business have been reclassified to Liabilities Held for Sale on the Eversource balance sheet. As of December 31, 2023, these balances were recorded within Regulatory Liabilities on the Eversource balance sheet. For further information, see Note 24, “Assets Held for Sale.” 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. 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. 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. AFUDC - Transmission: Regulatory liabilities were recorded by CL&P and NSTAR Electric for AFUDC accrued on certain reliability-related transmission projects to reflect local rate base recovery. These regulatory liabilities will be amortized over the depreciable life of the related transmission assets. Other Regulatory Liabilities: Other Regulatory Liabilities primarily include EGMA’s acquired regulatory liability as a result of the 2020 DPU-approved rate settlement agreement and the CMA asset acquisition on October 9, 2020, and various other items. FERC ROE Complaints: As of December 31, 2024 and 2023, 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, 2024 and 2023 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. Regulatory Developments: CL&P RAM Filing: On April 17, 2024, PURA issued an interim decision in CL&P’s 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. 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. 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 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 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 adjustment for capital additions based on the difference between the historical five-year average of total capital additions and the base capital revenue requirement. NSTAR Gas Distribution Rates: NSTAR Gas’ PBR mechanism allows for an annual adjustment to base distribution rates for inflation and exogenous events. On September 16, 2024, NSTAR Gas submitted its annual PBR Adjustment filing for a $12.7 million increase to base distribution rates for effect on November 1, 2024. On October 30, 2024, the DPU approved this filing. 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. 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. 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. 2023 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 Pole Plant Adjustment Mechanism (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.

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