What changed in this filing

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Item 8. Financial Statements and Supplementary Data

2026-02-09 compared with 2025-02-10 · 608 added, 351 removed, 1081 unchanged (47% of the section changed)

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Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

As described in Management’s Report on Internal Control over Financial Reporting, management excluded from its assessment the internal control over financial reporting at Maine Natural Gas Corporation, which was acquired on October 31, 2025, and whose financial statements constitute approximately 4.9% and 1.5%, respectively, of the Company's consolidated total assets and revenues as of and for the year ended December 31, 2025.

Accordingly, our audit of internal control over financial reporting did not include the internal control over financial reporting at Maine Natural Gas Corporation.

Basis for Opinions

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Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

accepted accounting principles.

A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company;

(2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the

and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions focused on the base rate proceedings for Fitchburg Gas and Electric Light Company and Granite State Gas Transmission, Inc.

and included the following, among others:

Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:

• We tested the effectiveness of controls over the relevant regulatory account balances and disclosures, including management’s controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

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Interest Payable

Taxes Payable

Other Current Liabilities

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Property, Plant and Equipment Additions

Acquisitions, Net of Cash Acquired

Cash Used In Investing Activities

Financing Activities:

(Repayment of) Proceeds from Short-Term Debt, net

Proceeds (Repayment of) from Short-Term Debt, net

Issuance of Long-Term Debt

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Long-Term Debt Issuance Costs

Increase (Decrease) in Capital Lease Obligations

Net (Decrease) Increase in Exchange Gas Financing

Increase in Capital Lease Obligations

Net Increase (Decrease) in Exchange Gas Financing

Dividends Paid

Proceeds from Issuance of Common Stock

Construction Advances

Cash Provided by Financing Activities

Net (Decrease) Increase in Cash and Cash Equivalents

Net Increase (Decrease) in Cash and Cash Equivalents

Cash and Cash Equivalents at Beginning of Year

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(Unitil Energy), Fitchburg Gas and Electric Light Company (Fitchburg), Northern Utilities, Inc.

(Northern Utilities), Granite State Gas Transmission, Inc.

(Northern Utilities), Bangor Natural Gas Company (Bangor), Maine Natural Gas Corporation (Maine Natural), Granite State Gas Transmission, Inc.

(Granite State), Unitil Power Corp.

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(Unitil Realty), Unitil Service Corp.

(Unitil Service) and Unitil Resources, Inc.

(Unitil Resources).

(Unitil Service), Unitil Resources, Inc.

(Unitil Resources) and Unitil Water Corp.

(Unitil Water).

The Company’s earnings are seasonal and are typically higher in the first and fourth quarters when customers use natural gas for heating purposes.

Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and capital city areas of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts.

Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire;

Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and capital city areas of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area, portions of central Maine including Augusta and the Bangor area, and in the greater Fitchburg area of north central Massachusetts.

Unitil has five distribution utility subsidiaries, Unitil Energy, which operates in New Ha mpshire;

Fitchburg, which operates in Massachusetts;

and Northern Utilities, which operates in New Hampshire and Maine (collectively, the distribution utilities).

Northern Utilities, which operates in New Hampshire and Maine;

and Bangor and Maine Natural, which operate in Maine (collectively, the distribution utilities).

Granite State is an interstate natural gas transmission pipeline company, operating 85 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire.

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Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.

A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy, but ceased being the wholesale supplier of Unitil Energy with the implementation of industry restructuring and divested its long-term power supply contracts.

Unitil also has three other wholly-owned subsidiaries:

Unitil Service, Unitil Resources and Unitil Realty.

A seventh utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy, but ceased being the wholesale supplier of Unitil Energy with the implementation of industry restructuring and divested its long-term power supply contracts.

Unitil also has four other wholly-owned subsidiaries:

Unitil Service, Unitil Resources, Unitil Realty and Unitil Water.

Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies.

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Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement.

Unitil Realty also owns land for future use in Kingston, New Hampshire.

On January 31, 2025, Unitil Corporation acquired Bangor Natural Gas Company, a natural gas distribution utility.

Unitil Realty also owns land in Kingston, New Hampshire on which Unitil Energy’s solar facility is located, which became operational in May 2025.

Unitil Water currently has no activity.

Basis of Presentation

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Total Electric and Gas Operating Revenues

The Company’s electric and gas sales in Massachusetts and New Hampshire are largely decoupled.

Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or gas sales.

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These revenue decoupling targets may be adjusted as a result of rate cases and other authorized adjustments that the Company files with the MDPU and NHPUC.

Fitchburg has been subject to revenue decoupling since 2011.

Unitil Energy has been subject to revenue decoupling since June 1, 2022.

As a result of Unitil Energy now being subject to revenue decoupling, as of June 1, 2022, revenue decoupling now applies to substantially all of Unitil’s total annual electric sales volumes.

Substantially all of Northern Utilities’ gas sales volumes in New Hampshire have been subject to decoupling since August 1, 2022.

The Company's electric and gas sales in New Hampshire and Massachusetts are now largely decoupled.

Northern Utilities’ gas sales volumes in Maine are not subject to revenue decoupling.

The Company bills its customers for sales tax in Massachusetts and Maine.

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Income Taxes - The Company is subject to Federal and State income taxes as well as various other business taxes.

The Company’s process for determining income tax amounts involves estimating the Company’s current tax liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes.

taxable income for tax and book accounting purposes.

These temporary differences result in deferred tax assets and liabilities, which are included in the Company’s Consolidated Balance Sheets.

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The amendments in ASU 2023-09 are effective for annual periods beginning after December 15, 2024, with early adoption permitted.

The Company does not expect this new guidance to have a material effect on the Company’s Consolidated Financial Statements.

The Company adopted this new guidance for the year ended December 31, 2025 and it did not have a material effect on the Company’s Consolidated Financial Statements (See Note 9 Income Taxes).

Dividends - The Company’s dividend policy is reviewed periodically by the Board.

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For the year ended December 31, 2025, the Company paid quarterly dividends of $ 0.45 per share, resulting in an annualized dividend rate of $ 1.80 per common share.

For the years ended December 31, 2023 and 2022, the Company paid quarterly dividends of $ 0.405 and $ 0.39 per common share, respectively, resulting in annualized dividend rates of $ 1.62 and $ 1.56 per common share, respectively.

For the years ended December 31, 2024 and 2023, the Company paid quarterly dividends of $ 0.425 and $ 0.405 per common share, respectively, resulting in annualized dividend rates of $ 1.70 and $ 1.62 per common share, respect ively.

At a January 2026 meeting of the Board, the Board declared a quarterly dividend on the Company’s common stock of $ 0.475 per share, an increase of $ 0.025 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $ 1.90 per share from $ 1.80 per share.

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Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the Company’s credit rating.

On December 31, 2024 and 2023, the Unitil subsidiaries had deposited $ 5.0 million and $ 3.3 million, respectively, to satisfy their ISO-NE obligations.

On December 31, 2025 and 2024, the Unitil subsidiaries had deposite d $ 8.5 m illion and $ 5.0 million, respectively, to satisfy their ISO-NE obligations.

Allowance for Doubtful Accounts - The Company recognizes a provision for doubtful accounts that reflects the Company’s estimate of expected credit losses for electric and gas utility service accounts receivable.

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The Company also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms.

The Company’s distribution utilities are authorized by regulators to recover the costs of the energy commodity portion of bad debts through rate mechanisms.

The Company’s distribution utilities which are under traditional cost of service regulation are authorized by regulators to recover the costs of the energy commodity portion of bad debts through rate mechanisms.

Also, the electric and gas divisions of Fitchburg are authorized to recover through rates past due amounts associated with protected hardship accounts.

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(See Note 3 Allowance for Doubtful Accounts).

Accounts Receivable, Net includes $ 2.3 million and $ 2.3 million of the Allowance for Doubtful Accounts at December 31, 2024 and December 31, 2023, respectively.

Unbilled Revenues, net (a component of Accrued Revenue) includes $ 0.1 million and $ 0.1 million of the Allowance for Doubtful Accounts at December 31, 2024 and December 31, 2023, respectively.

Accounts Receivable, Net include s $ 2.1 m illion and $ 2.3 million of the Allowance for Doubtful Accounts at December 31, 2025 and December 31, 2024, respectively.

Unbilled Revenues, net (a component of Accrued Revenue) includ es less than $ 0.1 million and $ 0.1 million of the Allowance for Doubtful Accounts at December 31, 2025 and December 31, 2024, respectively.

Accrued Revenue - Accrued Revenue includes the current portion of Regulatory Assets (see “Regulatory Accounting”) and unbilled revenues (see “Utility Revenue Recognition”).

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Total Accrued Revenue

Exchange Gas Receivable - Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party.

Exchange Gas Receivable - Northern Utilities, Fitchburg and Bangor have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third-party.

The third-party delivers natural gas back to the Company during the months of November through March.

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Total Gas Inventory

The Company also has an inventory of Materials and Supplies in the amounts of $ 14.2 million and $ 13.5 million as of December 31, 2024 and December 31, 2023, respectively.

The Company also has an inventory of Materials and Supplies in the amounts of $ 15.4 mill ion and $ 14.2 million as of December 31, 2025 and December 31, 2024, respectively.

These amounts are recorded at weighted average cost.

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Cost of additions consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC).

The average interest rates applied to AFUDC were 6.22 %, 5.48 % and 2.50 % in 2024, 2023 and 2022, respectively.

The average interest rates applied to AFUDC we re 5.39 %, 6.22 % and 5.48 % in 2025, 2024 and 2023, respectively.

The costs of current repairs and minor replacements are charged to appropriate operating expense accounts.

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The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value.

At December 31, 2024 and 2023, the Company has recorded cost of removal amounts of $ 139.2 million and $ 126.3 million, respectively, that have been collected in depreciation rates but have not yet been expended, and which represent regulatory liabilities.

At December 31, 2025 and 2024, the Company has recorded cost of removal amounts o f $ 153.0 million and $ 139.2 million, respectively, that have been collected in depreciation rates but have not yet been expended, and which represent regulatory liabilities.

These amounts are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations.

Regulatory Accounting - The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities:

Unitil Energy, Fitchburg and Northern Utilities.

Regulatory Accounting - The Company’s principal business is the distribution of electricity and natural gas by the five distribution utilities:

Unitil Energy, Fitchburg, Northern Utilities, Bangor and Maine Natural.

Unitil Energy and Fitchburg are subject to regulation by the FERC.

Fitchburg is also regulated by the Massachusetts Department of Public Utilities (MDPU), Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC) and Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC.

Fitchburg is also regulated by the Massachusetts Department of Public Utilities (MDPU), Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC), Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC, Bangor is regulated by the MPUC and Maine Natural is regulated by the MPUC.

Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC.

Accordingly, the Company uses the Regulated Operations guidance as set forth in the FASB Codification.

The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit,

in accordance with rate provisions approved by the applicable public utility regulatory commission.

The electric and gas divisions of Fitchburg are authorized to recover through rates past due amounts associated with hardship accounts that are protected from shut-off.

As of December 31, 2024 and December 31, 2023, the Company has recorded $ 7.9 million and $ 6.0 million, respectively, of hardship accounts in Regulatory Assets.

The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.

The electric and gas divisions

of Fitchburg are authorized to recover through rates past due amounts associated with hardship accounts that are protected from shut-off.

As of December 31, 2025 and December 31, 2024, the Company has record ed $ 8.9 m illion and $ 7.9 million, respectively, of hardship accounts in Regulatory Assets.

These amounts are included in “Other Deferred Charges” in the following table.

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Regulatory Liabilities consist of the following (millions)

Rate Adjustment Mechanisms

Rate Adjustment Mechanisms and Other

Derivative Assets

Retirement Benefits

Total Regulatory Liabilities

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Regulatory Liabilities—noncurrent

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made.

Included in Regulatory Assets as of December 31, 2024 are $ 7.1 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years.

Regulators have authorized recovery of these expenditures, but without a return.

Generally, the Company receives a return on invest ment on its regulated assets for which a cash outflow has been made.

Included in Regulatory Assets as of December 31, 2025 are $ 6.5 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods.

Re gulators have authorized recovery of these expenditures, but without a return.

Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material effect on the Company’s Consolidated Financial Statements.

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For each contract, the Company reviews and documents the key terms of the contract.

Based on those terms and any additional relevant components of the contract, the Company determines and documents whether the contract qualifies as a derivative instrument as defined in the FASB Codification.

The Company has determined that its energy supply contracts either do not qualify as a derivative instrument

under the guidance set forth in the FASB Codification, have been elected as normal purchase, or have contingencies that have not yet been met in order to establish a notional amount.

Fitchburg has entered into power purchase agreements for which contingencies exist (see “Fitchburg – Massachusetts RFP’s” section of Note 7 (Commitments and Contingencies)).

Until these contingencies are satisfied, these contracts will not qualify for derivative accounting.

The Company believes that the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg.

Investments in Marketable Securities - The Company maintains a trust through which it invests in a money market fund and a fixed income fund.

Based on those terms and any additional relevant components of the contract, the

Company determines and documents whether the contract qualifies as a derivative instrument as defined in the FASB Codification.

The Company has determined that its energy supply contracts either do not qualify as a derivative instrument under the guidance set forth in the FASB Codification, have been elected as normal purchase, or have contingencies that have not yet been met in order to establish a notional amount.

The Company has contracts that meet the definition of derivatives (see Note 7 Derivatives).

Derivatives are recognized on the balance sheet at fair value as either assets or liabilities.

The Company considers the amount of the derivative expected to be settled within the next twelve months as current and the remainder as long-term.

Derivative instruments are presented on a gross basis in the consolidated balance sheets.

Cash flows related to derivative settlements are classified as operating activities in the consolidated statements of cash flows.

Regulatory assets or liabilities are recorded to offset the fair value of derivatives, as contract settlement amounts are tracked and reconciled as a pass-through to customers.

Costs associated with the Purchase Power Agreement (PPA) are approved by the MDPU to be passed through to customers through the Company’s Long-Term Renewable Contract Adjustment Clause tariff and accounted for per FASB Accounting Standard Codification 980, Regulated Operations.

Unrealized gains or losses resulting from the change in fair value are not recognized in the income statement.

Instead, they are deferred and recorded as a regulatory asset for losses or a regulatory liability for gains.

The Company recognizes an environmental attribute asset at the allocated contract cost upon receipt of the associated certificates in the applicable registry and derecognizes the asset upon retirement, at which time the related cost is recognized in Cost of Electric Sales, which are tracked and reconciled costs as pass-through to customers.

Please see Note 7 (Derivatives) for additional information.

Investme nts in Marketable Securities - The Company maintains a trust through which it invests in a money market fund and a fixed income fund.

These funds are intended to satisfy obligations under the Company’s Supplemental Executive Retirement Plan (SERP).

See additional discussion of the SERP in Note 10 Retirement Benefit Plans.

At December 31, 2024 and 2023, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $ 6.3 million and $ 6.0 million, respectively, as shown in the following table.

At December 31, 2025 and 2024, the fair value of the Com pany’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $ 6.7 mill ion and $ 6.3 million, respectively, as shown in the following table.

These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied.

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A trust has been established to invest the funds associated with the DC Plan.

At December 31, 2024 and 2023, the fair value of the Company’s investments in these trading securities related to the DC Plan, which are recorded on the Consolidated Balance Sheets in Other Assets, were $ 2.2 million and $ 1.3 million, respectively.

At December 31, 2025 and 2024, the fair value of the Company’s investments in these trading securities related to the DC Plan, which are recorded on the Consolidated Balance Sheets in Other Assets, w ere $ 3.5 m illion and $ 2.2 million, respectively.

These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied.

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Total Marketable Securities

Goodwill - In January, the Company completed the acquisition of Bangor Natural Gas Company resulting in the recognition of $ 1.6 million of goodwill.

In October, the Company completed the acquisition of Maine Natural Gas Corporation resulting in the recognition of $ 2.7 million of goodwill.

Goodwill is not amortized but is tested for impairment at least annually, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value.

The Company performed the annual impairment assessment of goodwill at November 1, 2025 for the gas reporting unit.

The Company generally uses a qualitative analysis assessment to determine if it was more likely than not that the fair value of the reporting unit exceeded its carrying value, including goodwill.

The qualitative assessment did not identify any triggering events that would indicate potential impairment of the reporting unit.

Therefore, it was determined that the fair value of the reporting unit exceeded its carrying value and no goodwill impairments were recognized during the year ended December 31, 2025.

Energy Supply Obligations - The following discussion and table summarize the nature and amounts of the items recorded as Energy Supply Obligations on the Company’s Consolidated Balance Sheets.

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Due to timing differences between collection of revenue from customers and payment of REC costs to suppliers, Unitil Energy and Fitchburg typically defer costs for RPS compliance which are recorded within Accrued Revenue with a corresponding liability in Energy Supply Obligations on the Company’s Consolidated Balance Sheets.

Fitchburg has entered into long-term renewable contracts for the purchase of clean energy and/or RECs pursuant to Massachusetts legislation.

The generating facilities associated with ten of these contracts have been constructed and are now operating.

Three approved contracts are currently under development.

These include long-term contracts filed with the MDPU in 2018, two for offshore wind generation (totaling 1,200 MW) and one for imported hydroelectric power and associated transmission, all three of which were approved in 2019.

Four offshore wind contracts, totaling 2,400 MW, previously solicited for pursuant to the Green Communities Act and approved by the MDPU in 2021 and 2022, were subsequently terminated in 2023.

In compliance with the Green Communities Act as amended by the Energy Diversity Act and the Act Driving Clean Energy and Offshore Wind in coordination with the other electric distribution companies (EDCs) in Massachusetts, on August 30, 2023 the Company issued a fourth offshore wind Request for Proposal seeking to procure at least 400 MW and up to the maximum amount remaining of the statutory requirement.

The EDCs received bids for Offshore Wind Generation from three developers as part of a multi-state solicitation with Rhode Island and Connecticut and on September 6, 2024, the Department of Energy Resources selected a portfolio of projects totaling 2,678 MW from three projects.

The EDCs have commenced contract negotiations which are scheduled to be completed in March 2025.

Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism, and has received remuneration for entering into them.

In December 2024, the Massachusetts Legislature approved “ An Act promoting a clean energy grid, advancing equity, and protecting ratepayers” which among other provisions, extends the period for long-term renewable contracts up to 30 years and directs the EDCs to “jointly and competitively solicit proposals for energy storage systems and enter into cost-effective long-term contracts equal to, in the aggregate, approximately 5,000 megawatts of energy storage systems not later than July 31, 2030.” The first solicitation will be for approximately 1,500 megawatts of mid-duration storage to be procured by July 31, 2025.

Exchange Gas Obligation - Northern Utilities enters into gas exchange agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager.

Fitchburg has entered into long-term renewable contracts for the purchase of its pro rata share of clean energy and/or RECs under statewide procurement processes pursuant to Massachusetts legislation.

The generating facilities associated with some of these contracts have been constructed and are now operating.

Please see Note 8 (Commitments and Contingencies) discussion in Regulatory Matters for additional detail.

Exchange Gas Obligation - Northern Utilities and Bangor enter into gas exchange agreements under which Northern Utilities and Bangor release certain natural gas pipeline and storage assets, resell the natural gas storage inventory to an asset manager and subsequently repurchase the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager.

The gas inventory related to these agreements is recorded in Exchange Gas Receivable on the Company’s Consolidated Balance Sheets while the corresponding obligations are recorded in Energy Supply Obligations.

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Additionally, the Company sponsors the PBOP Plan, primarily to provide health care and life insurance benefits to retired employees.

The Company records on its balance sheets as an asset or liability the overfunded or underfunded status of its retirement benefit obligations (RBO) based on the projected benefit obligations.

The Company has recognized a corresponding Regulatory Asset, reflecting ultimate recovery from customers through rates.

The Company records on its balance sheets as an asset or liability for the overfunded or underfunded status of its retirement benefit obligations (RBO) based on the projected benefit obligations.

The Company has recognized a corresponding Regulatory Asset or Regulatory Liability, reflecting ultimate recovery from or refunded to customers through rates.

The regulatory asset (or regulatory liability) is amortized as the actuarial gains and losses and prior service cost are amortized to net periodic benefit cost for the Pension and PBOP plans.

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Environmental Matters - The Company’s past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations.

The Company has recovered or will recover substantially all of the costs of the environmental remediation work performed to date from customers or from its insurance carriers.

The Company has recovered or will recover substantially all the costs of the environmental remediation work performed to date from customers or from its insurance carriers.

The Company believes it is in compliance with all applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2025, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 8 (Commitments and Contingencies).

Changes in future environmental compliance regulations or in future cost estimates of environmental remediation costs could have a material effect on the Company’s financial position if those amounts are not recoverable in regulatory rate mechanisms.

Recently Issued Pronouncements - In November 2023, the FASB issued ASU 2023-07, Segment Reporting – Improvements to Reportable Segment Disclosures (ASU 2023-07).

The amendments in ASU 2023-07 are intended to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses.

The amendments in ASU 2023-07 are effective for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted.

The Company adopted this new guidance for the year-ended December 31, 2024 and it did not have a material effect on the Company’s Consolidated Financial Statements (See Note 2:

Segment Information).

Recently Issued Pronouncements - In 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (DISE), requiring public business entities to provide enhanced disclosures about the nature of expenses.

The standard mandates a tabular footnote disclosure detailing relevant expense captions into natural expense categories such as purchases of inventory, employee compensation, and depreciation.

It also requires disclosure of total selling expenses and, annually, the definition of selling expenses.

ASU 2024-03 is effective for annual periods beginning after December 15, 2026, and interim periods within those periods starting after December 15, 2027;

early adoption is permitted.

The Company is evaluating the standard's impact on its Consolidated Financial Statements.

In December 2023, the FASB issued ASU 2023-09, Income Taxes - Improvements to Income Tax Disclosures (ASU 2023-09).

ASU 2023-09 establishes new income tax disclosure requirements in addition to modifying and eliminating certain existing requirements.

The amendments in ASU 2023-09 are effective for annual periods beginning after December 15, 2024, with early adoption permitted.

The Company adopted this new guidance for the year ended December 31, 2025, and it did not have a material effect on the Company’s Consolidated Financial Statements (See Note 9 Income Taxes.)

Acquisition of Bangor Natural Gas Company - On January 31, 2025, the Company acquired all issued and outstanding shares of Bangor Natural Gas Company for $ 71.4 million, which includes an estimated working capital adjustment.

Through this acquisition, the Company expanded its service territory to include approximately 8,500 customers in the greater Bangor area of central Maine.

In connection with this acquisition, the Company recorded $ 66.7 million of net utility plant, $ 3.8 million working capital, $ 1.6 million goodwill, $ 0.2 million noncurrent assets and $ 0.9 million noncurrent regulatory liabilities.

The financial results associated with this acquisition are included within the gas segment.

Bangor’s operating revenues of $ 27.9 million and net income of $ 2.2 million were included in the consolidated results for the year ended December 31, 2025.

Goodwill represents the amount by which the purchase price exceeds the estimated fair value of the net assets acquired.

The goodwill related to Bangor is partially tax deductible.

The tax deductible portion of goodwill is $ 0.4 million and will be amortized over 15 years.

In connection with Unitil’s acquisition of Bangor, the Company entered into a Transition Services Agreement (TSA) dated January 31, 2025 between Bangor and Hope Utilities, Inc.

(Hope Utilities).

Pursuant to the TSA, Hope Utilities provided Bangor with certain services at cost, for up to 12 months, in order to continue the operation and maintenance of Bangor substantially consistent with past practices until Unitil has completed the successful transition.

The TSA was completed in November 2025.

Acquisition of Maine Natural Gas Corporation - On October 31, 2025, the Company acquired all issued and outstanding shares of Maine Natural for $ 86.0 million in cash, plus $ 7.1 million in working capital, subject to certain adjustments as provided in the Purchase Agreement.

Through this acquisition, the Company expanded its service territory to include approximately 6,300 customers in the Portland area of central Maine, as well as the capital city of Augusta.

In connection with this acquisition, the Company recorded $ 82.0 million of net utility plant, $ 10.4 million working capital, $ 2.7 million goodwill, $ 1.4 million noncurrent assets and $ 3.4 million noncurrent regulatory liabilities.

The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions and purchase accounting adjustments.

The financial results associated with this acquisition are included within the gas segment.

Maine Natural’s operating revenues of $ 8.3 million and net income of $ 2.8 million were included in the consolidated results for the year ended December 31, 2025.

Goodwill represents the amount by which the purchase price exceeds the estimated fair value of the net assets acquired.

In connection with Unitil’s acquisition of Maine Natural, the Company entered into a TSA dated October 31, 2025 between Maine Natural and Avangrid Service Company (Avangrid).

Pursuant to the TSA, Avangrid will provide Maine Natural with certain services at cost, for up to 12 months, in order to continue the operation and maintenance of Maine Natural substantially consistent with past practices until Unitil has completed the successful transition.

The Company has recorded $ 0.2 million of TSA costs as of December 31, 2025.

Acquisition of Aquarion Water Companies - On May 6, 2025, Unitil entered into a definitive agreement to acquire Aquarion Water Company of Massachusetts, Inc., Aquarion Water Company of New Hampshire, Inc., and Abenaki Water Co., Inc.

(the Aquarion Companies) from the Aquarion Water Authority, a quasi-public corporation and political subdivision of the State of Connecticut and a standalone, newly created water authority alongside the South Central Connecticut Regional Water Authority subject to certain closing adjustments.

The aggregate enterprise value of the sale is approximately $ 100.0 million, which includes approximately $ 70.0 million in cash and the assumption of approximately $ 30.0 million of debt.

The transaction is subject to approval by the MDPU, the NHPUC and the MPUC.

Subsequent Events - The Company evaluates all events or transactions through the date of the related filing.

During the period through the date of this filing, the Company did not have any material subsequent events that would result in adjustment to or disclosure in its Consolidated Financial Statements, except for the closing of the Company’s acquisition of Bangor Natural Gas Company (Bangor) and the amendment to the Company’s revolving credit facility.

See below for the discussion on Bangor and see Note 4, Debt and Financing Arrangements for a discussion on the amendment to the Company’s revolving credit facility.

Acquisition of Bangor Natural Gas Company - On July 8, 2024, Unitil entered into a Stock Purchase Agreement (the “Purchase Agreement”) among the Company, PHC Utilities, Inc.

(the “Seller”), and, with respect to certain portions of the Purchase Agreement, Hearthstone Utilities, Inc., d/b/a Hope Companies, Inc.

(the “Parent”).

The Seller is a subsidiary of the Parent.

Pursuant to, and subject to the terms and conditions of, the Purchase Agreement, the Company agreed to acquire all of the issued and outstanding shares of capital stock of Bangor from the Seller (the “Acquisition”) for $ 70.9 million in cash, subject to certain adjustments as provided in the Purchase Agreement.

The MPUC issued an order on December 18, 2024 ap proving the merger of Bangor into Unitil.

The transaction closed on January 31, 2025.

During the period through the date of this filing, the Company did not have any material subsequent events that would result in adjustment to or disclosure in its Consolidated Financial Statements.

Segment Information

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utility electric operations and utility gas operations.

Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capital regions of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts.

Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire, Fitchburg, which operates in Massachusetts and Northern Utilities, which operates in New Hampshire and Maine.

Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capital regions of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area, portions of central Maine including Augusta and the Bangor area, and in the greater Fitchburg area of north central Massachusetts.

Unitil has five distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire, Fitchburg, which operates in Massachusetts, Northern Utilities, which operates in New Hampshire and Maine, Bangor, which operates in Maine and Maine Natural, which operates in Maine.

Unitil Energy and the electric division of Fitchburg are included in the electric segment.

Northern Utilities and the gas division of Fitchburg

are included in the gas segment.

Unitil Energy, Fitchburg and Northern Utilities have a well-diversified customer mix and are not dependent on a single customer, or a few customers, for their electric and natural gas sales.

Northern Utilities, Bangor, Maine Natural and the gas division of Fitchburg are included in the gas segment.

Unitil Energy, Fitchburg, Northern Utilities, Bangor

and Maine Natural have a well-diversified customer mix and are not dependent on a single customer, or a few customers, for their electric and natural gas sales.

Granite State is an interstate natural gas transmission pipeline company, operating 85 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire.

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Unitil Service provides centralized management and administrative services, including information systems management and financial record keeping to support the affiliated Unitil companies.

Unitil Realty owns certain real estate, principally the Company’s corporate headquarters in Hampton, New Hampshire and land for future use in Kingston, New Hampshire.

Unitil Realty owns certain real estate, principally the Company’s corporate headquarters in Hampton, New Hampshire and land in Kingston, New Hampshire on which Unitil Energy’s solar facility is located, which became operational in May 2025.

Unitil Service’s and Unitil Realty’s costs are allocated to the Electric and Gas segments based on cost allocation factors.

Unitil Water does not have any activity.

The segments follow the same accounting policies as described in the Summary of Significant Accounting Policies.

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Operation and Maintenance

Depreciation and Amortization

Depreciation and Amortization Expense

Other Segment Expenses (Income)

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Year Ended December 31, 2024

Total Reportable Segments

Total Operating Revenues

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Provision for Income Taxes

Segment Profit (Loss)

Net Income Attributable to Commons Shares

Segment Assets

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Year Ended December 31, 2023

Total Reportable Segments

Total Operating Revenues

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Provision for Income Taxes

Segment Profit (Loss)

Net Income Attributable to Commons Shares

Segment Assets

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Allowance for Doubtful Accounts

Unitil’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms.

In 2024, 2023 and 2022, the Company recorded provisions for the energy commodity portion of bad debts of $ 1.6 million, $ 3.8 million and $ 3.8 million, respectively.

Unitil’s distribution utilities which are under traditional cost of service regulation are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms.

In 2025, 2024 and 2023, the Company recorded provisions for the energy commodity portion of bad debts o f $ 2.6 mi llion, $ 1.6 million and $ 3.8 million, respectively.

These provisions were recognized in Cost of Electric Sales and Cost of Gas Sales expense as the associated electric and gas utility revenues were billed.

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The Company currently receives recovery in rates or expects to receive recovery of these hardship accounts in future rate cases.

Accounts Receivable, Net includes $ 2.3 million and $ 2.3 million of the Allowance for Doubtful Accounts at December 31, 2024 and December 31, 2023, respectively.

Unbilled Revenues, net (a component of Accrued Revenue) includes $ 0.1 million and $ 0.1 million of the Allowance for Doubtful Accounts at December 31, 2024 and December 31, 2023, respectively.

Accounts Receivable, Net inclu des $ 2.1 m illion and $ 2.3 million of the Allowance for Doubtful Accounts at December 31, 2025 and December 31, 2024, respectively.

Unbilled Revenues, net (a component of Accrued Revenue) includes less than $ 0.1 m illion and $ 0.1 million of the Allowance for Doubtful Accounts at December 31, 2025 and December 31, 2024, respectively.

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2025, 2024 and 2023 (millions):

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Long-Term Debt and Interest Expense

Long-Term Debt Structure and Covenants - The debt agreements for Unitil and its utility subsidiaries, Unitil Energy, Fitchburg, Northern Utilities, and Granite State, contain various covenants and restrictions.

Long-Term Debt Structure and Covenants - The debt agreements for Unitil and its utility subsidiaries, Unitil Energy, Fitchburg, Northern Utilities, Bangor and Granite State, contain various covenants and restrictions.

These agreements do not contain any covenants or restrictions pertaining to the maintenance of financial ratios or the issuance of short-term debt.

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The Unitil Energy default provisions are not triggered by the actions or defaults of Unitil or its other subsidiaries.

All of the long-term debt of Fitchburg, Northern Utilities and Granite State are issued under Unsecured Promissory Notes with negative pledge provisions.

All of the long-term debt of Fitchburg, Northern Utilities, Bangor and Granite State are issued under Unsecured Promissory Notes with negative pledge provisions.

Each issue of long-term debt ranks pari passu with its other senior unsecured long-term debt within that subsidiary.

The long-term debt’s negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt.

The long-term debt’s negative pledge provisions contain restrictions which, among other

things, limit the incursion of additional long-term debt.

Accordingly, in order for Fitchburg, Northern Utilities or Granite State to issue new long-term debt, the covenants of the existing long-term agreements of that subsidiary must be satisfied, including that the subsidiary have total funded indebtedness less than 65 % of total capitalization.

Additionally, to issue new long-term debt, Fitchburg must maintain earnings available for interest equal to at least two times the interest charges for funded indebtedness.

As with the Unitil Energy agreements, the Fitchburg, Northern Utilities and Granite State long-term debt agreements each require that if that subsidiary defaults on any of its own long-term debt agreements, it would constitute a default under all of that subsidiary’s long-term debt agreements.

None of the Fitchburg, Northern Utilities and Granite State default provisions are triggered by the actions or defaults of Unitil or any of its other subsidiaries.

The Unitil, Unitil Energy, Fitchburg, Northern Utilities and Granite State long-term debt instruments and agreements contain covenants restricting the ability of each company to incur liens and to enter into sale and leaseback transactions, and restricting the ability of each company to consolidate with, to merge with or into, or to sell or otherwise dispose of all or substantially all of its assets.

Unitil Energy, Fitchburg, Northern Utilities and Granite State pay common dividends to their sole common shareholder, Unitil Corporation and these common dividends are the primary source of cash for the payment of dividends to Unitil’s common shareholders.

The long-term debt issued by the Company and its subsidiaries contains certain covenants that determine the amount that the Company and each of these subsidiary companies has available to pay for dividends.

As with the Unitil Energy agreements, the Fitchburg, Northern Utilities, Bangor and Granite State long-term debt agreements each require that if that subsidiary defaults on any of its own long-term debt agreements, it would constitute a default under all of that subsidiary’s long-term debt agreements.

None of the Fitchburg, Northern Utilities, Bangor and Granite State default provisions are triggered by the actions or defaults of Unitil or any of its other subsidiaries.

The Unitil, Unitil Energy, Fitchburg, Northern Utilities, Bangor and Granite State long-term debt instruments and agreements contain covenants restricting the ability of each company to incur liens and to enter into sale and leaseback transactions, and restricting the ability of each company to consolidate with, to merge with or into, or to sell or otherwise dispose of all or substantially all of its assets.

Unitil Energy, Fitchburg, Northern Utilities, Bangor and Granite State pay common dividends to their sole common shareholder, Unitil Corporation and these common dividends are the primary source of cash for the payment of dividends to Unitil’s common shareholders.

The long-term debt issued by the Company and its subsidiaries contains certain covenants that determine the amount that t he Company and each of these subsidiary companies has available to pay for dividends.

As of December 31, 2025, in accordance with the covenants, these subsidiary companies had a combined amount of $ 563.1 million available for the payment of dividends and Unitil Corporation had $ 318.5 million available for the payment of dividends.

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Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2025 for the payment of dividends.

Issuance of Long-Term Debt - O n July 6, 2023, Fitchburg issued $ 12.0 million of Notes due July 2, 2033 at 5.70 % and $ 13.0 million of Notes due July 2, 2053 at 5.96 %.

Fitchburg used the net proceeds from these offerings to refinance existing debt and for general corporate purposes.

Issuance of Long-Term Debt - On July 8, 2025, Bangor issued $ 14.0 million of Notes due 2030 at 5.70 % and $ 18.0 million of Notes due 2035 at 6.31 %.

Bangor used the net proceeds to refinance existing debt and for general corporate purposes.

Approximately $ 0.2 million of costs associated with this issuance were recorded as a reduction of Long-Term Debt for presentation purposes on the Consolidated Balance Sheet in the third quarter of 2025.

On August 21, 2024, Unitil Corporation issued $ 20.0 million of Notes due 2034 at 5.99 %.

O n August 21, 2024, Unitil Corporation issued $ 20.0 million of Notes due 2034 at 5.99 %.

Fitchburg issued $ 12.5 million of Notes due 2034 at 5.54 % and $ 12.5 million of Notes due 2044 at 5.99 %.

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Approximately $ 1.0 million of costs associated with this issuance were recorded as a reduction of Long-Term Debt for presentation purposes on the Consolidated Balance Sheet in the third quarter of 2024.

Debt Repayment - The total aggregate amount of debt repayments relating to bond issues and normal scheduled long-term debt repayments amounted to $ 4.9 million, $ 6.9 million and $ 10.4 million in 2024, 2023, and 2022, respectively.

Debt Repayment - The total aggregate amount of debt repayments relating to bond issues and normal scheduled long-term debt repayments amounted to $ 4.9 m illion, $ 4.9 million and $ 6.9 million in 2025, 2024, and 2023, respectively.

The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2025 is:

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4.04 % Senior Notes, Due September 12, 2049

5.70 % Senior Notes, Due July 8, 2030

6.31 % Senior Notes, Due July 8, 2035

Granite State:

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Credit Arrangements

On January 29, 2025, the Company entered into an amendment to the Credit Facility, which (among other things) increased the borrowing limit under the Credit Facility from $ 200 million to $ 275 million and extended the term of the Credit Facility from September 29, 2027 until September 29, 2028.

Unitil may borrow under the Credit Facility until September 29, 2028, subje ct to two one-year extensions under certain circumstances.

The Credit Facility has a borrowing limit of $ 275 million ($ 200 million as of December 31, 2024), which includes a $ 25 million sublimit for the issuance of standby letters of credit .

Unitil may increase the borrowing limit under the Credit Facility by up to $ 75 million under certain circumstances.

T he Credit Facility generally provides Unitil with the ability to elect that borrowings under the Credit Facility bear interest under several options, including a daily fluctuating rate equal to (a) the forward-looking secured overnight financing rate (as administered by the Federal Reserve Bank of New York) term rate with a term equivalent to one month beginning on that date, plus (b) 0.1000 %, plus (c) a margin of 1.125 % to 1.375 % (based on Unitil’s credit rating).

On September 29, 2022, the Company entered into a Third Amended and Restated Credit Agreement with a syndicate of lenders (collectively, the “Credit Facility”), which amended and restated the prior credit facility in full, and on January 29, 2025, the Company executed an amendment that increased the borrowing limit under the Credit Facility from $ 200 million to $ 275 million and extended the term of the maturity date from September 29, 2027 until September 29, 2028.

Unitil may borrow under the Credit Facility until September 29, 2028, subje ct to two one-year extensions un der certain circumstances.

The Credit Facility provides for a borrowing limit of $ 275 million, including a $ 25 million sublimit for standby letters of credit, and permits Unitil to increase the borrowing limit by up to $ 75 million under certain circumstances.

B orrowings under the Credit Facility may bear interest at various rate options, including a daily fluctuating rate equal to the forward-looking one-month secured overnight financing rate (SOFR) term rate (as administered by the Federal Reserve Bank of New York), plus 0.1000 %, plus a margin of 1.125 % to 1.375 % based on Unitil’s credit rating.

The Company generally utilizes the Credit Facility for cash management purposes related to its short-term operating activities and may use the Credit Facility for certain acquisition financing.

Total gross borrowings were $ 308.4 million and $ 327.2 million for the years ended December 31, 2024 and December 31, 2023, respectively.

Total gross repayments were $ 364.6 million and $ 281.2 million for the years ended December 31, 2024 and December 31, 2023, respectively.

Total gross borrowings we re $ 476.4 million and $ 308.4 million for the years ended December 31, 2025 and December 31, 2024, respectively.

Total gross repayments were $ 412.5 m illion and $ 364.6 million for the years ended December 31, 2025 and December 31, 2024, respectively.

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2025 and December 31, 2024:

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The Company believes it has sufficient sources of working capital to fund its operations.

The weighted average interest rates on all short-term borrowings were 6.5 %, 6.4 %, and 3.3 % during 2024, 2023, and 2022, respectively.

Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State are currently rated “BBB+” by Standard & Poor’s Ratings Services.

The weighted average interest rates on all short-term borrowings w ere 5.4 %, 6.5 %, and 6.4 % during 2025, 2024, and 2023, respectively.

On October 31, 2025, the Company entered into a senior unsecured delayed-draw term loan facility with The Bank of Nova Scotia.

The proceeds of the $ 86.0 million facility were used to initially fund the acquisition of Maine Natural on October 31, 2025.

The facility provides that the Company has an option for determining whether interest on loans under the facility will bear interest based on a Base Rate plus an applicable margin of 0.25 % or based on a one month Term SOFR plus a SOFR adjustment of 0.10 % plus an applicable margin of 1.25 %.

The Base Rate is equal to the highest of the (a) Federal Funds Rate plus 0.50 %, (b) the rate of interest in effect for such day as publicly announced from time to time by The Bank of Nova Scotia as its "prime rate", or (c) one month Term SOFR plus a SOFR adjustment of 0.10% plus 1.00%.

The facility has a maturity date of October 31, 2026 .

Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State are currently rated “BBB+” and Bangor is currently rated “BBB” by Standard & Poor’s Ratings Services.

Unitil Corporation and Granite State are currently rated “Baa2”, and Fitchburg, Unitil Energy and Northern Utilities are currently rated “Baa1” by Moody’s Investors Services.

Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager.

Northern Utilities and Bangor enter into asset management agreements under which Northern Utilities and Bangor release certain natural gas pipeline and storage assets, resell the natural gas storage inventory to an asset manager and subsequently repurchase the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager.

There was $ 9.3 million of natural gas storage inventory and corresponding obligations at December 31, 2025, related to these asset management agreements.

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Unitil’s subsidiaries lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements.

Total rental expense under operating leases charged to operations for the years ended December 31, 2024, 2023 and 2022 amounted to $ 2.2 million, $ 2.1 million and $ 1.8 million respectively.

Total rental expense under operating leases charged to operations for the years ended December 31, 2025, 2024 and 2023 amounted t o $ 2.3 m illion, $ 2.2 million and $ 2.1 million respectively.

The balance sheet classification of the Company’s lease obligations was as follows:

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Total Lease Obligations

Cash paid for amounts included in the measurement of operating lease obligations for the twelve months ended December 31, 2024 and 2023 was $ 2.2 million and $ 2.1 million, respectively and was included in Cash Provided by Operating Activities on the Consolidated Statements of Cash Flows.

Assets under capital leases amounted to approximately $ 0.6 million and $ 0.7 million as of December 31, 2024 and 2023, respectively, less accumulated amortization of $ 0.1 million and $ 0.2 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheets.

Cash paid for amounts included in the measurement of operating lease obligations for the twelve months ended December 31, 2025 and 2024 wa s $ 2.3 m illion and $ 2.2 million, respectively and was included in Cash Provided by Operating Activities on the Consolidated Statements of Cash Flows.

Assets under capital leases amounted to approximatel y $ 0.9 milli on and $ 0.6 million as of December 31, 2025 and 2024, respectively, less accumulated amortization o f $ 0.3 million and $ 0.1 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheets.

The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2025.

The payments for operating leases consist of $ 1.8 million of current operating lease obligations and $ 4.9 million of noncurrent operating lease obligations on the Company’s Consolidated Balance Sheets as of December 31, 2024.

The payments for capital leases consist of $ 0.1 million of current Capital Lease Obligations, which are included in Other Current Liabilities, and $ 0.4 million of noncurrent Capital Lease Obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2024.

The payments for operating leases consist of $ 2.1 mi llion of current operating lease obligations an d $ 4.9 mill ion of noncurrent operating lease obligations on the Company’s Consolidated Balance Sheets as of December 31, 2025.

The payments for capital leases consist o f $ 0.2 million of current Capital Lease Obligations, which are included in Other Current Liabilities, and $ 0.4 m illion of noncurrent Capital Lease Obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2025.

Lease Payments ($000’s)

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In determining the present value of lease payments, the Company used the interest rate stated in each lease agreement.

As of December 31, 2024, the weighted average remaining lease term is 4.2 years and the weighted average operating discount rate used to determine the operating lease obligations was 5.1 %.

As of December 31, 2023, the weighted average remaining lease term was 3.7 years and the weighted average operating discount rate used to determine the operating lease obligations was 4.4 %.

The Company provides limited guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities.

As of December 31, 2025, the weighted average remainin g lease term is 3.8 years and the weighted average operating discount rate used to determine the operating lease obligations was 5.3 %.

As of De cember 31, 2024, the weighted average remaining lease term was 4.2 years and the weighted average operating discount rate used to determine the operating lease obligations was 5.1 %.

The Company provides limited guarantees on certain energy and natural gas asset management contracts entered into by the distribution utilities.

The Company’s policy is to limit the duration of these guarantees.

As of December 31, 2024, there were no guarantees outstanding.

As of December 31, 2025, there were $ 50.3 million of guarantees outstanding.

The Company has common stock outstanding and one of the Company’s subsidiaries has preferred stock outstanding.

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The Company has 25,000,000 shares of common stock authorized as of December 31, 2025 and December 31, 2024.

The following table summarizes the Company’s common shares activity for the year ended December 31, 2025:

Shares as of December 31, 2024

Shares Issued - Equity Issuance

Shares Issued - ATM

Shares Issued - DRP

Shares Issued - Directors

Shares Issued - RSU Settlement

Shares Issued - Time Restricted

Shares Issued - Performance Restricted

Forfeited Shares - Time Restricted

Forfeited Shares - Performance Restricted

Shares as of December 31, 2025

Unitil Corporation Underwritten Common Stock Offering— On August 18, 2025, the Company issued and sold 1,602,358 shares of its common stock at a price of $ 46.65 per share in an underwritten registered public offering (Offering).

The Company’s net increase to Common Equity and Cash proceeds from the Offering was approximately $ 71.8 million.

The proceeds will be used to make equity capital contributions to the Company’s regulated ut ility subsidiaries, to repay debt and for other general corporate purposes.

Overall, the results of operations and earnings in 2025 reflect the higher number of average shares outstanding.

At-the-Market Equity Offering Program — On June 3, 2025, the Company entered into an at-the-market equity offering program (ATM program) with sales agents under which the Company may, from time to time, offer and sell shares of its common stock having an aggregate offering price of up to $ 50 million.

Sales of common stock under the ATM program are made pursuant to a shelf registration statement on Form S-3 (File No.

333-287753) and a related prospectus supplement filed with the Securities and Exchange Commission.

During the year ended December 31, 2025, the Company sold 27,620 shares of common stock under the ATM program at an average price of $ 53.00 per share, resulting in gross proceeds of $ 1.5 million and net proceeds of $ 1.4 million after deducting commissions and offering expenses.

As of December 31, 2025, $ 48.5 million remains available for future sales under the program.

The Company intends to use the net proceeds from the ATM program for general corporate purposes, including capital contributions to the Company's utility subsidiaries, repayment of debt, acquisitions, capital expenditures and working capital, as described in the prospectus supplement relating to the ATM program.

Dividend Reinvestment and Stock Purchase Plan— During 2025, the Company sold 21,519 shares of its common stock, at an average price of $ 51.83 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $ 1.1 million.

The DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock.

T he DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock.

During 2024 and 2023, the Company raised $ 1.1 million and $ 1.1 million, respectively, through the issuance of 19,510 and 21,321 shares, respectively, of its common stock in connection with its DRP and 401(k) plans.

Common Shares Repurchased, Cancelled and Retired— Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted by the Company on May 1, 2014 (trading plan), until October 3, 2023, the Company periodically repurchased shares of its common stock on the open market related to the

stock portion of the annual retainer for the members of the Company’s Board of Directors.

Common Shares Repurchased, Cancelled and Retired— Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted by the Company on May 1, 2014 (trading plan), until October 3, 2024, the Company periodically repurchased shares of its common stock on the open market related to the stock portion of the annual retainer for the members of the Company’s Board of Directors.

Until December 1, 2018, the Company also periodically repurchased shares of its common stock on the open market related to Employee Length of Service Awards.

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(See Part II, Item 5, for additional information).

During 2024, 2023 and 2022, the Company repurchased zero , 14,680 and 9,449 shares of its common stock, respectively, pursuant to the Rule 10b5-1 trading plan.

The expense recognized by the Company for these repurchases was zero , $ 0.6 million, and $ 0.4 million in 2024, 2023 and 2022, respectively.

During 2025, 2024 and 2023, the Company repurchased zero , zero and 14,680 shares of its common stock, respectively, pursuant to the Rule 10b5-1 trading plan.

The expense recognized by the Company for these repurchases was zero , zero , and $ 0.6 million in 2025, 2024 and 2023, respectively.

During 2025, 2024 and 2023, the Company did not cancel or retire any of its common stock.

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The Company accounts for its stock-based compensation plan in accordance with the provisions of the FASB Codification and measures compensation costs at fair value at the grant date.

Stock Plan— The Company maintains the Unitil Corporation Third Amended and Restated 2003 Stock Plan (as amended, the “Stock Plan”).

The Company maintains the Unitil Corporation Third Amended and Restated 2003 Stock Plan (as amended, the “Stock Plan”).

Participants in the Stock Plan are selected by the Compensation Committee of the Board of Directors to receive awards under the Stock Plan, including:

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Market Value (millions)

There were 34,417 and 36,483 non-vested Time Restricted Shares under the Stock Plan as of December 31, 2024 and 2023, respectively.

The weighted average grant date fair value of these shares was $ 48.84 per share and $ 46.94 per share, respectively.

The compensation expense associated with the issuance of Time Restricted Shares under the Stock Plan is being

recorded over the vesting period and was $ 1.4 million, $ 1.4 million and $ 2.1 million in 2024, 2023 and 2022, respectively.

At December 31, 2024, there was approximately $ 0.8 million of total unrecognized compensation cost for Time Restricted Shares under the Stock Plan which is expected to be recognized over approximately 2.4 years.

During 2024, there were 354 Time Restricted Shares forfeited and zero Time Restricted Shares cancelled under the Stock Plan.

The compensation expense associated with the issuance of Time Restricted Shares under the Stock Plan is being recorded over the vesting period and wa s $ 1.9 million, $ 1.4 million and $ 1.4 million in 2025, 2024 and 2023, respectively.

At December 31, 2025, there was approximately $ 0.8 mi llion of total unrecognized compensation cost for Time Restricted Shares under the Stock Plan which is expected to be recognized over approximately 2.6 years.

D uring 2025, there were 396 Time Restricted Shares forfeited and zero Time Restricted Shares cancelled under the Stock Plan.

On January 27, 2026, there were 32,330 Time Restricted Shares issued under the Stock Plan with an aggregate market value of $ 1.6 million.

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Prior to the end of the performance period, the Performance Restricted Shares are subject to forfeiture if the participant ceases to be employed by the Company other than due to the participant’s death, disability or retirement.

Initial awards of Performance Restricted Shares were granted January 24, 2023.

No Performance Restricted Shares were awarded in 2022.

Performance Restricted Shares issued in the years ended 2023, 2024 and 2025 in conjunction with the Stock Plan are presented in the following table:

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Market Value (millions)

There were 44,449 non-vested Performance Restricted Shares under the Stock Plan as of December 31, 2024.

The weighted average grant date fair value of these shares was $ 50.26 p er share.

The compensation expense associated with the issuance of Performance Restricted Shares under the Stock Plan is being recognized over the vesting period and wa s $ 1.0 million and $ 0.5 million i n 2024 and 2023, respectively.

The compensation expense associated with the issuance of Performance Restricted Shares under the Stock Plan is being recognized over the vesting period and wa s $ 1.4 million, $ 1.0 million and $ 0.5 million i n 2025, 2024 and 2023, respectively.

At December 31, 2025, there was approximately $ 1.7 million of total unrecognized compensation cost for Performance Restricted Shares under the Stock Plan which is expected to be recognized over approximately 1.7 years.

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On January 27, 2026, there were 32,330 Performance Restricted Shares issued under the Stock Plan with an aggregate market value of $ 1.6 million.

The Time Restricted Shares and Performance Restricted Shares unvested activity during the year ended December 31, 2025 in conjunction with the Stock Plan is presented in the following table:

Restricted Shares

Time Restricted Shares

Performance Restricted Shares

Restricted Shares as of December 31, 2024

Shares Issued

Restricted Shares as of December 31, 2025

Restricted Stock Units

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The Restricted Stock Units will be paid such that the Director will receive (i) 70 % of the shares of the Company’s common stock underlying the restricted stock units and (ii) cash in an amount equal to the fair market value of 30 % of the shares of the Company’s common stock underlying the Restricted Stock Units.

The equity portion of Restricted Stock Units activity during 2024 and 2023 in conjunction with the Stock Plan are presented in the following table:

Restricted Stock Units (Equity Portion)

Beginning Restricted Stock Units

The equity and liability portions of Restricted Stock Units activity during 2025 and 2024 in conjunction with the Stock Plan are presented in the following table:

Restricted Stock Units

(Equity Portion)

(Liability Portion)

Restricted Stock Units as of December 31, 2023

Restricted Stock Units Granted

Dividend Equivalents Earned

Restricted Stock Units as of December 31, 2024

Restricted Stock Units Granted

Dividend Equivalents Earned

Restricted Stock Units Settled

Ending Restricted Stock Units

Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2024 and 2023 include $ 0.9 million and $ 0.8 million, respectively, representing the fair value of liabilities associated with the portion of fully vested RSUs that will be settled in cash.

Restricted Stock Units as of December 31, 2025

Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2025 and 2024 include $ 0.7 million an d $ 0.9 million, respectively, representing the fair value of liabilities associated with the portion of fully vested RSUs that will be settled in cash.

Directors Stock

Members of the Company’s Board of Directors who do not elect to receive Restricted Stock Units are issued shares of common stock.

During the year ended December 31, 2025, 14,610 shares of common stock were issued to Directors.

Preferred Stock

There were $ 0.2 million, or 1,727 shares, of Unitil Energy’s 6.00 % Series Preferred Stock outstanding as of December 31, 2024 and December 31, 2023.

There wer e $ 0.2 million, or 1,727 sh ares, of Unitil Energy’s 6.00 % Series Preferred Stock outstanding as of December 31, 2025 and December 31, 2024.

There were less than $ 0.1 million of total dividends declared on Preferred Stock in each of the twelve month periods ended December 31, 2025 and December 31, 2024, respectively.

Earnings Per Share

Unitil has granted restricted stock awards and restricted stock units with non-forfeitable dividend rights, which are considered participating securities.

Accordingly, earnings per share are computed using the two-class method as required by FASB ASC 260-10-45.

Basic earnings per common share is calculated by dividing net income allocated to common shareholders by the weighted average number of common shares outstanding during the period, which excludes the participating securities.

Diluted earnings per common share are adjusted for the dilutive effects of restricted stock.

The following table reconciles basic and diluted earnings per share (EPS).

(Millions except shares and per share data)

Earnings Available to Common Shareholders

Weighted Average Common Shares Outstanding—Basic (000’s)

Diluted Effect of Incremental Shares (000’s)

Weighted Average Common Shares Outstanding—Diluted (000’s)

Earnings per Share—Basic and Diluted

Earnings Per Share (millions, except shares and per share data)

Less allocation of earnings and dividends to participating securities

Net income allocated to common shareholders

Weighted average common shares outstanding, gross

Less average participating securities

Weighted average number of shares outstanding used in the calculation of basic earnings per share

Add dilutive effect of:

Restricted stock and restricted stock units

Adjusted weighted average number of shares outstanding used in the calculation of diluted earnings per common share

Earnings per common share:

The following table shows the number of weighted average non-vested restricted shares that were not included in the above computation of EPS because the effect would have been antidilutive.

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As of December 2025, 85% of Unitil’s largest New Hampshire customers, representing 24% of Unitil’s New Hampshire electric kilowatt-hour (kWh) sales, and 96% of Unitil’s largest Massachusetts customers, representing 25% of Unitil’s Massachusetts electric kWh sales, purchased their electric power supply in the competitive market.

Additionally, cities and towns in Massachusetts may, with approval from the MDPU, implement municipal aggregations whereby the municipality purchases electric power on behalf of all citizens and businesses that do not opt out of the

The Towns of Lunenburg, Townsend, Ashby, and the City of Fitchburg have active municipal aggregations.

Customers in these four town’s represent 99.8% of Fitchburg’s customer base.

In New Hampshire, a majority of residential and small commercial customers purchase their electric supply through Community Choice Aggregations (CCA) and retail electric suppliers.

As of December 2024, the percentage of residential customers purchasing electricity from a third-party supplier or CCA increased to 68% from nearly 22% in December 2023.

There are currently 14 communities with active aggregations, representing 73% of Unitil’s customer base in New Hampshire.

In Massachusetts, as of December 2024, 75% of Unitil’s residential customers in Massachusetts purchased their electricity from a CCA or third-party supplier which is up from 75% in 2023.

In New Hampshire, as of December 2025, the percentage of residential customers purchasing electricity from a third-party supplier or CCA decreased to 66% from 68% in 2024.

In Massachusetts, as of December 2025, the percentage of residential customers purchasing electricity from a third-party supplier or municipal aggregation increased to 84% from 75% in 2024.

Regulated Electric Power Supply

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Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers.

Currently, with approval of the NHPUC, Unitil Energy purchases Default Service power supply contracts for small, medium and large customers every six months for 90 % of the supply requirements.

10 % of supply requirements are procured via direct market purchases from ISO-New England.

Currently, with approval of the NHPUC, Unitil Energy purchases Default Service power supply contracts for small, medium and large customers every six months for 50 % of the supply requirements and the remaining 50 % of supply requirements are procured via direct market purchases from ISO-New England.

Fitchburg typically maintains power supply contracts with various wholesale suppliers for the provision of Basic Service electric supply.

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As such, Fitchburg procures electric power supply for large account customers directly through ISO-NE’s markets.

The Company experienced a failed solicitation in its November 2024 solicitation, which results in Fitchburg self-supplying 50 % of its load requirements for the February through July 2025 period.

The failed solicitation was due to a combination of lack of bidders and excessively high-priced bids, which the Company rejected.

The Company was successful in procuring 100 % of supply requirements for the small customer group from the traditional procurement process.

The Company experienced a failed solicitation in its November 2025 solicitation for the medium customer group, which results in Fitchburg self-supplying 100 % of its load requirements for the February through July 2026 period.

The failed solicitation was due to no bidders for the medium customer group.

The implications of the failed solicitation result in 100 % of wholesale supply charges settling at the real-time energy price.

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The Company reconciles and recovers these supply expenses in its rates at cost on a pass through basis and therefore changes in approved expenses do not affect earnings.

The NHPUC and MDPU regularly review alternatives to their procurement policy for all electric distribution companies, and currently have open investigations in procurements processes, which may lead to future changes in this regulated power supply procurement structure.

Regional Electric Transmission and Power Markets

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NATURAL GAS SUPPLY

Unitil purchases and manages gas supply for customers served by Northern Utilities in Maine and New Hampshire, and by Fitchburg in Massachusetts.

Unitil purchases and manages gas supply for customers served by Northern Utilities in Maine and New Hampshire, by Fitchburg in Massachusetts, and by Bangor and Maine Natural in Maine.

Unitil began purchasing and managing gas supply for customers served by Bangor on January 31, 2025 and Maine Natural on October 31, 2025.

Northern Utilities’ Commercial and Industrial (C&I) customers are entitled to purchase their natural gas supply from third-party gas suppliers.

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Most small C&I customers, and all residential customers, purchase their gas supply from Northern Utilities under regulated rates and tariffs.

As of December 2024, 74% of Unitil’s largest New Hampshire gas customers, representing 40% of Unitil’s New Hampshire gas therm sales, and 62% of Unitil’s largest Maine customers, representing 22% of Unitil’s Maine gas therm sales, purchased their gas supply from a third-party supplier.

As of December, 2025, 71% of Northern Utilities’s largest New Hampshire gas customers, representing 38% of Northern Utilities’s New Hampshire gas therm sales, and 59% of Northern Utilities’s largest Maine customers, representing 21% of Northern Utilities’s Maine gas therm sales, purchased their gas supply from a third-party supplier.

Bangor’s C&I customers are entitled to purchase their natural gas supply from third-party gas suppliers.

Many of Bangor’s large, and some of its medium, C&I customers purchase their gas supply from third-party suppliers.

Most small C&I customers, and all residential customers, purchase their gas supply from Bangor under regulated rates and tariffs.

As of December 2025, 49% of Bangor’s largest customers, representing 46% of Bangor’s gas therm sales, purchased their gas supply from a third-party supplier.

Maine Natural’s C&I customers are entitled to purchase their natural gas supply from third-party gas suppliers.

Many of Maine Natural’s large, and some of its medium, C&I customers purchase their gas supply from third-party suppliers.

Most small C&I customers, and all residential customers, purchase their gas supply from Maine Natural under regulated rates and tariffs.

As of December 2025, 11% of Maine Natural’s largest customers, representing 25% of Maine Natural gas therm sales, purchased their gas supply from a third-party supplier.

Fitchburg’s residential and C&I business customers are entitled to purchase their natural gas supply from third-party gas suppliers.

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Northern Utilities arranges for gas transportation and delivery to its system through its own long-term contracts with various interstate pipeline and storage facilities, through peaking supply contracts delivered to its system, or in the case of liquefied natural gas (LNG), via trucking of supplies to storage facilities within Northern Utilities’ service territory.

Northern Utilities has available under firm contract 85,500 million British Thermal Units (MMBtu) per day of year-round and an additional 44,000 MMBtu of winter seasonal transportation capacity to its distribution facilities, and 6.3 billion cubic feet (BCF) of underground storage.

Nort hern Utilities has available under firm contract 85,500 million British Thermal Units (MMBtu) per day of year-round and an additional 44,000 MMBtu of winter seasonal transportation capacity to its distribution facilities, and 6.3 billion cubic feet (BCF) of underground storage.

As a supplement to pipeline natural gas, Northern Utilities owns an LNG storage and vaporization facility.

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These plants are used principally during peak load periods to augment the supply of pipeline natural gas.

Bangor purchases the majority of its natural gas from U.S.

domestic and Canadian suppliers largely under contracts of one year or less, and on occasion from producers and marketers on the spot market.

Bangor arranges for gas transportation and delivery to its system through its own long-term contracts with various interstate pipeline and storage facilities.

Bangor has firm contracts for up to 35,000 MMBtu per day of year-round transportation and 0.69 BCF of underground storage capacity to its distribution facilities.

Bangor Natural Gas has contracted for year-round and supplemental winter supplies to meet Bangor system demands.

Maine Natural purchases its natural gas from suppliers largely under contracts of one year or less.

Maine Natural Gas arranges for gas transportation and delivery to its system through firm pipeline capacity.

Maine Natural has available under firm contract 6,500 MMB tu per day of year-round transportation.

As a supplement to year-round pipeline natural gas, Maine Natural has contracted for additional supplies to meet winter demands.

In 2018, Fitchburg entered into a long-term power purchase agreement (PPA) with H.Q.

Energy Services (U.S.) Inc.

(HQUS) to procure bundled clean energy and associated environmental attributes pursuant to Section 83D of “An Act to Promote Energy Diversity” (2016).

The PPA requires Fitchburg to purchase specified quantities of electric energy over the 20-year contract term and provides for the transfer of associated environmental attributes.

(See Note 8 Commitments and Contingencies:

Fitchburg - Massachusetts Request for Proposals.)

During 2025, based on the status of the NECEC Transmission Line and the Company’s assessment that the contingency related to the commencement of deliveries was substantially resolved as of December 31, 2025, the Company concluded that the PPA met the definition of a derivative.

The Company evaluated the PPA under ASC 815 and concluded that (i) the host contract includes environmental attributes that do not meet the definition of a derivative and (ii) the PPA contains an embedded derivative related to the energy component that requires bifurcation.

The Company has not designated the derivative as a hedging instrument.

Additionally, the derivative does not qualify for the normal purchase normal sale scope exception.

Accordingly, the Company accounts for the embedded energy derivative at fair value, with subsequent changes in fair value recognized as a regulatory offset.

Please see Note 1 (Summary of Significant Accounting Policies - Derivatives) for a discussion of the Company’s regulatory accounting treatment of derivatives.

The PPA provides a bundled price for energy and environmental attributes.

In connection with bifurcation and fair value measurement of the embedded energy derivative, the Company applied an allocation approach to separate the embedded energy derivative from the non-derivative environmental attribute component.

The fair value of the embedded energy derivative is estimated using a discounted cash flow model that compares forward market prices to the adjusted fixed price for the energy component of the PPA, multiplied by expected delivery volumes, and discounted using a rate that reflects the relevant counterparty’s credit risk.

Observable inputs include on-peak and off-peak forward electricity prices and the Company incorporates an adjustment to estimate the pricing through the term of the PPA.

As of December 31, 2025, the Company classified the embedded derivative within Level 3 of the fair value hierarchy due to the use of significant unobservable inputs in estimating the value of the embedded derivative.

Please also see Note 1 (Summary of Significant Accounting Policies) for a discussion of the Company’s fair value accounting policy.

The fair value of the derivative was $ 17.7 million as of December 31, 2025, with $ 2.8 million recorded in Prepayments and Other related to the current portion and $ 14.9 million in Other Assets related to the noncurrent portion.

The Company has recorded corresponding Current and Noncurrent Regulatory Liabilities related to the fair value of the derivative.

No derivative assets or liabilities were recognized as of December 31, 2024.

The Company does not offset derivative assets and liabilities in the balance sheet.

The Company entered into a long-term energy procurement arrangement primarily to comply with regulatory clean energy requirements.

The Company does not enter into such arrangements for trading or speculative purposes.

The Company is exposed to credit risk related to possible nonperformance by its counterparty.

The Company manages this risk through ongoing credit monitoring and, as applicable, the use of collateral or other credit enhancements.

Commitments and Contingencies

Regulatory Matters

Overview— Unitil’s distribution utilities deliver electricity and/or natural gas to customers in the Company’s service territories at rates established under traditional cost of service regulation.

Under this regulatory structure, Unitil Energy, Fitchburg, and Northern Utilities are provided the opportunity to recover the cost of providing distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets.

Overview— Unitil’s distribution utilities primarily deliver electricity and/or natural gas to customers in the Company’s service territories at rates established under traditional cost of service regulation.

Under this regulatory structure, Unitil Energy, Fitchburg, Northern Utilities and Maine Natural’s non-Augusta service area are provided the opportunity to recover the cost of providing distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets.

Unitil Energy, Northern Utilities' New Hampshire division, and Fitchburg’s electric and gas divisions operate under revenue decoupling mechanisms.

Bangor and Maine Natural’s Augusta Service Area delivery rates to natural gas customers are established under alternative rate plans, which provide multi-year rate changes designed to approximate market-based rates.

Most of Unitil’s customers are entitled to purchase their electric or natural gas supplies from third-party suppliers.

For Northern Utilities, only business customers are entitled to purchase their natural gas supplies from third-party suppliers at this time.

Most small and medium-sized customers, however, continue to purchase such supplies through Unitil Energy, Fitchburg and Northern Utilities as the providers of basic or default service energy supply.

Unitil Energy, Fitchburg and Northern Utilities purchase electricity or natural gas for basic or default service from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup, through reconciling, pass-through rate mechanisms that are periodically adjusted.

The MDPU, the NHPUC and the MPUC each have continued to approve these reconciling rate mechanisms which allow Fitchburg, Unitil Energy and Northern Utilities to recover their actual wholesale energy costs for electric power and natural gas.

For Northern Utilities, Bangor, and Maine Natural, only business customers are entitled to purchase their natural gas supplies from

third-party suppliers.

Municipal aggregation has also occurred in a number of towns in Unitil’s New Hampshire and Massachusetts service territories.

As the providers of basic or default service, Unitil Energy, Fitchburg, Northern Utilities, Bangor and Maine Natural purchase wholesale electricity or natural gas and recover the actual costs of these supplies, without profit or markup, through reconciling, pass-through rate mechanisms that are periodically adjusted.

The MDPU, the NHPUC and the MPUC each have continued to approve these reconciling rate mechanisms which allow Fitchburg, Unitil Energy, Northern Utilities, Bangor and Maine Natural to recover their actual wholesale energy costs for electric power and natural gas.

Rate Case Activity

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In its Final Order issued on February 28, 2018 for Northern Utilities’ 2017 base rate case, the MPUC approved an extension of the TIRA mechanism for an additional eight-year period, which will allow for annual rate adjustments through the end of the CIRP program.

The Company’s most recent request under the TIRA mechanism, to increase annual base rates by $ 2.4 million for 2023 eligible facilities, was filed with the MPUC on April 24, 202 4.

The Company’s most recent request under the TIRA mechanism, to increase annual base rates by $ 2.1 million for 2024 eligible facilities, was filed with the MPUC on February 28, 2025 for rates effective May 1, 2025.

On April 29, 2025, the MPUC issued an order approving the filing, for rates effective May 1, 2025.

During 2024, Northern Utilities performed its fourteenth and final year of construction on the 14-year combined CIRP, (Unprotected Steel and Farm Tap project ordered by the MPUC in Docket Nos.

2008-00151 and 2013-00133).

As the Cast Iron Replacement Program and related unprotected steel and Farm Tap programs have been completed and all leak-prone pipe has been removed, this is Northern’s final TIRA rate adjustment.

Northern Utilities - Base Rates - New Hampshire - On July 20, 2022, the NHPUC issued an Order in the distribution base rate case filed with the NHPUC on August 2, 2021 by Northern Utilities.

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On August 31, 2022, the NHPUC approved the Company’s filing.

Unitil Energy - Base Rates - On May 3, 2022, the NHPUC issued an Order in the distribution base rate case filed with the NHPUC on April 2, 2021 by Unitil Energy.

The Order approved, in part, a comprehensive Settlement Agreement between the Company, the New Hampshire DOE, the OCA, the New Hampshire Department of Environmental Services, Clean Energy New Hampshire, and ChargePoint, Inc.

In addition to authorizing an increase to permanent distribution rates of $ 6.3 million, effective June 1, 2022, the Order approved the following components of the Settlement Agreement:

(1) a multi-year rate plan, (2) a revenue decoupling mechanism, (3) time-of-use rates, (4) resiliency programs to support the Company’s commitment to reliability, and (5) other rate design and tariff changes.

On May 10, 2022, the Company filed a request for clarification with the NHPUC to clarify that the authorized revenue requirement should exclude expenses related to the Company’s proposed Arrearage Management Program (AMP), which was not approved in the Order.

On May 12, 2022, the Commission issued an Order, which clarified that because the Company will not incur the expenses associated with the AMP, those costs should be removed from the revenue requirement, and that the adjusted increase of $ 5.9 million will result in reasonable rates.

The increase in permanent rates was reconciled back to June 1, 2021, the effective date of temporary rates previously approved in this docket.

This distribution base rate case reflected the Company’s operating costs and investments in utility plant for a test year ended December 31, 2020 as adjusted for known and measurable changes.

The Order provided for a return on equity of 9.2 % and a capital structure reflecting 52 % equity and 48 % long-term debt.

On July 28, 2022, the NHPUC approved the Company’s first step increase of approximately $ 1.3 million of annual revenue to recover eligible 2021 capital investments,

effective August 1, 2022.

On May 31, 2023, the NHPUC approved the Company’s second and final step adjustment increase of approximately $ 1.2 million to recover eligible 2022 capital investments, effective June 1, 2023.

Unitil Energy - Base Rates - On May 1, 2025 Unitil Energy filed for an increase in distribution base rates with the NHPUC.

The Company is seeking an increase in base rates of approximately $ 18.5 million or 7.3 % above present rates.

Unitil Energy also requested implementation of temporary rates for service rendered on and after July 1, 2025, and until a final order on permanent rates is issued.

The requested temporary rates were approved at the requested levels, resulting in an increase in annual revenues of $ 7.8 million, or a 3.7 % increase above present rates.

As provided by statute, once a final order on permanent rates is issued, the permanent rate level is reconciled back to the effective date of the temporary rates.

The filing includes (1) a proposed multi-year rate plan, (2) a continuation of its revenue decoupling mechanism, (3) an update to the previously approved suite of proposed time of use (TOU) rates including rates for electric vehicles (4) resiliency programs to further the Company’s commitment to reliability, (5) an Arrearage Management Program for financial hardship customers;

and (6) other rate design and tariff changes.

This matter remains pending.

Fitchburg - Base Rates - Electric - Fitchburg’s base rates are decoupled and subject to an annual revenue decoupling adjustment mechanism, which includes a cap on the amount that rates may be increased in any year.

In addition, Fitchburg has an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions.

On July 26, 2023, the MDPU issued an Order approving the Company's cumulative revenue requirement of $ 3.1 million associated with its 2019-2021 capital expenditures.

26, 2023, the MDPU issued an Order approving the Company's cumulative revenue requirement of $ 3.1 million associated with its 2019-2021 capital expenditures.

On September 11, 2024, the MDPU issued a final order approving the cumulative revenue requirement of $ 3.5 million associated with its 2019-2022 capital expenditures.

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On December 23, 2024, the MDPU approved recovery through its capital cost recovery mechanism effective January 1, 2025.

On October 31, 2025, Fitchburg submitted its revenue requirement analysis for 2024 capital expenditures.

In accordance with its tariff, Fitchburg sought approval to recover $ 0.2 million effective January 1, 2026.

On December 30, 2025, the MDPU approved the proposed recovery, subject to investigation.

On August 17, 2023, Fitchburg filed a petition with the MDPU seeking approval for a $ 6.8 million increase to base distribution rates, with new rates to be effective July 1, 2024.

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On July 16, 2024 the MDPU approved its revised compliance filing.

Part of the transfer of revenues from reconciling mechanisms to base rates included $ 0.8 million of pension/PBOP revenues.

In its Order, the MDPU found that allowing the Company to recover pension and PBOP expense through its Pension/PBOP Adjustment mechanism is no longer warranted.

Instead, the MDPU concluded that these expenses should be recovered in base distribution rates, the mechanism should be discontinued and any unrecovered expenses existing as of the effective date of new rates will be recovered over two years.

On July 18, 2024, the Company filed a Motion for Reconsideration and Recalculation in connection with this issue.

The motion specifically requested that the MDPU reconsider its decision to require the Company to absorb $ 1.4 million in negative excess accumulated deferred income taxes (ADIT) because the effect of the Order was to inappropriately claw back amounts that were previously approved by the MDPU for recovery from customers.

On July 18, 2024, the Company filed a Motion for Reconsideration and Recalculation requesting that the MDPU reconsider its decision to require the Company to absorb $ 1.4 million in negative excess accumulated deferred income taxes (ADIT) because the effect of the Order was to inappropriately claw back amounts that were previously approved by the MDPU for recovery from customers.

On November 26, 2024, the MDPU issued an Order on the Company’s motion holding, in part, that Pension/PBOP expenses shall be recovered in base distribution rates.

On December 9, 2024 the Company filed an appeal with Massachusetts Supreme Judicial Court requesting that it reverse and remand the final decision issued by the MDPU on June 28, 2024 along with the MDPU’s decision on reconsideration, issued November 26, 2024, unlawfully denying the Company’s recovery of approximately $ 1.4 million of negative, excess ADIT.

On December 9, 2024, the Company filed an appeal with Massachusetts Supreme Judicial Court on the grounds that the MDPU’s Order unlawfully denies the Company’s recovery of approximately $ 1.4 million of negative, excess ADIT.

The amount of $ 1.4 million is disaggregated between the Company’s gas division ($ 0.6 million) and the electric division ($ 0.8 million).

This motion is pending.

This appeal is pending.

The ruling on November 26, 2024 approved certain other recalculations, resulting in an additional increase to electric base rates of $ 0.1 million effective December 1, 2024.

Fitchburg - Performance Base Rate Adjustment - Electric - On February 28, 2025, Fitchburg filed its first Performance Based Revenue Adjustment (PBRA) for rates effective July 1, 2025.

The calculated PBRA adjustment resulted in a distribution revenue increase of $ 1.6 million.

On June 20, 2025, the MDPU issued an order approving the proposed increase effective July 1, 2025.

Fitchburg - Base Rates - Gas - On August 17, 2023, Fitchburg filed a petition with the MDPU seeking approval for a $ 10.9 million increase to base distribution rates, with new rates anticipated to be effective July 1, 2024.

Fitchburg proposed to transfer $ 4.2 million in revenue requirements recovered through its Gas System Enhancement Program to base distribution rates.

Net of these transfers, the proposed overall increase to distribution revenues is $ 6.7 million.

As part of this filing, Fitchburg is requesting approval for a PBR plan for up to a five-year term and continuation of its revenue decoupling mechanism.

Net of these transfers, the proposed overall increase to distribution revenues was $ 6.7 million.

As part of this filing, Fitchburg requested approval for a PBR plan for up to a five-year term and continuation of its revenue decoupling mechanism.

On June 28, 2024, the MDPU issued an Order providing for a $ 10.1 million increase to base rates, effective July 1, 2024.

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On July 16, 2024, the MDPU approved its revised compliance filing.

Part of the transfer of revenues from reconciling mechanisms to base rates included $ 0.9 million of pension/PBOP revenues.

In its Order, the MDPU found that allowing the Company to recover pension and PBOP expense through its Pension/PBOP Adjustment mechanism is no longer warranted.

On July 18, 2024, the Company filed a Motion for Reconsideration and Recalculation in connection with this issue.

The motion specifically requested that the MDPU reconsider its decision to require the Company to absorb $ 1.4

million in negative excess accumulated deferred income taxes (ADIT) because the effect of the Order was to inappropriately claw back amounts that were previously approved by the MDPU for recovery from customers.

On November 26, 2024, the MDPU issued an Order on the Company’s motion holding, in part, that Pension/PBOP expenses shall be recovered in base distribution rates.

On July 18, 2024, the Company filed a Motion for Reconsideration and Recalculation requesting that the MDPU reconsider its decision to require the Company to absorb $ 1.4 million in negative excess ADIT because the effect of the Order was to inappropriately claw back amounts that were previously approved by the MDPU for recovery from customers.

26, 2024, the MDPU issued an Order on the Company’s motion holding, in part, that Pension/PBOP expenses shall be recovered in base distribution rates.

The amount of $ 1.4 million is disaggregated between the Company’s Gas Division ($ 0.6 million) and the Electric Division ($ 0.8 million).

This motion is pending.

This appeal is pending.

The ruling on November 26, 2024 approved certain other recalculations, resulting in an additional increase to gas base rates of $ 0.1 million effective December 1, 2024.

Fitchburg - Gas System Enhancement Program - Pursuant to statute and MDPU order, Fitchburg has an approved Gas System Enhancement Plan tariff through which it may recover certain gas infrastructure replacement and safety related investment costs, subject to an annual cap.

Fitchburg - Performance Base Rate Adjustment - Gas - On February 28, 2025, Fitchburg filed its first PBRA for rates effective July 1, 2025.

The calculated PBRA adjustment resulted in a distribution revenue increase of $ 0.7 million.

On June 20, 2025, the MDPU issued an order approving the proposed increase effective July 1, 2025.

Fitchburg - Gas System Enhancement Program - Pursuant to statute and MDPU order, Fitchburg has an approved Gas System Enhancement Plan (GSEP) tariff through which it may recover certain gas infrastructure replacement and safety related investment costs, subject to an annual cap.

Under the plan, the Company is required to make two annual filings with the MDPU:

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and a filing, submitted on or before May 1, of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably and prudently incurred.

Fitchburg’s forward-looking cumulative revenue requirement filing submitted on October 31, 2023 requested recovery of approximately $ 6.4 million, and received final approval on April 30, 2024, effective May 1, 2024.

On July 15, 2024 the Company reduced the approved recovery of $ 6.4 million to $ 4.0 million to reflect the transfer of recovery of capital expenditures associated with its 2019-2022 year investments into base distribution rates effective July 1, 2024, as well as the impact of the base distribution rate case on forward looking revenue requirements.

The MDPU approved the request on July 16, 2024.

The Company’s most recent forward-looking cumulative revenue requirement filing, filed on October 31, 2024, requested recovery of approximately $ 3.5 million associated with 2023-2025 year investments.

Fitchburg’s forward-looking cumulative revenue requirement filing, filed on October 31, 2024, requested recovery of approximately $ 3.5 million associated with 2023-2025 year investments.

On April 30, 2025, the MDPU issued an Order approving Fitchburg’s 2025 GSEP and associated revenue requirement of approximately $ 3.5 million with an additional $ 1.6 million in prior deferrals for a total of approximately $ 5.1 million to be recovered through the Gas System Enhancement Adjustment Factors for effect May 1, 2025.

However, the MDPU also took steps to “substantially reform the GSEP process,” including (but not limited to):

reducing the currently applicable revenue cap on recovery from 3.0 % to 2.5 % for the 2025 GSEPs, with “likely” further reductions to 2.0 % for the 2026 GSEPs and 1.5 % for the 2027 GSEPs;

and eliminating carrying charges on GSEP deferrals.

On May 20, 2025, Fitchburg filed a motion for reconsideration and / or clarification regarding application of the reduced cap to a Fitchburg specific project, and joined a joint motion for reconsideration and / or clarification with other Massachusetts Electric Distribution Companies (EDCs) regarding aspects of the Order applicable to all Massachusetts companies.

On August 26, 2025, the MDPU issued an order denying the motions for reconsideration and clarification.

The Company filed its most recent forward-looking cumulative revenue requirement filing on October 31, 2025, requesting recovery of approximately $ 5.4 million with an additional $ 1.0 million in prior deferrals for a total of approximately $ 6.4 million to be recovered through the Gas System Enhancement Adjustment Factors for effect May 1, 2026.

This matter remains pending.

Granite State - Base Rates - On August 24, 2021, the FERC accepted Granite State’s first limited Section 4 rate adjustment pursuant to the Settlement Agreement, for an annual revenue increase of $ 0.1 million, effective September 1, 2021.

On August 19, 2022, the FERC accepted Granite State’s second limited Section 4 rate adjustment pursuant to the Settlement Agreement, for an annual revenue increase of $ 0.3 million, effective September 1, 2022.

O n July 27, 2023, Granite State filed its third and final limited Section 4 rate adjustment pursuant to the Settlement Agreement, for an annual revenue i ncrease of $ 1.0 million, effective September 1, 2023.

On August 22, 2023, the FERC approved this filing.

On October 4, 2024, Granite State filed an uncontested rate settlement with the FERC which provides for an increase in annual revenues of $ 3.0 million, effective November 1, 2024.

Granite State - Base Rates - On October 4, 2024, Granite State filed an uncontested rate settlement with the FERC which provides for an increase in annual revenues of $ 3.0 million, effective November 1, 2024.

The Settlement Agreement permits the filing of limited Section 4 rate adjustments for capital cost projects eligible for cost recovery in 2025, 2026, and 2027, and sets forth an overall cap of $ 29.9 million on the capital costs recoverable under such filings.

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On November 25, 2024, the FERC approved Granite State’s filing.

As authorized by the Settlement Agreement, on July 29, 2025, Granite State filed a limited Section 4 rate adjustment for an annual revenue increase of $ 1.2 million, effective September 1, 2025.

On August 13, 2025, the FERC approved this filing.

Other Matters

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On May 1, 2023, the NHPUC issued an Order approving the Company's petition.

On February 5, 2024, the NH Department of Environmental Services (NHDES) issued an Alteration of Terrain Permit for the project.

On February 9, 2024, NHDES issued a Wetland and Non-Site Specific Permit for the project.

On February 14, 2024, the United States Army Corps of Engineers issued a NH General Permit for the project.

The Company has commenced site work for the project.

Unitil Energy - Major Storm Cost Reserve Recovery - On April 26, 2024, Unitil Energy filed a request with the NHPUC to increase its Storm Reserve Adjustment Factor effective June 1, 2024.

The increase would allow the Company to recover the under-collected Major Storm Cost Reserve (MSCR) balance as of December 31, 2023 of approximately $ 3.7 million plus $ 0.2 million of projected carrying costs over a three-year period.

On May 31, 2024, the NHPUC approved the Company’s request, subject to further investigation and reconciliation.

On November 14, 2024, the NHPUC granted final approval.

The facility became fully commissioned in May 2025.

Unitil Energy has included a cost recovery proposal associated with the solar facility as part of its pending base rate proceeding filing.

Unitil Energy - Major Storm Cost Reserve Recovery - On February 28, 2025, Unitil Energy filed a request with the NHPUC to increase its Storm Recovery Adjustment Factor (SRAF) effective August 1, 2025.

The Company proposed to reduce its Major Storm Cost Reserve deferral balance by transferring its April 2024 Nor’easter costs of approximately $ 1.8 million into

the SRAF and recover the cost over the next three years.

On June 27, 2025, the New Hampshire DOE filed a statement in support of the Company’s request.

On August 29, 2025, the NHPUC issued an order approving the Company’s request.

Massachusetts Inquiry into Gas and Electric Delivery Charge and Bill Redesign - On December 15, 2025, the MDPU opened an investigation to conduct a comprehensive review of gas and electric delivery rates and charges with the aims of containing customer costs, reducing utility bill volatility, and increasing utility bill transparency and accessibility.

Each Distribution Company has been directed to submit a report that includes certain requested information regarding delivery related reconciling mechanisms and costs by February 13, 2026.

The MDPU also seeks written comments from the Distribution Companies and other interested stakeholders responding to a list of questions regarding delivery related reconciling charges on April 14, 2026.

Reply comments are due on May 14, 2026.

As a second phase of this investigation, the MDPU will investigate how to redesign utility bills to enhance customer knowledge, agency, and responsiveness to price and policy signals.

The MPDU has also indicated its intent to open investigations as follows:

1) in response to the Department of Energy Resources’ (“DOER”) petition requesting an investigation into electric rate design and regulatory mechanisms, 2) to investigate reporting of AMI interval data to ISO New England for load settlement and capacity tag calculations, accelerated switching, and dynamic rate-ready TVR offered by competitive suppliers and municipal aggregators, and 3) to examine the utilities’ current practices and recent performance in customer billing and determine whether the current billing and termination regulations are sufficient to ensure consumer protection.

Massachusetts Solar Massachusetts Renewable Target Program (SMART) 3.0 - On November 21, 2025, the EDCs jointly filed a new tariff (the SMART 3.0 Tariff) with the MDPU to implement the SMART 3.0 Program regulations 225 C.M.R.

28.00, which were filed with the Secretary of State on September 12, 2025 (SMART Regulations).

The SMART Program, which was first implemented in 2017, establishes a voluntary statewide solar incentive program under the direction of the DOER.

In 2020, the DOER revised its SMART Program regulations, 225 C.M.R.

20.00 -- an update commonly referred to as SMART 2.0.

The SMART Program relies on the EDCs to issue incentive payments and alternative on-bill credits to participating customers.

Accordingly, the EDCs are seeking approval of revised SMART Tariffs.

SMART 3.0 replaces the structure of the initial SMART Program, a declining block incentive program, with a program that contains capacity targets and incentive rates adjusted annually by the DOER.

SMART 3.0 Program incentives will be paid over a 20 year term and will vary based on a project’s category and capacity.

On January 9, 2026, the EDCs supplemented their filing to provide updated program costs estimates reflecting SMART 3.0 applications received in program year 2025 and assuming full enrollment of all available capacity in program year 2026.

Because program year 2025 application levels were significantly lower than the maximum capacity quantities across the EDCs, this resulted in a decrease in estimated maximum statewide costs from $ 6.7 billion to $ 4.5 billion over 20 years.

Fitchburg’s estimated maximum cost is $ 191 million over 20 years.

The cost projections are illustrative and intended to give the MDPU a sense of scale of the potential long-term costs of the SMART 3.0 Program.

The EDCs are not seeking approval of specific costs at this time.

The EDCs recover SMART Program costs from all distribution customers through the SMART factor, which is set forth in its current SMART tariff and is updated annually.

This matter remains pending.

Fitchburg - Grid Modernization - On July 1, 2021, Fitchburg submitted its Grid Modernization Plan (GMP) to the MDPU.

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The Company may recover eligible costs incurred for preauthorized grid-facing investments and customer-facing investments that will be made during the 2022-2025 GMP term through the GMFs, subject to certain modifications to the Company’s GMF tariff and a final prudence review.

On March 31, 2023, the Company submitted an AMI opt-out tariff with full support of proposed opt-out fees in compliance with the Track 2 Order.

The MDPU approved the tariff on April 7, 2023.

On April 24, 2023, Fitchburg submitted its 2022 Grid Modernization Plan Annual Report to the MDPU.

Among other things, the Company explained a modification to its implementation of the AMI plan that the MDPU preauthorized in D.P.U.

Due to a discontinuation of the meter technology upon which the Company’s initial AMI plan relied, the Company reported that it will need to replace its meters with a new meter technology and to implement a new communications system.

On May 31, 2023, the MDPU issued an Order indicating its intent to explore the impact of the discontinuation and determine the appropriate next steps outside the GMF proceeding.

On April 15, 2024, the Company submitted its annual Grid Modernization Filing seeking recovery of costs related to grid modernization investments placed into service in 2023.

In connection with this filing, the Company submitted a request for preauthorization of communications systems and head end system investments that will be implemented in connection with the Company’s advanced metering infrastructure replacement project.

The matter remains pending.

The MDPU conducted a hearing on September 26, 2023 on the Company’s then-pending GMF filings and Grid Modernization Term Report.

This matter remains pending.

In its Track 2 Order, the MDPU directed the Company and other EDCs to convene a statewide AMI stakeholder working group (AMI Working Group) to address the following issues:

(1) customer and third-party access to customer usage data;

(2) customer education and engagement;

(3) billing of time varying rates (TVR) offered by competitive suppliers;

and (4) AMI deployment strategies that may expedite the ability for competitive suppliers to offer TVR products.

Additionally, the MDPU directed the EDCs to file quarterly status reports, including a final report that sets forth issues on which a consensus had been reached and those issues that remain to be resolved.

On August 1, 2024, the EDCs filed a final report identifying where stakeholders were able and unable to reach consensus.

On November 20, 2024, the MA Legislature enacted the 2024 Climate Act that, among other things, requires the EDCs to jointly establish a centralized data repository in a cost-effective manner as approved by the MDPU, to allow customers and third parties, including competitive suppliers, access to detailed AMI customer data in near-real time, subject to customer approval and protections.

The EDCs must submit for MDPU approval a plan for the implementation of AMI data access protocols not later than one year after the effective date of the Act, i.e., by February 18, 2026, in conjunction with the centralized data repository.

The Climate Act allows the EDCs to recover prudent and necessary expenses for the implementation of advanced metering data repositories and permits the MDPU to implement penalties for failure by the EDCs to meet implementation goals.

The MDPU has opened a docket and provided substantive guidance in anticipation of the Company’s February 2026 filing.

Fitchburg - Grid Modernization Cost Recovery Factor - On April 15, 2023, Fitchburg filed its GMF rate adjustment and reconciliation filing for recovery of the costs incurred as a result of implementing the Company’s 2022-2025 GMP, approved by the MDPU in Orders dated October 7, 2022 and November 30, 2022.

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On June 28, 2024, the MDPU issued an Order in Fitchburg’s electric base rate case providing for the transfer of $ 1.6 million meter-related costs from base distribution rates to the GMF, effective July 1, 2024.

Fitchburg - Investigation into the role of gas LDCs to achieve Commonwealth 2050 climate goals - The MDPU has opened an investigation to examine the role of Massachusetts gas local distribution companies (LDCs) in helping the Commonwealth achieve its 2050 climate goal of net-zero greenhouse gas (GHG) emissions.

In its Order opening the inquiry, the MDPU stated it is required to consider new policies and structures as the Commonwealth reduces reliance on fossil fuels, including natural gas, which may require LDCs to make significant changes to their planning processes and business models.

The LDCs, including Fitchburg, engaged an independent consultant to conduct a study and prepare a report (Consultant Report), including a detailed study of each LDC, that analyzes the feasibility of all identified pathways to help the Commonwealth achieve its net-zero GHG goal.

The study includes an examination of the potential pathways identified in the 2050 Decarbonization Roadmap developed by the Massachusetts Executive Office of Energy and Environmental Affairs, in consultation with the Massachusetts Department of Environmental Protection and the Massachusetts Department of Energy Resources (DOER).

On December 6, 2023, the MDPU issued an Order announcing a regulatory framework intended to set forth its role and that of the LDCs in helping the Commonwealth achieve its target of net-zero GHG emissions by 2050.

In this proceeding, the

MDPU reviewed eight potential decarbonization “pathways” and six regulatory design recommendations intended to facilitate the Commonwealth’s transition.

On April 15, 2025, Fitchburg filed its GMF rate adjustment and reconciliation filing for recovery of the costs incurred as a result of implementing the Company’s 2022-2025 GMP and continued recovery of meter-related costs.

This filing seeks recovery of $ 1.4 million associated with its 2024 GMP revenue requirement as well as $ 1.5 million associated with its 2024 meter-related costs, effective June 1, 2025.

On May 30, 2025, the MDPU issued an order approving the Company’s proposed rate changes effective June 1, 2025 subject to further investigation and reconciliation.

This matter remains pending.

Fitchburg - Investigation into the role of gas LDCs to achieve Commonwealth 2050 climate goals - On December 6, 2023, the MDPU issued an Order announcing a regulatory framework intended to set forth its role and that of the LDCs in helping the Commonwealth achieve its target of net-zero GHG emissions by 2050.

In this proceeding, the MDPU reviewed eight potential decarbonization “pathways” and six regulatory design recommendations intended to facilitate the Commonwealth’s transition.

The MDPU made no specific findings as to a preferred pathway or technology, but did make specific findings regarding regulatory design recommendations.

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To that end, the MDPU ordered the LDCs to submit individual Climate Compliance Plans (CCP) every five years beginning in 2025, and to propose climate compliance performance metrics in upcoming performance-based regulation filings, ensuring a proactive approach to achieving climate targets.

The first CCP is due April 1, 2025.

On December 29, 2023, the LDCs filed a Joint Motion for Clarification and Extension of Judicial Appeal Period.

The Joint Motion requests clarification of three issues:

On December 29, 2023, the LDCs filed a Joint Motion for Clarification.

The Joint Motion requested clarification of three issues:

(1) the MDPU’s directive concerning the NPAs analysis;

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and (3) the methodology for emissions reduction accounting for Climate Compliance Plans, with particular attention to Scope 1 and Scope 3 emissions accounting.

On April 2, 2024, the Commission issued an Order on the LDCs’ Joint Motion.

In its Order, the MDPU clarified, among other things, that NPA analyses should be applied at the project level to all investment decisions going forward, and should be considered at project planning stage;

On April 2, 2024, the MDPU issued an Order on the LDCs’ Joint Motion.

In its Order, the MDPU clarified, among other things, that NPA analyses should be applied at the

project level to all investment decisions going forward, and should be considered at project planning stage;

that pending an approved NPA framework, LDCs should make all reasonable efforts to incorporate NPA analyses into investment decisions;

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The MDPU did not expressly exempt any category of project from the NPA analysis requirement.

On June 14, 2024, the MDPU directed the LDCs to provide certain information regarding the companies’ line extension policies for customers requesting new service.

The LDCs provided responsive information on August 13, 2024;

various interested parties provided comments on the companies’ policies on October 11, 2024, and the LDCs, including Fitchburg, provided reply comments on February 27, 2025.

On February 5, 2025, the MDPU issued a memorandum setting a draft line extension policy that would require customers seeking new gas service to pay the entire cost of connecting to the distribution system.

The Company provided comments on the draft policy on April 3, 2025.

On August 8, 2025, the MDPU issued an Interlocutory Order on Policies and Practices for Line Extension Allowances and Contributions In Aid of Construction for Gas Local Distribution Companies setting forth a revised Straw Proposal that would require customers seeking new gas service to pay the entire cost of connecting to the distribution system, subject to certain exceptions and requiring the LDCs to submit model tariffs incorporating the revised policy.

The LDCs sought clarification of the Order’s finality and a stay of the Order’s effect.

On September 5, 2025, the MDPU issued an Order on the LDCs’ motion, clarifying that the Interlocutory Order is not a final decision, the MDPU has not resolved issues concerning line extension allowance policies, and the LDCs and intervenors will have the opportunity to litigate the line extension allowance issues in the CCP proceedings.

The MDPU retained its direction that the LDCs file illustrative tariff revisions.

On April 1, 2025, Fitchburg filed its first CCP.

The Company’s plan presents a portfolio of initiatives that will help the Commonwealth meet its decarbonization goals over the next five-to-ten years, while maintaining a focus on customers’ long-term interests in safety, reliability, affordability, and equity.

Fitchburg also filed a model CCP Tariff to establish a cost recovery mechanism for the development and implementation of the CCP, including costs associated with assessing and implementing NPAs.

This matter remains pending.

Fitchburg - Electric Sector Modernization Plan - Pursuant to M.G.L.

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On February 20, 2024, the MDPU issued an interlocutory order finding in part that “to the extent that the MDPU determines that accelerated cost recovery through annual reconciling mechanisms for proposed investments identified in the ESMPs is appropriate, we anticipate establishing the appropriate parameters for those mechanisms through a separate phase of these proceedings to be conducted after August 29, 2024.” On August 29, 2024, the MDPU issued a final order approving Fitchburg’s ESMP.

Among other directives, the Order directs Fitchburg and other Massachusetts electric distribution companies (EDCs) to conduct a stakeholder process related to long term system planning related to forecasted DER interconnection and sets forth the criteria for biannual reports.

Among other directives, the Order directs Fitchburg and other Massachusetts EDCs to conduct a stakeholder process related to long-term system planning related to forecasted DER interconnection and sets forth the criteria for biannual reports.

The MDPU found it appropriate to allow Fitchburg and the other EDCs a short-term targeted cost recovery mechanism for ESMP costs.

On December 18, 2024 Fitchburg filed a model ESMP tariff and a company-specific exemplar ESMP mechanism tariff, which describes the parameters of cost-recovery in the second phase of this proceeding.

The MDPU conducted an evidentiary hearing on the Company’s proposal on March 12, 2025.

On June 13, 2025, the MDPU issued an order which approved the Company’s requested ESMP costs, in part.

The MDPU concluded that ESMP substation and distribution feeder investments are ineligible for recovery within the Company’s approved ESMP tariff, but are eligible for recovery under the PBRA.

The Company’s resulting approved five year budget is $21.5 million.

The Company’s compliance ESMP tariff was approved on July 3, 2025.

On September 30, 2025, the Company submitted its first Biannual Report on ESMP investments.

The Company informed the MDPU that it is collaborating with the other EDCs to develop a peak demand reduction methodology and template for the next biannual filing to be filed in March 2026.

The MDPU has indicated its intent to investigate how innovative approaches to cost recovery through base distribution rates can further the purpose of G.L.

164, § 92B, optimally balance the MDPU’s priorities, and promote efficiency.

The MDPU stated that such a proceeding will likely require a lengthy inquiry to identify, analyze, and resolve many complex ratemaking issues.

To help inform the subsequent proceeding(s), the MDPU requested comments from interested parties on items and issues that should be considered, including:

(1) information and data on innovative approaches to cost recovery, in

particular, to facilitate accelerated electrification and/or grid modernization efforts identified at the federal level and/or successfully implemented or being considered in other states;

and (2) discussion and proposals on performance metrics and incentives applicable to longer-term cost recovery considerations.

On October 1, 2025, the Company and the other EDCs, at the MDPU’s direction, submitted comments on potential future approaches to cost recovery for Electric Sector Modernization Plan investments and expenses.

On October 29, 2025, intervenors submitted comments.

Reply comments were filed on November 26, 2025.

Following the stakeholder process related to long-term system planning, Fitchburg and other EDCs submitted a draft Long-Term System Planning Proposal (LTSPP) for MDPU review and approval.

On December 16, 2025, the MDPU issued an Order establishing a phased approach to investigate the LTSPP jointly proposed by the electric distribution companies and stakeholders.

The MDPU intends to establish a uniform LTSPP for the Distribution Companies to proactively upgrade their respective electric power systems to enable increased, timely interconnection of new distributed generation (DG), which will support the Commonwealth’s energy and climate policies.

To expedite the cost-effective deployment and interconnection of DG, Phase I will focus on the establishment of a framework for the LTSPP and other necessary elements for the Distribution Companies to make the first LTSPP filings.

The MDPU will investigate additional topics in Phase II, in parallel with Phase I, to ensure effective LTSPP implementation following the MDPU’s review of proposed LTSPP investments.

This matter remains pending.

Fitchburg - Electric Vehicle (EV) Proceeding - On December 30, 2022, the MDPU issued an order approving Fitchburg’s five-year EV program with a $ 1.0 million budget consisting of:

Fitchburg - Electric Vehicle (EV) Proceedings - On December 30, 2022, the MDPU issued an order approving Fitchburg’s five-year EV program with a $ 1.0 million budget consisting of:

(1) public infrastructure offering ($ 0.5 million);

(2) Electric Vehicle Supply Equipment (EVSE) incentives for residential segment ($ 0.3 million);

(2) Electric Vehicle Supply Equipment incentives for residential segment ($ 0.3 million);

and (3) marketing and outreach ($ 0.2 million).

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On April 3, 2023, the electric companies filed comments on the MDPU’s proposed metrics.

On December 15, 2023, the MDPU approved

EV performance metrics.

On December 15, 2023, the MDPU approved EV performance metrics.

Following that approval, the MDPU required the electric companies to develop a joint state-wide program evaluation plan for MDPU approval and stakeholder input.

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On December 20, 2024, the Company submitted a request for approval to modify certain aspects of the public, residential, and income eligible offers of its EV program.

Fitchburg does not anticipate any rate changes resulting from this filing, which is currently pending before the MDPU.

Fitchburg - Storm Cost Deferral Petition - On November 2, 2023, Fitchburg filed a request with the MDPU to increase its Storm Reserve Adjustment Factor effective January 1, 2024.

The increase would allow the Company to recover approximately $ 4.8 million of costs of repairing damage to its electrical system plus $ 1.4 million of projected carrying costs resulting from the January and March 2023 winter storms over a five-year period.

On December 19, 2023, the MDPU allowed the associated rate increase to become effective on January 1, 2024, subject to further investigation and reconciliation.

This matter remains pending before the MDPU.

On October 17, 2025, the MDPU approved the Company’s proposed modifications.

On December 31, 2025, Fitchburg submitted to the MDPU a petition for approval of a right-of-way and pole-mounted electric vehicle supply equipment (EVSE) proposal as required by the 2024 Climate Act (Chapter 239, Section 134 of the Acts of 2024).

The Company proposes to leverage the program modifications approved on October 17, 2025 to continue to promote public EVSE through its currently approved EV program, which will extend through 2027.

This matter remains pending.

Fitchburg - Storm Cost Deferral Petition - On November 3, 2025, Fitchburg filed a request with the MDPU regarding its Storm Reserve Adjustment Factor effective January 1, 2026.

The Company requested continued recovery of storm costs resulting from the January and March 2023 winter storms over a three-year period.

On December 29, 2025, the MDPU allowed the associated rate increase to become effective January 1, 2026, subject to further investigation and reconciliation.

This matter remains pending before the Commission.

Fitchburg- Approval of Gas Supply Agreement with Constellation LNG - On February 16, 2024, Fitchburg filed a petition with the MDPU for approval of a six year agreement with Constellation LNG for the purchase of natural gas in the liquid or vapor form for the period June 1, 2024 through May 31, 2030 heating seasons.

This request is for the approval of two contracts, the first for up to 3,400 Dth per day of natural gas peaking supply to the Company.

This request is for the approval of two

contracts, the first for up to 3,400 Dth per day of natural gas peaking supply to the Company.

This first contract will be broken out for 3,000 Dth per Day in the form of LNG for use at the Company’s Westminster LNG facility and 400 Dth per Day will be in the form of natural gas supply delivered to the city-gate connecting the Company’s system to the Tennessee Gas Pipeline.

The second contract will provide up to 3,000 Dth per day of LNG trucking from the Everett Marine Terminal to the Company’s Westminster LNG facility.

This proposed agreement would ensure that the Everett Marine Terminal, which plays a critical role in both the Company’s and the New England energy market’s efficient and reliable operation, will continue to be available for the next six winter seasons.

This Agreement would ensure that the Everett Marine Terminal, which plays a critical role in both the Company’s and the New England energy market’s efficient and reliable operation, will continue to be available for the next six winter seasons.

A six year agreement was also requested by Boston Gas Company, Eversource Gas Company, and NSTAR Gas Company.

Fitchburg and the other LDCs received an Order on May 17, 2024 approving the agreements.

Unitil Corporation – Merger of Bangor Natural Gas, Inc.

- On July 15, 2024, Unitil, Northern Utilities, Hearthstone Holdings, Inc.

d/b/a Hope Companies, Inc.

(HUI), PHC Utilities, Inc.

(PHC), and Bangor Natural Gas Company filed a Joint Petition requesting that the MPUC approve the merger of Bangor into Unitil pursuant to a July 8, 2024 Stock Purchase Agreement among PHC, HUI and Unitil.

Furthermore, Unitil requested that the MPUC issue an order excusing Bangor and Unitil from certain regulatory conditions and obligations imposed upon Bangor or its affiliates in conjunction with prior reorganizations of Bangor.

Unitil filed a Stipulation supporting the proposed merger, signed by all parties to the docket, on December 4, 2024.

Among other provisions, Unitil and Bangor agreed that Bangor would not file a general rate case prior to January 1, 2027.

The MPUC issued an Order approving the Stipulation on December 18, 2024.

In a separate Order issued January 14, 2025, the MPUC approved the proposed long-term debt facility.

Unitil completed the acquisition of Bangor on January 31, 2025.

Unitil Corporation – Merger of Maine Natural Gas Corporation - On May 9, 2025, Unitil, Northern Utilities, Bangor, Avangrid Enterprises, Inc.

and Maine Natural filed a Joint Petition requesting that the MPUC approve the merger of Maine Natural into Unitil pursuant to a Stock Purchase Agreement among Avangrid and Unitil.

A procedural schedule has been established which includes discovery, technical conferences, testimonies and briefs.

To comply with the statutory timeframe of 180 days, deliberations are scheduled to be held no later than early November 2025.

The MPUC issued an Order approving the Stipulation on September 12, 2025.

In a separate Order issued September 16, 2025, the MPUC approved the proposed long-term debt facility.

Unitil completed the acquisition of Maine Natural on October 31, 2025.

Unitil Corporation – Merger of Aquarion Water Companies - On May 6, 2025, Unitil announced that it has entered into a definitive agreement to acquire Aquarion Water Company of Massachusetts Inc., Aquarion Water Company of New Hampshire, Inc., and Abenaki Water Co., Inc.

(the Aquarion Companies) from the Aquarion Water Authority (AWA), a quasi-public corporation chartered by the Connecticut General Assembly in 2024 to acquire Aquarion and to operate as a water authority.

Unitil’s acquisition of the Aquarion Companies is contingent upon the initial sale of Aquarion by Eversource to the AWA (Initial Transaction), which will then simultaneously convey the Aquarion Companies to Unitil.

On November 19, 2025, the Connecticut Public Utilities Regulatory Authority (PURA) denied approval of the Initial Transaction.

On December 2, 2025, the joint applicants in the Connecticut proceeding filed a judicial appeal of PURA’s decision denying the Initial Transaction.

On January 15, 2026, a decision was issued that remanded the case back to PURA for further deliberations.

This case remains pending at PURA.

On May 8, 2025, Eversource Energy (Eversource), the AWA, and Unitil submitted an amended and restated petition to the MDPU for approval of a change of control of Aquarion Water Company of Massachusetts, Inc.

On December 12, 2025, the MDPU issued an Order approving the stock sale of Aquarion by Eversource to AWA, and, in turn, AWA’s simultaneous sale of AWC-MA to Unitil.

The approval is subject to certain conditions, including quarterly service quality reporting and a two-year rate case filing moratorium.

The approval is also contingent upon, inter alia, approval of the Initial Transaction.

The MDPU also declined to rule on the issue, raised by the MA AGO, of ratemaking treatment of the gain on sale of certain assets that occurred under Eversource ownership.

On January 2, 2026, Unitil, Eversource, and AWA filed a motion for reconsideration and clarification of the MDPU’s Order with respect to the rate case moratorium and ratemaking treatment of the gain on sale.

This matter remains pending.

On May 8, 2025, Unitil, Eversource, Aquarion Water Company of New Hampshire, Inc., (AWC-NH), Abenaki Water Company (Abenaki) and AWA filed a motion to amend the petition originally filed on April 10, 2025 by Eversource.

AWC-NH, Abenaki and AWA, requesting that the NHPUC approve the acquisition of AWC-NH and Abenaki by Unitil.

On August 28, 2025, the Joint Petitioners and the DOE submitted a settlement agreement to the NHPUC recommending approval of the proposed acquisition subject to certain conditions, including a rate case stay-out through June 1, 2026.

The Office of the Consumer Advocate did not join the settlement.

The NHPUC conducted a hearing on the matter on September 25, 2025.

On October 7, 2025, the NHPUC issued an Order approving the settlement agreement.

On May 23, 2025, pursuant to 35-A M.R.S.

§ 708, Northern Utilities filed a request that the MPUC grant an exemption from approval of the reorganization that will be triggered by the anticipated acquisition by Unitil of the three water utilities in Massachusetts and New Hampshire.

The MPUC has previously granted Maine public utilities exemptions from regulatory approval of reorganizations under circumstances similar to those presented in this case involving the acquisition of companies outside of Maine by a utility’s holding company parent that will have no direct financial or operational impact on the Maine utility.

Based on MPUC precedent in similar reorganizations, Northern Utilities requested an exemption from Section 708 approval of Unitil’s acquisition of the Aquarion MA-NH Companies.

In the alternative, if the MPUC declines to grant the requested exemption, then Northern Utilities requested that the MPUC approve the reorganization pursuant to Section 708.

The MPUC approved the reorganization, subject to certain conditions agreed upon by Unitil, on January 6, 2025.

Northern Utilities / Granite State - Firm Capacity Contract - Northern Utilities relies on the transportation of gas supply over its affiliate Granite State pipeline to serve its customers in the Maine and New Hampshire service areas.

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On March 31, 2025, Northern Utilities submitted an annual informational report requesting approval on a one-year extension for the period of November 1, 2025 through October 31, 2026.

The Company received an order approving the 2024-2025 contract on July 10, 2024.

The Company received an order approving the one-year extension of its request on June 3, 2025.

Northern Utilities / Portland Natural Gas Transmission System (PNGTS) and TransCanada Pipelines Limited (TCPL) transportation from Empress, Alberta to Granite State Gas Transmission, Inc.

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On January 26, 2024 and January 30, 2024, the Company received orders from the NHPUC and MPUC, respectively, approving Northern Utilities’ proposal for Empress Agreements with PNGTS and TransCanada Pipelines.

Conservation Law Foundation filed a motion for reconsideration of the Maine Commission’s decision on February 15, 2024.

The Company objected to the motion, which remains pending before the Commission.

Reconciliation Filings - Fitchburg, Unitil Energy and Northern Utilities each have a number of regulatory reconciling accounts that require annual or semi-annual filings with the MDPU, NHPUC and MPUC, respectively, to reconcile revenues and costs, and to seek approval of any rate changes.

Conservation Law Foundation filed a motion for reconsideration of the MPUC’s decision on February 15, 2024.

The Company objected to the motion, and on March 26, 2025, the Hearing Examiners issued a Recommended Order on Reconsideration from the MPUC on this CLF motion.

The Recommended Order, if adopted, would affirm the MPUC’s previous decision to approve the Company’s entry into these Agreements.

The MPUC issued an Order reaffirming and clarifying its initial Order approving the Empress Agreements, and specifically affirmed its conclusion that entering into the Empress Capacity Agreements is prudent, in the public interest, and not inconsistent with the state’s climate policy.

Maine Inquiry Into the Future of Gas - On May 13, 2025, the MPUC initiated an inquiry to explore the implications of Maine’s decarbonization goals for natural gas utilities and their customers and solicit information from stakeholders.

Specifically, the MPUC opened the inquiry with the goal of 1) developing a consistent methodology or framework to incorporate and evaluate the GHG emissions impact in the MPUC’s decision-making around gas infrastructure investments and contractual commitments for supply or capacity needed to serve customers;

2) evaluating the consistency of these investments with state goals and 3) assisting in evaluation of a broader path for the future of natural gas in Maine.

Initial comments on the scope of the inquiry were submitted on June 17, 2025.

On December 18, 2025, the MPUC issued a Procedural Order scheduling a workshop on January 21, 2026 to explore issues raised in comments.

Reconciliation Filings - Fitchburg, Unitil Energy, Northern Utilities, Bangor and Maine Natural each have a number of regulatory reconciling accounts that require annual or semi-annual filings with the MDPU, NHPUC and MPUC, respectively, to reconcile revenues and costs, and to seek approval of any rate changes.

These filings include:

annual electric reconciliation filings by Fitchburg and Unitil Energy for a number of items, including default service, stranded cost changes and transmission charges;

costs associated

with energy efficiency programs in New Hampshire and Massachusetts, as directed by the NHPUC and MDPU;

annual electric reconciliation filings by Fitchburg and Unitil Energy for a number of items, including default service, stranded cost changes and transmission

costs associated with energy efficiency programs in New Hampshire and Massachusetts, as directed by the NHPUC and MDPU;

recovery of the ongoing costs of storm repairs incurred by Unitil Energy and Fitchburg;

and the actual wholesale energy costs for electric power and gas incurred by each of the three companies.

Fitchburg, Unitil Energy and Northern Utilities have been, and remain in full compliance with all directives and orders regarding these filings.

and the actual wholesale energy costs for electric power and gas incurred by each of the five companies.

Fitchburg, Unitil Energy, Northern Utilities, Bangor and Maine Natural have been, and remain in full compliance with all directives and orders regarding these filings.

The Company considers these to be routine regulatory proceedings, and there are no material issues outstanding.

Fitchburg - Massachusetts Request for Proposals (RFPs) - Pursuant to Section 83C of “An Act to Promote Energy Diversity” (2016) (the Act), the Massachusetts EDCs, including Fitchburg, are required to jointly procure a total of 1,600 MW of offshore wind by June 30, 2027.

Under Section 83D of the Act, the EDCs are required to jointly seek proposals for cost-effective clean energy (hydroelectric, solar and land-based wind) long-term contracts via one or more staggered solicitations for a total of 9,450,000 megawatt-hours (MWh) by December 31, 2022.

Fitchburg’s pro rata share of these contracts is approximately 1%.

The EDCs issued the RFP for Section 83D Long-Term Contracts in March 2017, and power purchase agreements (PPAs) for 9,554,940 MWh of hydroelectric generation and associated environmental attributes from Hydro-Quebec Energy Services (U.S.), Inc.

were filed in July 2018 for approval by the MDPU.

On June 25, 2019, the MDPU approved the PPAs, including the EDCs’ proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market revenue to customers.

Fitchburg - Massachusetts Request for Proposals (RFPs) - Pursuant to Section 83 of “An Act Relative to Green Communities,” St.

169, as amended, the Massachusetts EDCs, including Fitchburg, have conducted numerous procurements of long-term renewable energy and environmental attributes.

“An Act to Promote Energy Diversity” (2016) (the Act) added Section 83C, which required the joint procurement of 1,600 MW of offshore wind by June 30, 2027 (this target has since been increased as explained below) and Section 83D, which required the joint procurement of cost-effective long-term contracts for an annual total of 9,450,000 megawatt-hours (MWh) of clean energy (hydroelectric, solar and land-based wind) by December 31, 2022.

Fitchburg’s pro rata share of the contracts resulting from these procurements is approximately 1%.

The EDCs issued the RFP for Section 83D Long-Term Contracts in March 2017, and transmission service agreements with NECEC Transmission LLC and power purchase agreements (PPAs) for 9,554,940 MWh annually of hydroelectric generation and associated environmental attributes with Hydro-Quebec Energy Services (U.S.), Inc.

(together, the NECEC project) over a 20-year period, were filed for approval by the MDPU in July 2018.

The MDPU approved the agreements in June 2019, including the EDCs’ proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market revenue to customers.

The MDPU also approved the EDCs’ request for remuneration equal to 2.75 % of the contract payments, as well as the EDCs’ proposal to recover costs associated with the contracts.

On January 13, 2023, NECEC Transmission LLC (NECEC), the company with which Fitchburg and the other EDCs entered into transmission service agreements (TSAs) for the delivery of the Hydro-Quebec energy, provided a letter to the EDCs purporting to give notice of a “change in applicable law” related to a Maine ballot initiative and requesting a negotiated amendment to the TSAs including a price adjustment.

On June 27, 2023, NECEC sent a letter to the EDCs seeking schedule relief also in accordance with their “change in law” determination.

The EDCs are in the process of evaluating an amendment to the Transmission Service Agreement.

Section 83C of “An Act Relative to Green Communities,” St.

169, as amended by St.

188, § 12 (Section 83C) requires the EDCs to jointly and competitively solicit proposals for offshore wind energy generation not later than June 30, 2017.

The EDCs issued an initial RFP pursuant to Section 83C in June 2017.

On July 23, 2018, the EDCs, filed two long-term contracts with Vineyard Wind, each for 400 MW of offshore wind energy generation, for approval by the MDPU.

On April 12, 2019, the MDPU approved the offshore wind energy generation PPAs, including the EDCs’ proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market revenue to customers.

The EDCs issued a second RFP pursuant to Section 83C to procure an additional 800 MW of offshore wind energy generation in May 2019.

The EDCs filed for approval of two PPAs with Mayflower Wind Energy LLC (now known as SouthCoast Wind), each for 400 MW of offshore wind energy generation, on February 10, 2020.

On November 5, 2020, the MDPU approved the PPAs.

In both cases, the MDPU approved the EDCs’ request for remuneration equal to 2.75 % of the contract payments, as well as the EDCs’ proposal to recover costs associated with the contracts.

In April 2023, SouthCoast Wind engaged with the EDCs to explore options to mitigate impacts of global resource constraints and pricing challenges associated with the PPAs from this procurement.

They cited an inability to finance the project within the terms set out in the PPA.

The EDCs negotiated a termination agreement with SouthCoast Wind which was filed with the MDPU for approval on August 28, 2023 and which received approval on September 30, 2023.

In accordance with “An Act to Advance Clean Energy” (2018) the DOER recommended that the EDCs solicit up to 1,600 MW in additional offshore wind in 2022 and 2024.

On May 7, 2021, the EDCs issued a third RFP for up to an additional 1,600 MW of off shore wind generation.

On May 25, 2022, the EDCs sought approval of PPAs with Commonwealth Wind for 1,200 MW and with SouthCoast Wind for 400 MW.

On December 16, 2022, Commonwealth Wind filed a motion requesting that the MDPU dismiss proceedings related to the approval of its contract, arguing that, due to various economic conditions, its contracts with the EDCs would no longer facilitate the financing of offshore wind energy generation.

On December 30, 2022, the MDPU denied Commonwealth’s motion and approved the PPAs.

The MDPU also approved the EDCs’ request for remuneration equal to 2.25 % as reasonable and in the public interest.

On January 19, 2023, Commonwealth Wind filed a Petition for Appeal with the Massachusetts Supreme Judicial Court (SJC) seeking to set aside and vacate the MDPU’s Order approving the PPAs.

In April 2023, SouthCoast Wind engaged with the EDCs to explore options to mitigate global resource constraints and pricing challenges associated with their PPAs from this procurement.

SouthCoast Wind noted challenges around an inability to finance the projects under the current terms.

The EDCs negotiated termination agreements with Commonwealth Wind and SouthCoast Wind and submitted the agreements to the MDPU for approval on July 13, 2023 and August 28, 2023, respectively.

The MDPU approved both termination agreements on September 30, 2023.

In connection with the termination agreements from the second and third solicitations, the Company received termination payments from Commonwealth Wind and SouthCoast Wind totaling $ 1.1 million which is recorded as a regulatory liability on the Company’s Consolidated Balance Sheets to be flowed back to customers.

On October 12, 2023, Commonwealth Wind requested that the case with the SJC be entered as dismissed.

Concurrently, Commonwealth Wind announced publicly they could not finance the project under the terms of the PPA.

The “Energy Diversity Act” (2021) and “An Act Driving Clean Energy and Offshore Wind” (2022) enacted by the Massachusetts legislature, increased the total solicitation target (including future solicitations) for offshore wind energy generation to 5,600 MW by June 30, 2027.

On August 30, 2023, the EDCs issued a fourth offshore wind RFP seeking to procure at least 400 MW and up to the maximum amount remaining of the statutory requirement under Section 83C of 5,600 MW of Offshore Wind Energy Generation, and taking into account offshore wind generation under contract at the time when proposals are due.

Bidders are allowed to offer proposals of at least 200 MW up to 2,400 MW of offshore wind generation.

On January 18, 2024, the EDCs notified the MDPU that they are extending the bid submission date and subsequent solicitation schedule dates by an additional 56 days each to allow bidders the opportunity to gain more certainty around their eligibility for the investment tax credit and factor it into their proposals.

The submission date was revised to March 27, 2024.

The EDCs received bids for Offshore Wind Generation from three developers as part of a multi-state solicitation with Rhode Island and Connecticut and on September 6, 2024, the DOER selected a portfolio of projects totaling 2,678 MW from three projects.

The EDCs have commenced contract negotiations which are scheduled to be completed in March 2025.

The NECEC project achieved commercial operation in January 2026.

The EDCs issued the first RFP for offshore wind energy generation pursuant to Section 83C in June 2017.

In July 2018, the EDCs filed two long-term PPA’s with Vineyard Wind, each for 400 MW for approval by the MDPU.

In April 2019, the MDPU approved the offshore wind PPAs, including similar requirements for the EDCs’ to sell the energy procured and credit or charge net costs to customers including EDC remuneration of 2.75 %.

The expected commercial operation dates for Vineyard Wind are January 15, 2027 for Facility 1 and May 31, 2026 for Facility 2.

The EDCs issued additional RFPs pursuant to Section 83C to procure additional offshore wind energy generation in May 2019 and in May 2021.

These two procurements led to four additional PPAs for a total of 2400 MW that were approved by MDPU but were later terminated in September 2023.

The EDCs issued a fourth offshore wind RFP in August 2023 seeking to procure at least 400 MW and up to the maximum amount remaining of the statutory requirement under Section 83C of 5,600 MW of Offshore Wind Energy Generation, pursuant to “An Act Driving Clean Energy and Offshore Wind” (2022), which increased the total solicitation target (including future solicitations) for offshore wind energy generation to 5,600 MW by June 30, 2027.

The EDCs received bids for offshore wind energy generation from three developers as part of a multi-state solicitation with Rhode Island and Connecticut.

In September 2024, the Massachusetts DOER selected a portfolio of projects totaling 2,678 MW from the three projects, one of which was dependent on commitments from Connecticut.

In December 2024, Connecticut withdrew from contract negotiations resulting in the termination of the conditional project.

Contract negotiations with the remaining two developers have been extended and are targeted to be completed by June 30, 2026.

In December 2024, the Massachusetts Legislature approved “ An Act promoting a clean energy grid, advancing equity, and protecting ratepayers” which among other provisions, extends the period for long-term renewable contracts up to 30 years and directs the EDCs, under a new Section 83E, to “jointly and competitively solicit proposals for energy storage systems and enter into cost-effective long-term contracts equal to, in the aggregate, approximately 5,000 megawatts of energy storage systems not later than July 31, 2030.” Pursuant to Section 83E, the EDCs jointly issued the first RFP for energy storage systems (ESS) in July 2025 seeking environmental attributes associated with approximately 1,500 megawatts of mid-duration energy storage systems.

In December 2025, the DOER selected a portfolio of battery energy storage projects that total 1,268 MW and contract negotiations are underway.

A second solicitation under Section 83E is currently being developed for release in July 2026.

Fitchburg’s pro rata share of the contracts resulting from these procurements is approximately 1%.

Pursuant to Section 82 of Chapter 179 of the Acts of 2022 ( An Act driving clean energy and offshore wind ), the Massachusetts DOER is authorized to coordinate with other New England states issuing competitive solicitations for long-term clean energy generation, including nuclear power generation, associated environmental attributes, transmission or capacity for

the benefit of residents of the Commonwealth and the region.

If the DOER, in consultation with the EDCs and the office of the Attorney General, determines not later than December 31, 2027, that a project would satisfy the benefits listed in Section 82, DOER may direct the EDCs to enter into cost-effective long-term contracts.

DOER is currently exploring procurements issued by Maine and Connecticut.

In September 2025, Connecticut issued an Expedited Zero Carbon RFP and following selections made by Connecticut, DOER selected two projects for Massachusetts.

Unitil Energy/Northern Utilities - 2024-2026 Triennial Energy Efficiency Plan - New Hampshire - On November 30, 2023, the NHPUC approved the changes to New Hampshire’s ratepayer-funded energy efficiency program offerings for the 2024–2026 period requested by New Hampshire’s electric and gas utilities.

On July 1, 2024, the New Hampshire electric and gas utilities filed an interim update with the Commission, seeking approval to update the energy efficiency program models with benefit assumptions from the recently issued report of Avoided Energy Supply Components in New England:

On July 1, 2024, the New Hampshire electric and gas utilities filed an interim update with the NHPUC, seeking approval to update the energy efficiency program models with benefit assumptions from the recently issued report of Avoided Energy Supply Components in New England:

Fitchburg Energy Efficiency Programs - Both the electric and gas divisions of Fitchburg actively participate in the energy efficiency programs in Massachusetts, as directed by the MDPU.

These programs require periodic filings and are subject to investigation and review.

The Company considers these to be routine regulatory proceedings.

The MDPU recently approved the Massachusetts utilities’ 2025-2027 three-year energy efficiency plan subject to certain modifications, including a $ 500 million reduction to the total residential sector budget.

FERC Transmission Formula Rate Proceedings - Pursuant to Section 206 of the Federal Power Act, there are several pending proceedings before the FERC concerning the justness and reasonableness of the Return on Equity (ROE) component of the ISO-New England, Inc.

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The Company does not believe these proceedings will have a material adverse effect on its financial condition or results of operations.

On December 13, 2022, RENEW Northeast, Inc., a non-profit entity that advocates for the business interests of renewable power generators in New England filed a complaint with FERC against ISO-NE and the PTOs requesting a determination that certain open-access transmission tariff schedules are unjust and unreasonable to the extent they permit PTOs to directly assign to interconnection customers O&M costs associated with network upgrades.

On December 13, 2022, RENEW Northeast, Inc.

(RENEW), a non-profit entity that advocates for the business interests of renewable power generators in New England filed a complaint with FERC against ISO-NE and the PTOs requesting a determination that certain open-access transmission tariff schedules are unjust and unreasonable to the extent they permit PTOs to directly assign to interconnection customers O&M costs associated with network upgrades.

Fitchburg and Unitil Energy are PTOs, although Unitil Energy does not own transmission plant.

The PTOs answered the complaint on January 23, 2023.

This matter remains pending.

FERC issued an Order December 19, 2024 and a compliance filing was made on February 18, 2025 revising the ISO-NE OATT accordingly.

While most of the intervening parties supported the compliance filing a new issue was raised by one participant.

RENEW and the NETO’s have resolved their issues and filed briefs in support of the compliance filing.

This matter remains pending in Docket No.

The Company does not believe these proceedings will have a material adverse effect on its financial condition or results of operations.

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From year to year, there are likely to be timing differences associated with the cash recovery of such costs, creating under- or over-recovery situations at any point in time.

Rate recovery mechanisms are typically designed to collect the under-recovered cash or refund the over-collected cash over subsequent periods of less than a year.

Rate recovery mechanisms are

typically designed to collect the under-recovered cash or refund the over-collected cash over subsequent periods of less than a year.

Legal Proceedings

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In anticipation of the NH DES approval of one of the RAP alternatives and subsequent request for project design, the Company has accrued $ 5.8 million for estimated costs to complete the remediation at the Rochester site, which is included in Environmental Obligations on the Company’s Consolidated Balance Sheets.

Due to extended regulatory review time periods, Northern Utilities anticipates the commencement of remediation activities later in 2025.

Due to extended regulatory review time periods, Northern Utilities anticipates the commencement of remediation activities in 2026.

The NHPUC and MPUC have approved regulatory mechanisms for the recovery of MGP environmental costs.

For Northern Utilities’ New Hampshire division, the NHPUC has approved the recovery of MGP environmental costs over

succeeding seven-year periods.

For Northern Utilities’ New Hampshire division, the NHPUC has approved the recovery of MGP environmental costs over succeeding seven-year periods.

For Northern Utilities’ Maine division, the MPUC has authorized the recovery of environmental remediation costs over succeeding five-year periods.

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Fitchburg’s Manufactured Gas Plant Site - Fitchburg has worked with the Massachusetts Department of Environmental Protection (Mass DEP) to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring continues.

In April 2020, Fitchburg received notification from the Massachusetts Department of Transportation (Mass DOT) that a portion of the site may be incorporated into the proposed Twin City Rail Trail with an anticipated commencement date in 2025.

Depending upon the final agreement between Fitchburg and Mass DOT, additional minor costs are expected prior to completion.

The Company is awaiting a decision regarding an Immediate Response Action (IRA) plan with three remediation alternatives, submitted to the MA DEP in October 2023 with an update in November 2024, regarding contaminants in the sediment and riverbank of an abutting watercourse, and observed river seep.

In anticipation of the DEP accepting one of the remediation alternatives, Fitchburg has accrued $ 40,000 for estimated costs to complete the remediation at the Sawyer Passway site, which is included in Environmental Obligations on the Company’s Consolidated Balance Sheets.

The Company has determined that the high end of the range of reasonably possible remediation costs for the Sawyer Passway site could be $ 3.5 million based on remediation alternatives.

Fitchburg anticipates the commencement of some remediation activities by the middle of 2025, while the river seep will likely be addressed in 2026.

Following submittal of the Immediate Response Action (IRA) plan in October 2023 and an update in November 2024, the Mass DEP, in May 2025 concurred with the proposed limited excavation and armoring of the riverbank at the identified seep area.

Fitchburg has accrued $ 280,000 for estimated costs to complete the remediation at the Sawyer Passway site, which is included in Environmental Obligations on the Company’s Consolidated Balance Sheets.

The Company has determined that the high end of the range of reasonably possible

remediation costs for the Sawyer Passway site could be $ 3.7 million based on remediation alternatives.

Fitchburg anticipates the commencement of the remediation activity in 2026.

Fitchburg recovers the environmental response costs incurred at this former MGP site in gas rates pursuant to the terms of a cost recovery agreement approved by the MDPU.

Pursuant to this agreement, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods.

Unitil Energy - Kensington Distribution Operations Center - Unitil Energy conducted a Phase I and II environmental site assessment (ESA) in the second quarter of 2021 at its former distribution operations center in Kensington, NH.

The Company is awaiting a decision on a report, submitted to the NH DES in June 2023, as to whether there is a need to conduct further investigation or remedial actions regarding the impacts of soil and groundwater contaminants identified in the ESA.

Unitil Energy anticipates the commencement of remediation activities in 2026, following work plan approval by the NH DES decision.

Unitil Energy - Kensington Distribution Operations Center - Unitil Energy conducted a Phase I and II supplement environmental site assessment (ESA) in the second quarter of 2021 at its former distribution operations center in Kensington, NH.

In November 2025, the NH DES requested additional investigation to further refine the Supplemental Site Investigation (SSI) submitted in June 2023, as well as develop a remedial action plan (RAP) based upon reported observations.

Unitil Energy anticipates the commencement of remediation activities in late 2026 or early 2027, following RAP approval by the NH DES.

The Company does not believe this investigation will have a material adverse effect on its financial condition, results of operations or cash flows.

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Total Income Tax Expense

The differences between the Company’s provisions for Income Taxes and the provisions calculated at the statutory federal tax rate, expressed in percentages, are shown in the following table:

In December 2023, the FASB issued ASU 2023-09 – Income taxes:

Improvements to Income Tax Disclosures which includes amendments that further enhance income tax disclosures and income taxes paid by jurisdiction.

The Company has

elected to adopt ASU 2023-09 on a prospective basis.

The following table presents the Company’s provisions for Income Taxes and the provisions calculated at the statutory federal tax rate for the year ended December 31, 2025:

(Dollars in thousands)

Federal Statutory Tax Rate

State Income Taxes, net of Federal Income Tax

Production Tax Credit

Nontaxable and Nondeductible Items

Regulatory Amortization of Excess ADIT

Income Tax Expense and Effective Income Tax Rate

The differences between the Company’s provision for Income Tax and the provisions calculated at the statutory federal tax rate, expressed in percentages for the years ended December 31, 2024 and 2023, are shown in the following table:

Statutory Federal Income Tax Rate

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Effective Income Tax Rate

Income taxes paid, net of refunds are shown in the following table:

(in thousands)

Cash Paid for Income Taxes, net of Refunds

Federal Income Taxes

State Income Taxes

Massachusetts

New Hampshire

Total State Income Taxes

Total Cash Paid for Income Taxes, net of Refunds

* Did not meet the 5% threshold required for separate disclosure

Temporary differences which gave rise to deferred tax assets and liabilities in 2025 and 2024 are shown in the following table:

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Retirement Benefit Obligations

Regulatory Assets & Liabilities

Regulatory Assets and Liabilities **

Net Operating Loss Carryforwards

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Utility Plant Differences

Regulatory Assets & Liabilities

Regulatory Assets and Liabilities **

Total Deferred Tax Liabilities

Net Deferred Tax Liabilities

** The Company’s Net Deferred Tax Liabilities for Regulatory Assets and Liabilities are shown net.

Gross Regulatory Assets were $ 16.8 million and $ 16.6 million for the years ended December 31, 2025 and 2024, respectively.

Gross Regulatory Liabilities were $ 17.1 million and $ 11.0 million for the years ended December 31, 2025 and 2024, respectively.

Under the Company’s Tax Sharing Agreement (the Agreement) which was approved upon the formation of Unitil as a public utility holding company, the Company files consolidated Federal and State tax returns and Unitil Corporation and each of its utility operating subsidiaries recognize the results of their operations in its tax returns as if it were a stand-alone taxpayer.

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The Company has evaluated its tax positions at December 31, 2025 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, de-recognition, settlement or foreseeable future events to any tax liabilities or assets as defined by the FASB Codification is required.

The Company remains subject to examination by Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2023;

In August 2025, Unitil Corporation received notice that its Federal Income Tax return filing for the year ending December 31, 2023 is under examination by the IRS.

Currently, the Company believes that the ultimate resolution of this examination will not have a material impact on the Company’s financial statements.

The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2024;

December 31, 2023;

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Income tax filings for the year ended December 31, 2024 have been filed with the IRS, Massachusetts Department of Revenue, the Maine Revenue Service, and the New Hampshire Department of Revenue Administration.

In the Company’s federal tax returns for the year ended December 31, 2023 which were filed with the IRS in October 2024, the Company generated federal Net Operating Loss Carryforward (NOLC) assets of $ 2.9 million increasing the total amount of NOLC to $ 7.3 million to offset future years income.

As of December 31, 2024, the Company recognized the utilization of approximately $ 6.6 million of the NOLC asset and $ 1.3 million of federal tax credits available to offset current taxes payable.

In the Company’s federal tax returns for the year ended December 31, 2024 which were filed with the IRS in October 2025, the Company utilized federal Net Operating Loss Carryforward (NOLC) assets of $ 5.6 million and $ 1.0 million of federal tax credit carryforward.

As of December 31, 2025, the Company has fully utilized all NOLC and federal tax credits available.

In addition, at December 31, 2025, the Company had $ 1.8 million of cumulative state tax credit carryforwards to offset future income taxes payable.

If unused, the Company’s state tax credit carryforwards will begin to expire in 2027.

On July 4, 2025, the One Big Beautiful Bill Act (OBBBA) was enacted into law.

The OBBBA provided permanent and limited modifications to many provisions that had expired or would soon expire as well as eliminating many green energy provisions.

The Company does not expect that the OBBBA will have a material effect on the Company's Consolidated Financial Statements.

On April 14, 2023, the IRS issued Revenue Procedure 2023-15 that provides a safe harbor method of accounting that taxpayers may use to determine whether to deduct or capitalize expenditures to repair, maintain, replace, or improve natural gas transmission and distribution property.

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The Company elected a change in its tax accounting method on the 2023 consolidated tax return.

In August 2022, the Inflation Reduction Act of 2022 (IRA) was signed into law.

The IRA included new taxes on corporations, including the Corporate Alternative Minimum Tax (AMT) and the Excise Tax on Repurchase of Corporate Stock.

The AMT is equal to 15 % of a corporation’s adjusted financial statement income (AFSI).

The AMT applies to companies that have a three year average AFSI of greater than $ 1 billion.

The IRA also extended and modified certain renewable energy related credits.

The Company has evaluated the IRA provisions and determined that they do not have a material effect on the Company’s financial statements as of December 31, 2024.

A 481(a) adjustment was calculated and resulted in an additional $ 9.4 million in tax expense on the 2023 consolidated tax return.

In December 2017, the Tax Cuts and Jobs Act (TCJA), which included a reduction of the corporate federal income tax rate to 21 % effective January 1, 2018, was signed into law.

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Effective January 1, 2010, the Pension Plan was closed to new non-union employees.

For union employees, the Pension Plan was closed on various dates between December 31, 2010 and June 1, 2013, depending on the various Collective Bargaining Agreements of each union.

For union employees, the

Pension Plan was closed on various dates between December 31, 2010 and June 1, 2013, depending on the various Collective Bargaining Agreements of each union.

• The Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan)—The PBOP Plan provides health care and life insurance benefits to retirees.

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Rate of Compensation Increase

The health care cost trend rate used to determine plan costs for 2024 for pre-65 retirees is 8.00 %, with an ultimate rate of 4.50 % in 2033 , and for post-65 retirees, the health care cost trend rate is 6.00 %, with an ultimate rate of 4.50 % in 2033 .

The health care cost trend rate used to determine plan costs for 2025 for pre-65 retir ees is 8.50 %, with an ultimate rate of 4.50 % in 2034 , and for post-65 retirees, the health care cost trend rate is 7.50 %, with an ultimate rate of 4.50 % in 2034 .

The health care cost trend rate used to determine plan costs for 2024 for pre-65 retirees was 8.00 %, with an ultimate rate of 4.50 % in 2033 , and for post-65 retirees, the health care cost trend rate was 6.00 %, with an ultimate rate of 4.50 % in 2033 .

The health care cost trend rate used to determine plan costs for 2022 for both pre-65 retirees and post-65 retirees was 6.20 %, with an ultimate rate of 4.50 % in 2029 .

The health care cost trend rate used to determine plan costs for 2023 for pre-65 retirees was 8.00 %, with an ultimate rate of 4.50 % in 2030 , and for post-65 retirees was 6.25 %, with an ultimate rate of 4.50 % in 2030 .

The health care cost trend rate used to determine benefit obligations at December 31, 2025 for pre-65 retirees is 8.05 %, with an ultimate rate of 4.50 % in 2034 , and for post-65 retirees, the health care cost trend rate is 7.15 %, with an ultimate rate of 4.50 % in 2034 .

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The Discount Rate assumptions used in determining retirement plan costs and retirement plan obligations are based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves.

For 2024, a change in the discount rate of 0.25 % would have resulted in an increase or decrease of approximately $ 450,800 in the Net Periodic Benefit Cost (NPBC).

For 2025, a change in the discount rate of 0.25 % would have resulted in an increase or decrease of approximatel y $ 428,700 in the Net Periodic Benefit Cost (NPBC).

The Rate of Compensation Increase assumption used for 2025 was based on the expected long-term increase in compensation costs for personnel covered by the plans.

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Since the market-related value of assets recognizes gains or losses over a three-year period, the future value of the market-related assets will be affected as previously deferred gains or losses are recognized.

Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2024, 2023 and 2022 would have been $ 1.8 million, $ 2.8 million and $ 2.4 million respectively, prior to amounts capitalized or deferred.

Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2025, 2024 and 2023 would have bee n ($ 0.5 ) mi llion, $ 1.8 million and $ 2.8 million respectively, prior to amounts capitalized or deferred.

The following table represents information on the plans’ assets, projected benefit obligations (PBO), and funded status (000’s):

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Interest Cost

Plan Amendments

Participant Contributions

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Assets vs PBO

The decrease in the PBO for the Pension and SERP plans as of December 31, 2024 compared to December 31, 2023 primarily reflects an increase in the assumed discount rate as of December 31, 2024 and normal changes in service cost, interest cost and demographic data.

The increase in the PBO for the PBOP plan as of December 31, 2024 compared to December 31, 2023 primarily reflects an increase in medical costs and normal changes in service cost, interest cost and demographic data, partially offset by an increase in the assumed discount rate as of December 31, 2024.

The increase in the PBO for the Pension and SERP plans as of December 31, 2025 compared to December 31, 2024 primarily reflects a decrease in the assumed discount rate as of December 31, 2025 and normal changes in service cost, interest cost and demographic data.

The increase in the PBO for the PBOP plan as of December 31, 2025 compared to December 31, 2024 primarily reflects an increase in medical costs, a decrease in the assumed discount rate and normal changes in service cost and interest cost, partially offset by a decrease in demographic data as of December 31, 2025.

The funded status of the Pension, PBOP and SERP Plans is calculated based on the difference between the benefit obligation and the fair value of plan assets and is recorded on the balance sheets as an asset or a liability.

1 unchanged sentence

The Company has recorded on its consolidated balance sheets as a liability the underfunded status of its and its subsidiaries’ retirement benefit obligations based on the projected benefit obligation.

The Company has recognized Regulatory Assets, net of deferred tax benefits, of $ 14.4 million and $ 29.8 million at December 31, 2024 and 2023, respectively, to account for the future collection of these plan obligations in electric and gas rates.

The Company has recognized Regulatory Assets, net of deferred tax benefits, o f $ 13.7 million and $ 14.4 million at December 31, 2025 and 2024, respectively, to account for the future collection of these plan obligations in electric and gas rates.

These amounts are recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans.

1 unchanged sentence

The difference between the PBO and the ABO is that the PBO includes projected compensation increases.

The ABO for the Pension Plan was $ 141.6 million and $ 146.3 million as of December 31, 2024 and 2023, respectively.

The ABO for the

SERP was $ 12.4 million and $ 14.4 million as of December 31, 2024 and 2023, respectively.

the Pension Plan w as $ 146.7 mil lion and $ 141.6 million as of December 31, 2025 and 2024, respectively.

The ABO for the SERP w as $ 13.3 m illion and $ 12.4 million as of December 31, 2025 and 2024, respectively.

For the PBOP Plan, the ABO and PBO are the same.

62 unchanged sentences

Employees may direct, at their sole discretion, the investment of their savings plan balances (both the employer and employee portions) into a variety of investment options, including a Company common stock fund.

The Company’s contributions to the 401(k) Plan were $ 4.5 million, $ 4.0 million and $ 3.5 million for the years ended December 31, 2024, 2023 and 2022, respectively.

The Company’s contributions to the 401(k) Plan wer e $ 5.0 m illion, $ 4.5 million and $ 4.0 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 8. Financial Statements and Supplementary Data