What changed in this filing

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Item 8. Financial Statements and Supplementary Data

2025-02-10 compared with 2024-02-13 · 301 added, 225 removed, 1131 unchanged (32% of the section changed)

23 unchanged sentences

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 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 Northern Maine and Fitchburg Gas and Electric and included the following, among others:

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:

• 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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Operating Lease Obligations

Interest Payable

Taxes Payable

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Stockholders’ Equity:

Common Equity (Outstanding 16,116,724 and 16,043,355 Shares)

Common Equity ( No par value, Authorized 25,000,000 Shares;

Outstanding 16,192,345 and 16,116,724 Shares as of respective dates)

Retained Earnings

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Financing Activities:

Proceeds from Short-Term Debt, net

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

Issuance of Long-Term Debt

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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.

Basis of Presentation

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The difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recognized as an increase or a decrease in Accrued Revenue, which forms the basis for resetting rates for future cash recoveries from, or credits to, customers.

These revenue decoupling targets may be adjusted as a result of rate cases and other authorized adjustments that the Company files with the Massachusetts Department of Public Utilities (MDPU) and New Hampshire Public Utilities Commission (NHPUC).

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.

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

The following table shows the estimated percentages of electric and gas sales, as of December 31, 2023, that are subject to revenue decoupling for the periods presented.

Revenue Decoupling

Estimated Percentage of Decoupled Sales

For Periods Presented

Before June 1, 2022

After June 1, 2022

Substantially All

Before August 1, 2022

After August 1, 2022

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

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

The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors.

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

The amount and timing of all dividend payments is subject to the discretion of the Board and will depend upon business conditions, results of operations, financial conditions and other factors.

For the year ended December 31, 2024, the Company paid quarterly dividends of $ 0.425 per share, resulting in an annualized dividend rate of $ 1.70 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.

At its January 2024 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $ 0.425 per share, an increase of $ 0.02 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $ 1.70 per share from $ 1.62 per share.

At a January 2025 meeting of the Board, the Board declared a quarterly dividend on the Company’s common stock of $ 0.45 per share, an increase of $ 0.025 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $ 1.80 per share from $ 1.70 per share.

Cash and Cash Equivalents - Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title.

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Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE.

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.

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.

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

Fitchburg is also regulated by the 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) and Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC.

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 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.

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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 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)).

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Investments 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 9 Retirement Benefit Plans).

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

See additional discussion of the SERP in Note 9 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.

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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, specifically, An Act Relative to Green Communities (Green Communities Act, 2008), An Act Relative to Competitively Priced Electricity in the Commonwealth (2012) and An Act to Promote Energy Diversity (Energy Diversity Act, 2016).

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 (each 400MW) 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 September 30, 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 under Section 83C of 5,600 MW.

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 new submission date is March 27, 2024.

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.

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.

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.

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.

Retirement Benefit Obligations - The Company sponsors the Pension Plan, which is a defined benefit pension plan.

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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).

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.

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.

Segment Information

The Company’s Chief Operating Decision Maker (CODM), consists of the Company’s Chairman and Chief Executive Officer, President and Chief Administrative Officer, Chief Financial Officer, and Chief Accounting Officer.

These individuals assess financial performance and make decisions, including the allocation of resources to the various business segments, based on meeting with the managers of each segment and through their review of reports and analyses that are regularly provided to the CODM.

Unitil reports two segments:

These individuals assess financial performance and make decisions, including the allocation of resources to the various operating segments, based on meeting with the managers of each segment and through their review of reports and analyses that are regularly provided to the CODM.

The CODM uses Net Income Applicable to Common Shares for each segment predominantly in the annual budget and forecasting process.

The CODM considers budget-to-actual variances on a quarterly basis when making decisions about the allocation of operating and capital resources to each segment.

Unitil reports two operating and reportable segments:

utility electric operations and utility gas operations.

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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 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.

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 is included in the utility gas operations segment.

Unitil Service, Unitil Resources, Unitil Realty and the holding company are included in Other.

Unitil Service provides centralized management and administrative services, including information systems management and financial record keeping.

Unitil Resources is the Company’s wholly-owned non-regulated subsidiary, which currently does not have any activity.

Unitil Realty owns certain real estate, principally the Company’s corporate headquarters.

The earnings of the holding company are principally derived from income earned on short-term investments and real property owned for Unitil and its subsidiaries’ use.

(the holding company), and Unitil Resources are included in the “Other” category (ASC 280-10-50-15).

The holding company has no operating income of its own.

The earnings of the holding company are principally derived from income earned on short-term investments.

Unitil Resources is the Company’s wholly-owned non-regulated subsidiary and currently does not have any activity.

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

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

Intersegment sales take place at cost and the effects of all intersegment and/or intercompany transactions are eliminated in the consolidated financial statements.

Segment profit or loss is based on profit or loss from operations after income taxes and preferred stock dividends.

Intrasegment sales take place at cost and the effects of all intrasegment and/or intercompany transactions are eliminated in the consolidated financial statements.

Segment profit or loss is based on Net Income Applicable to Common Shares.

Expenses used to determine operating income before taxes are charged directly to each segment or are allocated based on cost allocation factors included in rate applications approved by the FERC, NHPUC, MDPU, and MPUC.

Assets allocated to each segment are based upon specific identification of such assets provided by Company records.

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

The following tables provide significant segment financial data for the years ended December 31, 2024, 2023 and 2022 (millions):

Year Ended December 31, 2024

Billed and Unbilled Revenue

Rate Adjustment Mechanism Revenue

Total Reportable Segments

Total Operating Revenues

Energy Supply Costs

Operation and Maintenance

Depreciation and Amortization

Other Segment Expenses (Income)

Interest Income

Interest Expense

Depreciation & Amortization Expense

Income Tax Expense (Benefit)

Segment Profit (Loss)

Provision for Income Taxes

Net Income Attributable to Commons Shares

Segment Assets

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Year Ended December 31, 2023

Billed and Unbilled Revenue

Rate Adjustment Mechanism Revenue

Total Operating Revenues

Energy Supply Costs

Operation and Maintenance

Depreciation & Amortization Expense

Other Segment Expenses (Income)

Interest Income

Interest Expense

Depreciation & Amortization Expense

Income Tax Expense (Benefit)

Provision for Income Taxes

Segment Profit (Loss)

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Year Ended December 31, 2022

Billed and Unbilled Revenue

Rate Adjustment Mechanism Revenue

Total Operating Revenues

Energy Supply Costs

Operation and Maintenance

Depreciation & Amortization Expense

Other Segment Expenses (Income)

Interest Income

Interest Expense

Depreciation & Amortization Expense

Income Tax Expense (Benefit)

Segment Profit

Provision for Income Taxes

Segment Profit (Loss)

Segment Assets

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Year Ended December 31, 2022

* In 2021, the Company recorded higher than normal expected bad debt expense due to the coronavirus pandemic.

The incremental bad debt expense amounts were previously deferred as regulatory assets based on certain regulatory proceedings and management’s view that such amounts were probable of recovery.

Based on actual billing and collections experience, the Company has not deferred any incremental bad debt expense as a regulatory asset as of December 31, 2023 and December 31, 2022.

Debt and Financing Arrangements

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Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2024 for the payment of dividends.

Issuance of Long-Term Debt - On 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 %.

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.

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 2023.

On 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 %.

Unitil Energy issued $ 40.0 million of Bonds due 2054 at 5.69 %.

Northern Utilities issued $ 25.0 million of Notes due 2034 at 5.54 % and $ 15.0 million of Notes due 2039 at 5.74 %.

Granite State issued $ 10.0 million of Notes due 2034 at 5.74 %.

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

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.

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In estimating the fair value of the Company’s long-term debt, the assumed market yield reflects the Moody’s Baa Utility Bond Average Yield.

Costs, including prepayment costs, associated with the early settlement of long-term debt are not taken into consideration in determining fair value.

Costs, including

prepayment costs, associated with the early settlement of long-term debt are not taken into consideration in determining fair value.

Estimated Fair Value of Long-Term Debt (millions)

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3.43 % Senior Notes, Due December 18, 2029

5.99 % Senior Notes, Due August 21, 2034

Unitil Energy First Mortgage Bonds:

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4.18 % Senior Secured Notes, Due November 30, 2048

6.79 % Senior Notes, Due October 15, 2025

5.69 % Senior Secured Notes, Due August 21, 2054

3.52 % Senior Notes, Due November 1, 2027

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5.70 % Senior Notes, Due July 2, 2033

5.54 % Senior Notes, Due August 21, 2034

3.78 % Senior Notes, Due September 15, 2040

5.99 % Senior Notes, Due August 21, 2044

4.32 % Senior Notes, Due November 1, 2047

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3.52 % Senior Notes, Due November 1, 2027

5.54 % Senior Notes, Due August 21, 2034

7.72 % Senior Notes, Due December 3, 2038

5.74 % Senior Notes, Due August 21, 2039

3.78 % Senior Notes, Due September 15, 2040

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3.72 % Senior Notes, Due November 1, 2027

5.74 % Senior Notes, Due August 21, 2034

Unitil Realty Corp.:

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Interest expense is mainly comprised of interest on long-term debt and short-term borrowings.

In addition, certain reconciling rate mechanisms

used by the Company’s distribution operating utilities give rise to regulatory assets and regulatory liabilities on which interest is calculated.

In addition, certain reconciling rate mechanisms used by the Company’s distribution operating utilities give rise to regulatory assets and regulatory liabilities on which interest is calculated.

Unitil’s utility subsidiaries operate a number of reconciling rate mechanisms to recover specifically identified costs on a pass-through basis.

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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 in its entirety the prior credit facility.

Unitil may borrow under the Credit Facility until September 29, 2027, subject to two one-year extensions under certain circumstances.

The Credit Facility terminates and all amounts outstanding thereunder are due and payable on September 29, 2027, subject to the potential extension discussed in the prior sentence.

The Credit Facility has a borrowing limit of $ 200 million, which includes a $ 25 million sublimit for the issuance of standby letters of credit.

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.

The 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).

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities.

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).

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.

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

The Company has common stock outstanding and one of our subsidiaries has preferred stock outstanding.

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

The Company’s common stock trades on the New York Stock Exchange under the symbol “UTL”.

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The Company has 25,000,000 shares of common stock authorized as of December 31, 2024 and December 31, 2023.

Unitil Corporation Common Stock Offering— On August 6, 2021, the Company issued and sold 800,000 shares of its common stock at a price of $ 50.80 per share in a registered public offering (Offering).

The Company’s net increase to Common Equity and Cash proceeds from the Offering was approximately $ 38.6 million.

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

As part of the Offering, the Company granted the underwriters a 30 -day option to purchase additional shares.

The underwriters exercised the option and purchased an additional 120,000 shares of the Company’s common stock on September 8, 2021.

The Company’s net increase to Common Equity and Cash proceeds from the exercise of the option was approximately $ 5.9 million.

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

Dividend Reinvestment and Stock Purchase Plan— During 2024, the Company sold 19,510 shares of its common stock, at an average price of $ 54.40 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.

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During 2023 and 2022, the Company raised $ 1.1 million and $ 1.0 million, respectively, through the issuance of 21,321 and 18,853 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, the Company may periodically repurchase shares of its common stock on the open market related to the stock portion of the Directors’ annual retainer.

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.

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.

On May 31, 2024, the Company’s 2023 trading plan terminated in accordance with its terms.

The Company did not adopt a new written trading plan under Rule 10b5-1 and does not anticipate doing so in the near term.

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

During 2023, 2022 and 2021, the Company repurchased 14,680 , 9,449 and 8,012 shares of its common stock, respectively, pursuant to the Rule 10b5-1 trading plan.

The expense recognized by the Company for these repurchases was $ 0.6 million, $ 0.4 million, and $ 0.4 million in 2023, 2022 and 2021, respectively.

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 2024, 2023 and 2022, the Company did not cancel or retire any of its common stock.

1 unchanged sentence

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 Second Amended and Restated 2003 Stock Plan (the Stock Plan).

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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and, subject to the provisions of the Stock Plan, amend the terms and conditions of any outstanding award to the extent such terms and conditions are within the discretion of the Compensation Committee as provided for in the Stock Plan.

On April 19, 2012, the Company’s shareholders approved an amendment to the Stock Plan to, among other things, increase the maximum number of shares of common stock available for awards to plan participants.

The maximum number of shares available for awards to participants under the Stock Plan is 677,500 .

On April 19, 2012 and May 1, 2024, the Company’s shareholders approved amendments to the Stock Plan to, among other things, increase the maximum number of shares of common stock available for awards to plan participants.

The maximum number of shares available for awards to participants under the Stock Plan was 677,500 as of March 31, 2024, and was increased on May 1, 2024 to 1,027,500 .

The maximum number of shares that may be awarded in any one calendar year to any one participant is 20,000 .

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Prior to the end of the vesting period, the Time 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.

Time Restricted Shares issued for 2021 – 2023 in conjunction with the Stock Plan are presented in the following table:

Time Restricted Shares issued in the years ended 2022, 2023, and 2024 in conjunction with the Stock Plan are presented in the following table:

Issuance Date

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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, $ 2.1 million and $ 1.4 million in 2023, 2022 and 2021, 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 2023, there were zero Time Restricted Shares forfeited or cancelled under the Stock Plan.

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

On January 28, 2025, there were 26,430 Time Restricted Shares issued under the Stock Plan with an aggregate market value of $ 1.4 million.

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

No Performance Restricted Shares were awarded in 2022 or 2021.

On January 24, 2023, there were 18,770 Performance Restricted Shares issued under the Stock Plan with an aggregate market value of $ 1.0 million.

No Performance Restricted Shares were awarded in 2022.

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

Issuance Date

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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 $ 51.83 per 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 $ 0.5 million i n 2023.

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.

At December 31, 2024, there was approximately $ 1.5 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.

During 2023, there were zero Performance Restricted Shares forfeited or cancelled under the Stock Plan.

During 2024, there were 250 Performance Restricted Shares forfeited and zero Performance Restricted Shares cancelled under the Stock Plan.

On January 28, 2025, there were 26,430 Performance Restricted Shares issued under the Stock Plan with an aggregate market value of $ 1.4 million.

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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, 2023.

There were $ 0.2 million, or 1,861 shares, of Unitil Energy’s 6.00 % Series Preferred Stock outstanding as of December 31, 2022.

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 were less than $ 0.1 million of total dividends declared on Preferred Stock in each of the twelve month periods ended December 31, 2024 and December 31, 2023, respectively.

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As of December 2024, 89% of Unitil’s largest New Hampshire customers, representing 25% of Unitil’s New Hampshire electric kilowatt-hour (kWh) sales, and 100% of Unitil’s largest Massachusetts customers, representing 30% 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 aggregation.

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

Customers in these three town’s represent 88% of Fitchburg’s customer base.

In New Hampshire, most residential and small commercial customers continue to purchase their electric supply through Unitil’s electric distribution utilities under regulated energy rates and tariffs, although this trend is changing.

As of December 2023, the percentage of residential customers purchasing electricity from a third-party supplier increased to 22% from nearly 9% in December 2022.

Municipal aggregation is now offered in New Hampshire.

The towns of Exeter and Canterbury currently have active aggregations.

Customers in these two towns represent 12% of Unitil’s customer base in New Hampshire.

In Massachusetts, as of December 2023, 75% of Unitil’s residential customers in Massachusetts purchased their electricity from a third-party supplier which is up from 28% in December 2022.

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.

Regulated Electric Power Supply

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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.

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

Pursuant to MDPU policy, Basic Service power supply contracts for residential and for small and medium general service customers are acquired every six months, are 12 months in duration and provide 50 percent of the supply requirements.

On June 13, 2012, the MDPU approved Fitchburg’s request to discontinue the procurement process for Fitchburg’s large customers and become the load-serving entity for these customers.

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

In its August 2022 solicitation, Fitchburg received no supply offers for load-following power to meet the needs of customers taking service under its Default Service tariff beginning December 2022.

As such, beginning December 1, 2022 through July 31, 2023, Fitchburg began procuring electric supply for residential and small commercial customers directly from the ISO New England markets.

In 2023, the Company ran successful solicitations in May and October and has returned to its staggered approach for procuring 50 % of supply requirements for 12 months.

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 implications of the failed solicitation result in 50 % of wholesale supply charges settling at the real-time energy price.

The failed solicitation has no impact on the ability to provide default energy service to Fitchburg’s customers.

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.

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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.

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

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

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

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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 $ 2.1 million for 2022 eligible facilities, was filed with the MPUC on February 28, 202 3.

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.

On April 30, 2024, the MPUC issued an order approving the filing, for rates effective May 1, 2024.

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The Order provided for a return on equity of 9.3 % and a capital structure reflecting 52 % equity and 48 % long-term debt.

In light of the Step Adjustment, the Company shall not file a distribution rate case with the Commission before January 1, 2024 (the Stay-Out Period).

However, during the term of the Stay-Out Period, the Company will be allowed to adjust distribution rates upward or downward resulting from a singular (not collective) exogenous event that exceeds $ 200,000 .

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

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

Under the terms of the Settlement Agreement, parties agreed that the Company shall recover revenues associated with the full rate year (August 1, 2022 – July 31, 2023) over an eleven-month period beginning September 1, 2022 and ending July 31, 2023.

On May 5, 2023, the Company made a compliance filing to adjust base distribution rates downward to reflect a 12-month recovery period effective August 1, 2023.

On July 13, 2023, the NHPUC approved the Company’s compliance 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.

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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.

(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.

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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 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.

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

On November 2, 2022, Fitchburg filed its cumulative revenue requirement of $ 3.1 million associated with its 2019-2021 capital expenditures.

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

On July 26, 2023, the MDPU issued an Order approving the Company's filing.

On November 1, 2023, Fitchburg filed its cumulative revenue requirement of $ 3.6 million associated with its 2019-2022 capital expenditures.

On November 27, 2023, Fitchburg revised its cumulative revenue requirement to $ 3.5 million.

On December 22, 2023, the MDPU allowed the associated rate increase to become effective on January 1, 2024, subject to further investigation and reconciliation.

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 anticipated to be effective July 1, 2024.

Fitchburg proposes to transfer $ 2.7 million in revenue requirements recovered through certain reconciling mechanisms to base distribution rates.

Net of these transfers, the proposed overall increase to distribution revenues is $ 4.1 million.

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

A decision from the MDPU is expected in June 2024.

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.

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.

On November 1, 2024, Fitchburg filed its cumulative revenue requirement of $ 0.5 million associated with its 2023 capital expenditures, which reflects the transfer of capital expenditures associated with its 2019-2023 year investments into base distribution rates effective July 1, 2024.

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

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.

Fitchburg also requested, among other things, approval for a performance-based ratemaking (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 $ 4.7 million increase to base rates, effective July 1, 2024.

This includes a transfer of $ 2.2 million in costs from certain reconciling mechanisms to base distribution rates.

In addition to authorizing an increase to base rates, the Order approved a PBR plan for up to a five-year term and continuation of the Company’s revenue decoupling mechanism.

The Order provided for a return on equity of 9.4 % and a capital structure reflecting 52 % equity and 48 % long-term debt.

On July 5, 2024, the Company filed its compliance tariff filing and made further revisions as directed by the MDPU on July 15, 2024.

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 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.

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.

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

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.

A decision from the MDPU is expected in June 2024.

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

This includes a transfer of $ 4.9 million in costs from certain reconciling mechanisms to base distribution rates.

In addition to authorizing an increase to base rates, the Order approved a PBR plan for up to a five-year term.

The order approves continuation of the Company’s revenue decoupling mechanism but changes the structure from a revenue per customer benchmark to a total revenue cap.

The Order provided for a return on equity of 9.4 % and a capital structure reflecting 52 % equity and 48 % long-term debt.

On July 5, 2024, the Company filed its compliance tariff filing and made further revisions as directed by the MDPU on July 15, 2024.

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.

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.

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.

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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.

The Company’s most recent forward-looking cumulative revenue requirement filing, filed on October 31, 2023, requested recovery of approximately $ 6.4 million.

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

Granite State - Base Rates - On November 30, 2020, the FERC approved Granite State’s filing of an uncontested rate settlement which provided for an increase in annual revenues of approximately $ 1.3 million, effective November 1, 2020.

The Settlement Agreement permits the filing of limited Section 4 rate adjustments for capital cost projects eligible for cost recovery in 2021, 2022, and 2023, and sets forth an overall investment cap of approximately $ 14.6 million on the capital cost recoverable under such filings during the term of the Settlement.

Under the Settlement Agreement, Granite may not file a new general rate case earlier than April 30, 2024 with rates to be effective no earlier than November 1, 2024 based on a test year ending no earlier than December 31, 2023.

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 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.

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.

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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.

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.

Under the Settlement Agreement, Granite State may not file a new general rate case earlier than April 30, 2028 with rates to be effective no earlier than September 1, 2028 based on a test year ending no earlier than December 31, 2027.

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

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

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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 Department preauthorized in D.P.U.

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.

Fitchburg - Grid Modernization Cost Recovery Factor - On April 15, 2022, Fitchburg filed its GMF rate adjustment and reconciliation filing pursuant to the Company’s GMF Tariff, for recovery of the costs incurred as a result of implementing the Company’s 2018-2021 GMP, previously approved by the MDPU on February 7, 2019.

The proposed GMF of $ 0.4 million was approved on May 27, 2022, effective June 1, 2022, subject to further investigation and reconciliation.

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.

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.

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.

On May 31, 2023, the MDPU approved, subject to further investigation and reconciliation, the cumulative recovery of $ 1.0 million associated with the Company’s 2022 GMP revenue requirement, effective June 1, 2023.

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The matter remains pending.

On April 15, 2024, 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.

On May 31, 2024, the MDPU approved, subject to further investigation and reconciliation, the cumulative recovery of $ 1.3 million associated with its 2023 revenue requirement, effective June 1, 2024.

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.

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 MA Executive Office of Energy and Environmental Affairs, in consultation with the Massachusetts Department of Environmental Protection and the Massachusetts Department of Energy Resources (DOER).

Following an active stakeholder process, on March 18, 2022, Consultant Reports on decarbonization pathways, regulatory designs and stakeholder engagement were submitted to the MDPU.

Also on March 18, 2022, the LDCs, including Fitchburg, submitted proposals to the MDPU that include the LDCs’ recommendations and plans for helping the Commonwealth achieve its 2050 climate goals, supported by the Consultant Reports.

The MDPU held a technical session on the Consultant Report on March 30, 2022 and a technical session on the LDC proposals on April 15, 2022.

Discovery by the MDPU is complete, and the LDCs responded to stakeholder comments on July 29, 2022.

Final comments from stakeholders replying to the LDCs’ comments and making any other final remarks for the MDPU’s consideration were filed on October 14, 2022.

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

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.

The MDPU instructed the LDCs in their next rate case to revise their per-customer revenue decoupling mechanism to a decoupling approach based on total revenues.

The MDPU emphasized that the Order is not intended to jeopardize the rate recovery of existing investments in natural gas infrastructure by Fitchburg.

As part of future cost recovery proposals, LDCs will bear the burden of demonstrating that non-gas pipeline alternatives were adequately considered and found to be non-viable or cost prohibitive to receive full cost recovery of investments.

As part of future cost recovery proposals, LDCs will bear the burden of demonstrating that non-gas pipeline alternatives (NPAs) were adequately considered and found to be non-viable or cost prohibitive to receive full cost recovery of investments.

The MDPU further found that the “clean energy transition” will require coordinated planning between LDCs and electric distribution companies, monitoring progress through LDC reporting, and aligning existing MDPU practices with climate targets.

To that end, the MDPU ordered the LDCs to submit individual Climate Compliance Plans 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.

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:

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

(2) the timetable for establishing ‘incentives and disincentives’ for progress toward compliance with Climate Act mandates as part of a PBR framework and achievement of approved Climate Compliance Plans;

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;

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

and that LDCs will have the burden to demonstrate the prudence of implementing a traditional project instead of a NPA.

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

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

164 § 92B, Fitchburg submitted a draft Electric Sector Modernization Plan (ESMP) to the statutorily created Massachusetts Grid Modernization Advisory Council (Council) for the Council’s review, input, and recommendations.

The ESMP is a plan intended to upgrade the Company’s distribution system to enable and accommodate increased distributed energy resources and electrification technologies, improve grid reliability and resiliency, and assist the Commonwealth in achieving climate goals, among other objectives.

The ESMP is a plan intended to upgrade the Company’s distribution system to enable and accommodate increased distributed energy resources (DERs) and electrification technologies, improve grid reliability and resiliency, and assist the Commonwealth in achieving climate goals, among other objectives.

The Council provided recommendations on the ESMP in November 2023.

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The Company concurrently submitted a proposal to recover, among other things, incremental costs associated with ESMP investments through an annual reconciling rate adjustment mechanism.

This matter remains pending before the MDPU.

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.

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.

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:

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Any spending above the approved EV program budget or above the 15% cap for each program segment is not eligible for targeted cost recovery through the GMF and, instead, may be recovered in a base distribution rate proceeding subsequent to a prudency finding by the MDPU.

Further, the MDPU has convened an EV stakeholder process to finalize EV program performance metrics.

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

Once performance metrics are finalized, the MDPU will require the electric companies to develop a joint state-wide program evaluation plan for MDPU approval and stakeholder input and will determine next steps at that time.

The MDPU directs the Companies to submit annual reports that document their performance and these reports will be due on or before May 15th of each year.

The first EV annual report is due May 15, 2024.

The Company shall file annual rate adjustment and reconciliation filings on or before April 15, with rates effective June 1.

The MDPU’s Order directs the Companies to submit annual reports that document their performance and these reports are due on or before May 15th of each year.

The MDPU accepted the Company’s Demand Charge Alternative proposal and directed implementation within six months.

The Demand Charge Alternative is offered for a ten-year period beginning July 1, 2023 with tiered rates to separately-metered EV general delivery service customers.

The MDPU accepted the Company’s proposed residential EV TOU rate, effective April 1, 2023.

The MDPU also accepted the Company’s proposed residential EV TOU rate, effective April 1, 2023.

In June 2023, the MDPU convened an EV stakeholder process to finalize EV program performance metrics.

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.

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

On May 15, 2024, Fitchburg submitted its first annual report on the performance of its EV Program, and along with the other Massachusetts EDCs, a proposed statewide program evaluation plan for MDPU approval and stakeholder input.

On September 30, 2024, the MDPU stamp approved the Joint Statewide Electric Vehicle Program Evaluation Plan.

In addition, on October 1, 2024 the MDPU approved Fitchburg’s request for a supplemental budget increase to engage a consultant to assist with the Joint Statewide Electric Vehicle Program Evaluation Plan.

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.

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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.

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 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.

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.

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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Pursuant to statutory requirements in Maine and orders of the MPUC, Northern Utilities submits an annual informational report requesting approval of a one-year extension of its 12-month contract for firm pipeline capacity reservation, with an evergreen provision and three-month termination notification requirement.

On April 3, 2023, Northern Utilities submitted an annual informational report requesting approval on a one-year extension for the period of November 1, 2023 through October 31, 2024.

The MPUC issued an Order on June 13, 2023 approving the one-year extension.

On March 29, 2024, Northern Utilities submitted an annual informational report requesting approval on a one-year extension for the period of November 1, 2024 through October 31, 2025.

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

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

(GSGT) - On October 5, 2023, Northern Utilities filed with the NHPUC and the MPUC a request to approve agreements for the ability for Northern Utilities to increase supply portfolio capacity by 12,500 Dth per day in New Hampshire and Maine.

This incremental capacity to Northern Utilities’ supply portfolio is proposed for effect April 1, 2024 for a thirty-year term.

This incremental capacity to Northern Utilities’ supply portfolio took effect April 1, 2024 for a thirty-year term.

Northern Utilities was able to acquire this incremental supply of TCPL capacity through an open season process.

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.

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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;

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;

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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 electric distribution companies (EDCs), including Fitchburg, are required to jointly procure a total of 1,600 MW of offshore wind by June 30, 2027.

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.

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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 evaluating NECEC’s requests.

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.

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.

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, in February 10, 2020.

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.

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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 Massachusetts Department of Energy Resources (DOER) recommended that the EDCs solicit up to 1,600 MW in additional offshore wind in 2022 and 2024.

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.

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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 seeking to set aside and vacate the MDPU’s Order approving the PPAs.

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 have 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 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 the Company received $ 1.1 million from Commonwealth Wind and SouthCoast Wind 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 Supreme Court be entered as dismissed.

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.

In 2021, the MA legislature increased the total solicitation target (including future solicitations) for offshore wind energy generation to 5,600 MW by June 30, 2027.

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.

The new submission date is March 27, 2024.

Section 82 of the Acts of 2022 authorizes DOER to coordinate with other New England states to consider projects for long-term clean energy generation, transmission or capacity for the benefit of residents of the Commonwealth and the region.

If DOER, in consultation with the Attorney General, determines that a project would satisfy all of the benefits listed in Section 82, then pursuant to Section 82 the EDCs shall enter into cost-effective long-term contracts with a maximum term of twenty years upon such a finding.

On October 26, 2022, the MPUC announced its selection of a Transmission Project and a Generation Project to promote renewable energy development in northern Maine.

On December 30, 2022, the DOER made a positive determination that the selected projects would have benefits to Massachusetts and the region and Massachusetts would procure up to 40% of the projects.

On December 22, 2023, the MPUC terminated the procurement after the transmission project developer indicated that it could no longer hold to the fixed price contained in its term sheet and required a price adjustment.

Fitchburg/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.

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.

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:

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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Court of Appeals for the D.C.

Circuit (the Court) issued an opinion vacating and remanding FERC’s decision, finding that FERC had failed to articulate a satisfactory explanation for its orders.

Circuit issued an opinion vacating and remanding FERC’s decision, finding that FERC had failed to articulate a satisfactory explanation for its orders.

At this time, the ROE set in the vacated order will remain in place until further FERC action is taken.

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In Maine, Northern Utilities has documented the presence of MGP sites in Lewiston and Portland, and a former MGP disposal site in Scarborough.

Northern Utilities has worked with the Maine Department of Environmental Protection and New Hampshire Department of Environmental Services (NH DES) to address environmental concerns with these sites.

Northern Utilities has worked with the New Hampshire Department of Environmental Services (NH DES) and Maine Department of Environmental Protection to address environmental concerns with these sites.

Northern Utilities or others have completed remediation activities at all sites;

however, on site monitoring continues at several sites which may result in future remedial actions as directed by the applicable regulatory agency.

In July 2019, the NH DES requested that Northern Utilities review modeled expectations for groundwater contaminants against observed data at the Rochester site.

In June 2020, the NH DES coupled the submittal of the review to a proposed extension of the gas distribution system by Northern Utilities.

Northern Utilities submitted the review in January 2022, and the NH DES directed that soil treatability studies as part of a Remedial Action Plan (RAP) be developed in June 2022.

The Company submitted the studies and RAP to the NH DES in December 2022 and continues to await a decision from the agency;

the RAP included three remediation alternatives for consideration by NH DES.

In anticipation of the probable NH DES approval of one of the remediation alternatives and subsequent request for project design, the Company has accrued $ 2.5 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.

The Company has determined that the high end of the range of reasonably possible remediation costs for the Rochester site could be $ 5.6 million based on remediation alternatives.

Due to extended regulatory review time periods, Northern Utilities anticipates the commencement of remediation activities in 2025.

In May 2024, NH DES requested additional information in connection with the Company’s December 2022 remedial action plan (RAP), regarding groundwater contaminants at the Rochester site.

In anticipation of the NH DES approval of one of the RAP alternatives and subsequent request for project design, the Company has accrued $ 5.6 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.

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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Depending upon the final agreement between Fitchburg and Mass DOT, additional minor costs are expected prior to completion.

In August 2021, the Mass DEP issued a Notice of Non-compliance to Fitchburg following a November 2020 audit of the September 2015 Response Action Outcome on the MGP site.

Mass DEP directed Fitchburg to further define the extent of MGP site contaminants in the sediment and riverbank of an abutting watercourse.

Fitchburg began the investigation in November 2021 with the Mass DEP expanding the scope in June 2022 to include an observed river seep.

Fitchburg submitted the results of its investigation and an Immediate Response Action (IRA) plan associated with the river seep to the Mass DEP in December 2022.

The Mass DEP has review and approval authority over the IRA plan’s recommendations.

Fitchburg submitted an updated IRA plan to the Mass DEP in October 2023.

The Company obtained cost-estimates for several remediation alternatives.

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 remediation activities by the end of 2024.

Fitchburg anticipates the commencement of some remediation activities by the middle of 2025, while the river seep will likely be addressed 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.

The ESA results identified soil and groundwater contaminants in excess of state regulatory standards.

In September 2021, the NH DES directed Unitil Energy to conduct a supplemental site investigation (SSI) and identify whether there is a need to conduct further investigation or remedial actions.

Unitil Energy began the SSI in December 2021 with the NH DES extending the SSI scope in June 2022 to further delineate potential impacts.

Unitil Energy completed the field portion of the SSI in September 2022 and submitted the report to the NH DES in June 2023 and is awaiting a decision by the agency.

Unitil Energy anticipates the commencement of remediation activities in 2025.

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.

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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Retirement Benefit Obligations

Regulatory Assets & Liabilities

Net Operating Loss Carryforwards

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Income tax filings for the year ended December 31, 2023 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, 2022 which were filed with the IRS in October 2023, the Company utilized federal Net Operating Loss Carryforward (NOLC) assets of $ 1.4 million and $ 0.2 million of federal tax credit carryforward.

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.

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The revenue procedure may be adopted in tax years ending after May 1, 2023.

The Company is evaluating the revenue procedure and the effect adopting the safe harbor would have on its property that is subject to this guidance.

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.

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The AMT is equal to 15 % of a corporation’s adjusted financial statement income (AFSI).

The AMT applies to companies that have a 3 year average AFSI of greater than $ 1 billion.

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.

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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.

In accordance with FASB Codification Topic 740, the Company revalued its Accumulated Deferred Income Taxes (ADIT) and recorded a net Regulatory Liability in the amount of $ 48.9 million at December 31, 2017.

In accordance with FASB Codification Topic 740, the Company revalued its Accumulated Deferred Income Taxes (ADIT) and recorded a net liability in the amount of $ 48.9 million at December 31, 2017.

The Company expects to flow through to customers $ 47.1 million of excess ADIT in utility base rates.

Approximately $ 1.8 million of excess ADIT was created through reconciling mechanisms at December 31, 2017, which had not been previously collected from customers through utility rates.

The Company reconciled these excess ADIT amounts

through the specific reconciliation mechanisms in each of those individual reconciling mechanisms which were reviewed by state regulators.

The benefit of protected excess ADIT amounts will be subject to flow back to customers in utility rates according to the Average Rate Assumption Method (ARAM).

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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 2022 for both pre-65 retirees and post-65 retirees is 6.20 %, with an ultimate rate of 4.50 % in 2029 .

The health care cost trend rate used to determine plan costs for 2021 for both pre-65 retirees and post-65 retirees is 6.60 %, with an ultimate rate of 4.50 % in 2029 .

The health care cost trend rate used to determine benefit obligations at December 31, 2023 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 2023 for pre-65 retirees was 8.00 %, with an ultimate rate of 4.50 % in 2030 , and for post-65 retirees, the health care cost trend rate was 6.25 %, with an ultimate rate of 4.50 % in 2030 .

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 benefit obligations at December 31, 2024 for pre-65 retirees 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 benefit obligations at December 31, 2021 for both pre-65 and post-65 retirees is 6.20 %, with an ultimate rate 4.50 % in 2029 .

The health care cost trend rate used to determine benefit obligations at December 31, 2023 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 benefit obligations at December 31, 2022 for pre-65 retirees was 8.00 %, with an ultimate rate of 4.50 % in 2030 , and for post-65 retirees, the health care cost trend rate was 6.25 %, with an ultimate rate of 4.50 % in 2030 .

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.

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Participant Contributions

Plan Amendments

Benefits Paid

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Assets vs PBO

The increase in the PBO for the Pension, PBOP and SERP plans as of December 31, 2023 compared to December 31, 2022 primarily reflects a decrease in the assumed discount rate as of December 31, 2023 and normal changes in service cost, interest cost and demographic data.

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 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.

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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 $ 14.4 million and $ 13.9 million as of December 31, 2023 and 2022, respectively.

The ABO for the

SERP was $ 12.4 million and $ 14.4 million as of December 31, 2024 and 2023, respectively.

For the PBOP Plan, the ABO and PBO are the same.

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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