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Item 8. Financial Statements and Supplementary Data

2024-02-13 compared with 2023-02-14 · 448 added, 483 removed, 908 unchanged (51% of the section changed)

Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

R eport of Independent Registered Public Accounting Firm

To the shareholders and the Board of Directors of Unitil Corporation:

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We have audited the accompanying consolidated balance sheets of Unitil Corporation and subsidiaries (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of earnings, changes in common stock equity, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements").

We also have audited the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control —

Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control —

Integrated Framework (2013) issued by COSO.

Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

Basis for Opinions

The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting.

Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S.

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Definition and Limitations of Internal Control over Financial Reporting

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

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;

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.

(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;

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

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The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Impact of Rate-Regulation on Various Account Balances and Disclosures —

Refer to Notes 1 and 7 to the financial statements

Impact of Rate-Regulation on Various Account Balances and Disclosures — Refer to Notes 1 and 7 to the financial statements

Critical Audit Matter Description

The Company’s principal business is the distribution of electricity and natural gas and is subject to regulation by the Massachusetts, New Hampshire and Maine Public Service Commissions as well as the Federal Energy Regulatory Commission (collectively, the “Commissions”).

Accordingly, the Company accounts for their regulated operations in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 980, Regulated Operations , and 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 Commission.

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If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met.

In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

Accounting for the economics of rate regulation affects multiple financial statement line items, including property, plant, and equipment;

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operating revenues;

and depreciation expense, and affects multiple disclosures in the Company’s financial statements.

While the Company has indicated that it expects to recover costs and a return on its investments, there is a risk that the Commissions’

will not approve full recovery of the costs of providing utility service or recovery of all amounts invested in the utility business and a reasonable return on that investment.

and depreciation expense, and affects multiple disclosures in the Company’s financial statements.

While the Company has indicated that it expects to recover costs and a return on its investments, there is a risk that the Commissions’ will not approve full recovery of the costs of providing utility service or recovery of all amounts invested in the utility business and a reasonable return on that investment.

As a result, we identified the impact of rate regulation as a critical audit matter due to the high degree of subjectivity involved in assessing the impact of current and future regulatory orders on events that have occurred as of December 31, 2023, and the judgments made by management to support its assertions about impacted account balances and disclosures.

Management judgments included assessing the likelihood of (1) recovery in future rates of incurred costs or (2) refunds to customers or future reduction in rates.

Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the commissions, auditing these judgments require specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

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 New Hampshire and Unitil Energy Systems 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.

We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

We made inquiries of management and read relevant regulatory orders and settlements issued by the Commissions in Massachusetts, New Hampshire and Maine, regulatory statutes, interpretations, procedural memorandums, filings

made by interveners or the Company, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’

treatment of similar costs under similar circumstances.

We evaluated this external information and compared to management’s recorded regulatory asset and liability balances and searched for any evidence that might contradict management’s assertions.

We obtained an analysis from management describing the orders and filings that support management’s assertions regarding the probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

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:

• 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.

• We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

• We made inquiries of management and read relevant regulatory orders and settlements issued by the Commissions in Massachusetts, New Hampshire and Maine, regulatory statutes, interpretations, procedural memorandums, filings made by interveners or the Company, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances.

We evaluated this external information and compared to management’s recorded regulatory asset and liability balances and searched for any evidence that might contradict management’s assertions.

• We obtained an analysis from management describing the orders and filings that support management’s assertions regarding the probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

/s/ Deloitte & Touche LLP

February 13, 2024

We have served as the Company’s auditor since 2014.

We have served as the Company's auditor since 2014.

CONSOLIDATED STATEMENTS OF EARNINGS

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Net Income Applicable to Common Shares

Earnings per Common Share—Basic and Diluted

Weighted Average Common Shares Outstanding—(Basic and Diluted)

Earnings per Common Share—Basic and Diluted

Weighted Average Common Shares Outstanding - (Basic)

Weighted Average Common Shares Outstanding - (Diluted)

(The accompanying Notes are an integral part of these consolidated financial statements.)

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Environmental Obligations

Operating Lease Obligations

Taxes Payable

Other Current Liabilities

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Environmental Obligations

Operating Lease Obligations

Other Noncurrent Liabilities

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Long-Term Debt, Less Current Portion

Stockholders’

Stockholders’ Equity:

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

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Preferred Stock

Total Stockholders’

Total Stockholders’ Equity

Total Capitalization

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Financing Activities:

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

Proceeds from Short-Term Debt, net

Issuance of Long-Term Debt

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Long-Term Debt Issuance Costs

Decrease in Capital Lease Obligations

Net Increase (Decrease) in Exchange Gas Financing

Increase (Decrease) in Capital Lease Obligations

Net (Decrease) Increase in Exchange Gas Financing

Dividends Paid

Proceeds from Issuance of Common Stock

Cash Provided by (Used In) Financing Activities

Net Increase (Decrease) in Cash and Cash Equivalents

Cash Provided by Financing Activities

Net (Decrease) Increase in Cash and Cash Equivalents

Cash and Cash Equivalents at Beginning of Year

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Shares Issued Under Stock Plans

Issuance of 23,658 Commons Shares (See Note 5)

Issuance of 942,316 Common Shares (See Note 5)

Balance at December 31, 2021

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Shares Issued Under Stock Plans

Issuance of 942,316 Commons Shares (See Note 5)

Issuance of 18,853 Common Shares (See Note 5)

Balance at December 31, 2022

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Shares Issued Under Stock Plans

Issuance of 18,853 Commons Shares (See Note 5)

Issuance of 21,321 Common Shares (See Note 5)

Balance at December 31, 2023

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(Unitil Resources).

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

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

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

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

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

A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy.

In connection with the implementation of electric industry restructuring in New Hampshire, on May 1, 2003 Unitil Power ceased being the wholesale supplier of Unitil Energy and divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers.

In the period since, Unitil Power continued to flow revenues and expenses from remaining contracts to Unitil Energy under the Amended Unitil System Agreement.

The last of those contracts expired October 31, 2020, and the Company no longer has material revenues or expenses associated with those contracts.

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

Unitil also has three other wholly-owned subsidiaries:

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

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

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

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

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

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

Basis of Presentation

Principles of Consolidation - The Company’s consolidated financial statements include the accounts of Unitil and all of its wholly-owned subsidiaries and all intercompany transactions are eliminated in consolidation.

Use of Estimates - The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (GAAP) requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities, and requires disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period.

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Accordingly, the degree of judgment exercised by the Company in determining fair value is greatest for instruments categorized in Level 3.

A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.

Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure.

Therefore, even when market assumptions are not readily available, the Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date.

The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation.

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These unbilled revenues are estimated each month based on estimated customer usage by class and applicable customer rates, taking into account current and historical weather data, assumptions pertaining to metering patterns, billing cycle statistics, and other estimates and assumptions, and are then reversed in the following month when billed to customers.

A majority of the Company’s revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customer monthly consumption.

Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer.

The Company’s billed and unbilled revenue meets the definition of “revenues from contracts with customers”

as defined in Accounting Standards Codification (ASC) 606.

The Company’s billed and unbilled revenue meets the definition of “revenues from contracts with customers” as defined in Accounting Standards Codification (ASC) 606.

Revenue recognized in connection with rate adjustment mechanisms is consistent with the definition of alternative revenue programs in ASC 980, as the Company has the ability to adjust rates in the future as a result of past activities or completed events.

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Total Electric and Gas Operating Revenues

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

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 MDPU and NHPUC.

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).

Fitchburg has been subject to revenue decoupling since 2011.

Unitil Energy is subject to revenue decoupling as of June 1, 2022.

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

As a result of the recently received final order in Northern Utilities’

base rate case in New Hampshire, substantially all of Northern Utilities’

gas sales volumes in New Hampshire are subject to decoupling as of August 1, 2022.

As of August 1, 2022, the Company estimates that revenue decoupling applies to approximately 43 % of Unitil’s total annual gas sales volumes.

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

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

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

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

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

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

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

These taxes are remitted to the appropriate departments of revenue in each state and are excluded from revenues on the Company’s Consolidated Statements of Earnings.

Depreciation and Amortization - Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets, and judgment is involved when estimating the useful lives of certain assets.

The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company’s fixed assets.

A change in the estimated useful lives of these assets could have a material effect on the Company’s consolidated financial statements.

Provisions for depreciation were equivalent to the following composite rates, based on the average depreciable property balances at the beginning and end of each year:

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

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

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

The Company accounts for income tax assets, liabilities and expenses in accordance with the FASB Codification guidance on Income Taxes.

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Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities.

The Company’s deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid.

In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known.

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

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

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

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

The Company 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.

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For the years ended December 31, 2022 and 2021, the Company paid quarterly dividends of $ 0.39 and $ 0.38 per common share, respectively, resulting in annualized dividend rates of $ 1.56 and $ 1.52 per common share, respectively.

At its January 2023 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $ 0.405 per share, an increase of $ 0.015 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $ 1.62 per share from $ 1.56 per share.

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.

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

Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits.

The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits.

The Company has not experienced any losses in such accounts.

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, 2023 and 2022, the Unitil subsidiaries had deposited $ 3.3 million and $ 6.0 million, respectively, to satisfy their ISO-NE obligations.

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

The allowance for doubtful accounts is calculated by applying a historical loss rate to customer account balances and management’s assessment of current and expected economic conditions, customer trends, or other factors.

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

The Company’s distribution utilities are

authorized by regulators to recover the costs of the energy commodity portion of bad debts through rate mechanisms.

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

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

Evaluating the adequacy of the allowance for doubtful accounts requires judgment about the assumptions used in the analysis.

The Company’s experience has been that the assumptions used in evaluating the adequacy of the allowance for doubtful accounts have proven to be reasonably accurate.

(See Note 3 Allowance for Doubtful Accounts).

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Unbilled Revenues, net (a component of Accrued Revenue) includes $ 0.1 million and $ 0.1 million of the Allowance for Doubtful Accounts at December 31, 2023 and December 31, 2022, respectively.

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

The following table shows the components of Accrued Revenue as of December 31, 2023 and 2022.

Accrued Revenue (millions)

Regulatory Assets—Current

Unbilled Revenues

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

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

Unitil Energy, Fitchburg and Northern Utilities.

Unitil Energy and Fitchburg are subject to regulation by

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.

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.

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As of December 31, 2023 and December 31, 2022, the Company has recorded $ 6.0 million and $ 5.8 million, respectively, of hardship accounts in Regulatory Assets.

These amounts are included in “Other Deferred Charges”

in the following table.

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

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

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Current Portion of Regulatory Assets (1)

Regulatory Assets—noncurrent

(1) Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets.

Regulatory Assets—noncurrent

(1) Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets.

Regulatory Liabilities consist of the following (millions)

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Current Portion of Regulatory Liabilities

Regulatory Liabilities—noncurrent

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

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

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

The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets.

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If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification.

In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

Leases - The Company records assets and liabilities on the balance sheet for all leases with terms longer than 12 months.

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The Company has elected the practical expedient to not separate non-lease components from lease components and instead to account for both as a single lease component.

The Company’s accounting policy election for leases with a lease term of 12 months or less is to recognize the lease payments as lease expense in the Consolidated Statements of Earnings on a straight-line basis over the lease term.

See additional discussion in the “Leases”

section of Note 4 (Debt and Financing Arrangements).

Derivatives - The Company’s regulated energy subsidiaries enter into energy supply contracts to serve their electric and gas customers.

See additional discussion in the “Leases” section of Note 4 (Debt and Financing Arrangements).

Derivatives - The Company’s regulated energy subsidiaries enter into energy supply contracts to serve their electric and gas customers.

The Company follows a procedure for determining whether each contract qualifies as a derivative instrument under the guidance provided by the FASB Codification on Derivatives and Hedging.

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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).

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

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

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

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

This fund is 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, 2022 and 2021, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $ 5.8 million and $ 5.7 million, respectively, as shown in the following table.

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).

At December 31, 2023 and 2022, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $ 6.0 million and $ 5.8 million, respectively, as shown in the following table.

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

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Money Market Funds

Fixed Income Funds

Total Marketable Securities

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The DC Plan is a non-qualified deferred compensation plan that provides a vehicle for participants to accumulate tax-deferred savings to supplement retirement income.

The DC Plan, which was effective January 1, 2019, is open to senior management or other highly compensated employees as determined by the Company’s Board of Directors, and may also be used for recruitment and retention purposes for newly hired senior executives.

The DC Plan design mirrors the Company’s Tax Deferred Savings and Investment Plan formula, but provides for contributions on compensation above the IRS limit, which will allow participants to defer up to 85% of base salary, and up to 85% of any cash incentive for retirement.

The Company may also elect to make discretionary contributions on behalf of any participant in an amount determined by the Company’s Board of Directors.

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

At December 31, 2022 and 2021, the fair value of the Company’s investments in these trading securities related to the DC Plan, which are recorded on the Consolidated Balance Sheets in Other Assets, were $ 0.6 million and $ 0.6 million, respectively.

At December 31, 2023 and 2022, the fair value of the Company’s investments in these trading securities related to the DC Plan, which are recorded on the Consolidated Balance Sheets in Other Assets, were $ 1.3 million and $ 0.6 million, respectively.

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

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Fair Value of Marketable Securities (millions)

Fixed Income Funds

Money Market Funds

Total Marketable Securities

Energy Supply Obligations—

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

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

Energy Supply Obligations consist of the following (millions)

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Exchange Gas Obligation

Power Supply Contract Divestitures

Total Energy Supply Obligations

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Unitil Energy and Fitchburg collect RPS compliance costs from customers throughout the year and demonstrate compliance for each calendar year on the following July 1.

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).

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Three approved contracts are currently under development.

These include two long-term contracts filed with the MDPU in 2018, one for offshore wind generation and one for imported hydroelectric power and associated transmission, both of which were approved in 2019, and another for offshore wind generation filed with the MDPU during the first quarter of 2020 and approved in 2021.

In compliance with An Act to Promote a Clean Energy Future (2018), in 2021 in coordination with the other electric utilities in Massachusetts, the Company issued its most recent long-term renewable solicitation seeking up to an additional 1,600 megawatts (MW) of offshore wind generation.

In December 2021, a portfolio of projects comprising 1,600 MW of offshore wind capacity was selected for negotiation.

Those contracts were approved by the MDPU on December 30, 2022.

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.

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.

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.

Power Supply Contract Divestitures - Unitil Energy’s and Fitchburg’s customers are entitled to purchase their electric or natural gas supplies from third-party suppliers.

In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts.

Unitil Energy and Fitchburg recover in rates all costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs.

As of December 31, 2022 and December 31, 2021, Fitchburg and Unitil Energy have fully recovered their power supply-related stranded costs.

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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(See Note 9 Retirement Benefit Plans).

Commitments and Contingencies - The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur.

As of December 31, 2023, the Company is not aware of any material commitments or contingencies other than those disclosed in Note 7 (Commitments and Contingencies).

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

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

The Company believes it is in compliance with all applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2023, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 7 (Commitments and Contingencies).

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

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

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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:

utility electric operations and utility gas operations.

Unitil previously reported a non-regulated segment.

Unitil divested its non-regulated business in the first quarter of 2019.

Since 2019 information is no longer presented, the Company has restated prior periods to remove the non-regulated segment as that segment did not have any continuing significance in the periods presented.

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

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

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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’

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

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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 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 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, 2023, 2022 and 2021 (millions):

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Allowance for Doubtful Accounts

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

In 2023, 2022 and 2021, the Company recorded provisions for the energy commodity portion of bad debts of $ 3.8 million, $ 3.8 million and $ 2.4 million, respectively.

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Unbilled Revenues, net (a component of Accrued Revenue) includes $ 0.1 million and $ 0.1 million of the Allowance for Doubtful Accounts at December 31, 2023 and December 31, 2022, respectively.

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2022, 2021 and 2020 (millions):

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2023, 2022 and 2021 (millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS

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Year Ended December 31, 2021

* In 2021 and 2020, 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, 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

The Company funds a portion of its operations through the issuance of long-term debt, and short-term borrowings under its revolving Credit Facility.

The Company’s subsidiaries conduct a portion of their operations in leased facilities and lease some of their machinery, vehicles and office equipment.

Long-Term Debt and Interest Expense

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The long-term debt of Unitil is issued under Unsecured Promissory Notes with negative pledge provisions.

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

Accordingly, in order for Unitil to issue new long-term debt, the covenants of the existing long-term agreement(s) must be satisfied, including that Unitil has total funded indebtedness less than 70 % of total capitalization, and earnings available for interest equal to at least two times the interest charges for funded indebtedness.

Each future senior long-term debt issuance of Unitil will rank pari passu with all other senior unsecured long-term debt issuances.

The Unitil long-term debt agreement requires that if Unitil defaults on any other future long-term debt agreement(s), it would constitute a default under Unitil’s present long-term debt agreement.

Furthermore, the default provisions are triggered by the defaults of certain Unitil subsidiaries or certain other actions against Unitil subsidiaries.

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In order to issue new FMB, the customary covenants of the existing Unitil Energy Indenture Agreement must be met, including that Unitil Energy have sufficient available net bondable plant to issue the securities and earnings available for interest charges equal to at least two times the annual interest requirement.

The Unitil Energy agreements

further require that if Unitil Energy defaults on any Unitil Energy FMB, it would constitute a default for all Unitil Energy FMB.

The Unitil Energy agreements further require that if Unitil Energy defaults on any Unitil Energy FMB, it would constitute a default for all Unitil Energy FMB.

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

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

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

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

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

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

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

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

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

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

As of December 31, 2023, in accordance with the covenants, these subsidiary companies had a combined amount of $ 409.9 million available for the payment of dividends and Unitil Corporation had $ 204.3 million available for the payment of dividends.

As of December 31, 2022, the Company’s balance in Retained Earnings was $ 132.5 million.

Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2022 for the payment of dividends.

Issuance of Long-Term Debt - On December 18, 2020, Unitil Realty Corp.

entered into a loan agreement in the amount of $ 4.7 million at 2.64 %, with a maturity date of December 18, 2030 .

Less than $ 0.1 million of costs associated with this loan have been recorded as a reduction to the proceeds.

Unitil Realty Corp.

used the net proceeds from this loan for general corporate purposes.

On September 15, 2020, Northern Utilities issued $ 40 million of Notes due 2040 at 3.78 %.

Fitchburg issued $ 27.5 million of Notes due 2040 at 3.78 %.

Unitil Energy issued $ 27.5 million of Bonds due 2040 at 3.58 %.

Northern Utilities, Fitchburg and Unitil Energy used the net proceeds from these offerings to repay short-term debt and for general corporate purposes.

Approximately $ 0.5 million of costs associated with these issuances have been recorded as a reduction to Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.

As of December 31, 2023, the Company’s balance in Retained Earnings was $ 151.5 million.

Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2023 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 %.

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.

Debt Repayment - The total aggregate amount of debt repayments relating to bond issues and normal scheduled long-term debt repayments amounted to $ 6.9 million, $ 10.4 million and $ 25.8 million in 2023, 2022, and 2021, respectively.

The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2023 is:

2023 –

2024 – $ 4.9 million;

2024 –

2025 – $ 4.9 million;

2025 –

2026 – $ 37.9 million;

2026 –

2027 – $ 55.7 million;

2027 –

2028 – $ 10.7 million and thereafter $ 403.1 million.

Fair Value of Long-Term Debt - Currently, the Company believes that there is no active market in the Company’s debt securities, which have all been sold through private placements.

If there were an active market for the Company’s debt securities, the fair value of the Company’s long-term debt would be estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities.

The fair value of the Company’s long-term debt is estimated using Level 2 inputs (valuations based on quoted prices available in active markets for similar assets or liabilities, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are directly observable, and inputs derived principally from market data).

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.

Fair Value of Long-Term Debt - Currently, the Company believes that there is no active market in the Company’s debt securities, which have all been sold through private placements.

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.

Estimated Fair Value of Long-Term Debt (millions)

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Unitil Energy First Mortgage Bonds:

8.49 % Senior Secured Notes, Due October 14, 2024

6.96 % Senior Secured Notes, Due September 1, 2028

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7.98 % Senior Notes, Due June 1, 2031

5.70 % Senior Notes, Due July 2, 2033

3.78 % Senior Notes, Due September 15, 2040

4.32 % Senior Notes, Due November 1, 2047

5.96 % Senior Notes, Due July 2, 2053

Northern Utilities:

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(1) The Current Portion of Long-Term Debt includes sinking fund payments.

Interest Expense, Net—

Interest expense is presented in the financial statements net of interest income.

Interest Expense, Net— Interest expense is presented in the financial statements net of interest income.

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.

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

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.

These reconciling rate mechanisms track costs and revenue on a monthly basis.

In any given month, this monthly tracking and reconciling process will produce either an under-collected or an over-collected balance of costs.

accordance with the distribution utilities’

rate tariffs, interest is accrued on these balances and will produce either interest income or interest expense.

In accordance with the distribution utilities’ rate tariffs, interest is accrued on these balances and will produce either interest income or interest expense.

Consistent with regulatory precedent, interest income is recorded on an under-collection of costs, which creates a regulatory asset to be recovered in future periods when rates are reset.

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Short-Term Debt

Regulatory Liabilities

Regulatory Liabilities & Other

Subtotal Interest Expense

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Total Interest Expense, Net

(1) AFUDC—Allowance for Funds Used During Construction

Credit Arrangements

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.

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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.

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The Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants.

There are restrictions on, among other things, Unitil’s and its subsidiaries’

ability to permit liens or incur indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business.

There are restrictions on, among other things, Unitil’s and its subsidiaries’ ability to permit liens or incur

indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business.

The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized).

The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65 %, tested on a quarterly basis .

At December 31, 2023 and December 31, 2022, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.

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The weighted average interest rates on all short-term borrowings were 6.4 %, 3.3 %, and 1.2 % during 2023, 2022, and 2021, respectively.

Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State are currently rated “BBB+”

by Standard & Poor’s Ratings Services.

Unitil Corporation and Granite State are currently rated “Baa2”, and Fitchburg, Unitil Energy and Northern Utilities are currently rated “Baa1”

by Moody’s Investors Services.

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

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

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

There was $ 20.1 million and $ 8.3 million of natural gas storage inventory at December 31, 2022 and 2021, respectively, related to these asset management agreements.

The amount of natural gas inventory released in December 2022, which was payable in January 2023, was $ 3.8 million and was recorded in Accounts Payable at December 31, 2022.

There was $ 10.9 million of natural gas storage inventory and corresponding obligations at December 31, 2023 related to these asset management agreements.

The amount of natural gas inventory released in December 2023, which was payable in January 2024, was $ 2.2 million and was recorded in Accounts Payable at December 31, 2023.

Contractual Obligations

The following table lists the Company’s contractual obligations for long-term debt as of December 31, 2022.

The following table lists the Company’s contractual obligations for long-term debt as of December 31, 2023.

Payments Due by Period

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Interest on Long-Term Debt

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

Total rental expense under operating leases charged to operations for the years ended December 31, 2023, 2022 and 2021 amounted to $ 2.1 million, $ 1.8 million and $ 1.9 million respectively.

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

Lease Obligations (millions)

Operating Lease Obligations:

Other Current Liabilities (current portion)

Other Noncurrent Liabilities (long-term portion)

Operating Lease Obligations (current portion)

Operating Lease Obligations (long-term portion)

Total Operating Lease Obligations

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Cash paid for amounts included in the measurement of operating lease obligations for the twelve months ended December 31, 2023 and 2022 was $ 2.1 million and $ 1.8 million, respectively and was included in Cash Provided by Operating Activities on the Consolidated Statements of Cash Flows.

Assets under capital leases amounted to approximately $ 0.6 million and $ 0.7 million as of December 31, 2022 and 2021, respectively, less accumulated amortization of $ 0.4 million and $ 0.3 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheets.

Assets under capital leases amounted to approximately $ 0.7 million and $ 0.6 million as of December 31, 2023 and 2022, respectively, less accumulated amortization of $ 0.2 million and $ 0.4 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheets.

The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2023.

The payments for operating leases consist of $ 1.5 million of current operating lease obligations, which are included in Other Current Liabilities and $ 2.8 million of noncurrent operating lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2022.

The payments for capital leases consist of $ 0.1 million of current Capital Lease Obligations, which are included in Other Current Liabilities, and $ 0.1 million of noncurrent Capital Lease Obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2022.

Lease Payments ($000’s)

The payments for operating leases consist of $ 1.9 million of current operating lease obligations and $ 3.7 million of noncurrent operating lease obligations on the Company’s Consolidated Balance Sheets as of December 31, 2023.

The payments for capital leases consist of $ 0.1 million of current Capital Lease Obligations, which are included in Other Current Liabilities, and $ 0.4 million of noncurrent Capital Lease Obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2023.

Lease Payments ($000’s)

Year Ending December 31,

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

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

As of December 31, 2022, there were approximately $ 1.2 million of guarantees outstanding with a duration of less than one year.

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

As of December 31, 2023 there were no guarantees outstanding.

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

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

The Company had 16,116,724 and 16,043,355 shares of common stock outstanding at December 31, 2023 and December 31, 2022, respectively.

The Company has 25,000,000 shares of common stock authorized as of December 31, 2023 and December 31, 2022.

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.

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 2022, the Company sold 18,853 shares of its common stock, at an average price of $ 52.18 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $ 1.0 million.

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

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 2023, the Company sold 21,321 shares of its common stock, at an average price of $ 51.58 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $ 1.1 million.

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

During 2022 and 2021, the Company raised $ 1.0 million and $ 1.0 million, respectively, through the issuance of 18,853 and 22,316 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, the Company may periodically repurchase shares of its common stock on the open market related to the stock portion of the Directors’ annual retainer.

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

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During 2023, 2022 and 2021, the Company did not cancel or retire any of its common stock.

Stock-Based Compensation Plans—

Unitil maintains a stock-based compensation plan.

Stock-Based Compensation Plans— Unitil maintains a stock-based compensation plan.

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 Second Amended and Restated 2003 Stock Plan (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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construe and interpret the Stock Plan and any agreement or instrument entered into under the Stock Plan as they apply to participants;

establish, amend, or waive rules and regulations for the Stock Plan’s administration as they apply to participants;

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 .

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

In the event of certain changes in capitalization of the Company, the Compensation Committee is authorized to make an equitable adjustment to the number and kind of shares of common stock that may be delivered under the Stock Plan and, in addition, may authorize and make an equitable adjustment to the Stock Plan’s annual individual award limit.

Time Restricted Shares

Outstanding awards of Time Restricted Shares fully vest over a period of four years at a rate of 25 % each year.

During the vesting period, dividends on Time Restricted Shares underlying the award may be credited to a participant’s account.

The Company may deduct or withhold, or require a participant to remit to the Company, an amount sufficient to satisfy any taxes required by federal, state, or local law or regulation to be withheld with respect to any taxable event arising in connection with an award.

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 2020 –

2022 in conjunction with the Stock Plan are presented in the following table:

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

Issuance Date

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At December 31, 2023, there was approximately $ 0.7 million of total unrecognized compensation cost for Time Restricted Shares under the Stock Plan which is expected to be recognized over approximately 2.2 years.

There were 270 Time Restricted Shares forfeited and zero Time Restricted Shares cancelled under the Stock Plan during 2022.

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

On January 30, 2024, there were 22,680 Time Restricted Shares issued under the Stock Plan with an aggregate market value of $ 1.1 million.

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if goals are not met, a portion of the Performance Restricted Shares may vest and/or all or a portion of the Performance Restricted Shares may be forfeited.

During the performance period, dividends on Performance Restricted Shares underlying the award may be credited to a participant’s account.

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

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

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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.

Issuance Date

Market Value (millions)

There were 18,770 non-vested Performance Restricted Shares under the Stock Plan as of December 31, 2023.

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.

At December 31, 2023, there was approximately $ 0.9 million of total unrecognized compensation cost for Performance Restricted Shares under the Stock Plan which is expected to be recognized over approximately 2.0 years.

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

On January 30, 2024, there were 22,680 Performance Restricted Shares issued under the Stock Plan with an aggregate market value of $ 1.1 million.

Restricted Stock Units

Restricted Stock Units, which are issued to members of the Company’s Board of Directors, earn dividend equivalents and will generally be settled by payment to each Director as soon as practicable following the Director’s separation from service to the Company.

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

The equity portion of Restricted Stock Units activity during 2023 and 2022 in conjunction with the Stock Plan are presented in the following table:

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Ending Restricted Stock Units

Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2022 and 2021 include $ 1.0 million and $ 1.0 million, respectively, representing the fair value of liabilities associated with the portion of fully vested RSUs that will be settled in cash.

Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2023 and 2022 include $ 0.8 million and $ 1.0 million, respectively, representing the fair value of liabilities associated with the portion of fully vested RSUs that will be settled in cash.

Preferred Stock

There were $ 0.2 million, or 1,861 shares, of Unitil Energy’s 6.00 % Series Preferred Stock outstanding as of December 31, 2022 and December 31, 2021.

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 less than $ 0.1 million of total dividends declared on Preferred Stock in each of the twelve month periods ended December 31, 2023 and December 31, 2022, respectively.

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Earnings Available to Common Shareholders

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

Diluted Effect of Incremental Shares (000’s)

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

Earnings per Share—Basic and Diluted

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

Diluted Effect of Incremental Shares (000’s)

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

Earnings per Share—Basic and Diluted

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

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ELECTRIC POWER SUPPLY

Fitchburg, Unitil Energy, and Unitil Power each are members of the New England Power Pool (NEPOOL) and participate in the Independent System Operator—New England (ISO-NE) markets for the purpose of facilitating wholesale electric power supply transactions, which are necessary to serve Unitil’s electric customers with their supply of electricity.

Unitil’s customers in both New Hampshire and Massachusetts are entitled to purchase their electric supply from competitive third-party suppliers.

As of December 2022, 80% of Unitil’s largest New Hampshire customers, representing 24% of Unitil’s New Hampshire electric kilowatt-hour (kWh) sales, and 86% of Unitil’s largest Massachusetts customers, representing 34% 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 have active municipal aggregations.

Customers in Lunenburg comprise about 17% of Fitchburg’s customer base, and customers in Ashby comprise another 4%.

On December 31, 2020, the city of Fitchburg filed with the MDPU for approval of its Aggregation Plan.

The aggregation is expected to be implemented in March 2023.

Customers located in the city of Fitchburg comprise about 69% of Fitchburg’s sales.

Most residential and small commercial customers continue to purchase their electric supply through Unitil’s electric distribution utilities under regulated energy rates and tariffs.

As of December 2022, 28% of Unitil’s residential customers in Massachusetts purchased their electricity from a third-party supplier, up 1% from December 2021.

In New Hampshire, the percentage of residential customers purchasing electricity from a third-party supplier in 2022 was 9% which is an increase of 1% from December 2021.

Municipal aggregation is now provided for in New Hampshire, but no aggregations have begun in Unitil Energy’s service area.

Unitil’s customers in both New Hampshire and Massachusetts are entitled to purchase their electric supply from competitive third-party suppliers.

As of December 2023, 88% of Unitil’s largest New Hampshire customers, representing 26% of Unitil’s New Hampshire electric kilowatt-hour (kWh) sales, and 97% of Unitil’s largest Massachusetts customers, representing 35% 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.

Regulated Electric Power Supply

To provide regulated electric supply service to their customers, Unitil’s electric distribution utilities enter into load-following wholesale electric power supply contracts to purchase electric supply from various wholesale suppliers.

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

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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.

Starting in 2021, the impending City of Fitchburg municipal aggregation limited Fitchburg’s ability to purchase Basic Service supply from wholesale suppliers for terms longer than six months for residential and small commercial customers.

As a result of uncertainty around the timing of the Fitchburg aggregation launch as well as energy price volatility, Fitchburg received no supply offers in its most recent solicitation, conducted in late 2022.

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

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

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

Regional Electric Transmission and Power Markets

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

Northern Utilities’

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

Many of Northern Utilities’

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

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

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

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

As of December 2022, 73% of Unitil’s largest New Hampshire gas customers, representing 38% of Unitil’s New Hampshire gas therm sales, and 54% of Unitil’s largest Maine customers, representing 23% of Unitil’s Maine gas therm sales, purchased their gas supply from a third-party supplier.

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

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

Most of Fitchburg’s residential and small C&I customers continue to purchase their supplies at regulated rates from Fitchburg.

As of December 2022, 70% of Unitil’s largest Massachusetts gas customers, representing 28% of Unitil’s

Massachusetts gas therm sales, purchased their gas supply from third-party suppliers.

As of December 2023, 75% of Unitil’s largest New Hampshire gas customers, representing 40% of Unitil’s New Hampshire gas therm sales, and 59% of Unitil’s largest Maine customers, representing 21% of Unitil’s Maine gas therm sales, purchased their gas supply from a third-party supplier.

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

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

Most of Fitchburg’s residential and small C&I customers continue to purchase their supplies at regulated rates from Fitchburg.

As of December 2023, 77% of Unitil’s largest Massachusetts gas customers, representing 29% of Unitil’s Massachusetts gas therm sales, purchased their gas supply from third-party suppliers.

The approved costs associated with natural gas supplied to customers who do not contract with third-party suppliers are recovered on a pass-through basis through periodically adjusted rates, and are included in Cost of Gas Sales in the Consolidated Statements of Earnings.

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

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

service territory.

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

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Fitchburg purchases natural gas under contracts from producers and marketers largely under contracts of one year or less, and occasionally on the spot market.

Fitchburg arranges for gas transportation and delivery to its system through its own long-term contracts with Tennessee Gas Pipeline, through peaking supply contracts delivered to its system, or in the case of LNG or liquefied propane gas (LPG), via trucking of supplies to storage facilities within Fitchburg’s service territory.

Fitchburg has available under firm contract 14,439 MMBtu per day of year-round transportation and 0.4 BCF of underground storage capacity to its distribution facilities.

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Regulatory Matters

Overview—

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

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

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

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.

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.

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

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Rate Case Activity

Northern Utilities - Base Rates - Maine - On March 26, 2020, the MPUC approved an increase to base revenue of $ 3.6 million, a 3.6 % increase over the Company’s test year operating revenues, effective April 1, 2020.

The order approved a Return on Equity of 9.48 %, and a hypothetical capital structure of 50 % equity and 50 % debt.

As part of the order and increase in base revenue, the MPUC provided for recovery of some, but not all, of the Company’s implementation costs associated with its customer information system pending the completion of an investigation, including a third-party audit.

On March 9, 2021, the MPUC opened a new docket to investigate the amount of customer information system costs that will be allowed in rates.

On January 27, 2022, the Company and the Maine Office of the Public Advocate filed a stipulation in this docket.

The stipulation includes no finding of imprudence or asset disallowance.

The terms of the stipulation provide for recovery of the revenue

requirement related to the Company’s customer information system in base rates starting November 1, 2022, which coincides with the timing of the Company’s winter cost of gas rate change.

On February 9, 2022, the MPUC approved the stipulation.

On September 30, 2022, the Company filed revised distribution rates to recover the annual revenue requirement of $ 0.6 million for effect November 1, 2022.

Northern Utilities - Targeted Infrastructure Replacement Adjustment (TIRA) - Maine - The settlement in Northern Utilities’

Maine division’s 2013 rate case authorized the Company to implement a TIRA rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects, including the Company’s Cast Iron Replacement Program (CIRP).

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 $ 1.5 million for 2021 eligible facilities, was filed with the MPUC on February 28, 2022.

Northern Utilities - Base Rates - Maine - On September 20, 2023, the MPUC issued an order approving a Stipulation filed on August 31, 2023, between Northern Utilities and the Office of the Public Advocate which resolved all matters in the base rate filing made by Northern Utilities with the MPUC on May 1, 2023.

The order approves an increase in distribution revenues of $ 7.6 million effective October 1, 2023.

The order reflects a return on equity of 9.35 %, an equity ratio of 52.01 %, and a weighted average cost of capital of 7.22 %.

Northern Utilities - Targeted Infrastructure Replacement Adjustment (TIRA) - Maine - The settlement in Northern Utilities’ Maine division’s 2013 rate case authorized the Company to implement a TIRA rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects, including the Company’s Cast Iron Replacement Program (CIRP).

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.

On April 26, 2023, the MPUC issued an order approving the filing, for rates effective May 1, 2023.

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

The Order approves a comprehensive Settlement Agreement between the Company, the New Hampshire Department of Energy (DOE), and the Office of the Consumer Advocate (OCA).

As provided in the Settlement Agreement, in addition to authorizing an increase to permanent distribution rates of $ 6.1 million, effective August 1, 2022, the Order (1) approves a revenue decoupling mechanism and (2) allows for a step adjustment effective September 1, 2022 covering the additional revenue requirement resulting from changes in Net Plant in Service associated with non-growth investments for the period January 1, 2021, through December 31, 2021.

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

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

The Order approved a comprehensive Settlement Agreement between the Company, the New Hampshire Department of Energy (DOE), and the Office of the Consumer Advocate (OCA).

As provided in the Settlement Agreement, in addition to authorizing an increase to permanent distribution rates of $ 6.1 million, effective August 1, 2022, the Order (1) approved a revenue decoupling mechanism and (2) allowed for a step adjustment effective September 1, 2022 covering the additional revenue requirement resulting from changes in Net Plant in Service associated with non-growth investments for the period January 1, 2021, through December 31, 2021.

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

The Order provided for a return on equity of 9.3 % 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 .

On June 8, 2022, the Company filed for its step increase of approximately $ 1.6 million of annual revenue, for rates effective as of September 1, 2022, to recover eligible 2021 capital investments.

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

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

On June 8, 2022, the Company filed for its step increase of approximately $ 1.6 million of annual revenue, for rates effective as of September 1, 2022, to recover eligible 2021 capital investments.

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.

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

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

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

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

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

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

(1) a multi-year rate plan, (2) a revenue decoupling mechanism, (3) time-of-use rates, (4) resiliency programs to support the Company’s commitment to

reliability, and (5) other rate design and tariff changes.

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

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

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

The Order provides 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, subject to reconciliation, the Company’s first step increase of approximately $ 1.3 million of annual revenue to recover eligible 2021 capital investments, effective August 1, 2022.

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

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

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

On July 28, 2022, the NHPUC approved the Company’s first step increase of approximately $ 1.3 million of annual revenue to recover eligible 2021 capital investments, effective August 1, 2022.

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

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

On November 2, 2021, Fitchburg filed its cumulative revenue requirement of $ 1.6 million associated with its 2019 and 2020 capital expenditures.

The MDPU allowed the associated rate increase to become effective on January 1, 2022, subject to further investigation and reconciliation.

On June 24, 2022, the MDPU issued an Order approving the Company’s filing.

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 April 17, 2020, the MDPU approved a settlement agreement entered into by the Company and the Massachusetts Office of the Attorney General providing for a distribution increase of $ 1.1 million, effective November 1, 2020.

The Company’s subsequent Compliance Filing reflected an adjusted distribution increase of $ 0.9 million, a decrease of $ 0.2 million from the original settlement amount due to the finalization of actual rate case expenses.

On May 21, 2020, the MDPU approved the Company’s Compliance Filing.

The agreement provides for a Return on Equity of 9.7 % and a capital structure reflecting 52.45 % equity and 47.55 % long-term debt.

Under the agreement, the Company will not increase or redesign base distribution rates to become effective prior to November 1, 2023, though the Company may seek cost recovery for certain exogenous events that meet a revenue threshold of $ 0.1 million.

The agreement also provides for the implementation of a major storm reserve fund, whereby the Company may recover the costs of restoration for qualifying storm events.

In addition, the agreement provides for the extension of the annual capital cost recovery mechanism, modified to allow the recovery of property tax on the cumulative net capital expenditures.

On September 22, 2022, Fitchburg filed a petition with the MDPU to adjust its base distribution rates by $ 0.7 million effective January 1, 2023 to recover costs due to the exogenous event described below.

The filing also includes a request to recover the exogenous costs incurred from July 2021 through December 2022 through a reconciling mechanism over a 24 month period, beginning January 1, 2023.

The Massachusetts Department of Revenue has determined that the “net book value”

or “NBV”

of utility plant is no longer the basis of valuation for utility property.

Most of the municipalities that levy property taxes on Fitchburg have adopted a hybrid valuation approach that increases property tax expense over and above what it would be if NBV was used as the basis of valuation.

The change in valuation is a regulatory change that is outside the Company’s control and it uniquely affects the electric and gas industries, thus it is an exogenous event.

On December 30, 2022, the MDPU approved the Company’s request to adjust its base distribution rates effective January 1, 2023 and to recover deferred costs of $ 1.1 million incurred from July 2021 through December 2022 through a reconciling mechanism over a 24 month period, also beginning January 1, 2023.

Fitchburg - Base Rates - Gas - Pursuant to its revenue decoupling adjustment clause tariff, as approved in its last base rate case, the Company is allowed to modify, on a semi-annual basis, its base distribution rates to an established revenue per customer target in order to mitigate economic, weather, and energy efficiency effects to the Company’s revenues.

The MDPU consistently has found the Company’s filings are in accord with its approved tariffs, applicable law and precedent, and that they result in just and reasonable rates.

On February 28, 2020, the MDPU approved a settlement agreement between the Company and the Massachusetts Office of the Attorney General.

The agreement provides for an annual distribution revenue increase of $ 4.6 million to be phased in over two years :

(1) an increase of $ 3.7 million, which became effective on March 1, 2020;

and (2) an increase of $ 0.9 million, which became effective on March 1, 2021.

Under the agreement, the Company will not increase or redesign base distribution rates to become effective prior to March 1, 2023, though the Company may seek cost recovery for certain exogenous events that meet a revenue effect threshold of $ 40,000 .

The agreement provides for a Return on Equity of 9.7 % and a capital structure reflecting 52.45 % equity and 47.55 % long-term debt.

In its September 22, 2022 exogenous cost filing as discussed above, the Company also requested to adjust its gas base distribution rates by $ 0.7 million effective March 1, 2023 to recover these exogenous costs.

The filing also includes a request to recover the exogenous costs incurred from July 2021 through February 2023 through a reconciling mechanism over a 24 month period, beginning March 1, 2023.

On December 30, 2022, the MDPU approved the Company’s request to adjust its base distribution rates effective March 1, 2023 and to recover deferred costs of $ 1.2 million incurred from July 2021 through February 2023 through a reconciling mechanism over a 24 month period, also beginning March 1, 2023.

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.

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.

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.

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

Fitchburg’s forward-looking cumulative revenue requirement filing submitted on October 29, 2021 requested recovery of approximately $ 3.3 million, and received final approval on April 28, 2022, effective May 1, 2022.

The Company’s most recent forward-looking

cumulative revenue requirement filing, filed on October 31, 2022, requested recovery of approximately $ 4.5 million.

Fitchburg’s forward-looking cumulative revenue requirement filing submitted on October 31, 2022 requested recovery of approximately $ 4.5 million, and received final approval on April 28, 2023, effective May 1, 2023.

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 provides for an increase in annual revenues of approximately $ 1.3 million, effective November 1, 2020.

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

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

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

Other Matters

Unitil Energy - Proposal to Construct Utility-Scale Solar Facility 

- On October 31, 2022, Unitil Energy submitted a petition to the NHPUC for review of Unitil Energy’s proposal to construct, own, and operate a 4.99 MW utility-scale photovoltaic generating facility.

The Company has requested a finding from the NHPUC within six months of the filing date that the project, as proposed, is in the public interest.

This matter is subject to review by the NHPUC and remains pending.

Unitil Energy - Proposal to Construct Utility-Scale Solar Facility - On October 31, 2022, Unitil Energy submitted a petition to the NHPUC for review of Unitil Energy’s proposal to construct, own, and operate a 4.99 MW utility-scale photovoltaic generating facility, which was subsequently revised to a 4.88 MW facility.

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

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

The GMP includes a five-year strategic plan, including a plan for the full deployment of advanced metering functionality, and a four-year short-term investment plan, which focuses on foundational investments to facilitate the interconnection and integration of distributed energy resources, optimizing system performance through command and control and self-healing measures, and optimizing system demand by facilitating consumer price-responsiveness.

On October 7, 2022, the MDPU issued a “Track 1”

Order approving a budget cap of $ 9.3 million through 2025 for previously deployed or preauthorized grid modernization investments.

On November 30, 2022, the MDPU issued its “Track 2”

Order addressing new technologies and Advanced Metering Infrastructure (AMI) proposals.

The MDPU preauthorizes a four-year $ 1.5 million budget for Fitchburg’s additional grid-facing investments.

On October 7, 2022, the MDPU issued a “Track 1” Order approving a budget cap of $ 9.3 million through 2025 for previously deployed or preauthorized grid modernization investments.

On November 30, 2022, the MDPU issued its “Track 2” Order addressing new technologies and Advanced Metering Infrastructure (AMI) proposals.

The MDPU preauthorizes a four-year $ 1.5 million budget for Fitchburg’s additional grid-facing investments.

Any spending over the total budget cap is not eligible for targeted cost recovery through its Grid Modernization Factor (GMF), and instead, may be recovered by the Company in a base distribution rate proceeding subsequent to a prudency finding by the MDPU in a GMF filing or term review Order.

The MDPU also preauthorized the Company’s AMI meter replacement investments, with a budget of $ 11.2 million through 2025.

Additionally, the MDPU provided preliminary approval for the Company’s customer engagement and experience and data sharing platform investments, with a combined budget of $ 2.3 million through 2025.

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

The MDPU also directed the Company to submit a proposed AMI opt-out tariff with full support for any proposed opt-out fees as a compliance filing by April 1, 2023.

On September 7, 2022, in docket DPU 15-121, the MDPU directed the electric distribution companies (EDCs) to apply a protocol for identifying and tracking incremental grid modernization O&M expense for recovery through the GMFs.

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 MDPU also preauthorized the Company’s AMI meter replacement investments, with a budget of $ 11.2 million through 2025.

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

The MDPU approved the tariff on April 7, 2023.

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

Among other things, the Company explained a modification to its implementation of the AMI plan that the Department 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.

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 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.

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

The matter remains pending.

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

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

The LDCs, including Fitchburg, engaged an independent consultant to conduct a study and prepare a report (Consultant Report), including a detailed study of each LDC, that analyzes the feasibility of all identified pathways to help the

Commonwealth achieve its net-zero GHG goal.

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 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.

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.

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:

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.

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.

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.

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.

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 Council provided recommendations on the ESMP in November 2023.

The Company submitted its final ESMP to the MDPU on January 29, 2024.

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.

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:

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

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

The Company may shift spending between program segments and between years over the five-year term of its program, subject to a 15 percent cap.

Any spending above the approved EV program budget or above the 15 percent 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 will convene an EV stakeholder process to finalize EV program performance metrics.

The Company may shift spending between program segments and between years over the five-year term of its program, subject to a 15% cap.

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.

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

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 with tiered rates to separately-metered EV general delivery service customers.

Finally, the MDPU accepted the Company’s proposed residential EV TOU rate.

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 territories.

Granite State facilitates critical upstream interconnections with interstate pipelines and third party suppliers essential to Northern Utilities’

service to its customers.

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.

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

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

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

Granite State facilitates critical upstream interconnections with interstate pipelines and third party suppliers essential to Northern Utilities’ service to its customers.

Northern Utilities reserves firm capacity through a contract with Granite State, which is renewed annually.

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

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 costs and revenues, and to seek approval of any rate changes.

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.

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.

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.

These filings include:

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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;

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

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

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

Under Section 83D of the Act, the EDCs are required to jointly seek proposals for cost-effective clean energy (hydroelectric, solar and land-based wind) long-term contracts via one or more staggered solicitations for a total of 9,450,000 megawatt-hours (MWh) by December 31, 2022.

Fitchburg’s pro rata share of these contracts is approximately 1%.

The EDCs issued the RFP for Section 83D Long-Term Contracts in March 2017, and power purchase agreements (PPAs) for 9,554,940 MWh of hydroelectric generation and associated environmental attributes from Hydro-Quebec Energy

Services (U.S.), Inc.

Fitchburg’s pro rata share of these contracts is approximately 1%.

were filed in July 2018 for approval by the MDPU.

On June 25, 2019, the MDPU approved the PPAs, including the EDCs’

proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market costs to customers.

The MDPU also approved the EDCs’

request for remuneration equal to 2.75 % of the contract payments, as well as the EDCs’

proposal to recover costs associated with the contracts.

On June 25, 2019, the MDPU approved the PPAs, including the EDCs’ proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market revenue to customers.

The MDPU also approved the EDCs’ request for remuneration equal to 2.75 % of the contract payments, as well as the EDCs’ proposal to recover costs associated with the contracts.

On January 13, 2023, NECEC Transmission LLC (NECEC), the company with which Fitchburg and the other EDCs entered into transmission service agreements (TSAs) for the delivery of the Hydro-Quebec energy, provided a letter to the EDCs purporting to give notice of a “change in applicable law” related to a Maine ballot initiative and requesting a negotiated amendment to the TSAs including a price adjustment.

On June 27, 2023, NECEC sent a letter to the EDCs seeking schedule relief also in accordance with their “change in law” determination.

The EDCs are evaluating NECEC’s requests.

The EDCs issued an initial RFP pursuant to Section 83C in June 2017.

On July 23, 2018, the EDCs, filed two long-term contracts with Vineyard Wind, each for 400 MW of offshore wind energy generation, for approval by the MDPU.

On April 12, 2019, the MDPU approved the offshore wind energy generation PPAs, including the EDCs’

proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market costs to customers.

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, each for 400 MW of offshore wind energy generation, in February 10, 2020.

On November 5, 2020, the MDPU approved the second RFP PPAs.

In both cases, the MDPU approved the EDCs’

request for remuneration equal to 2.75 % of the contract payments, as well as the EDCs’

proposal to recover costs associated with the contracts.

In 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.

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.

On November 5, 2020, the MDPU approved the PPAs.

In both cases, the MDPU approved the EDCs’ request for remuneration equal to 2.75 % of the contract payments, as well as the EDCs’ proposal to recover costs associated with the contracts.

In April 2023, SouthCoast Wind engaged with the EDCs to explore options to mitigate impacts of global resource constraints and pricing challenges associated with the PPAs from this procurement.

They cited an inability to finance the project within the terms set out in the PPA.

The EDCs negotiated a termination agreement with SouthCoast Wind which was filed with the MDPU for approval on August 28, 2023 and which received approval on September 30, 2023.

In accordance with “An Act to Advance Clean Energy” (2018) the Massachusetts Department of Energy Resources (DOER) recommended that the EDCs solicit up to 1,600 MW in additional offshore wind in 2022 and 2024.

On May 7, 2021, the EDCs issued a third RFP for up to an additional 1,600 MW of off shore wind generation.

On May 25, 2022, the EDCs sought approval of PPAs with Commonwealth Wind for 1,200 MW and with Mayflower Wind for 400 MW.

On May 25, 2022, the EDCs sought approval of PPAs with Commonwealth Wind for 1,200 MW and with SouthCoast Wind for 400 MW.

On December 16, 2022, Commonwealth Wind filed a motion requesting that the MDPU dismiss proceedings related to the approval of its contract, arguing that, due to various economic conditions, its contracts with the EDCs would no longer facilitate the financing of offshore wind energy generation.

On December 30, 2022, the MDPU denied Commonwealth’s motion and approved the PPAs.

The MDPU also approved the EDCs’

request for remuneration equal to 2.25 % as reasonable and in the public interest.

On January 19, 2023, Commonwealth Wind filed a Petition for Appeal with the Massachusetts Supreme Judicial Court seeking to set aside and vacate the MDPU’s Order approving the PPAs.

On the same day, Mayflower Wind submitted a motion to the MDPU requesting that it extend the period for filing an appeal (which otherwise expired on January 19, 2023) by five business days from the date that the motion is approved.

The appeal and the motion are pending.

On December 30, 2022, the MDPU denied Commonwealth’s motion and approved the PPAs.

The MDPU also approved the EDCs’ request for remuneration equal to 2.25 % as reasonable and in the public interest.

On January 19, 2023, Commonwealth Wind filed a Petition for Appeal with the Massachusetts Supreme Judicial Court 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 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.

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.

an additional 2,400 MW of offshore wind capacity remains to be procured in the future.

The next RFP for offshore wind is expected to be released in May 2023 for at least 400 MW and up to 2,400 MW of additional offshore wind capacity.

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.

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, the EDCs shall enter into cost-effective long-term contracts.

On October 26, 2022, the Maine PUC 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 determination that the selected projects would have benefits to Massachusetts and the region.

Pursuant to Section 82, Massachusetts EDCs shall enter into cost-effective long-term contracts with a maximum term of twenty years upon such a finding by the DOER.

Fitchburg is in the process of evaluating potential contractual commitments under Section 82.

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.

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.

Participating Transmission Owners’

(PTOs) Regional Network Service and Local Network Service formula rates.

Participating Transmission Owners’ (PTOs) Regional Network Service and Local Network Service formula rates.

In August 2013, FERC had found that the Transmission Owners existing ROE was unlawful, and set a new ROE.

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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.

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

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This matter remains pending.

The Company does not believe these proceedings will have a material adverse effect on its financial condition or results of operations.

Contractual Obligations

The following table lists the Company’s known specified gas and electric supply contractual obligations as of December 31, 2022.

The following table lists the Company’s known specified gas and electric supply contractual obligations as of December 31, 2023.

Payments Due by Period

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Environmental Matters

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

The Company is in material compliance with applicable environmental and safety laws and regulations and, as of December 31, 2023, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts.

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It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.

Based on its current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, the Company does not believe that these environmental costs will have a material adverse effect on the Company’s consolidated financial position or results of operations.

Northern Utilities Manufactured Gas Plant Sites - Northern Utilities has an extensive program to identify, investigate and remediate former manufactured gas plant (MGP) sites, which were operated from the mid-1800s through the mid-1900s.

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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.

Company submitted the studies and RAP to the NH DES in December 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 a ccrued $ 2.5 million for estimated costs to complete the remediation at the Rochester site, which is included in Environmental Obligations.

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.

Northern Utilities anticipates the commencement of remediation activities in 2024.

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

Maine division, the MPUC has authorized the recovery of environmental remediation costs over succeeding five-year periods.

The Environmental Obligations table shows the amounts accrued for Northern Utilities related to estimated future cleanup costs associated with Northern Utilities’

environmental remediation obligations for former MGP sites.

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.

The Environmental Obligations table includes amounts accrued for Northern Utilities related to estimated future cleanup costs associated with Northern Utilities’ environmental remediation obligations for former MGP sites.

Corresponding Regulatory Assets were recorded to reflect that the future recovery of these environmental remediation costs is expected based on regulatory precedent and established practices.

Fitchburg’s Manufactured Gas Plant Site - Fitchburg has worked with the Massachusetts Department of Environmental Protection (Mass DEP) to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring continues.

In April 2020, Fitchburg received notification from the Massachusetts Department of Transportation (Mass DOT) that a portion of the site may be incorporated into the proposed Twin City Rail Trail with an anticipated completion date in 2024.

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 FGE following a November 2020 audit of the September 2015 Response Action Outcome on the MGP site.

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.

FGE 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, and FGE anticipates a limited remediation effort associated with the seep in 2023.

The Company does not believe this investigation will have a material adverse effect on its financial condition, results of operations or cash flows.

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.

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 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.

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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 anticipates submitting a report to the NH DES in the first quarter of 2023.

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.

The Company does not believe this investigation will have a material adverse effect on its financial condition, results of operations or cash flows.

The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the years-ended December 31, 2022 and 2021.

The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the years-ended December 31, 2023 and 2022.

Environmental Obligations (millions)

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Total Income Tax Expense

The differences between the Company’s provisions for Income Taxes and the provisions calculated at the statutory federal tax rate, expressed in percentages, are shown in the following table:

Statutory Federal Income Tax Rate

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Net Deferred Tax Liabilities

Under the Company’s Tax Sharing Agreement (the Agreement) which was approved upon the formation of Unitil as a public utility holding company, the Company files consolidated Federal and State tax returns and Unitil Corporation and each of its utility operating subsidiaries recognize the results of their operations in its tax returns as if it were a stand-alone taxpayer.

The Agreement provides that the Company will account for income taxes in compliance with U.S.

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Income tax filings for the year ended December 31, 2022 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, 2021 which were filed with the IRS in October 2022, the Company utilized

federal Net Operating Loss Carryforward (NOLC) assets of $ 2.4 million.

As of December 31, 2022, the Company recognized the utilization of approximately $ 2.8 million of the NOLC asset to offset current taxes payable.

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.

As of December 31, 2023, the Company recognized the utilization of approximately $ 4.4 million of the NOLC asset and $ 1.7 million of federal tax credits available to offset current taxes payable.

In addition, at December 31, 2023, the Company had $ 1.3 million of cumulative state tax credit carryforwards to offset future income taxes payable.

If unused, the Company’s state tax credit carryforwards will begin to expire in 2027.

In March 2020, the Coronavirus Aid, Relief and Economic Security (CARES) Act was signed into law.

The CARES Act included several tax changes as part of its economic package.

These changes principally related to expanded Net Operating Loss carryback periods, increases to interest deductibility limitations, and accelerated Alternative Minimum Tax refunds.

The Company has evaluated these items and determined that the items do not have a material effect on the Company’s financial statements as of December 31, 2021.

Additionally, the CARES Act enacted the Employee Retention Credit (ERC) to incentivize companies to retain employees.

The ERC is a 50 % credit on employee wages for employees that are retained and cannot perform their job duties at 100 % capacity as a result of coronavirus pandemic restrictions.

In December 2020, the Consolidated Appropriations Act, 2021 (CAA) was signed into law.

The CAA included additional funding through tax credits as part of its economic package for 2021.

These changes include the temporary removal of deduction limitations on business meals through December 2022 and additional funding for the ERC with expanded benefits extended through June 30, 2021.

The expanded ERC is a 70 % credit on employee wages for employees that are retained and cannot perform their job duties at 100 % capacity as a result of coronavirus pandemic restrictions.

In March 2021, the American Rescue Plan Act of 2021 (ARPA) was signed into law.

The ARPA included certain provisions that provide economic relief for the ongoing COVID-19 pandemic, such as extending the ERC through December 31, 2021, and other future governmental revenue producing provisions, such as expanding the scope for deduction limitations on executive compensation in future years.

If unused, the Company’s state tax credit carryforwards will begin to expire in 2027.

On April 14, 2023, the IRS issued Revenue Procedure 2023-15 that provides a safe harbor method of accounting that taxpayers may use to determine whether to deduct or capitalize expenditures to repair, maintain, replace, or improve natural gas transmission and distribution property.

Under the revenue procedure, the method of accounting will depend on the property’s classification as linear transmission property, linear distribution property, or non-linear property.

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.

In August 2022, the Inflation Reduction Act of 2022 (IRA) was signed into law.

The IRA included new taxes on corporations, including the Corporate Alternative Minimum Tax (AMT) and the Excise Tax on Repurchase of Corporate Stock.

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

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

The IRA also extended and modified certain renewable energy related credits.

The Company has evaluated each of the CARES, CAA, ARPA and IRA provisions and determined that they do not have a material effect on the Company’s financial statements as of December 31, 2022.

The Company has recorded a reduction in payroll taxes related to the ERC for $ 0.4 million in 2021 and $ 0.6 million in 2020.

These credits were recorded as a reduction to payroll tax expense which is recorded in Taxes Other Than Income Taxes in the Consolidated Statements of Earnings.

The Company has evaluated the IRA provisions and determined that they do not have a material effect on the Company’s financial statements as of December 31, 2023.

In December 2017, the Tax Cuts and Jobs Act (TCJA), which included a reduction of the corporate federal income tax rate to 21 % effective January 1, 2018, was signed into law.

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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 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 Company sponsors the following retirement benefit plans to provide certain pension and post-retirement benefits for its retirees and current employees as follows:

The Unitil Corporation Retirement Plan (Pension Plan)—The Pension Plan is a defined benefit pension plan.

Under the Pension Plan, retirement benefits are based upon an employee’s level of compensation and length of service.

• The Unitil Corporation Retirement Plan (Pension Plan)—The Pension Plan is a defined benefit pension plan.

Under the Pension Plan, retirement benefits are based upon an employee’s level of compensation and length of service.

Effective January 1, 2010, the Pension Plan was closed to new non-union employees.

For union employees, the Pension Plan was closed on various dates between December 31, 2010 and June 1, 2013, depending on the various Collective Bargaining Agreements of each union.

The Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan)—The PBOP Plan provides health care and life insurance benefits to retirees.

• The Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan)—The PBOP Plan provides health care and life insurance benefits to retirees.

The Company has established Voluntary Employee Benefit Trusts, into which it funds contributions to the PBOP Plan.

The Unitil Corporation Supplemental Executive Retirement Plan (SERP)—The SERP is a non-qualified retirement plan, with participation limited to executives selected by the Board of Directors.

The following table includes the key assumptions used in determining the Company’s benefit plan costs and obligations:

• The Unitil Corporation Supplemental Executive Retirement Plan (SERP)—The SERP is a non-qualified retirement plan, with participation limited to executives selected by the Board of Directors.

The following table includes the key assumptions used in determining the Company’s benefit plan costs and obligations:

Used to Determine Plan costs for years ended December 31:

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Expected Long-term rate of return on plan assets

Health Care Cost Trend Rate Assumed for Next Year

Ultimate Health Care Cost Trend Rate

Year that Ultimate Health Care Cost Trend Rate is reached

Used to Determine Benefit Obligations at December 31:

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Rate of Compensation Increase

The health care cost trend rate used to determine plan costs for 2023 for pre-65 retirees is 8.00 %, with an ultimate rate of 4.50 % in 2030 , and for post-65 retirees, the health care cost trend rate is 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 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 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, 2022 for pre-65 retirees is 8.00 %, with an ultimate rate of 4.50 % in 2030 , and for post-65 retirees, the health care cost trend rate is 6.25 %, with an ultimate rate of 4.50 % in 2030 .

The health care cost trend rate used to determine benefit obligations at December 31, 2021 for both pre-65 and post-65 retirees is 6.20 %, with an ultimate rate 4.50 % in 2029 .

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The Rate of Compensation Increase assumption used for 2023 was based on the expected long-term increase in compensation costs for personnel covered by the plans.

The following table provides the components of the Company’s Retirement plan costs (000’s):

Interest Cost

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Since the market-related value of assets recognizes gains or losses over a three-year period, the future value of the market-related assets will be affected as previously deferred gains or losses are recognized.

The Company’s pension expense for the years 2022, 2021 and 2020 before capitalization and deferral was $ 3.6 million, $ 7.2 million and $ 6.9 million, respectively.

Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2023, 2022 and 2021 would have been $ 2.8 million, $ 2.4 million and $ 6.1 million respectively, prior to amounts capitalized or deferred.

The following table represents information on the plans’

assets, projected benefit obligations (PBO), and funded status (000’s):

The following table represents information on the plans’ assets, projected benefit obligations (PBO), and funded status (000’s):

Change in Plan Assets:

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Assets vs PBO

The decrease in the PBO for the Pension, PBOP and SERP plans as of December 31, 2022 compared to December 31, 2021 primarily reflects an increase in the assumed discount rate as of December 31, 2022.

Additionally, as of the end of 2022, the Company changed from a Medicare Supplement plan to a Medicare Advantage plan, which resulted in a significant reduction in the PBO for the PBOP plan as of December 31, 2022.

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 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.

Because the Company recovers the retiree benefit costs from customers through rates, regulatory assets are recorded in lieu of an adjustment to Accumulated Other Comprehensive Income/(Loss).

The Company has recorded on its consolidated balance sheets as a liability the underfunded status of its and its subsidiaries’

retirement benefit obligations based on the projected benefit obligation.

The Company has recorded on its consolidated balance sheets as a liability the underfunded status of its and its subsidiaries’ retirement benefit obligations based on the projected benefit obligation.

The Company has recognized Regulatory Assets, net of deferred tax benefits, of $ 29.8 million and $ 29.1 million at December 31, 2023 and 2022, respectively, to account for the future collection of these plan obligations in electric and gas rates.

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(See Note 1 (Summary of Significant Accounting Policies) for further discussion of SERP funding.)

The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan in 2023 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’

rates for these Pension Plan costs.

The following table represents employer contributions, participant contributions and benefit payments (000’s).

The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan in 2024 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension Plan costs.

The following table represents employer contributions, participant contributions and benefit payments (000’s).

Employer Contributions

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Benefit Payments

The following table represents estimated future benefit payments (000’s).

Estimated Future Benefit Payments

The Expected Long-Term Rate of Return on Pension Plan assets assumption used by the Company is developed based on input from actuaries and investment managers.

The Company’s Expected Long-Term Rate of Return on Pension Plan assets is based on target investment allocation of 56 % in common stock equities, 39 % in fixed income securities and 5 % in real estate securities.

The Company’s Expected Long-Term Rate of Return on PBOP Plan assets is based on target investment allocation of 55 % in common stock equities and 45 % in fixed income securities.

The Company’s Expected Long-Term Rate of Return on Pension Plan assets is based on target investment allocation of 58 % in common stock equities, 37 % in fixed income securities and 5 % in real estate securities.

The Company’s Expected Long-Term Rate of Return on PBOP Plan assets is based on target investment allocation of 55 % in common stock equities and 45 % in fixed income securities.

The actual investment allocations are shown in the following tables.

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The Company evaluates the actuarial assumptions, including the expected rate of return, at least annually.

The primary financial objective of the plans is to earn their expected long-term returns without assuming undue risks of funded

status volatility.

The primary financial objective of the plans is to earn their expected long-term returns without assuming undue risks of funded status volatility.

The target rate of return for the Plans has been based upon an analysis of historical returns supplemented with an economic and structural review for each asset class.

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There have been no changes in the methodologies used at December 31, 2023 and 2022.

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

Equity, Fixed Income, Index and Asset Allocation Funds

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These investments are valued at net asset value per unit based on a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity.

In accordance with FASB Codification Topic 820, “Fair Value Measurement”, these investments have not been classified in the fair value hierarchy.

The fair value amounts presented in the tables below for the Real Estate Fund are intended to permit reconciliation of the fair value hierarchy to the “Plan Assets at End of Year”

line item shown in the “Change in Plan Assets”

Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2022 and 2021 are as follows (000’s):

In accordance with FASB Codification Topic 820, “Fair Value Measurement”, these investments have not been classified in the fair value hierarchy.

The fair value amounts presented in the tables below for the Real Estate Fund are intended to permit reconciliation of the fair value hierarchy to the “Plan Assets at End of Year” line item shown in the “Change in Plan Assets” table above.

Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2023 and 2022 are as follows (000’s):

Fair Value Measurements at Reporting Date Using

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Total Assets in the Fair Value Hierarchy

Real Estate Fund–Measured at Net Asset Value

Pension Plan Assets:

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Total Assets in the Fair Value Hierarchy

Real Estate Fund–Measured at Net Asset Value

Redemptions of the Real Estate Fund are subject to a sixty-five day notice period and the fund is valued quarterly.

There are no unfunded commitments.

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2022 and 2021 are as follows (000’s):

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2023 and 2022 are as follows (000’s):

Fair Value Measurements at Reporting Date Using

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Fixed Income Funds

Employee 401(k) Tax Deferred Savings Plan—

The Company sponsors the Unitil Corporation Tax Deferred Savings and Investment Plan (the 401(k) Plan) under Section 401(k) of the Internal Revenue Code and covering substantially all of the Company’s employees.

Employee 401(k) Tax Deferred Savings Plan— The Company sponsors the Unitil Corporation Tax Deferred Savings and Investment Plan (the 401(k) Plan) under Section 401(k) of the Internal Revenue Code and covering substantially all of the Company’s employees.

Participants may elect to defer current compensation by contributing to the plan.

Employees may direct, at their sole discretion, the investment of their savings plan balances (both the employer and employee portions) into a variety of investment options, including a Company common stock fund.

The Company’s contributions to the 401(k) Plan were $ 3.5 million, $ 3.3 million and $ 3.0 million for the years ended December 31, 2022, 2021 and 2020, respectively.

The Company’s contributions to the 401(k) Plan were $ 4.0 million, $ 3.5 million and $ 3.3 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 8. Financial Statements and Supplementary Data