What changed in this filing

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Item 8. Financial Statements and Supplementary Data

2022-02-01 compared with 2021-02-02 · 412 added, 384 removed, 1066 unchanged (43% of the section changed)

22 unchanged sentences

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;

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;

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Critical Audit Matter Description

Unitil’s (the “Company”) 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 (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.

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.

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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How the Critical Audit Matter Was Addressed in the Audit

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

Our audit procedures related to the uncertainty of future decisions by the Commissions focused on the ongoing base rate proceedings for Northern New Hampshire and Unitil Energy Systems as well as the ongoing prudency evaluation of the CIS project for Northern Maine and included the following, among others:

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

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Operating Expenses:

Cost of Gas Sales

Cost of Electric Sales

Cost of Gas Sales

Operation and Maintenance

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Proceeds from Divestiture, Net (See Note 1)

Cash Used In Investing Activities

Cash Used In Inves t

ing Activities

Financing Activities:

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

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

Issuance of Long-Term Debt

2 unchanged sentences

Decrease in Capital Lease Obligations

Net (Decrease) Increase in Exchange Gas Financing

Net Increase (Decrease) in Exchange Gas Financing

Dividends Paid

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Capital Expenditures Included in Accounts Payable

Additions to Property, Plant and Equipment

Assets Obtained in Exchange for Lease Obligations

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(Unitil Realty), Unitil Service Corp.

(Unitil Service) and its non-regulated

business unit Unitil Resources, Inc.

(Unitil Service) and its non-regulated business unit Unitil Resources, Inc.

(Unitil Resources).

1 unchanged sentence

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

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

Unitil 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 (collectively referred to as the “distribution utilities”).

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

Granite State is an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire.

2 unchanged sentences

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, Unitil Power ceased being the wholesale supplier for

Unitil Energy on May 1, 2003 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 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.

Unitil also has three other wholly-owned subsidiaries:

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and Usource L.L.C.

(collectively, Usource), which the Company divested of in the first quarter of 2019, were wholly-owned subsidiaries of Unitil Resources.

(collectively, Usource), which the Company divested in the first quarter of 2019, were wholly-owned subsidiaries of Unitil Resources.

Usource provided energy brokering and advisory services to large commercial and industrial customers in the northeastern United States.

Divestiture of Non-Regulated

Business Subsidiary

On March 1, 2019, the Company divested of its non-regulated

energy brokering and advisory business subsidiary, Usource.

The Company recognized an after-tax

net gain of approximately $ 9.8 million on this divestiture in the first quarter of 2019.

net gain of approximately $ 13.4 million on this divestiture is included in Other Income (Expense), Net on the Consolidated Statements of Earnings for the year-ended December 31, 2019, while the income taxes associated with this transaction of $ 3.6 million are included in the Provision For Income Taxes.

Divestiture of Non-Regulated Business Subsidiary

On March 1, 2019, the Company divested its non-regulated energy brokering and advisory business subsidiary, Usource.

The Company recognized an after-tax net gain of approximately

million on this divestiture in the first quarter of 2019.

The pre-tax net gain of approximately

$ 13.4 million on this divestiture is included in Other Income (Expense), Net on the Consolidated Statements of Earnings for the year-ended December 31, 2019, while the income taxes associated with this transaction of

$ 3.6 million are included in the Provision For Income Taxes.

Basis of Presentation

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Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.

To the extent that valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment.

To the extent valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment.

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

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Utility Revenue Recognition

Gas Operating Revenues and Electric Operating Revenues consist of billed and unbilled revenue and revenue from rate adjustment mechanisms.

Electric Operating Revenues and Gas Operating Revenues consist of billed and unbilled revenue and revenue from rate adjustment mechanisms.

Billed and unbilled revenue includes delivery revenue and pass-through revenue, recognized according to tariffs approved by federal and state regulatory commissions which determine the amount of revenue the Company will record for these items.

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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.

Revenue recognized in connection with rate adjustment mechanisms is consistent with the definition of alternative revenue programs in ASC 980-605-25-3,

as the Company has the ability to adjust rates in the future as a result of past activities or completed events.

The Company’s billed and unbilled rev e

nue 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.

The rate adjustment mechanisms meet the criteria within ASC 980.

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December 31, 2021

Gas and Electric Operating Revenues (millions):

Electric and Gas Operating Revenues (millions):

Billed and Unbilled Revenue:

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Rate Adjustment Mechanism Revenue

Total Gas and Electric Operating Revenues

Total Electric and Gas Operating Revenues

Twelve Months Ended

December 31, 2020

Gas and Electric Operating Revenues (millions):

Electric and Gas Operating Revenues (millions):

Billed and Unbilled Revenue:

2 unchanged sentences

Rate Adjustment Mechanism Revenue

Total Gas and Electric Operating Revenues

Total Electric and Gas Operating Revenues

Twelve Months Ended

December 31, 2019

Gas and Electric Operating Revenues (millions):

Electric and Gas Operating Revenues (millions):

Billed and Unbilled Revenue:

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Rate Adjustment Mechanism Revenue

Total Gas and Electric Operating Revenues

Total Electric and Gas Operating Revenues

Fitchburg is subject to revenue decoupling.

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

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

between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recorded as an increase or a decrease in the current portion of 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 that the Company files with the Massachusetts Department of Public Utilities (MDPU).

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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.

Other Operating

Revenue—Non-regulated

Other Operating Revenue

consists solely of revenue from Usource, Unitil’s non-regulated

subsidiary, which, the Company divested on March 1, 2019.

Other Operating Revenue—Non-regulated

Other Operating Revenue consists solely of revenue from Usource, Unitil’s non-regulated subsidiary, which, the Company divested on March 1, 2019.

Usource conducted its business activities as a broker of competitive energy services.

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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.

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:

1 unchanged sentence

Stock-based Employee Compensation

—Unitil accounts for stock-based employee compensation using the fair value-based method (See Note 6 (Equity)).

Sales and Consumption Taxes

—The Company bills its customers sales tax in Massachusetts and Maine and consumption tax in New Hampshire.

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.

The consumption tax in New Hampshire has been repealed effective January 1, 2019.

Income Taxes—

Unitil accounts for stock-based employee compensation using the fair value method (See Note 5 (Equity)).

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

3 unchanged sentences

The Company classifies penalties and interest expense related to income tax liabilities as income tax expense and interest expense, respectively, in the Consolidated Statements of Earnings.

Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented.

for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented.

The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes.

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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.

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

—The Company’s dividend policy is reviewed periodically b y

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.

For the year ended December 31, 2021 the Company paid quarterly dividends of $ 0.38 per share, resulting in an annualized dividend rate of $ 1.52 per common share.

For the years ended December 31, 2019 and 2018, the Company paid quarterly dividends of $ 0.37 and $ 0.365 per common share, respectively, resulting in annualized dividend rates of $ 1.48 and $ 1.46 per common share, respectively.

At its January 2021 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of

$ 0.38 per share, an increase of $ 0.005 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $ 1.52 per share from $ 1.50 per share.

For the years ended December 31, 2020 and 2019, the Company paid quarterly dividends of $ 0.375 and $ 0.37 per common share, respectively, resulting in

annualized dividend rates of $ 1.50 and $ 1.48 per common share, respectively.

At its January 2022 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $ 0.39 per share, an increase of $ 0.01 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $ 1.56 per share from $ 1.52 per share.

Cash and Cash Equivalents

7 unchanged sentences

months of outstanding obligations, less credit amounts that are based on the Company’s credit rating.

On December 31, 2020 and 2019, the Unitil subsidiaries had deposited $ 2.4 million and $ 1.9 million, respectively ,

to satisfy their ISO-NE

On December 31, 2021 and 2020, the Unitil subsidiaries had deposited $ 2.7 million and $ 2.4 million, respectively, to satisfy their ISO-NE

Financial Instruments

5 unchanged sentences

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, which is adjusted for current conditions, customer trends, or other factors such as macroeconomic conditions, to customer account balances.

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 their energy commodity portion of bad debts through rate mechanisms.

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 such as the extent and duration of any shutoff or collection moratoriums.

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.

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

3 unchanged sentences

Accounts Receivable, Net includes $ 3.1 million and $ 3.1 million of the Allowance for Doubtful Accounts at December 31, 2021 and December 31, 2020, respectively.

Unbilled Revenues, net (a component of Accrued Revenue )

includes $ 0.2 million of the Allowance for Doubtful Accounts at December 31, 2020.

Unbilled Revenues, net (a component of Accrued Revenue) includes $ 0.2 million and $ 0.2 million of the Allowance for Doubtful Accounts at December 31, 2021 and December 31, 2020, respectively.

Accrued Revenue—

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

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

The third party delivers natural gas back to the Company during the months of November

through March.

The exchange and storage gas volumes are recorded at weighted average cost.

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—The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized.

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

Cost of additions consists of

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

The average interest rates applied to AFUDC were 1.71 %, 3.12 % and 3.90 % in 2021, 2020 and 2019, respectively.

3 unchanged sentences

At December 31, 2021 and 2020, the Company has recorded cost of removal amounts of $ 107.5 million and $ 105.2 million, respectively, that have been collected in depreciation rates but have not yet been expended, and which represent regulatory liabilities.

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

These amounts are recorded on the Consolidated Balance Sh e

ets in Cost of Removal Obligations.

Regulatory Accounting

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

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

As of December 31, 2021 and December 31, 2020, the Company has recorded

$ 7.9 million and $ 6.8 million, respectively, of hardship accounts in Regulatory Assets.

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.

Regulatory Assets consist of the following (millions)

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

Included in Regulatory Assets as of December 31, 2020 are $ 8.0

million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years.

Included in Regulatory Assets as of December 31, 2021 are $ 8.5 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years.

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

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.

If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and 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, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for

application of the FASB Codification topic on Regulated Operations.

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.

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

assets, including regulatory assets.

If unable to continue to apply the FASB Codification provisions for Regul a

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.

1 unchanged sentence

Leases are classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement.

The Company has elected the practical expedient to

not separate non-lease

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 on a straight-line basis over the lease term.

The Company recognizes those lease payments in the Consolidated Statements of Earnings on a straight-line basis over the lease term.

See additional discussion in the “Leases” section of Note 5 (Debt and Financing Arrangements).

The Company recognizes those lease payments in the Consolidated Statements of Earnings on a straight-line basis o v

er the lease term.

See additional discussion in the “Leases” section of Note 4

(Debt and Financing Arrangements).

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

2 unchanged sentences

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

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

The Company previously operated a regulatory approved hedging program for Northern Utilities designed to fix or cap a portion of its gas supply costs for the coming years of service, which included use of derivative instruments.

The hedging program was terminated in 2018.

Under the hedging program previously operated by Northern Utilities, any gains or losses resulting from the change in the fair value of these derivatives were passed through to ratepayers directly through Northern Utilities’ Cost of Gas Clause.

The fair value of these derivatives was determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date.

As a result of the ratemaking process, the Company recorded gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassified these gains or losses into Cost of Gas Sales when the gains and losses were passed through to customers through the Cost of Gas Clause.

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

The Company had no derivative assets or liabilities recorded on its Consolidated Balance Sheets as of December 31, 2021 and December 31, 2020.

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

At December 31, 2020 and 2019, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $ 5.7 million and $ 5.6 million, respectively, as shown in the table below.

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, 2021 and 2020, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $ 5.7 million and $ 5.7 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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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 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, 2020 and 2019, 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 $ 0.5 million and $ 0.2 million, respectively .

31, 2021 and 2020, 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 $

0.5 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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Energy Supply Obligations

—The following discussion and table summarize the nature and amounts of the items recorded as Energy Supply Obligations (current portion) and Other Noncurrent Liabilities (noncurrent portion) on the Company’s Consolidated Balance Sheets.

—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:

Exchange Gas Obligation

Renewable Energy Portfolio Standards

Power Supply Contract Divestitures

Total Energy Supply Obligations—Current

Exchange Gas Obligation

Power Supply Contract Divestitures

Total Energy Supply Obligations

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.

Renewable Energy Portfolio Standards

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RPS compliance costs are a supply cost that is recovered in customer default service rates.

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.

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).

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

In 2020, three of the long-term contracts were terminated due to an inability to meet critical milestones.

In 2018, the Company filed two long-term contracts with the MDPU, one for offshore wind generation and another for imported hydroelectric power and associated transmission.

Those contracts were approved in 2019.

In 2019, the Company participated in an additional statewide procurement for offshore wind generation and the resulting contracts were filed with the MDPU during the first quarter of 2020.

An Order approving the contracts was issued by the MDPU in November 2020 but the Attorney General’s Office immediately filed a Motion for Reconsideration on the issue of remuneration.

The matter is pending at the MDPU.

In compliance with An Act to Promote a Clean Energy Future (2018), in late 2020 in coordination with the other electric utilities in Massachusetts, the Company began efforts on the next long-term renewable procurement which will seek up to an additional 1,600MW of offshore wind generation.

Fitchburg has e n

tered 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).

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

Three approved contracts are currently under development.

These include two long-term contracts filed with the MDPU in 2018, one for offshore wind generation and one for imported hydroelectric power and associated transmission, which were approved in 2019 and another for offshore wind generation contracts 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 are expected to be filed for approval with the MDPU in April 2022.

Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

Exchange Gas Obligation

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.

In connection with the implementation of retail ch o

ice, 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 their rates all the 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, 2020, Fitchburg has fully-recovered its power supply-related stranded costs and Unitil Energy has $ 0.3 million remaining to recover.

The obligations related to these divestitures are recorded in Energy Supply Obligations (current portion) and Other Noncurrent Liabilities (noncurrent portion) on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue (current portion) and Regulatory Assets (noncurrent portion).

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

The obligations for prior periods related to these divestitures are recorded in Energy Supply Obligations on the Company’s Consolidated Balance Sheets with a corresponding regulatory asset recorded in Accrued Revenue.

Retirement Benefit Obligations

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—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, 2020, the Company is not aware of any material commitments or contingencies other than those disclosed in Note 8 (Commitments and Contingencies).

As of December 31, 2021, the Company is not aware of any material commitments or contingencies other than those disclosed in Note 7

(Commitments and Contingencies).

Environmental Matters

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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, 2020, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 8 (Commitments and Contingencies).

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

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, 2021, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 7

(Commitments and Contingencies).

t recoverable in regulatory rate mechanisms.

Subsequent Events

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

Quarterly Financial Information (unaudited;

millions, except per share data)

Quarterly earnings per share may not agree with the annual amounts due to rounding and the effect of additional common share issuances.

Basic and Diluted Earnings per Share are the same for the periods presented.

The Company divested Usource in the first quarter of 2019 (see Note 1 (Summary of Significant Accounting Policies)).

Three Months Ended

September 30,

Total Operating Revenues

Operating Income

Net Income Applicable to Common

Per Share Data:

Earnings Per Common Share

Dividends Paid Per Common Share

Table of Content s

Segment Information

Unitil reports three segments:

utility gas operations

, utility electric operations and non-regulated.

utility electric operations, utility gas operations and non-regulated.

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.

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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

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

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

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Income Tax Expense (Benefit)

Segment Profit

Segment Profit (Loss)

Segment Assets

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Rate Adjustment Mechanism Revenue

Other Operating Revenue— Non-Regulated

Total Operating Revenues

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Capital Expenditures

Allowance for Doubtful Accounts

Allowance for Doubtful Account s

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

In 2021, 2020 and 2019, the Company recorded provisions for the energy commodity portion of bad debts of $ 2.4 million, $ 1.6 million and $ 2.3 million, respectively.

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

Cost of Gas Sales and Cost of Electric Sales costs are recovered from customers through periodic rate reconciling mechanisms.

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

Cost of Electric Sales and Cost of Gas Sales costs are recovered from customers through periodic rate reconciling mechanisms.

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

As of December 31, 2021 and 2020, the Company has recorded $ 7.9 million and $ 6.8 million, respectively, of hardship accounts in Regulatory Assets.

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

Accounts Receivable, Net includes $ 3.1 million and $ 1.0 million of the Allowance for Doubtful Accounts at December 31, 2020 and December 31, 2019, respectively.

Unbilled Revenues, net (a component of Accrued Revenue) includes $ 0.2 million of the Allowance for Doubtful Accounts at December 31, 2020.

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for

2018—2020 (millions):

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

Accounts Receivable, Net includes $ 3.1 million and $ 3.1 million of the

Allowance for Doubtful Accounts at December 31, 2021 and December 31, 2020, respectively.

Unbilled Revenues, net (a component of Accrued Revenue) includes $ 0.2 million and $ 0.2 million of the Allowance for Doubtful Accounts at December 31, 2021 and December 31, 2020, respectively.

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2021, 2020 and 2019 (millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS

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Incremental bad debt expense amounts have been deferred as regulatory assets based on certain regulatory proceedings and management’s belief that such amounts are probable of recovery (See the “Financial Effects of COVID-19

Pandemic” section in Note 8 (Commitments and Contingencies).

Pandemic” section in Note 7

(Commitments and Contingencies).

The Company will track the collection of receivables and to the extent incremental bad debt amounts are collected in the future, such amounts will reduce the regulatory assets recorded.

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These agreements do contain covenants relating to, among other things, the issuance of additional long-term debt, cross-default provisions and business combinations.

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

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 have 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.

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 ha s

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.

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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 %.

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 %.

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The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2021 is:

2021—$ 8.8 million;

2022—$ 23.4 million;

2023—$ 6.9 million;

2024—$ 7.0 million;

38.0 million and thereafter $ 444.4 million.

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Unitil Energy First Mortgage Bonds:

5.24 % Senior Secured Notes, Due March 2, 2020

8.49 % Senior Secured Notes, Due October 14, 2024

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Northern Utilities:

5.29 % Senior Notes, Due March 2, 2020

3.52 % Senior Notes, Due November 1, 2027

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

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

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

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.

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

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.

Interest expense is recorded on an over-collection of costs, which creates a regulatory liability to be refunded in future periods when rates are reset.

Interest expense is recorded on an over-collection of costs, which creates a regulatory liability to be refunded

in future periods when rates are reset.

A summary of interest expense and interest income is provided in the following table :

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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).

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, 2020 and December 31, 2019, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.

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

The weighted average interest rates on all short-term borrowings were 1.7 %, 3.4 %, and 3.3 % during 2020

, respectively.

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, 2021 and

December 31, 2020, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.

The Company believes i

t has sufficient sources of working capital to fund its operations.

The weighted average interest rates on all short-term borrowings were 1.2 %, 1.7 %, and 3.4 % during 2021, 2020, and 2019, 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.

In April 2014, Unitil Service entered into a financing arrangement, structured as a capital lease obligation, for various information

systems and technology equipment.

In April 2014, Unitil Service entered into a financing arrangement, structured as a

capital lease obligation, for various information systems and technology equipment.

Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $ 13.4 million.

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There was $ 8.3 million and $ 5.4 million of natural gas storage inventory at December 31, 2021 and 2020, respectively, related to these asset management agreements.

The amount of natural gas inventory released in December 2020, which was payable in January 2021, was $ 1.0 million and recorded in Accounts Payable at December 31, 2020.

The amount of natural gas inventory released in December 2019, which was payable in January 2020, was $ 1.0 million and recorded in Accounts Payable at December 31, 2019.

The amount of natural gas inventory released in December 2021, which was payable in January 2022, was $ 1.6 million and was recorded in Accounts Payable at December 31, 2021.

The amount of natural gas inventory released in December 2020, which was payable in January 2021, was $ 1.0 million and was recorded in Accounts Payable at December 31, 2020.

Contractual Obligations

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

Total rental expense under operating leases charged to operations for the years ended December 31, 2020, 2019 and 2018 amounted to $ 1.8 million, $ 1.4 million and $ 2.2 million respectively.

Total rental expense under operating leases charged to operations for the years ended December 31, 2021, 2020 and 2019 amounted

to $ 1.9 million, $ 1.8 million and $ 1.4 million respectively.

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

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Total Lease Obligations

Cash paid for amounts included in the measurement of operating lease obligations for the twelve months ended December 31, 2020 and 2019 were

$ 1.8 million and $ 1.4 million, respectively and w

Cash paid for amounts included in the measurement of operating lease obligations for the twelve months ended December 31, 2021 and 2020 w as

$ 1.9 million and $ 1.8 million, respectively and w as

included in Cash Provided by Operating Activities on the Consolidated Statements of Cash Flows.

Assets under capital leases amounted to approximately $ 1.0 million and $ 1.2 million as of December 31, 2020 and 2019, respectively, less accumulated amortization of $ 0.5 million and $ 0.6 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 $ 1.0 million as of December 31, 2021 and 2020, respectively, less accumulated amortization of $ 0.3 million and $ 0.5 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheet s.

The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2021.

The payments for capital leases consist of $ 0.2 million of current Capital Lease Obligations, which are included in Other Current Liabilities, and $ 0.2 million of noncurrent Capital Lease Obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2020.

The payments for operating leases consist of $ 1.6 million of current operating lease obligations, which are included in Other Current Liabilities and $ 3.1 million of noncurrent operating lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2021.

The payments for capital leases consist of $ 0.1 million of current Capital Lease Obligations , which are included in Other Current Liabilities, and $ 0.2 million of noncurrent Capital Lease Obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2021.

Lease Payments ($000’s)

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

As of December 31, 2020, the weighted average remaining lease term is

3.8 years and the weighted average operating discount rate used to determine the operating

lease obligations was 4.4 %.

As of December 31, 2021, the weighted average remaining lease term is 3.5 years and the weighted average operating discount rate used to determine the operating lease obligations was 3.9 %.

As of December 31, 2020, the weighted average remaining lease term was 3.8 years and the weighted average operating discount rate used to determine the operating lease obligations was 4.4 %.

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

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, 2020, there were approximately $ 1.3 million of guarantees

outstanding with a duration of less than one year.

As of December 31, 2021, there were approximately $ 0.7 million of guarantees outstanding with a duration of less than one year.

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

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The Company has 25,000,000 shares of common stock authorized as of December 31, 2021 and December 31, 2020.

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.

Overall, the results of operations and earnings reflect the higher number of average shares outstanding period over period.

Dividend Reinvestment and Stock Purchase Plan

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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 2019 and 2018, the Company raised $ 1.1

million and $ 1.2 million, respectively, through the issuance of 20,065 and 25,932 shares, respectively, of its common stock in connection with its DRP and 401(k) plans.

During 2020 and 2019, the Company raised $ 1.1 million and $ 1.1 million, respectively, through the issuance of 23,658 and 20,065 shares, respectively, of its common stock in connection with its DRP and 401(k) plans.

Common Shares Repurchased, Cancelled and Retired

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trading plan.

The expense recognized by the Company for these repurchases was $ 0.5 million, $ 0.2 million, and less than $ 0.1 million in 2020, 2019 and 2018, respectively.

The expense recognized by the Company for these repurchases was $ 0.4 million, $ 0.5 million, and $ 0.2 million in 2021, 2020 and 2019, respectively.

During 2021, 2020 and 2019, the Company did not cancel or retire any of its common stock.

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

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

During the vesting period, dividends on 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.

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At December 31, 2021, there was approximately $ 0.6 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.5 years.

There were 5,570 restricted shares forfeited and no restricted shares cancelled under the Stock Plan during 2020.

On January 26, 2021, there were 23,140 Restricted

Shares issued under the Stock Plan with an aggregate market value of $ 0.9 million.

There were zero restricted shares forfeited and zero restricted shares cancelled under the Stock Plan during 2021.

On January 25

, 2022, there were 36,770 Restricted Shares issued under the Stock Plan with an aggregate market value of $ 1.7 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.

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.

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Ending Restricted Stock Units

Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2020 and 2019 are $ 0.8 million and $ 1.9 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, 2021 and 2020

$ 1.0 million and $ 0.8 million, respectively, representing the fair value of liabilities ass o

ciated with the portion of fully vested RSUs that will be settled in cash.

Preferred Stock

There were $ 0.2 million, or 1,887 shares, of Unitil Energy’s 6.00 % Series Preferred Stock outstanding as of December 31, 2020 and 2019.

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

There were $ 0.2 million, or 1,887 shares, of Unitil Energy’s 6.00 % Series

Preferred Stock outstanding as of December 31, 2020.

There were less than $ 0.1 million of total dividends declared on Preferred Stock in each of the twelve month periods ended December 31, 2021 and December 31, 2020, respectively.

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Energy Supply

NATURAL GAS SUPPLY

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

Northern Utilities’ 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 2020, 80% of Unitil’s largest New Hampshire gas customers, representing 39% of Unitil’s New Hampshire gas therm sales, and 67% of Unitil’s largest Maine customers, representing 25% 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 2020, 78% of Unitil’s largest Massachusetts gas customers, representing 30% 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.

Regulated Natural Gas Supply

Northern Utilities purchases the

majority of its natural gas from U.S.

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

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 122,000 million British Thermal Units (MMbtu) per day of year-round and seasonal transportation capacity to its distribution facilities, and 4.3 billion cubic feet (BCF) of underground storage.

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

This plant is used principally during peak load periods to augment the supply of pipeline natural gas.

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.

As a supplement to pipeline natural gas, Fitchburg owns a propane air gas plant and an LNG storage and vaporization facility.

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

ELECTRIC POWER SUPPLY

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

In 2020, the City of Fitchburg voted to move forward with its community choice energy aggregation plan, and on December 31, 2020, the City filed with the MDPU for approval of its Aggregation Plan.

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

The aggregation is anticipated to be implemented in mid-2022.

The City of Fitchburg comprises about 69% of Company sales.

As of December 2020, nearly 27% of Unitil’s residential customers in Massachusetts purchased their electricity from a third-party supplier.

In New Hampshire, the percentage of residential customers purchasing electricity from a third-party supplier as of December 2020 is 8.3%, down 0.6% from 2019 and reflecting a downward trend from a high of 13% in 2015.

As of December 2021, 27% of Unitil’s residential customers in Massachusetts purchased their electricity from a third-party supplier.

In New Hampshire, the percentage of residential customers purchasing electricity from a third-party supplier in 2021 is 7.8%, down

% from 8.3% in 2020 and reflecting a downward trend from a high of 13% in 2015.

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

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

Regulated Electric Power Supply

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

MDPU policy establishes

the pricing structure and duration of each of these contracts.

MDPU policy establishes the pricing structure and duration of each of these contracts.

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 % of the supply requirements.

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Currently, all Basic Service power supply requirements for large accounts are assigned to Fitchburg’s ISO-NE

settlement account ,

where Fitchburg procures electric supply through ISO-NE’s

settlement account, where Fitchburg procures electric supply through ISO-NE’s

real-time market.

In 2021, Fitchburg adjusted its procurement schedule in response to the impending City of Fitchburg municipal aggregation.

In its most recent solicitation, Fitchburg solicited for 100% of default service supply for a limited six month period beginning December 1, 2021 to May 31, 2022.

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

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The companies have a continuing obligation to submit regulatory filings that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

Commitments and Contingencies

NATURAL GAS SUPPLY

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

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 2021, 74% of Unitil’s largest New Hampshire gas customers, representing 39% of Unitil’s New Hampshire gas therm sales, and 63% of Unitil’s largest Maine customers, representing 24% 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

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 2021, 67% of Unitil’s largest Massachusetts gas customers, representing 27% of Unitil’s Massachusetts gas therm sales, purchased their gas supply from third-party suppliers.

Regulated Natural Gas Supply

Northern Utilities purchases the majority of its natural gas from U.S.

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

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

This plant is used principally during peak load periods to augment the supply of pipeline

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 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.

As a supplement to pipeline natural gas, Fitchburg owns a propane air gas plant and an LNG storage and vaporization facility.

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

Commitments and Contingencie s

Regulatory Matters

—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.

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

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.

Fitchburg’s electric and gas divisions also operate under revenue decoupling mechanisms.

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

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

Most small and medium-sized

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

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

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

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

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

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These assets have been principally recovered as of December 31, 2020.

The remaining balance of these assets is $ 0.3 million, recorded in Current Assets as Accrued Revenue on the Company’s Consolidated Balance Sheet as of December 31, 2020 and projected to be recovered in the next year.

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

Unitil’s distribution companies have a continuing obligation to submit filings in Massachusetts and New Hampshire demonstrating their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

Tax Cuts and Jobs Act of 2017

x Cuts and Jobs Act of 2017

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (TCJA) was signed into law.

Among other things, the TCJA substantially reduced the corporate income tax rate to 21 %, effective January 1, 2018.

Among other things, the TCJA substantially reduced the corporate income tax rate to 21

%, effective January 1, 2018.

Each state public utility commission, with jurisdiction over the areas that are served by Unitil’s electric and gas subsidiary companies, issued orders directing how the tax law changes were to be reflected in rates.

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This matter was resolved for Granite State in its May 2, 2018 uncontested rate settlement filing, which accounted for the effect of the TCJA.

On November 21, 2019, the FERC issued Order No.

On November 21

, 2019, the FERC issued Order No.

864, a final rule on Public Utility Transmission Rate Changes to Address Accumulated Deferred Income Taxes.

The new rule requires public utilities with formula transmission rates to revise their formula rates to include a transparent methodology to address the TCJA and future tax law changes on customer rates by accounting for “excess” or “deficient” Accumulated Deferred Income Taxes (ADIT).

FERC also required transmission providers with stated rates to account for TCJA’s effect on ADIT in their next rate case.

The FERC also required transmission providers with stated rates to account for TCJA’s effect on ADIT in their next rate case.

The Company is complying with the new rule and there is no material effect on its financial position, operating results, or cash flows.

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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.

The Company believes that the customer information system costs were prudently incurred and that the investigation will not have a material impact on its financial position, operating results or cash flows.

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.

The stipulation is subject to approval by the MPUC.

Northern Utilities—Targeted Infrastructure Replacement Adjustment (TIRA)—Maine

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

The Company’s most recent request under the TIRA mechanism, to increase annual base rates by $ 1.4 million for 2019 eligible facilities, was approved by the MPUC on April 29, 2020, effective May 1, 2020.

The Company’s most recent request under the TIRA mechanism, to increase annual base rates by $ 1.1 million for 2020 eligible facilities, was approved by the MPUC effective May 1, 2021.

Northern Utilities—Base Rates—New Hampshire

On May 2, 2018, the NHPUC approved a settlement agreement providing for a net annual revenue increase of $ 3.2 million, incorporating the effect of the TCJA, and an initial step increase to recover post-test year capital investments.

The Company’s second annual revenue step increase of approximately $ 1.4 million to recover eligible capital investments in 2018 was approved by the NHPUC effective May 1, 2019.

According to the terms of the settlement agreement, Northern Utilities’ next distribution base rate case shall be based on a historical test year no earlier than the twelve months ending December 31, 2020.

—On August 2, 2021, Northern Utilities filed a base rate case with the NHPUC, requesting a permanent increase in total annual revenues of $ 7.8 million,

which represents an increase of 8.1 % over total annual revenue at present rates.

The multi-year rate filing includes a revenue decoupling mechanism and an Arrearage Management Program for financial hardship customers.

Northern Utilities also requested implementation of temporary rates for service rendered on and after October 1, 2021.

On September 30, 2021, the NHPUC approved a settlement providing for a temporary rate increase of $ 2.6 million, effective October 1, 2021.

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

Unitil Energy—Base Rates—

On April 20, 2017 the NHPUC issued its final order effective May 1, 2017, providing for a permanent increase of $ 4.1 million followed by two annual rate step adjustments to recover the revenue requirements associated with certain capital expenditures.

On April 30, 2018, the NHPUC approved Unitil Energy’s first step increase, effective May 1, 2018.

On April 22, 2019, the NHPUC approved Unitil Energy’s second and final step adjustment, providing a revenue increase of approximately $ 340,000 , effective May 1, 2019.

On April 2, 2021, Unitil Energy filed a base rate case with the NHPUC, requesting a permanent increase in total annual revenues of $ 12.0 million, which represents an increase of 4.4 % above present rates.

Unitil Energy also requested implementation of temporary rates for service rendered on and after June 1, 2021, and until a final order on permanent rates is issued.

The filing includes (1) a proposed multi-year rate plan, (2) a revenue decoupling mechanism, (3) a Grid Modernization plan that includes a group of foundational grid modernization projects, (4) a suite of proposed time of use (TOU) rates including rates for electric vehicles (EV), (5) an EV infrastructure development program which includes rebates for residential customers for the installation of smart charging equipment and a public “make-ready” program for general service customers under which the Company will install the infrastructure required to connect an EV charger, (6) a Marketing, Communications, and Education Plan to engage with customers about the TOU rates and EV program offerings, (7) resiliency programs to further the Company’s commitment to reliability, (8) an Arrearage Management Program for financial hardship customers, and (9) other rate design and tariff changes.

On April 24, 2020, the Governor of New Hampshire issued an executive order that extended the NHPUC’s authority to suspend rate schedules by six months, from 12 to 18 months, to conduct its investigation of a utility company’s request to increase rates.

On April 6, 2021, the NHPUC determined that the extension applies to this proceeding, but stated it will endeavor to set final rates as expeditiously as possible.

On May 27, 2021, the NHPUC approved a settlement agreement providing for a temporary rate increase of $ 4.5 million in annual electric distribution revenues, effective June 1, 2021.

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

The Company and all parties to the case filed a motion on January 25, 2022 advising the NHPUC that, as a result of settlement negotiations, they have reached a comprehensive settlement agreement in principle on final rates.

On January 26, 2022, the NHPUC suspended certain elements of the procedural schedule to allow the parties an opportunity to finalize and file the agreement.

Once the settlement agreement has been finalized and filed, it is subject to approval by the NHPUC.

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.

—Fitchburg’s base rates are decoupled in order to mitigate economic, weather, and energy efficiency effects to the Company’s revenues and subject to an annual revenue decoupling adjustment mechanism, which includes a cap on the amount that rates may be increased in any year.

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

On November 1, 2018, Fitchburg filed its cumulative revenue requirement of $ 0.9 million associated with the Company’s 2015-2017 capital expenditures.

On December 22, 2020,

final approval of

the filing was

On October 29, 2019, Fitchburg filed its cumulative revenue requirement of $ 1.1 million associated with the Company’s 2015-2018 capital expenditures.

On December 22, 2020, final approval of

the filing was issued

On November 2, 2020, Fitchburg filed its cumulative revenue requirement of $ 1.4 million associated with the Company’s 2015-2019 capital expenditures.

On December 17, 2020, the filing was approved, effective January 1, 2021, subject to further investigation and reconciliation.

On December 22, 2020, final approval of the filing was issued.

On October 29, 2019, Fitchburg filed its cumulative revenue requirement of $ 1.1

million associated with the Company’s 2015-2018 capital expenditures.

On December 22, 2020, final approval of the filing was issued.

On November 2, 2020, Fitchburg filed its cumulative revenue requirement of $

1.4 million associated with its 2019 capital expenditures.

The Department allowed the associated rate increase to become effective on January 1, 2021, subject to further investigation and reconciliation.

On June 15, 2021, final approval of the filing was issued.

On November 2, 2021, Fitchburg filed its cumulative revenue requirement of $

1.6 million associated with its 2019 and 2020 capital expenditures.

The Department allowed the associated rate increase to become effective on January 1, 2022, 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.

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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.

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.

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Fitchburg—Base Rates—Gas

Pursuant to the Company’s 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 impacts to the Company’s revenues.

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

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 affect 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 :

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, 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 impact threshold of $ 40,000 .

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

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.

Fitchburg—Gas System Enhancement Program

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

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.

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

a forward-looking filing for the subsequent construction year, to be filed on or before October 31 (the GSEP Filing);

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 (the GREC Filing).

a forward-looking filing for the subsequent construction year, to be filed on or before October 31;

Fitchburg’s forward-looking filing submitted on October 30, 2020 requested recovery of approximately

$ 2.2 million, and received final approval on April 29, 2021, effective May 1, 2021.

The Company’s most recent forward-looking filing, filed on October 29, 2021, requested recovery of approximately $ 3.3 million.

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

In an Order issued on April 30, 2019, the MDPU approved Fitchburg’s 2018 GSEP Filing and increased the annual cap on recovery.

The Order resulted in a revenue increase of

million that went into effect on May 1, 2019, subject to reconciliation.

The amount that exceeded the cap,

million, has been deferred to be recovered in a later proceeding.

On May 1, 2019, the Company made its 2019 GREC Filing, seeking a waiver of the annual cap and a revenue increase of

The MDPU approved the Company’s request in its Order issued October 31, 2019.

On October 31, 2019, the Company made its annual filing for an increase in revenues associated with 2020 GSEP investment for rates effective May 1, 2020.

On March 12, 2020, the Company made a revised GSEP filing to incorporate the 2015 through 2018 GSEP investments in base rates effective March 1, 2020;

on April 30, 2020, the MDPU approved the Company’s filing.

On May 1, 2020, the Company made its 2020 GREC Filing.

In accordance with the approved gas rate case settlement agreement, the Company decreased the Gas System Enhancement Reconciliation Adjustment Factors (GSERAF) and Gas System Enhancement Adjustment Factors to zero effective March 1, 2020, and will recover the February 29, 2020 GSEP deferral balance including interest over a 24 month period beginning March 1, 2021.

As a result, the current year’s GSERAF will change on March 1, 2021, instead of November 1, 2020.

The GSERAF recovery amount to be recovered over

months beginning March 1, 2021 is

This matter remains pending before the MDPU.

Granite State—Base Rates

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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.

Other Matters

Fitchburg—Independent Statewide Examination of the Safety of the Commonwealth’s Gas Distribution System—

The MDPU engaged a third-party evaluator to conduct an independent statewide examination of the safety of the gas distribution system to complement the investigation of the National Transportation Safety Board focused on the gas incident on September 13, 2018 in the Merrimack Valley and its potential causes.

The evaluator examined:

(1) the physical integrity and safety of the gas distribution system;

and (2) the operation and maintenance policies and practices of the gas companies and municipal gas companies, with respect to the Commonwealth’s gas distribution system, including recommendations for improvements.

The evaluator issued its final report on January 31, 2020, which contained a number of observations and recommendations for the improvement of gas distribution safety.

On February 28, 2020, the Company filed a response and plan to implement the Unitil-specific recommendations, as well as general safety improvements.

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.

The GMP is subject to review and approval by the MDPU and remains pending.

Fitchburg—Grid Modernization Cost Recovery Factor

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

The proposed GMF was approved on May 27, 2021, effective June 1, 2021, subject to further investigation and reconciliation.

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 to achieve its 2050 climate goal of net-zero

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 states that 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, have been directed to initiate a joint request for proposals (RFP) for an independent consultant(s) to conduct a study and prepare a report (Report), including a detailed study of each LDC that analyzes the feasibility of all identified pathways to help the Commonwealth achieve its net-zero

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

The study is to include 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.

On or before March 1, 2022, each LDC is required to submit a proposal to the MDPU that includes the LDC’s recommendations and plans for helping the Commonwealth achieve its 2050 climate goals, supported by the Report.

On or before March 1, 2022, each LDC is required to submit a proposal to the MDPU that includes the LDCs’ recommendations and plans for helping the Commonwealth achieve its 2050 climate goals, supported by the Report.

Prior to filing the Report and the LDCs’ proposals, the LDCs are directed to engage in a stakeholder process to solicit feedback and advice on both the Report and the proposals.

Fitchburg is actively involved in the LDC’s joint effort to respond to the MDPU’s directives.

Financial Effects of COVID-19

The NHPUC and the MDPU have opened proceedings to consider the revenue and cost effects on the regulated gas and electric utilities within their respective jurisdictions of the requirement to continue the availability of gas, electric and water service to customers during the COVID-19

Fitchburg is actively involved in the LDCs’ joint effort to respond to the MDPU’s directives.

Financial Effects of COVID-19 Pandemic

The NHPUC and the MDPU have opened proceedings to consider the revenue and cost effects on the regulated electric and gas utilities within their respective jurisdictions of the requirement to continue the availability of gas, electric and water service to customers during the COVID-19 pandemic.

Among the effects under investigation are the revenue effects associated with service disconnection moratoriums, the waiver of fees and expanded customer payments arrangements;

the increased cost of customer accounts that cannot be collected, including the cost of bad debt reserves and increased working capital costs;

and increased operating and maintenance

costs incurred for employees to work safely and protect the public.

Fitchburg, Unitil Energy and Northern Utilities are active participants in these proceedings, and are in full compliance with all regulatory orders governing service shut-off

moratoriums and other customer service protection measures.

and increased operating and maintenance costs incurred for employees to work safely and protect the public.

Fitchburg, Unitil Energy and Northern Utilities are active participants in these proceedings, and are in full compliance with all regulatory orders governing service shut-off moratoriums and other customer service protection measures.

These matters remain pending.

On December 31, 2020, in docket DPU 20-58,

the MDPU issued an order which, among other provisions, allows the utility companies to defer for future recovery bad debt expense in excess of a baseline.

On December 31, 2020, in docket DPU 20-58, the MDPU issued an order which, among other provisions, allows the utility companies to defer for future recovery bad debt expense in excess of a baseline.

On July 7, 2021, the NHPUC issued an order which declined to authorize New Hampshire’s rate-regulated utilities’ establishment of a regulatory asset for incremental bad debt or waived late payment fees related to the COVID-19 pandemic.

The NHPUC stated that these costs will be addressed in each utility’s next rate case.

On September 7, 2021, the NHPUC clarified its July 7 Order, determining that it has not foreclosed rate-regulated utilities from utilizing accounting mechanisms to defer costs in order to seek recovery in a future rate proceeding, and that Unitil Energy’s and Northern Utilities’ respective pending rate cases are the appropriate venue to address incremental bad debt and/or waived late payment fees resulting from the COVID-19 public health emergency orders and directives.

Northern Utilities / Granite State—Firm Capacity Contract

—Northern Utilities relies on the transport of gas supply over its affiliate Granite State pipeline to serve its customers in the Maine and New Hampshire service territories.

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.

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

Pursuant to statutory requirements in Maine and orders of the MPUC, Northern Utilities submits an annual informational report requesting approval of a one-year

extension of its 12-month

contract for firm pipeline capacity reservation, with an evergreen provision and three-month termination notification requirement.

On May 13, 2020, the MPUC approved Northern Utilities’ request to extend its contract for firm transmission service on its affiliate Granite State pipeline for another year, extending the current contract for the period of November 1, 2020 through October 31, 2021.

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

On March 30, 2021, Northern Utilities submitted an annual informational report requesting approval on a one-year extension for the period of November 1, 2021 through October 31, 2022.

The MPUC approved the request on June 29, 2021.

Reconciliation Filings

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

Fitchburg—Massachusetts RFPs—

Pursuant to a comprehensive energy law enacted in 2016, “An Act to Promote Energy Diversity,” (the Act) under Section 83C, the Massachusetts electric distribution

companies (EDCs), including Fitchburg, are required to jointly solicit

proposals for long-term contracts for at least 400 megawatts (MW) of offshore wind energy generation by June 30, 2017, as part of a total of

1,600 MW of offshore wind the EDCs are directed to procure 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.

Unitil’s pro rata share of these contracts is approximately one percent.

Fitchburg—Massachusetts Request for Proposals (RFPs)—

Pursuant to a comprehensive energy law enacted in 2016, “An Act to Promote Energy Diversity,” (the Act) under Section 83C, the Massachusetts electric distribution companies (EDCs), including Fitchburg, are required to jointly solicit proposals for long-term contracts for at least 400 megawatts (MW) of offshore wind energy generation by June 30, 2017, as part of a total of 1,600 MW of offshore wind the EDCs are directed to procure 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.

pro rata share of these contracts is approximately one percent.

The EDCs issued the RFP for Section 83D Long-Term Contracts for Qualified Clean Energy Projects in March 2017, and after selection of final projects and negotiation, final contracts for 9,554,940

9,554,940 MWh of Qualified Clean Energy and associated Environmental Attributes from hydroelectric generation were filed in July 2018 for approval by the MDPU.

On June 25, 2019, the MDPU approved the power purchase agreements, 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 determined that the EDCs’ request for remuneration equal to 2.75 % of the contract payments is reasonable and in the public interest and approved the EDCs’ proposal to amend their respective tariffs to include the recovery of costs associated with the contracts.

The Massachusetts Supreme Judicial Court upheld the MDPU’s approval in an Order dated September 3, 2020.

MWh of Qualified Clean Energy and associated Environmental Attributes from Hydro-Quebec Energy Services (U.S.), Inc.

for hydroelectric generation were filed in July 2018 for approval by the MDPU.

On June 25, 2019, the MDPU approved the power purchase agreements, 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 determined that the EDCs’ request for remuneration equal

to 2.75 % of the contract payments is reasonable and in the public interest and approved the EDCs’ proposal to amend their respective tariffs to include the recovery of costs associated with the contracts.

The Massachusetts Supreme Judicial Court upheld the MDPU’s approval in an opinion dated September 3, 2020.

The Company believes the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg, once certain conditions and contingencies are met.

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The Company believes that the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg, once certain conditions and contingencies are met.

The EDCs issued a second RFP pursuant to Section 83C for Long-Term Contracts for Offshore Wind Energy Generation on May 23, 2019.

This solicitation sought to procure the remaining obligation under 83C to procure an additional 800 MW of offshore wind energy generation.

The EDCs selected an 800 MW project submitted by Mayflower Wind and contracts were executed on January 10, 2020.

This solicitation sought to procure the obligation remaining under 83C at the time, an additional 800 MW of offshore wind energy generation.

The EDCs selected an 800 MW project submitted by Mayflower Wind Energy LLC and contracts were executed on January 10, 2020.

A filing with the MDPU for approval of two long-term contracts, each for 400 MW of offshore wind energy generation, was made on February 10, 2020.

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The MDPU also determined that the EDCs’ request for remuneration equal to 2.75 % is reasonable and in the public interest.

On November 25, 2020 the Office of the Attorney General filed a Motion for Reconsideration regarding the MDPU’s order as it relates to remuneration.

The matter is still pending at the MDPU.

The Company believes the power

purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg, once certain conditions and contingencies are met.

In accordance with the requirement of Chapter 227 of the Acts of 2018, An Act to Advance Clean Energy, signed August 9, 2018, Massachusetts Department of Energy Resources (MDOER) prepared a report on the necessity, benefits and costs of requiring the EDCs to competitively conduct offshore wind

generation RFPs for up to an additional

The MDOER filed its report with the Legislature in May,

2019 , recommending that, “the EDCs should proceed with additional offshore wind solicitations for up to

1,600 MW of offshore wind in

2024 and only enter into contracts if found to be cost-effective.” On March

2021 , Fitchburg, along with the other EDCs, filed a petition with the MDPU for approval of a proposed timetable and method of solicitation and execution of long-term contracts for up to an additional

1,600 MW of off shore wind generation.

2021 , the DPU approved the proposed timetable and method for the solicitation, and the RFP was issued on May

2021 , the EDCs selected a

1,600 MW portfolio of offshore wind generation that includes a

1,200 MW project submitted by Vineyard Wind and a

400 MW project submitted by Mayflower Wind.

Contract negotiations are expected to be completed by the end of

March 2022 and submitted for approval to the MDPU by the end

Section 83C of Chapter 169 of the Acts of 2008 was recently amended by the Acts of 2021 to increase the aggregate amount of offshore wind capacity to be procured to 5,600 MW not later than June 30, 2027.

After considering

the two approved offshore wind contracts of 800 MW each and the most recent selection of 1,600 MW there is

another 2,400 MW of offshore wind capacity to be procured in the future.

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’ Regional Network Service and Local Network Service formula rates.

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Circuit (the Court) issued an opinion vacating a decision of the FERC with respect to the ROE, and remanded it for further proceedings.

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

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

The Court found that the FERC had failed to articulate a satisfactory explanation for its orders.

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Separately, on March 15, 2018, the Transmission Owners filed a petition for review with the Court of certain orders of the FERC setting for hearing other complaints challenging the allowed Return on Equity component of the formula rates.

On November 21, 2019 the FERC issued an order in EL14-12,

Midcontinent Independent System Operator ROE, in which FERC outlined a new

methodology for calculating the ROE.

In response to the FERC order in EL 14-12,

the New England Transmission Owners (NETOs) filed a motion to reopen the record, which has been granted.

On November 21, 2019 the FERC issued an order in EL14-12, Midcontinent Independent System Operator ROE, in which FERC outlined a new methodology for calculating the ROE.

In response to the FERC order in EL 14-12, the New England Transmission Owners (NETOs) filed a motion to reopen the record, which has been granted.

This matter remains pending.

The FERC Section 206 proceeding concerning the justness and reasonableness of ISO-New

England, Inc.

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

The FERC Section 206 proceeding concerning the justness and reasonableness of ISO-New England, Inc.

Participating Transmission Owners’ Regional Network Service and Local Network Service formula rates and to develop formula rate protocols for these rates has been resolved.

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The procedural schedule was suspended September 24, 2019 in order to allow participants to focus on settlement negotiations.

On October 24, 2019, the NETO’s filed an unopposed motion to suspend the procedural schedule and waiver of answer period indicating that the NETO’s, Municipal Pool Transmission Facility Owners and the Commission Trial Staff have reached agreement in principle on the terms of a settlement to resolve all open issues in the proceeding.

On October 24, 2019, the NETOs filed an unopposed motion to suspend the procedural schedule and waiver of answer period indicating that the NETOs, Municipal Pool Transmission Facility Owners and the Commission Trial Staff have reached agreement in principle on the terms of a settlement to resolve all open issues in the proceeding.

On June 15, 2020 a settlement was filed.

The FERC approved the settlement agreement on December 28, 2020.

Under the terms of the settlement agreement, the negotiated formula rates will take effect on January 1, 2022.

Pursuant to the terms of the settlement agreement, the negotiated formula rates took effect on January 1, 2022.

Fitchburg and Unitil Energy are Participating Transmission Owners, although Unitil Energy does not own transmission plant.

To the extent that these proceedings result in any changes to the rates being charged, a retroactive reconciliation may be required.

To the extent these proceedings result in any changes to the rates being charged, a retroactive reconciliation may be required.

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

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Electric Supply Contracts

The Company and its subsidiaries have material energy supply commitments (see Note 7 (Energy Supply)).

The Company and its subsidiaries have material energy supply commitments (see Note 6

(Energy Supply)).

Cash outlays for the purchase of electricity and natural gas to serve customers are subject to reconciling recovery through periodic changes in rates, with carrying charges on deferred balances.

From year to year, there are likely to be timing differences associated with the cash recovery of such costs, creating under- or over-recovery situations at any point in time.

Rate recovery mechanisms are typically designed to collect the under-recovered cash or refund the over-collected cash over subsequent periods of less than a year.

Rate recovery mechanisms are typically designed to collect the

under-recovered cash or refund the over-collected cash over subsequent periods of less than a year.

Legal Proceedings

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However, the Company cannot assure that significant costs and liabilities will not be incurred in the future.

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 the Company’s 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.

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

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

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

both the review and extension are expected to be completed by the end of the second quarter of 2021.

While any recommendation is subject to approval by the NH DES, the Company has accrued $ 0.8 million for estimated costs to complete the remediation at the Rochester site, which is included in the Environmental Obligations table below.

In June 2020, the NH DES

coupled the submittal of the review to a proposed extension of the gas distribution system by Northern Utilities.

Northern Utilities submitted the review in January 2022.

In anticipation of the NH DES approval of the work plan, the Company has accrued $0.8 million for estimated costs to complete the remediation at the Rochester site, which is included in Environmental Obligations.

The NHPUC and MPUC have approved regulatory mechanisms for the recovery of MGP environmental costs.

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

Additionally, in November 2020, the Mass DEP conducted an audit of the final remediation solution at Sawyer Passway.

Site security improvements were required by the Mass DEP, which Fitchburg will complete in early 2021.

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.

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

FGE began the investigation in November 2021 with an anticipated completion by June 2022.

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

Fitchburg recovers the environmental response costs incurred at this former MGP site in gas rates pursuant to the terms of a cost recovery agreement approved by the MDPU.

Pursuant to this agreement, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods.

The following table sets forth a summary of changes in the Company’s liability for the current and long-term portions of the Company’s environmental obligations, which are included in Other Current Liabilities and Other Noncurrent Liabilities, respectively, on the Company’s Consolidated Balance Sheets as of December 31, 2020 and 2019.

Environmental Obligations

Unitil Energy—Kensington Distribution Operations Center

—Unitil Energy conducted a Phase I and II environmental site assessment (ESA) in the second quarter of 2021.

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

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

Unitil Energy began the SSI in December 2021 with an anticipated completion June 2022.

The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the years-ended December 31, 2021 and 2020.

Environmental Obligations ($ millions)

Total Balance at Beginning of Period

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Current Portion

Noncurrent Balance at December 31,

Provisions for Federal and State Income Taxes reflected as operating expenses in the accompanying consolidated statements of earnings for the years ended December 31, 2020, 2019 and 2018 are shown in the following table:

Noncurrent Balance at End of Period

Provisions for Federal and

State Income Taxes reflected

as operating expenses in the accompanying consolidated statements of earnings for the years ended December 31, 2021, 2020 ,

and 2019 are shown in the following table:

(in millions)

Current Income Tax Provision

Total Current Income Taxes

Deferred Income Provision

Deferred Income Tax Provision

Total Deferred Income Taxes

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Temporary differences which gave rise to deferred tax assets and liabilities in 2021 and 2020 are shown in the following table:

Temporary Differences (000’s)

Temporary Differences (in millions)

Deferred Tax Assets

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The Company has evaluated its tax positions at December 31, 2021 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, de-recognition,

settlement or foreseeable future events to any tax liabilities or assets as defined by the FASB Codification is required.

settlement or foreseeable future

events to any tax liabilities or assets as defined by the FASB Codification is required.

The Company remains subject to examination by Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2020;

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and December 31, 2018.

Income tax filings for the year ended December 31, 2019 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, 2019 which were filed with the IRS in October 2020, the Company utilized federal NOLC assets of

As of December 31, 2020, the Company had recognized the utilization of the remaining federal NOLC assets of

million to offset against taxes current payable.

The Company received

million of the Alternative Minimum Tax (AMT) credits in 2019 and will receive

million of the AMT credits in 2021 as provided for in the CARES Act.

Income tax filings

for the year ended December 31, 2020 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, 2020 which were filed with the IRS in October 2021, the Company generated federal Net Operating Loss Carryforward (NOLC) assets of $ 7.7 million, principally due to tax repairs expense and tax depreciation.

As of December 31, 2021, the Company recognized the utilization of approximately

$ 3.6 million of the NOLC asset to offset current taxes payable.

In addition, at December 31, 2021, the Company had $

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

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

The Company has evaluated these items and determined that the items do not have a material impact on the Company’s financial statements as of December 31, 2020.

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

50 % credit on employee wages for employees that are retained and cannot perform their job duties at

capacity as a result of coronavirus pandemic restrictions.

The ERC is take as a credit on employment tax form 941.

In the third quarter of 2020, the Company recorded an ERC of

million as a reduction to employment tax expense which is recorded as a reduction to Taxes other than Income Taxes in the consolidated statement of earnings .

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.

The Company evaluated these items in its tax computation as of December 31, 2020 and determined that the items do not have a material impact on the Company’s financial statements as of December 31, 2020.

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.

The Company has evaluated each of the CARES, CAA and ARPA

provisions and determined that they do not have a material effect on the Company’s financial statements as of December 31, 2021.

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.

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

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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.

In addition to the $ 48.9 million of net excess ADIT noted above, as of December 31, 2018, there was $ 2.0 million of remaining excess ADIT created by the recognition of Net Operating Loss Carryforward assets (NOLC), discussed below, and related to the implementation of the new federal tax rate of the TCJA, which had not been previously included in utility rates.

The Company recognized the benefit of this excess ADIT in accordance with the regulatory treatment of excess ADIT for each of jurisdiction.

In addition to the $ 48.9 million of net excess ADIT, as of December 31, 2018, there was $ 2.0 million of remaining excess ADIT created by the recognition of NOLC, and related to the implementation of the new federal tax rate of the TCJA, which had not been previously included in utility rates.

The Company recognized the benefit of this excess ADIT in accordance with the regulatory treatment of excess ADIT for each jurisdiction.

In 2019, the Company recognized $ 1.7 million of this amount and the remaining $ 0.3 million was recognized in

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

Based on communications received by the Company from its state regulators in rate cases and other regulatory proceedings in the first quarter of 2018 and as prescribed in the TCJA, the recent FERC guidance noted above and IRS normalization rules, the benefit of these protected excess ADIT amounts will be subject to flow back to customers in future utility rates according to the Average Rate Assumption Method (ARAM).

ARAM reconciles excess ADIT at the reversal rate of the underlying book/tax temporary timing differences.

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As of December 31, 2021, the Company flowed back $ 3.1 million to customers in its Massachusetts, Maine, and federal jurisdictions.

New Hampshire liabilities will begin to flow back once rate proceedings have finalized in that jurisdiction.

New Hampshire liabilities will begin to flow back once rate proceedings have finalized

in that jurisdiction.

Retirement Benefit Plans

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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 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:

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NPBC Recognized

The Company bases the actuarial determination of pension expense on a market-related valuation of assets, which reduces year-to-year volatility.

This market-related valuation recognizes investment gains or losses over a three-year period from the year in which they occur.

The Company bases the actuarial determination of pension expense on a market-related valuation of assets, which reduces year-to-year

This market-related valuation recognizes investment ga i

over a three-year period from the year in which they occur.

Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets.

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 2020, 2019 and 2018 before capitalization and deferral was

$ 6.9 million, $ 5.8 million and $ 7.6 million, respectively.

Company’s pension expense for the years 2021, 2020 and 2019 before capitalization and deferral was $ 7.2 million, $ 6.9 million and $ 5.8 million, respectively.

Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2021, 2020 and 2019 would have been $ 6.1 million, $ 6.5 million and $ 7.3 million respectively, prior to amounts capitalized or deferred.

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Assets vs PBO

The increases in the PBO for the Pension and PBOP plans as of December 31, 2020 compared to December 31, 2019 reflects a decrease in the assumed discount rate as of December 31, 2020.

The decrease in the PBO for the Pension plan as of Dece m

ber 31, 2021 compared to December 31, 2020 primarily reflects an increase in the assumed discount rate as of December 31, 2021.

The funded status of the Pension, PBOP and SERP Plans is calculated based on the difference between the benefit obligation and the fair value of plan assets and is recorded on the balance sheets as an asset or a liability.

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The Accumulated Benefit Obligation (ABO) is required to be disclosed for all plans where the ABO is in excess of plan assets.

The difference between the PBO and the ABO is that the PBO includes projected

compensation increases.

The difference between the PBO and the ABO is that the PBO includes projected compensation increases.

The ABO for the Pension Plan was $ 185.1 million and $ 189.4 million as of December 31, 2021 and 2020, respectively.

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

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

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

The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan in 2022 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 following table represents employer contributions, participant contributions and benefit payments ( 000

Employer Contributions

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Benefit Payments

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

The following table represents estimated future

payments (000’s).

Estimated Future Benefit Payments

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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.

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, 2021 and 2020 are as follows (000’s):

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Cash Equivalents

Total Assets in the Fair Value

Real Estate Fund–Measured at Net

Fair Value Measurements at Reporting Date Using

Balance as of

Total Assets in the Fair Value Hierarchy

Real Estate Fund–Measured at Net Asset Value

Pension Plan Assets:

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

What changed 10-K

Item 8. Financial Statements and Supplementary Data