0001193125-22-023936 | 10-K | XBRL Viewer

Operating Lease Right of Use Assets

108.9

127.4

4.7

5.2

Other Assets

9.8

12.8

Total Other Noncurrent Assets

123.4

145.4

TOTAL ASSETS

1,540.3

1,477.9

Current Liabilities:

Accounts Payable

1.6

33.2

Short-Term Debt

64.1

54.7

Long-Term Debt, Current Portion

^[1]

8.2

8.5

Energy Supply Obligations

9.5

5.5

14.5

10.4

Environmental Obligations

0.5

0.3

Other Current Liabilities

24.3

23.5

Total Current Liabilities

173.5

136.1

Noncurrent Liabilities:

Retirement Benefit Obligations

133.9

162.3

Deferred Income Taxes, net

127.7

109.0

Cost of Removal Obligations

107.5

105.2

Environmental Obligations

42.6

44.3

2.2

1.8

Other Noncurrent Liabilities

6.6

6.9

Total Noncurrent Liabilities

420.5

429.5

Capitalization:

Long-Term Debt, Less Current Portion

497.8

523.1

Stockholders' Equity:

Common Equity (Outstanding 15,977,766 and 15,012,310 Shares)

332.1

285.3

Retained Earnings

116.2

103.7

Total Common Stock Equity

448.3

389.0

Preferred Stock

0.2

Total Stockholders' Equity

448.5

389.2

Total Capitalization

946.3

912.3

Commitments and Contingencies (Note 7)

TOTAL LIABILITIES AND CAPITALIZATION

$ 1,540.3

$ 1,477.9

[1]	The Current Portion of Long-Term Debt includes sinking fund payments.

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2021	Dec. 31, 2020
Common Equity Outstanding	15,977,766	15,012,310

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Activities:
Net Income	$ 36.1	$ 32.2	$ 44.2
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	59.5	54.5	52.0
Deferred Tax Provision	10.8	9.3	13.5
Gain on Divestiture, net (See Note 1)			(13.4)
Changes in Working Capital Items:
Accounts Receivable	(4.9)	(6.9)	11.7
Accrued Revenue	(10.3)	(0.9)	4.7
Regulatory Liabilities	4.0	(1.9)	(4.1)
Exchange Gas Receivable	(2.5)	1.2	2.0
Accounts Payable	19.2	(4.4)	(5.0)
Other Changes in Working Capital Items	0.7	(2.4)	4.6
Deferred Regulatory and Other Charges	(2.7)	(9.3)	(5.3)
Other, net	(2.1)	4.3
Cash Provided by Operating Activities	107.8	75.7	104.9
Investing Activities:
Property, Plant and Equipment Additions	(115.0)	(122.6)	(119.2)
Proceeds from Divestiture, Net (See Note 1)			13.4
Cash Used In Investing Activities	(115.0)	(122.6)	(105.8)
Financing Activities:
Proceeds from (Repayment of) Short-Term Debt, net	9.4	(3.9)	(24.2)
Issuance of Long-Term Debt		99.7	70.0
Repayment of Long-Term Debt	(25.8)	(24.8)	(18.8)
Long-Term Debt Issuance Costs		(0.6)	(0.4)
Decrease in Capital Lease Obligations	(0.1)	(0.1)	(5.3)
Net Increase (Decrease) in Exchange Gas Financing	2.3	(1.1)	(2.0)
Dividends Paid	(23.6)	(22.6)	(22.1)
Proceeds from Issuance of Common Stock	45.5	1.1	1.1
Cash Provided by (Used In) Financing Activities	7.7	47.7	(1.7)
Net Increase (Decrease) in Cash and Cash Equivalents	0.5	0.8	(2.6)
Cash and Cash Equivalents at Beginning of Year	6.0	5.2	7.8
Cash and Cash Equivalents at End of Year	6.5	6.0	5.2
Supplemental Information:
Interest Paid	26.0	23.7	24.1
Income Taxes Paid	1.4	0.9	0.8
Payments on Capital Leases	0.2	0.3	5.5
Capital Expenditures Included in Accounts Payable	4.9	1.7	0.6
Right-of-Use Assets Obtained in Exchange for Lease Obligations	$ 0.7	$ 1.2	$ 4.0

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY - USD ($) $ in Millions	Total	Common Equity	Retained Earnings
Beginning Balance at Dec. 31, 2018	$ 351.1	$ 279.1	$ 72.0
Net Income	44.2		44.2
Dividends on Common Shares	(22.1)		(22.1)
Shares Issued Under Stock Plans	2.3	2.3
Issuance of Common Shares	1.1	1.1
Ending Balance at Dec. 31, 2019	376.6	282.5	94.1
Net Income	32.2		32.2
Dividends on Common Shares	(22.6)		(22.6)
Shares Issued Under Stock Plans	1.7	1.7
Issuance of Common Shares	1.1	1.1
Ending Balance at Dec. 31, 2020	389.0	285.3	103.7
Net Income	36.1		36.1
Dividends on Common Shares	(23.6)		(23.6)
Shares Issued Under Stock Plans	1.3	1.3
Issuance of Common Shares	45.5	45.5
Ending Balance at Dec. 31, 2021	$ 448.3	$ 332.1	$ 116.2

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

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Summary of Significant Accounting Policies

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Parenthetical) - $ / shares		12 Months Ended
	Aug. 06, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Dividends per Common Share		$ 1.52	$ 1.50	$ 1.48
Common stock, shares issued	800,000	942,316	23,658	20,065

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Note 1: Summary of Significant Accounting Policies

Nature of Operations

—

Unitil Corporation (Unitil or the Company) is a public utility holding company. Unitil and its subsidiaries are subject to regulation as a holding company system by the Federal Energy Regulatory Commission (FERC) under the Energy Policy Act of 2005. The following companies are wholly-owned subsidiaries of Unitil: Unitil Energy Systems, Inc. (Unitil Energy), Fitchburg Gas and Electric Light Company (Fitchburg), Northern Utilities, Inc. (Northern Utilities), Granite State Gas Transmission, Inc. (Granite State), Unitil Power Corp. (Unitil Power), Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) and its non-regulated business unit Unitil Resources, Inc. (Unitil Resources).

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

Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and capital city areas of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. 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, 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. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.

A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, on May 1, 2003 Unitil Power ceased being the wholesale supplier of Unitil Energy and divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers. In the period since, Unitil Power continued to flow revenues and expenses from remaining contracts to Unitil Energy under the Amended Unitil System Agreement. The last of those contracts expired October 31, 2020, and the Company no longer has material revenues or expenses associated

with those contracts.

Unitil also has three other wholly-owned subsidiaries: Unitil Service, Unitil Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned

non-regulated

subsidiary. Usource, Inc. and Usource L.L.C. (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 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. 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

Principles of Consolidation

—

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

Use of Estimates

—

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

Fair Value

—

The Financial Accounting Standards Board (FASB) Codification defines fair value, and establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under the FASB Codification include:


Level 1—		Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—		Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly.

Level 3—		Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.

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

Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure. Therefore, even when market assumptions are not readily available, the Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date. The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation. In periods of market dislocation, the observability of prices and inputs may be reduced for many instruments. This condition could cause an instrument to be reclassified from Level 1 to Level 2 or from Level 2 to Level 3.

There have been no changes in the valuation techniques used during the current period.

Utility Revenue Recognition

—

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. Revenue from rate adjustment mechanisms is accrued revenue, recognized in connection with rate adjustment mechanisms, and authorized by regulators for recognition in the current period for future cash recoveries from, or credits to, customers.

Billed and unbilled revenue is recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenues are calculated. These unbilled revenues are estimated each month based on estimated customer usage by class and applicable customer rates, taking into account current and historical weather data, assumptions pertaining to metering patterns, billing cycle statistics, and other estimates and assumptions, and are then reversed in the following month when billed to customers.

A majority of the Company’s revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customer monthly consumption. Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer.

The Company’s billed and unbilled rev

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. In cases where allowable costs are greater than operating revenues billed in the current period for the individual rate adjustment mechanism additional operating revenue is recognized. In cases where allowable costs are less than operating revenues billed in the current period for the individual rate adjustment mechanism, operating revenue is reduced. ASC 606 requires the Company to disclose separately the amount of revenues from contracts with customers and alternative revenue program revenues.

In the following tables, revenue is classified by the types of goods/services rendered and market/customer type.


	Twelve Months Ended December 31, 2021
Electric and Gas Operating Revenues (millions):	Electric		Gas		Total
Billed and Unbilled Revenue:
Residential	$	135.1	$	83.9	$	219.0
Commercial & Industrial		103.3		124.1		227.4
Other		10.1		9.6		19.7

Total Billed and Unbilled Revenue		248.5		217.6		466.1
Rate Adjustment Mechanism Revenue		—		7.2		7.2

Total Electric and Gas Operating Revenues	$	248.5	$	224.8	$	473.3


	Twelve Months Ended December 31, 2020
Electric and Gas Operating Revenues (millions):	Electric		Gas		Total
Billed and Unbilled Revenue:
Residential	$	128.7	$	73.1	$	201.8
Commercial & Industrial		91.4		104.5		195.9
Other		6.6		7.6		14.2

Total Billed and Unbilled Revenue		226.7		185.2		411.9
Rate Adjustment Mechanism Revenue		0.5		6.2		6.7

Total Electric and Gas Operating Revenues	$	227.2	$	191.4	$	418.6


	Twelve Months Ended December 31, 2019
Electric and Gas Operating Revenues (millions):	Electric		Gas			Total
Billed and Unbilled Revenue:
Residential	$	121.5	$	81.4		$	202.9
Commercial & Industrial		93.8		120.1			213.9
Other		7.8		10.6			18.4

Total Billed and Unbilled Revenue		223.1		212.1			435.2
Rate Adjustment Mechanism Revenue		10.8		(8.7	)		2.1

Total Electric and Gas Operating Revenues	$	233.9	$	203.4		$	437.3

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. 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). The Company estimates that revenue decoupling applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.

The Company bills its customers for sales tax in Massachusetts and Maine. These taxes are remitted to the appropriate departments of revenue in each state and are excluded from revenues on the Company’s Consolidated Statements of Earnings.

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. Usource did not take title to the electric and gas commodities which were the subject of the brokerage contracts. The Company recorded energy brokering revenues based upon the amount of electricity and gas delivered to customers through the end of the accounting period. Usource partnered with certain entities to facilitate these brokerage services and paid these entities a fee under revenue sharing agreements.

Depreciation and Amortization

—

Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets, and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company’s fixed assets. A change in the estimated useful lives of these assets could have a material effect on the Company’s consolidated financial statements. Provisions for depreciation were equivalent to the following composite rates, based on the average depreciable property balances at the beginning and end of each year: 2021 – 3.29%, 2020 – 3.34% and 2019 – 3.41%.

Stock-based Employee Compensation

—

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

Income Taxes

—

The Company is subject to Federal and State income taxes as well as various other business taxes. The Company’s process for determining income tax amounts involves estimating the Company’s current tax liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included in the Company’s Consolidated Balance Sheets. The Company accounts for income tax assets, liabilities and expenses in accordance with the FASB Codification guidance on Income Taxes. 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. 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. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known.

Dividends

—The Company’s dividend policy is reviewed periodically b

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, 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

—Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England

(ISO-NE)

Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to

ISO-NE.

Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately

2-1/2

months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. On December 31, 2021 and 2020, the Unitil subsidiaries had deposited $2.7 million and $2.4 million, respectively, to satisfy their

ISO-NE

obligations.

Financial Instruments

—In June 2016, the Financial Accounting Standards Board issued ASU

2016-13,

“Financial Instruments—Credit Losses (Topic 326)”, which provides a new model for recognizing credit losses on financial instruments based on an estimate of current expected credit losses. Under the new guidance, immediate recognition of all credit losses expected over the life of a financial instrument is required. The Company adopted this standard on the accounting for credit losses on its financial instruments, including accounts receivable, on January 1, 2020, and it did not have a material effect on the financial statements.

Allowance for Doubtful Accounts

—

The Company recognizes a provision for doubtful accounts that reflects the Company’s estimate of expected credit losses for electric and gas utility service accounts receivable. The allowance for doubtful accounts is calculated by applying a historical loss rate to customer account balances and management’s assessment of current and expected economic conditions, customer trends, or other factors 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. Evaluating the adequacy of the allowance for doubtful accounts requires judgment about the assumptions used in the analysis. The Company’s experience has been that the assumptions used in evaluating the adequacy of the allowance for doubtful accounts have proven to be reasonably accurate. See Note 3 (Allowance for Doubtful Accounts).

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.

Accrued Revenue—

Accrued Revenue includes the current portion of Regulatory Assets (see “Regulatory Accounting”) and unbilled revenues (see “Utility Revenue Recognition”). The following table shows the components of Accrued Revenue as of December 31, 2021 and 2020.


Accrued Revenue (millions)	December 31,
Accrued Revenue (millions)	2021		2020
Regulatory Assets—Current	$	47.4	$	37.3
Unbilled Revenues		13.8		13.6

Total Accrued Revenue	$	61.2	$	50.9

Exchange Gas Receivable

—

Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party. 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. The following table shows the components of Exchange Gas Receivable as of December 31, 2021 and 2020.


Exchange Gas Receivable (millions)	December 31,
Exchange Gas Receivable (millions)	2021		2020
Northern Utilities	$	6.7	$	4.4
Fitchburg		0.7		0.5

Total Exchange Gas Receivable	$	7.4	$	4.9

Gas Inventory

—The Company uses the weighted average cost methodology to value natural gas inventory. The following table shows the components of Gas Inventory as of December 31, 2021 and 2020.


Gas Inventory (millions)	December 31,
Gas Inventory (millions)	2021		2020
Natural Gas	$	0.5	$	0.2
Propane		0.4		0.3
Liquefied Natural Gas & Other		0.1		0.1

Total Gas Inventory	$	1.0	$	0.6

The Company also has an inventory of Materials and Supplies in the amounts of $8.6 million and $8.5 million as of December 31, 2021 and December 31, 2020, respectively. These amounts are recorded at weighted average cost.

Utility Plant

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

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.

The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At December 31, 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 Sh

ets in Cost of Removal Obligations.

Regulatory Accounting

—

The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the MDPU, Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC) and Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the FASB Codification. 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)	December 31,
Regulatory Assets consist of the following (millions)	2021		2020
Retirement Benefits	$	86.4	$	103.7
Energy Supply & Other Rate Adjustment Mechanisms		44.1		34.1
Deferred Storm Charges		3.3		4.1
Environmental		4.6		5.2
Income Taxes		2.6		3.4
Other Deferred Charges		15.3		14.2

Total Regulatory Assets		156.3		164.7
Less: Current Portion of Regulatory Assets (1)		47.4		37.3

Regulatory Assets—noncurrent	$	108.9	$	127.4

(1)

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


Regulatory Liabilities consist of the following (millions)	December 31,
Regulatory Liabilities consist of the following (millions)	2021		2020
Rate Adjustment Mechanisms	$	7.7	$	4.1
Income Taxes		44.3		45.5
Other		0.1		0.2

Total Regulatory Liabilities		52.1		49.8
Less: Current Portion of Regulatory Liabilities		9.5		5.5

Regulatory Liabilities—noncurrent	$	42.6	$	44.3

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, 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 Regul

ted

Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

Leases

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

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 o

er the lease term. See additional discussion in the “Leases” section of Note

(Debt and Financing Arrangements).

Derivatives

—

The Company’s regulated energy subsidiaries enter into energy supply contracts to serve their electric and gas customers. The Company follows a procedure for determining whether each contract qualifies as a derivative instrument under the guidance provided by the FASB Codification on Derivatives and Hedging. For each contract, the Company reviews and documents the key terms of the contract. Based on those terms and any additional relevant components of the contract, the Company determines and documents whether the contract qualifies as a derivative instrument as defined in the FASB Codification. The Company has determined that its energy supply contracts either do not qualify as a derivative instrument under the guidance set forth in the FASB Codification, have been elected as normal purchase, or have contingencies that have not yet been met in order to establish a notional amount.

The Company had no derivative assets or liabilities recorded on its Consolidated Balance Sheets as of December 31, 2021 and December 31, 2020. There were no losses / (gains) recognized in Regulatory Assets / Liabilities for the years ended December 31, 2021 and 2020. There were no losses / (gains) reclassified into the Consolidated Statements of Earnings for the years ended December 31, 2021, 2020 and 2019.

Fitchburg has entered into power purchase agreements for which contingencies exist (see “Fitchburg – Massachusetts RFP’s” section of Note 7 (Commitments and Contingencies). Until these contingencies are satisfied, these contracts will not qualify for derivative accounting. The Company believes that the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg.

Investments in Marketable Securities

—

The Company maintains a trust through which it invests in a money market fund. This fund is intended to satisfy obligations under the Company’s Supplemental Executive Retirement Plan (SERP) (See additional discussion of the SERP in Note 9 (Retirement Benefit Plans)).

At December 31, 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. Changes in the fair value of these investments are recorded in Other (Income) Expense, Net.


Fair Value of Marketable Securities (millions)	December 31,
	2021		2020
Money Market Funds	$	5.7	$	5.7

Total Marketable Securities	$	5.7	$	5.7

The Company also sponsors the Unitil Corporation Deferred Compensation Plan (the DC Plan). The DC Plan is a

non-qualified

deferred compensation plan that provides a vehicle for participants to accumulate

tax-deferred

savings to supplement retirement income. The DC Plan, which was effective January 1, 2019, is open to senior management or other highly compensated employees as determined by the Company’s Board of Directors, and may also be used for recruitment and retention purposes for newly hired senior executives. The DC Plan design mirrors the Company’s Tax Deferred Savings and Investment Plan formula, but provides for contributions on compensation above the IRS limit, which will allow

participants to defer up to 85% of base salary, and up to 85% of any cash incentive for retirement. The Company may also elect to make discretionary contributions on behalf of any participant in an amount determined by the Company’s Board of Directors. A trust has been established to invest the funds associated with the DC Plan.

At December

31, 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. Changes in the fair value of these investments are recorded in Other (Income) Expense, Net.


Fair Value of Marketable Securities (millions)	December 31,
	2021		2020
Equity Funds	$	0.2	$	0.2
Money Market Funds		0.4		0.3

Total Marketable Securities	$	0.6	$	0.5

Energy Supply Obligations

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


	December 31,
Energy Supply Obligations consist of the following: (millions)	2021		2020
Renewable Energy Portfolio Standards	$	7.8	$	5.7
Exchange Gas Obligation		6.7		4.4
Power Supply Contract Divestitures		—		0.3

Total Energy Supply Obligations	$	14.5	$	10.4

Renewable Energy Portfolio Standards

—Renewable Energy Portfolio Standards (RPS) require retail electricity suppliers, including public utilities, to demonstrate that required percentages of their sales are met with power generated from certain types of resources or technologies. Compliance is demonstrated by purchasing and retiring Renewable Energy Certificates (REC) generated by facilities approved by the state as qualifying for REC treatment. Unitil Energy and Fitchburg purchase RECs in compliance with RPS legislation in New Hampshire and Massachusetts for supply provided to default service customers. 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. 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 e

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

—

Northern Utilities enters into gas exchange agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. The gas inventory related to these agreements is recorded in Exchange Gas Receivable on the Company’s Consolidated Balance Sheets while the corresponding obligations are recorded in Energy Supply Obligations.

Power Supply Contract Divestitures—

Unitil Energy’s and Fitchburg’s customers are entitled to purchase their electric or natural gas supplies from third-party suppliers. In connection with the implementation of retail ch

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, 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

—The Company sponsors the Pension Plan, which is a defined benefit pension plan. Effective January 1, 2010, the Pension Plan was closed to new

non-union

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

non-qualified

retirement plan, the SERP, covering certain executives of the Company, and an employee 401(k) savings plan. Additionally, the Company sponsors the PBOP Plan, primarily to provide health care and life insurance benefits to retired employees.

The Company records on its balance sheets as an asset or liability the overfunded or underfunded status of its retirement benefit obligations (RBO) based on the projected benefit obligations. The Company has recognized a corresponding Regulatory Asset, reflecting ultimate recovery from customers through rates. The regulatory asset (or regulatory liability) is amortized as the actuarial gains and losses and prior service cost are amortized to net periodic benefit cost for the Pension and PBOP plans. All amounts are remeasured annually. (See Note 9 Retirement Benefit Plans).

Commitments and Contingencies

—The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of December 31, 2021, the Company is not aware of any material commitments or contingencies other than those disclosed in Note

(Commitments and Contingencies).

Environmental Matters

—The Company’s past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. The Company has recovered or will recover substantially all of the costs of the environmental remediation work performed to date from customers or from its insurance carriers. The Company believes it is in compliance with all applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2021, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note

(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 n

t recoverable in regulatory rate mechanisms.

Subsequent Events

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

Segment Information

12 Months Ended

Dec. 31, 2021

Segment Information

Note 2: Segment Information

Unitil reports three segments: 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. 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.

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. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transmission services provided to Northern Utilities and, to a lesser extent, third-party marketers. Granite State is included in the utility gas operations segment.

Unitil Resources is the Company’s wholly-owned

non-regulated

subsidiary. Usource, Inc. 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. Usource provided brokering and advisory services to large commercial and industrial customers in the northeastern United States. Unitil Realty and Unitil Service provide centralized facilities, operations and administrative services to support the affiliated Unitil companies. Unitil Resources and Usource are included in the

Non-Regulated

segment.

Unitil Realty, Unitil Service and the holding company are included in Other. Unitil Service provides centralized management and administrative services, including information systems management and financial record keeping. Unitil Realty owns certain real estate, principally the Company’s corporate headquarters. The earnings of the holding company are principally derived from income earned on short-term investments and real property owned for Unitil and its subsidiaries’ use.

The segments follow the same accounting policies as described in the Summary of Significant Accounting Policies. Intersegment sales take place at cost and the effects of all intersegment and/or intercompany transactions are eliminated in the consolidated financial statements. Segment profit or loss is based on profit or loss from operations after income taxes and preferred stock dividends. Expenses used to determine operating income before taxes are charged directly to each segment or are allocated based on cost allocation factors included in rate applications approved by the FERC, NHPUC, MDPU, and MPUC. Assets allocated to each segment are based upon specific identification of such assets provided by Company records.

The following tables provide significant segment financial data for the years ended December 31, 2021, 2020 and 2019 (millions)


Year Ended December 31, 2021	Electric		Gas			Non- Regulated			Other			Total

Revenues:

Billed and Unbilled Revenue	$	248.5	$	217.6		$	—		$	—		$	466.1

Rate Adjustment Mechanism Revenue		—		7.2			—			—			7.2


Total Operating Revenues		248.5		224.8			—			—			473.3


Interest Income		0.8		0.5			—			0.3			1.6

Interest Expense		9.0		15.3			—			2.9			27.2

Depreciation & Amortization Expense		25.9		32.6			—			1.0			59.5

Income Tax Expense (Benefit)		4.5		7.7			(0.1	)		(0.6	)		11.5

Segment Profit (Loss)		14.0		23.2			0.1			(1.2	)		36.1

Segment Assets		584.0		935.9			—			20.4			1,540.3

Capital Expenditures		38.1		75.8			—			1.1			115.0

Year Ended December 31, 2020

Revenues:

Billed and Unbilled Revenue	$	226.7	$	185.2		$	—		$	—		$	411.9

Rate Adjustment Mechanism Revenue		0.5		6.2			—			—			6.7


Total Operating Revenues		227.2		191.4			—			—			418.6


Interest Income		1.1		1.1			—			0.4			2.6

Interest Expense		8.7		14.2			—			3.5			26.4

Depreciation & Amortization Expense		23.8		29.8			—			0.9			54.5

Income Tax Expense (Benefit)		4.7		7.3			—			(1.8	)		10.2

Segment Profit		12.9		19.3			—			—			32.2

Segment Assets		571.8		886.3			—			19.8			1,477.9

Capital Expenditures		45.5		71.1			—			6.0			122.6

Year Ended December 31, 2019

Revenues:

Billed and Unbilled Revenue	$	223.1	$	212.1		$	—		$	—		$	435.2

Rate Adjustment Mechanism Revenue		10.8		(8.7	)		—			—			2.1

Other Operating Revenue—Non-Regulated		—		—			0.9			—			0.9


Total Operating Revenues		233.9		203.4			0.9			—			438.2


Interest Income		0.9		1.2			0.2			0.6			2.9

Interest Expense		9.4		14.4			—			2.8			26.6

Depreciation & Amortization Expense		22.6		28.5			—			0.9			52.0

Income Tax Expense (Benefit)		4.2		7.2			3.8			(1.4	)		13.8

Segment Profit		11.5		19.1			10.2			3.4			44.2

Segment Assets		529.3		823.3			0.3			17.9			1,370.8

Capital Expenditures		39.6		74.0			—			5.6			119.2

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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Allowance For Doubtful Accounts [Abstract]

Allowance for Doubtful Accounts

12 Months Ended

Dec. 31, 2021

Allowance for Doubtful Accounts

Note 3: Allowance for Doubtful Account

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 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 $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


	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Regulatory Deferrals*		Balance at End of Period
Year Ended December 31, 2021
Electric	$	1.6	$	3.3	$	0.4	$	3.4	$	0.1	$	2.0
Gas		1.7		2.3		0.4		3.1		—		1.3
Other		—		—		—		—		—		—

	$	3.3	$	5.6	$	0.8	$	6.5	$	0.1	$	3.3

Year Ended December 31, 2020
Electric	$	0.6	$	2.9	$	0.3	$	2.6	$	0.4	$	1.6
Gas		0.4		2.6		0.3		1.8		0.2		1.7
Other		—		—		—		—		—		—

	$	1.0	$	5.5	$	0.6	$	4.4	$	0.6	$	3.3

Year Ended December 31, 2019
Electric	$	0.5	$	3.0	$	0.3	$	3.2	$	—	$	0.6
Gas		0.8		1.9		0.5		2.8		—		0.4
Other		—		—		—		—		—		—

	$	1.3	$	4.9	$	0.8	$	6.0	$	—	$	1.0

COVID-19

Pandemic” section in Note

(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.

Debt and Financing Arrangements

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Debt and Financing Arrangements

Note 4: Debt and Financing Arrangements

The Company funds a portion of its operations through the issuance of long-term debt, and short-term borrowings under its revolving Credit Facility. The Company’s subsidiaries conduct a portion of their operations in leased facilities and lease some of their machinery, vehicles and office equipment.

Long-Term Debt and Interest Expense

Long-Term Debt Structure and Covenants

—

The debt agreements for Unitil and its utility subsidiaries, Unitil Energy, Fitchburg, Northern Utilities, and Granite State, contain various covenants and restrictions. These agreements do not contain any covenants or restrictions pertaining to the maintenance of financial ratios or the issuance of short-term debt. 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’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 ha

total funded indebtedness less than 70% of total capitalization, and earnings available for interest equal to at least two times the interest charges for funded indebtedness. Each future senior long-term debt issuance of Unitil will rank pari passu with all other senior unsecured long-term debt issuances. The Unitil long-term debt agreement requires that if Unitil defaults on any other future long-term debt agreement(s), it would constitute a default under Unitil’s present long-term debt agreement. Furthermore, the default provisions are triggered by the defaults of certain Unitil subsidiaries or certain other actions against Unitil subsidiaries.

Substantially all of the property of Unitil Energy is subject to liens of indenture under which First Mortgage Bonds (FMB) have been issued. In order to issue new FMB, the customary covenants of the existing Unitil Energy Indenture Agreement must be met, including that Unitil Energy have sufficient available net bondable plant to issue the securities and earnings available for interest charges equal to at least two times the annual interest requirement. The Unitil Energy agreements further require that if Unitil Energy defaults on any Unitil Energy FMB, it would constitute a default for all Unitil Energy FMB. The Unitil Energy default provisions are not triggered by the actions or defaults of Unitil or its other subsidiaries.

All of the long-term debt of Fitchburg, Northern Utilities and Granite State are issued under Unsecured Promissory Notes with negative pledge provisions. Each issue of long-term debt ranks pari passu with its other senior unsecured long-term debt within that subsidiary. The long-term debt’s negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt. Accordingly, in order for Fitchburg, Northern Utilities or Granite State to issue new long-term debt, the covenants of the existing long-term agreements of that subsidiary must be satisfied, including that the subsidiary have total funded indebtedness less than 65% of total capitalization. Additionally, to issue new long-term debt, Fitchburg must maintain earnings available for interest equal to at least two times the interest charges for funded indebtedness. As with the Unitil Energy agreements, the Fitchburg, Northern Utilities and Granite State long-term debt agreements each require that if that subsidiary defaults on any of its own long-term debt agreements, it would constitute a default under all of that subsidiary’s long-term debt agreements. None of the Fitchburg, Northern Utilities and Granite State default provisions are triggered by the actions or defaults of Unitil or any of its other subsidiaries.

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

Unitil Energy, Fitchburg, Northern Utilities and Granite State pay common dividends to their sole common shareholder, Unitil Corporation and these common dividends are the primary source of cash for the payment of dividends to Unitil’s common shareholders. The long-term debt issued by the Company and its subsidiaries contains certain covenants that determine the amount that the Company and each of these subsidiary companies has available to pay for dividends. As of December 31, 2021, in accordance with the covenants, these subsidiary companies had a combined amount of $358.7 million available for the payment of dividends and Unitil Corporation had $166.9 million available for the payment of dividends. As of December 31, 2021, the Company’s balance in Retained Earnings was $116.2 million. Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2021 for the payment of dividends.

Issuance of Long-Term Debt

—On December 18, 2020, Unitil Realty Corp. entered into a loan agreement in the amount of $4.7 million at 2.64%, with a maturity date of December 18, 2030. Less than $0.1 million of costs associated with this loan have been recorded as a reduction to the proceeds. Unitil Realty Corp. used the net proceeds from this loan for general corporate

purposes

On September 15, 2020, Northern Utilities issued $40

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

million of Notes due 2040 at 3.78%. Unitil Energy issued $27.5 million of Bonds due 2040 at 3.58%. Northern Utilities, Fitchburg and Unitil Energy used the net proceeds from these offerings to repay short-term debt and for general corporate purposes. Approximately $0.5 million of costs associated with these issuances have been recorded as a reduction to Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.

On December 18, 2019, Unitil Corporation issued $30 million of Notes due 2029 at 3.43%. Unitil Corporation used the net proceeds from this offering to repay short-term debt and for general corporate purposes. Approximately $0.2 million of costs associated with these issuances have been recorded as a reduction to Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.

On September 12, 2019, Northern Utilities issued $40 million of Notes due 2049 at 4.04%. Northern Utilities used the net proceeds from this offering to repay short-term debt and for general corporate purposes. Approximately $0.2 million of costs associated with these issuances have been recorded as a reduction to Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.

Debt Repayment

—The total aggregate amount of debt repayments relating to bond issues and normal scheduled long-term debt repayments amounted to $25.8 million, $24.8 million and $18.8 million in 2021, 2020, and 2019, respectively.

The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2021 is: 2022

– $

8.4 million; 2023

– $

6.9 million; 2024

– $

6.9 million; 2025

– $

5.0

million;

2026

– $

38.0 million and thereafter $444.4 million.

Fair Value of Long-Term Debt

—Currently, the Company believes that there is no active market in the Company’s debt securities, which have all been sold through private placements. If there were an active market for the Company’s debt securities, the fair value of the Company’s long-term debt would be estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities. The fair value of the Company’s long-term debt is estimated using Level 2 inputs (valuations based on quoted prices available in active markets for similar assets or liabilities, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are directly observable, and inputs derived principally from market data). In estimating the fair value of the Company’s long-term debt, the assumed market yield reflects the Moody’s Baa Utility Bond Average Yield. Costs, including prepayment costs, associated with the early settlement of long-term debt are not taken into consideration in determining fair value.


Estimated Fair Value of Long-Term Debt (millions)	December 31,
	2021		2020
Estimated Fair Value of Long-Term Debt	$	584.9	$	633.1

Details on long-term debt at December 31, 2021 and 2020 are shown below:


Long-Term Debt (millions)	December 31,
Long-Term Debt (millions)	2021		2020
Unitil Corporation:
6.33% Senior Notes, Due May 1, 2022	$	—	$	15.0
3.70% Senior Notes, Due August 1, 2026		30.0		30.0
3.43% Senior Notes, Due December 18, 2029		30.0		30.0

Unitil Energy First Mortgage Bonds:
8.49% Senior Secured Notes, Due October 14, 2024		1.5		3.0
6.96% Senior Secured Notes, Due September 1, 2028		14.0		16.0
8.00% Senior Secured Notes, Due May 1, 2031		15.0		15.0
6.32% Senior Secured Notes, Due September 15, 2036		15.0		15.0
3.58% Senior Secured Notes, Due September 15, 2040		27.5		27.5
4.18% Senior Secured Notes, Due November 30, 2048		30.0		30.0

Fitchburg:
6.75% Senior Notes, Due November 30, 2023		—		1.9
6.79% Senior Notes, Due October 15, 2025		6.0		10.0
3.52% Senior Notes, Due November 1, 2027		10.0		10.0
7.37% Senior Notes, Due January 15, 2029		9.6		10.8
5.90% Senior Notes, Due December 15, 2030		15.0		15.0
7.98% Senior Notes, Due June 1, 2031		14.0		14.0
3.78% Senior Notes, Due September 15, 2040		27.5		27.5
4.32% Senior Notes, Due November 1, 2047		15.0		15.0

Northern Utilities:
3.52% Senior Notes, Due November 1, 2027		20.0		20.0
7.72% Senior Notes, Due December 3, 2038		50.0		50.0
3.78% Senior Notes, Due September 15, 2040		40.0		40.0
4.42% Senior Notes, Due October 15, 2044		50.0		50.0
4.32% Senior Notes, Due November 1, 2047		30.0		30.0
4.04% Senior Notes, Due September 12, 2049		40.0		40.0

Granite State:
3.72% Senior Notes, Due November 1, 2027		15.0		15.0

Unitil Realty Corp.:
2.64% Senior Secured Notes, Due December 18, 2030		4.5		4.7

Total Long-Term Debt		509.6		535.4
Less: Unamortized Debt Issuance Costs		3.6		3.8

Total Long-Term Debt, net of Unamortized Debt Issuance Costs		506.0		531.6
Less: Current Portion (1)		8.2		8.5

Total Long-Term Debt, Less Current Portion	$	497.8	$	523.1

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

Interest Expense, Net

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

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


Interest Expense, Net (millions)
	2021			2020			2019
Interest Expense
Long-Term Debt	$	26.0		$	24.8		$	22.9
Short-Term Debt		0.8			1.4			3.0
Regulatory Liabilities		0.4			0.2			0.7

Subtotal Interest Expense		27.2			26.4			26.6

Interest Income
Regulatory Assets		(0.5	)		(0.8	)		(0.8	)
AFUDC (1) and Other		(1.1	)		(1.8	)		(2.1	)

Subtotal Interest Income		(1.6	)		(2.6	)		(2.9	)

Total Interest Expense, Net	$	25.6		$	23.8		$	23.7

(1)

AFUDC—Allowance for Funds Used During Construction

Credit Arrangements

On July 25, 2018, the Company entered into a Second Amended and Restated Credit Agreement (the “Credit Facility”) with a syndicate of lenders, which amended and restated in its entirety the Company’s prior credit agreement, dated as of October 4, 2013, as amended. The Credit Facility extends to July 25, 2023, subject to two

one-year

extensions and has a borrowing limit of $120 million, which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides the Company with the ability to elect that borrowings under the Credit Facility bear interest under several options, including at a daily fluctuating rate of interest per annum equal to

one-month

London Interbank Offered Rate plus 1.125%. Provided there is no event of default, the Company may increase the borrowing limit under the Credit Facility by up to $50 million.

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $239.1 million and $248.9 million for the years ended December 31, 2021 and December 31, 2020, respectively. Total gross repayments were $229.7 million and $252.8 million for the years ended December 31, 2021 and December 31, 2020, respectively. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2021 and December 31, 2020:


Revolving Credit Facility (millions)
	December 31,
	2021		2020
Limit	$	120.0	$	120.0
Short-Term Borrowings Outstanding	$	64.1	$	54.7
Letters of Credit Outstanding	$	—	$	0.1
Available	$	55.9	$	65.2

The Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, Unitil’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At December 31, 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

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. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. This capital lease was paid in full in the second quarter of 2019.

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

The following table lists the Company’s contractual obligations for long-term debt as of December 31, 2021.


			Payments Due by Period
Long-Term Debt Contractual Obligations (millions) as of December 31, 2021	Total		2022		2023		2024		2025		2026		2027 & Beyond
Long-Term Debt	$	509.6	$	8.4	$	6.9	$	6.9	$	5.0	$	38.0	$	444.4
Interest on Long-Term Debt		360.5		24.5		23.9		23.4		22.9		22.6		243.2

Total	$	870.1	$	32.9	$	30.8	$	30.3	$	27.9	$	60.6	$	687.6

Leases

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, 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:


	December 31,
Lease Obligations (millions)	2021		2020
Operating Lease Obligations:
Other Current Liabilities (current portion)	$	1.6	$	1.5
Other Noncurrent Liabilities (long-term portion)		3.1		3.7

Total Operating Lease Obligations		4.7		5.2

Capital Lease Obligations:
Other Current Liabilities (current portion)		0.1		0.2
Other Noncurrent Liabilities (long-term portion)		0.2		0.2

Total Capital Lease Obligations		0.3		0.4

Total Lease Obligations	$	5.0	$	5.6

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

$1.9 million and $1.8 million, respectively and w

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

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

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 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) Year Ending December 31,	Operating Leases		Capital Leases
2022	$	1,695	$	150
2023		1,399		107
2024		1,069		52
2025		503		19
2026		199		—
2027-2031		121		—

Total Payments		4,986		328

Less: Interest		316		12

Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$	4,670	$	316

Operating lease obligations are based on the net present value of the remaining lease payments over the remaining lease term. In determining the present value of lease payments, the Company used the interest rate stated in each lease agreement. 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%.

Guarantees

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

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

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Equity

12 Months Ended

Dec. 31, 2021

Equity

Note 5: Equity

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

Common Stock

The Company’s common stock trades on the New York Stock Exchange under the symbol “UTL”. The Company had 15,977,766 and 15,012,310 shares of common stock outstanding at December 31, 2021 and December 31, 2020, respectively. 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

—During 2021, the Company sold 22,316 shares of its common stock, at an average price of $46.98 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $1.0 million. The DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock. 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

—Pursuant to the written trading plan under Rule

10b5-1

under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted by the Company on May 1, 2014, the Company may periodically repurchase shares of its common stock on the open market related to the stock portion of the Directors’ annual retainer. Until December 1, 2018, the Company also periodically repurchased shares of its common stock on the open market related to Employee Length of Service Awards. (See Part II, Item 5, for additional information). During 2021, 2020 and 2019, the Company repurchased 8,012, 13,194 and 2,911 shares of its common stock, respectively, pursuant to the Rule

10b5-1

trading plan. The expense recognized by the Company for these repurchases was $0.4 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.

Stock-Based Compensation Plans

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

Stock Plan

—The Company maintains the Unitil Corporation Second Amended and Restated 2003 Stock Plan (the Stock Plan). Participants in the Stock Plan are selected by the Compensation Committee of the Board of Directors to receive awards under the Stock Plan, including awards of restricted shares (Restricted Shares), or of restricted stock units (Restricted Stock Units). The Compensation Committee has the authority to determine the sizes of awards; determine the terms and conditions of awards in a manner consistent with the Stock Plan; construe and interpret the Stock Plan and any agreement or instrument entered into under the Stock Plan as they apply to participants; establish, amend, or waive rules and regulations for the Stock Plan’s administration as they apply to participants; and, subject to the provisions of the Stock Plan, amend the terms and conditions of any outstanding award to the extent such terms and conditions are within the discretion of the Compensation Committee as provided for in the Stock Plan. On April 19, 2012, the Company’s shareholders approved an amendment to the Stock Plan to, among other things, increase the maximum number of shares of common stock available for awards to plan participants.

The maximum number of shares available for awards to participants under the Stock Plan is 677,500. The maximum number of shares that may be awarded in any one calendar year to any one participant is 20,000. In the event of any change in capitalization of the Company, the Compensation Committee is authorized to make an equitable adjustment to the number and kind of shares of common stock that may be delivered under the Stock Plan and, in addition, may authorize and make an equitable adjustment to the Stock Plan’s annual individual award limit.

Restricted Shares

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

Prior to the end of the vesting period, the restricted shares are subject to forfeiture if the participant ceases to be employed by the Company other than due to the participant’s death or retirement.

Restricted Shares issued for 2019 – 2021 in conjunction with the Stock Plan are presented in the following table:


Issuance Date	Shares	Aggregate Market Value (millions)
1/29/19	33,150	$1.6
1/28/20	28,630	$1.8
7/28/20	3,000	$0.1
1/26/21	23,140	$0.9

There were 37,621 and 39,426

non-vested

shares under the Stock Plan as of December 31, 2021 and 2020, respectively. The weighted average grant date fair value of these shares was $49.72 per share and $55.46 per share, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recorded over the vesting period and was $1.4 million, $2.2 million and $2.3 million in 2021, 2020 and 2019, respectively. 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 zero restricted shares forfeited and zero restricted shares cancelled under the Stock Plan during 2021. On January

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

The equity portion of Restricted Stock Units activity during 2021 and 2020 in conjunction with the Stock Plan are presented in the following table:


Restricted Stock Units (Equity Portion)
	2021				2020
	Units		Weighted Average Stock Price		Units			Weighted Average Stock Price
Beginning Restricted Stock Units		43,192	$	41.34		70,364		$	41.20
Restricted Stock Units Granted		4,519	$	43.35		3,743		$	39.26
Dividend Equivalents Earned		1,471	$	46.34		1,507		$	47.34
Restricted Stock Units Settled		—	$	—		(32,422	)	$	41.09

Ending Restricted Stock Units		49,182	$	41.67		43,192		$	41.34

Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2021 and 2020

include

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

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

Preferred Stock

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

Earnings Per Share

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


(Millions except shares and per share data)	2021		2020		2019
Earnings Available to Common Shareholders	$	36.1	$	32.2	$	44.2

Weighted Average Common Shares Outstanding—Basic (000’s)		15,373		14,951		14,894
Plus: Diluted Effect of Incremental Shares (000’s)		3		1		6

Weighted Average Common Shares Outstanding—Diluted (000’s)		15,376		14,952		14,900

Earnings per Share—Basic and Diluted	$	2.35	$	2.15	$	2.97

The following table shows the number of weighted average

non-vested

restricted shares that were not included in the above computation of EPS because the effect would have been antidilutive.


	2021		2020		2019
Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation		23,636		42,813		—

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

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Commitments and Contingencies Disclosure [Abstract]

Energy Supply	12 Months Ended
Energy Supply	Dec. 31, 2021
Energy Supply [Abstract]
Energy Supply	Note 6: Energy Supply ELECTRIC POWER SUPPLY Fitchburg, Unitil Energy, and Unitil Power each are members of the New England Power Pool (NEPOOL) and participate in the Independent System Operator—New England (ISO-NE) markets for the purpose of facilitating wholesale electric power supply transactions, which are necessary to serve Unitil’s electric customers with their supply of electricity. Unitil’s customers in both New Hampshire and Massachusetts are entitled to purchase their electric supply from competitive third-party suppliers. As of December 2021, nearly 77% of Unitil’s largest New Hampshire customers, representing 22% of Unitil’s New Hampshire electric kilowatt-hour (kWh) sales, and 80% of Unitil’s largest Massachusetts customers, representing 34% of Unitil’s Massachusetts electric kWh sales, purchased their electric power supply in the competitive market. Additionally, cities and towns in Massachusetts may, with approval from the MDPU, implement municipal aggregations whereby the municipality purchases electric power on behalf of all citizens and businesses that do not opt out of the aggregation. The Towns of Lunenburg and Ashby have active municipal aggregations. Customers in Lunenburg comprise about 17% of Fitchburg’s customer base, and customers in Ashby comprise another 4%. On December 31, 2020, the City of Fitchburg filed with the MDPU for approval of its Aggregation Plan. The aggregation is anticipated to be implemented in mid-2022. The City of Fitchburg comprises about 69% of Company sales. 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 0.5 % 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 To provide regulated electric supply service to their customers, Unitil’s electric distribution utilities enter into load-following wholesale electric power supply contracts to purchase electric supply from various wholesale suppliers. Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. Currently, with approval of the NHPUC, Unitil Energy purchases Default Service power supply contracts for small, medium and large customers every six months for 100% of the supply requirements. 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. 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. On June 13, 2012, the MDPU approved Fitchburg’s request to discontinue the procurement process for Fitchburg’s large customers and become the load-serving entity for these customers. 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 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. Regional Electric Transmission and Power Markets Fitchburg, Unitil Energy and Unitil Power, as well as virtually all New England electric utilities, are participants in the ISO-NE markets. ISO-NE is the Regional Transmission Organization (RTO) in New England. The purpose of ISO-NE is to assure reliable operation of the bulk power system in the most economical manner for the region. Substantially all operation and dispatching of electric generation and bulk transmission capacity in New England are performed on a regional basis. The ISO-NE tariff imposes generating capacity and reserve obligations, and provides for the use of major transmission facilities and associated support payments. The most notable benefits of the ISO-NE are coordinated, reliable power system operation and a supportive business environment for the development of competitive electric markets. Electric Power Supply Divestiture In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in 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 and other restructuring-related regulatory assets. 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. 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 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 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. 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.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies

Note 7: Commitments and Contingencie

Regulatory Matters

Overview

—Unitil’s distribution utilities deliver electricity and/or natural gas to customers in the Company’s service territories at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil Energy, Fitchburg, and Northern Utilities are provided the opportunity to recover the cost of providing distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets. Fitchburg’s electric and gas divisions also operate under revenue decoupling mechanisms.

Most of Unitil’s customers are entitled to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, only business customers are entitled to purchase their natural gas supplies from third-party suppliers at this time. Most small and medium-sized customers, however, continue to purchase such supplies through Unitil Energy, Fitchburg and Northern Utilities as the providers of basic or default service energy supply. Unitil Energy, Fitchburg and Northern Utilities purchase electricity or natural gas for basic or default service from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup, through reconciling, pass-through rate mechanisms that are periodically adjusted. The MDPU, the NHPUC and the MPUC each have continued to approve these reconciling rate mechanisms which allow Fitchburg, Unitil Energy and Northern Utilities to recover their actual wholesale energy costs for electric power and natural gas.

In connection with the implementation of retail choice, Unitil Power 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 and other restructuring-related regulatory assets. 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. 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.

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. 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. Unitil has complied with these orders and has made the required changes to its rates as directed by the commissions. The FERC issued a Notice of Proposed Rulemaking that would allow it to determine which pipelines under the Natural Gas Act may be collecting unjust and unreasonable rates in light of the corporate tax reduction. 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. 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). 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.

Rate Case Activity

Northern Utilities—Base Rates—Maine

—On March 26, 2020, the MPUC approved an increase to base revenue of $3.6 million, a 3.6% increase over the Company’s test year operating revenues, effective April 1, 2020. The order approved a Return on Equity of 9.48%, and a hypothetical capital structure of 50% equity and 50%

debt. As part of the order and increase in base revenue, the MPUC provided for recovery of some, but not all, of the Company’s implementation costs associated with its customer information system pending the completion of an investigation, including a third-party audit. On March 9, 2021, the MPUC opened a new docket to investigate the amount of customer information system costs that will be allowed in rates. On January 27, 2022, the Company and the Maine Office of the Public Advocate filed a stipulation in this docket. The stipulation includes no finding of imprudence or asset disallowance. The terms of the stipulation provide for recovery of the revenue requirement related to the Company’s customer information system in base rates starting November 1, 2022, which coincides with the timing of the Company’s winter cost of gas rate change. The stipulation is subject to approval by the MPUC.

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

—The settlement in Northern Utilities’ Maine division’s 2013 rate case authorized the Company to implement a TIRA rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects, including the Company’s Cast Iron Replacement Program (CIRP). In its Final Order issued on February 28, 2018 for Northern Utilities’ 2017 base rate case, the MPUC approved an extension of the TIRA mechanism for an additional eight-year period, which will allow for annual rate adjustments through the end of the CIRP program. The Company’s most recent request under the TIRA mechanism, to increase annual base rates by $1.1 million for 2020 eligible facilities, was approved by the MPUC effective May 1, 2021.

Northern Utilities—Base Rates—New Hampshire

—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 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 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 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. The Company’s subsequent Compliance Filing reflected an adjusted distribution increase of $0.9 million, a decrease of $0.2 million from the original settlement amount. On May 21, 2020, the MDPU approved the Company’s Compliance Filing. The agreement provides for a Return on Equity of 9.7% and a capital structure reflecting 52.45% equity and 47.55% long-term debt. Under the agreement, the Company will not increase or redesign base distribution rates to become effective prior to November 1,

2023, though the Company may seek cost recovery for certain exogenous events that meet a revenue threshold of $0.1 million. The agreement also provides for the implementation of a major storm reserve fund, whereby the Company may recover the costs of restoration for qualifying storm events. In addition, the agreement provides for the extension of the annual capital cost recovery mechanism, modified to allow the recovery of property tax on the cumulative net capital expenditures.

Fitchburg—Base Rates—Gas

—

Pursuant to its revenue decoupling adjustment clause tariff, as approved in its last base rate case, the Company is allowed to modify, on a semi-annual basis, its base distribution rates to an established revenue per customer target in order to mitigate economic, weather and energy efficiency 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: (1) an increase of $3.7 million, which became effective on March 1, 2020; and (2) an increase of $0.9 million, which became effective on March 1, 2021. Under the agreement, the Company will not increase or redesign base distribution rates to become effective prior to March 1, 2023, though the Company may seek cost recovery for certain exogenous events that meet a revenue effect threshold of $40,000. The agreement provides for a Return on Equity of 9.7% and a capital structure reflecting 52.45% equity and 47.55% long-term debt.

Fitchburg—Gas System Enhancement Program

—

Pursuant to statute and MDPU order, Fitchburg has an approved Gas System Enhancement Plan tariff through which it may recover certain gas infrastructure replacement and safety related investment costs, subject to an annual cap. 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; and a filing, submitted on or before May 1, of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably and prudently incurred. Fitchburg’s forward-looking 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.

Granite State—Base Rates

—On November 30, 2020, the FERC approved Granite State’s filing of an uncontested rate settlement which provides for an increase in annual revenues of approximately $1.3 million, effective November 1, 2020. The Settlement Agreement permits the filing of limited Section 4 rate adjustments for capital cost projects eligible for cost recovery in 2021, 2022, and 2023, and sets forth an overall cap of approximately $14.6 million on the capital cost recoverable under such filings during the term of the Settlement. Under the Settlement Agreement, Granite may not file a new general rate case earlier than April 30, 2024 with rates to be effective no earlier than November 1, 2024 based on a test year ending no earlier than December 31, 2023.

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

Other Matters

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 achieve its 2050 climate goal of

net-zero

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

GHG goal. 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 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 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. 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 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 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 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

—

Fitchburg, Unitil Energy and Northern Utilities each have a number of regulatory reconciling accounts that require annual or semi-annual filings with the MDPU, NHPUC and MPUC, respectively, to reconcile costs and revenues, and to seek approval of any rate changes. These filings include: annual electric reconciliation filings by Fitchburg and Unitil Energy for a number of items, including default service, stranded cost changes and transmission charges; costs associated with energy efficiency programs in New Hampshire and Massachusetts, as directed by the NHPUC and MDPU; recovery of the ongoing costs of storm repairs incurred by Unitil Energy; and the actual wholesale energy costs for electric power and gas incurred by each of the three companies. Fitchburg, Unitil Energy and Northern Utilities have been, and remain in full compliance with all directives and orders regarding these filings. The Company considers these to be routine regulatory proceedings, and there are no material issues outstanding.

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. Unitil’s

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

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.

The EDCs issued the RFP pursuant to Section 83C for Long-Term Contracts for Offshore Wind Energy Generation in June 2017. The EDCs selected an 800 MW project submitted by Vineyard Wind in May 2018, contracts were signed in July 2018 and on July 23, 2018, the EDCs, including Fitchburg, filed two long-term contracts, each for 400 MW of offshore wind energy generation with the MDPU for approval. On April 12, 2019, the MDPU approved the offshore wind energy generation 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 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.

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 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. On November 5, 2020, the MDPU approved the Offshore Wind Energy Generation power purchase agreements. The MDPU also determined that the EDCs’ request for remuneration equal to 2.75% is reasonable and in the public interest. 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

1,600

MW. 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

2022

and

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. On May

2021

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

2021

. On December

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

April 2022

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. On April 14, 2017, the U.S. Court of Appeals for the D.C. 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 set a new ROE. The Court found that the FERC had failed to articulate a satisfactory explanation for its orders. At this time, the ROE set in the vacated order will remain in place until further FERC action is taken. 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. This matter remains pending. The Company does not believe these proceedings will have a material adverse effect on its financial condition or results of operations.

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. On August 17, 2018 a joint settlement agreement among a number of the parties was filed with the FERC. FERC rejected the settlement agreement on May 22, 2019 and remanded the proceeding to the Chief Administrative Law Judge to resume hearing procedures. On May 24, 2019 the judge appointed a Dispute Resolution Facilitator to aid parties in settlement negotiations. The procedural schedule was suspended September 24, 2019 in order to allow participants to focus on settlement negotiations. 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. 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 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.

Contractual Obligations

The following table lists the Company’s known specified gas and electric supply contractual obligations as of December 31, 2021.


			Payments Due by Period
Gas and Electric Supply Contractual Obligations (millions) as of December 31, 2021	Total		2022		2023		2024		2025		2026		2027 & Beyond
Gas Supply Contracts	$	523.9	$	58.5	$	50.6	$	38.8	$	37.3	$	36.9	$	301.8
Electric Supply Contracts		14.2		1.2		1.2		1.2		1.3		1.3		8.0

Total	$	538.1	$	59.7	$	51.8	$	40.0	$	38.6	$	38.2	$	309.8

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

(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.

Legal Proceedings

The Company is involved in legal and administrative proceedings and claims of various types, including those which arise in the ordinary course of business. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these claims will not have a material effect on its financial position, operating results or cash flows.

Environmental Matters

The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company is in material compliance with applicable environmental and safety laws and regulations and, as of December 31, 2021, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. 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 its current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, the Company does not believe that these environmental costs will have a material adverse effect on the Company’s consolidated financial position or results of operations.

Northern Utilities Manufactured Gas Plant Sites

—Northern Utilities has an extensive program to identify, investigate and remediate former manufactured gas plant (MGP) sites, which were operated from the

mid-1800s

through the

mid-1900s.

In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. In Maine, Northern Utilities has documented the presence of MGP sites in Lewiston and Portland, and a former MGP disposal site in Scarborough.

Northern Utilities has worked with the Maine Department of Environmental Protection and New Hampshire Department of Environmental Services (NH DES) to address environmental concerns with these sites. Northern Utilities or others have completed remediation activities at all sites; however, on site monitoring continues at several sites which may result in future remedial actions as directed by the applicable regulatory agency.

In July 2019, the NH DES requested that Northern Utilities review modeled expectations for groundwater contaminants against observed data at the Rochester site. In June 2020, the NH DES

coupled the submittal of the review to a proposed extension of the gas distribution system by Northern Utilities. Northern Utilities submitted the review in January 2022. 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. For Northern Utilities’ New Hampshire division, the NHPUC has approved the recovery of MGP environmental costs over succeeding seven-year periods. For Northern Utilities’ Maine division, the MPUC has authorized the recovery of environmental remediation costs over succeeding five-year periods.

The Environmental Obligations table shows the amounts accrued for Northern Utilities related to estimated future cleanup costs associated with Northern Utilities’ environmental remediation obligations for former MGP sites. Corresponding Regulatory Assets were recorded to reflect that the future recovery of these environmental remediation costs is expected based on regulatory precedent and established practices.

Fitchburg’s Manufactured Gas Plant Site

—Fitchburg has worked with the Massachusetts Department of Environmental Protection (Mass DEP) to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring continues. In April 2020, Fitchburg received notification from the Massachusetts Department of Transportation (Mass DOT) that a portion of the site may be incorporated into the proposed Twin City Rail Trail with an anticipated completion in 2023. Depending upon the final agreement between Fitchburg and Mass DOT, additional minor costs are expected prior to completion.

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

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)


	December 31,
	2021		2020
Total Balance at Beginning of Period	$	2.1	$	2.7
Additions		0.9		0.2
Less: Payments / Reductions		0.3		0.8

Total Balance at End of Period		2.7		2.1

Less: Current Portion		0.5		0.3

Noncurrent Balance at End of Period	$	2.2	$	1.8

Income Taxes

12 Months Ended

Dec. 31, 2021

Income Taxes

Note 8: Income Taxes

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)
	2021		2020		2019
Current Income Tax Provision
Federal	$	—	$	0.3	$	—
State		0.7		0.6		0.3

Total Current Income Taxes	$	0.7	$	0.9	$	0.3

Deferred Income Tax Provision
Federal	$	7.3	$	6.5	$	9.4
State		3.5		2.8		4.1

Total Deferred Income Taxes		10.8		9.3		13.5

Total Income Tax Expense	$	11.5	$	10.2	$	13.8

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


	2021			2020			2019
Statutory Federal Income Tax Rate		21	%		21	%		21	%
Income Tax Effects of:
State Income Taxes, net		6			6			6
Utility Plant Differences		(3	)		(4	)		(3	)
Other, net		—			1			—

Effective Income Tax Rate		24	%		24	%		24	%

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


Temporary Differences (in millions)	2021		2020
Deferred Tax Assets
Retirement Benefit Obligations	$	34.1	$	40.7
Net Operating Loss Carryforwards		4.1		—
Tax Credit Carryforwards		0.7		0.3
Other, net		1.3		1.3

Total Deferred Tax Assets	$	40.2	$	42.3

Deferred Tax Liabilities
Utility Plant Differences		157.4	$	143.8
Regulatory Assets & Liabilities		9.4		6.2
Other, net		1.1		1.3

Total Deferred Tax Liabilities		167.9		151.3

Net Deferred Tax Liabilities	$	127.7	$	109.0

Under the Company’s Tax Sharing Agreement (the Agreement) which was approved upon the formation of Unitil as a public utility holding company, the Company files consolidated Federal and State tax returns and Unitil Corporation and each of its utility operating subsidiaries recognize the results of their operations in its tax returns as if it were a stand-alone taxpayer. The Agreement provides that the Company will account for income taxes in compliance with U.S. GAAP and regulatory accounting principles. 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. The Company remains subject to examination by Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2020; December 31, 2019; and December 31, 2018.

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 $

0.7 million of cumulative state tax credit carryforwards to offset future income taxes payable. If unused, the Company’s state tax credit carryforwards will begin to expire in 2024.

In March 2020, the Coronavirus Aid, Relief and Economic Security (CARES) Act was signed into law. The CARES Act included several tax changes as part of its economic package. These changes principally related to expanded Net Operating Loss carryback periods, increases to interest deductibility limitations, and accelerated Alternative Minimum Tax refunds. The Company has evaluated these items and determined that the items do not have a material effect on the Company’s financial statements as of December 31, 2021. Additionally, the CARES Act enacted the Employee Retention Credit (ERC) to incentivize companies to retain employees. The ERC is a 50% credit on employee wages for employees that are retained and cannot perform their job duties at 100% capacity as a result of coronavirus pandemic restrictions.

In December 2020, the Consolidated Appropriations Act, 2021 (CAA) was signed into law. The CAA included additional funding through tax credits as part of its economic package for 2021. These changes include the temporary removal of deduction limitations on business meals through December 2022 and additional funding for the ERC with expanded benefits extended through June 30, 2021. The expanded ERC is a 70% credit on employee wages for employees that are retained and cannot perform their job duties at 100% capacity as a result of coronavirus pandemic restrictions.

In March 2021, the American Rescue Plan Act of 2021 (ARPA) was signed into law. The ARPA included certain provisions that provide economic relief for the

ongoing COVID-19

pandemic, such as extending the ERC through December 31, 2021, and other future governmental revenue producing provisions, such as expanding the scope for deduction limitations on executive compensation in future years.

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. In accordance with FASB Codification Topic 740, the Company revalued its Accumulated Deferred Income Taxes (ADIT) at the new 21% tax rate at which the ADIT will be reversed in future periods. The Company recorded a net Regulatory Liability in the amount of $48.9 million at December 31, 2017 as a result of the ADIT revaluation. The Company expects to flow through to customers $47.1 million of excess ADIT in utility base rates. Approximately $1.8 million of excess ADIT was created through reconciling mechanisms at December 31, 2017, which had not been previously collected from customers through utility rates. The Company reconciled these excess ADIT amounts through the specific reconciliation mechanisms in each of those individual reconciling mechanisms which were reviewed by state regulators. 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

2020.

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. The Company estimates the ARAM flow back period for protected and unprotected excess ADIT to be between fifteen and twenty years over the remaining life of the related utility plant. Subject to regulatory approval, the Company expects to flow back to customers a net $47.1 million of protected excess ADIT created as a result of the lowering of the statutory tax rate by the TCJA over periods estimated to be fifteen to twenty years. 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.

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

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Retirement Benefit Plans

12 Months Ended

Dec. 31, 2021

Retirement Benefits [Abstract]

Retirement Benefit Plans

Note 9: Retirement Benefit Plans

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

•

The Unitil Corporation Retirement Plan (Pension Plan)—The Pension Plan is a defined benefit pension plan. Under the Pension Plan, retirement benefits are based upon an employee’s level of compensation and length of service. Effective January 1, 2010, the Pension Plan was closed to new non-union employees. For union employees, the Pension Plan was closed on various dates between December 31, 2010 and June 1, 2013, depending on the various Collective Bargaining Agreements of each union.

•

The Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan)—The PBOP Plan provides health care and life insurance benefits to retirees. The Company has established Voluntary Employee Benefit Trusts, into which it funds contributions to the PBOP Plan.

•

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

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


	2021			2020			2019
Used to Determine Plan costs for years ended December 31:


Discount Rate		2.50	%		3.25	%		4.25	%

Rate of Compensation Increase		3.00	%		3.00	%		3.00	%

Expected Long-term rate of return on plan assets		7.50	%		7.40	%		7.50	%

Health Care Cost Trend Rate Assumed for Next Year		6.60	%		7.00	%		7.00	%

Ultimate Health Care Cost Trend Rate		4.50	%		4.50	%		4.50	%

Year that Ultimate Health Care Cost Trend Rate is reached		2029			2029			2024


Used to Determine Benefit Obligations at December 31:

Discount Rate	2.85	%	2.50	%	3.25	%

Rate of Compensation Increase	3.00	%	3.00	%	3.00	%

Health Care Cost Trend Rate Assumed for Next Year	6.20	%	6.60	%	7.00	%

Ultimate Health Care Cost Trend Rate	4.50	%	4.50	%	4.50	%

Year that Ultimate Health Care Cost Trend Rate is reached	2029		2029		2029

The Discount Rate assumptions used in determining retirement plan costs and retirement plan obligations are based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves. For 2021, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $679,000 in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2021 was based on the expected long-term increase in compensation costs for personnel covered by the plans.

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


	Pension Plan									PBOP Plan									SERP
	2021			2020			2019			2021			2020			2019			2021			2020			2019

Service Cost	$	3,472		$	3,322		$	3,104		$	3,034		$	2,698		$	2,304		$	354		$	283		$	247

Interest Cost		5,003			5,776			6,484			2,740			3,121			3,426			458			549			567

Expected Return on Plan Assets		(9,693	)		(9,019	)		(8,475	)		(2,508	)		(2,063	)		(1,645	)		—			—			—

Prior Service Cost Amortization		301			320			320			1,208			1,210			1,213			56			57			56

Actuarial Loss Amortization		8,089			6,472			4,324			1,045			744			227			1,489			1,036			628


Sub-total		7,172			6,871			5,757			5,519			5,710			5,525			2,357			1,925			1,498

Amounts Capitalized or Deferred		(3,384	)		(3,083	)		(2,227	)		(3,136	)		(2,865	)		(2,317	)		(712	)		(579	)		(430	)

NPBC Recognized	$	3,788		$	3,788		$	3,530		$	2,383		$	2,845		$	3,208		$	1,645		$	1,346		$	1,068

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 ga

ns or losses

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 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.

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


	Pension Plan						PBOP Plan						SERP
Change in Plan Assets:	2021			2020			2021			2020			2021			2020


Plan Assets at Beginning of Year	$	137,406		$	125,755		$	32,847		$	27,280		$	—		$	—

Actual Return on Plan Assets		16,989			13,024			3,586			3,739			—			—

Employer Contributions		4,100			4,665			8,903			4,156			637			654

Participant Contributions		—			—			220			240			—			—

Benefits Paid		(6,489	)		(6,038	)		(2,905	)		(2,568	)		(637	)		(654	)

Plan Assets at End of Year	$	152,006		$	137,406		$	42,651		$	32,847		$	—		$	—


Change in PBO:

PBO at Beginning of Year	$	206,092		$	182,135		$	106,831		$	95,657		$	20,225		$	17,759

Service Cost		3,472			3,322			3,034			2,698			354			283

Interest Cost		5,003			5,776			2,740			3,121			458			549

Participant Contributions		—			—			220			240			—			—

Plan Amendments		674			732			—			—			—			—

Benefits Paid		(6,489	)		(6,038	)		(2,905	)		(2,568	)		(637	)		(654	)

Actuarial (Gain) or Loss		(9,334	)		20,165			2,167			7,683			(2,686	)		2,288

PBO at End of Year	$	199,418		$	206,092		$	112,087		$	106,831		$	17,714		$	20,225

Funded Status: Assets vs PBO	$	(47,412	)	$	(68,686	)	$	(69,436	)	$	(73,984	)	$	(17,714	)	$	(20,225	)

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

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

The Company has recorded on its consolidated balance sheets as a liability the underfunded status of its and its subsidiaries’ retirement benefit obligations based on the projected benefit obligation. The Company has recognized Regulatory Assets, net of deferred tax benefits, of $86.4 million and $103.7 million at December 31, 2021 and 2020, respectively, to account for the future collection of these plan obligations in electric and gas rates.

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 ABO for the Pension Plan was $185.1 million and $189.4 million as of December 31, 2021 and 2020, respectively. The ABO for the SERP was $17.5 million and $16.7 million as of December 31, 2021 and 2020, respectively. 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.)

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)


	Pension Plan						PBOP Plan						SERP
	2021		2020		2019		2021		2020		2019		2021		2020		2019

Employer Contributions	$	4,100	$	4,665	$	6,916	$	8,903	$	4,156	$	4,000	$	637	$	654	$	610
Participant Contributions	$	—	$	—	$	—	$	220	$	240	$	121	$	—	$	—	$	—
Benefit Payments	$	6,489	$	6,038	$	6,877	$	2,905	$	2,568	$	1,758	$	637	$	654	$	610

The following table represents estimated future

benefit

payments (000’s).


Estimated Future Benefit Payments
	Pension		PBOP		SERP
2022	$	7,040	$	3,151	$	637
2023		8,046		3,448		636
2024		8,497		3,559		635
2025		8,702		3,862		1,090
2026		9,804		4,158		1,144
2027—2031		54,565		23,853		5,583

The Expected Long-Term Rate of Return on Pension Plan assets assumption used by the Company is developed based on input from actuaries and investment managers. The Company’s Expected Long-Term Rate of Return on Pension Plan assets is based on target investment allocation of 56% in common stock equities, 39% in fixed income securities and 5% in real estate securities. The Company’s Expected Long-Term Rate of Return on PBOP Plan assets is based on target investment allocation of 55% in common stock equities and 45% in fixed income securities. The actual investment allocations are shown in the following tables.


Pension Plan	Target Allocation 2022			Actual Allocation at December 31,
	Target Allocation 2022			2021			2020			2019

Equity Funds		56	%		57	%		58	%		54	%
Debt Funds		39	%		38	%		37	%		36	%
Real Estate Fund		5	%		4	%		4	%		9	%
Other (1)		—			1	%		1	%		1	%

Total					100	%		100	%		100	%

(1)

Represents investments being held in cash equivalents as of December 31, 2021, December 31, 2020 and December 31, 2019 pending payment of benefits.


PBOP Plan	Target Allocation 2022			Actual Allocation at December 31,
PBOP Plan	Target Allocation 2022			2021			2020			2019

Equity Funds		55	%		56	%		55	%		56	%
Debt Funds		45	%		44	%		45	%		44	%

Total					100	%		100	%		100	%

The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 7.50% for 2021. The Company evaluates the actuarial assumptions, including the expected rate of return, at least annually. The desired investment objective is a long-term rate of return on assets that is approximately 5 – 6% greater than the assumed rate of inflation as measured by the Consumer Price Index. The target rate of return for the Plans has been based upon an analysis of historical returns supplemented with an economic and structural review for each asset class.

Following is a description of the valuation methodologies used for assets measured at fair value. There have been no changes in the methodologies used at December 31, 2021 and 2020. Please also see Note 1 (Summary of Significant Accounting Policies) for a discussion of the Company’s fair value accounting policy.

Equity, Fixed Income, Index and Asset Allocation Funds

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

Cash Equivalents

These investments are valued at cost, which approximates fair value, and are categorized in Level 1.

Real Estate Fund

These investments are valued at net asset value per unit based on a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity. In accordance with FASB Codification Topic 820, “Fair Value Measurement”, these investments have not been classified in the fair value hierarchy. The fair value amounts presented in the tables below for the Real Estate Fund are intended to permit reconciliation of the fair value hierarchy to

the “Plan Assets at End of Year” line item shown in the “Change in Plan Assets” 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):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2021
Pension Plan Assets:
Mutual Funds:

Equity Funds	$	86,356	$	86,356	$	—	$	—
Fixed Income Funds		57,883		57,883		—		—

Total Mutual Funds		144,239		144,239		—		—
Cash Equivalents		912		912

Total Assets in the Fair Value Hierarchy	$	145,151	$	145,151	$	—	$	—

Real Estate Fund–Measured at Net Asset Value		6,855

Total Assets	$	152,006


2020
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	79,690	$	79,690	$	—	$	—
Fixed Income Funds		50,622		50,622		—		—

Total Mutual Funds		130,312		130,312		—		—
Cash Equivalents		1,277		1,277

Total Assets in the Fair Value Hierarchy	$	131,589	$	131,589	$	—	$	—

Real Estate Fund–Measured at Net Asset Value		5,817

Total Assets	$	137,406

Redemptions of the Real Estate Fund are subject to a sixty-five day notice period and the fund is valued quarterly. There are no unfunded commitments.

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2021 and 2020 are as follows (000’s):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2021
PBOP Plan Assets:
Mutual Funds:

Fixed Income Funds	$	18,882	$	18,882	$	—	$	—
Equity Funds		23,769		23,769		—		—

Total Assets	$	42,651	$	42,651	$	—	$	—


2020
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	14,716	$	14,716	$	—	$	—
Equity Funds		18,131		18,131		—		—

Total Assets	$	32,847	$	32,847	$	—	$	—

Employee 401(k) Tax Deferred Savings Plan—

The Company sponsors the Unitil Corporation Tax Deferred Savings and Investment Plan (the 401(k) Plan) under Section 401(k) of the Internal Revenue Code and covering substantially all of the Company’s employees. Participants may elect to defer current compensation by contributing to the plan. Employees may direct, at their sole discretion, the investment of their savings plan balances (both the employer and employee portions) into a variety of investment options, including a Company common stock fund.

The Company’s contributions to the 401(k) Plan were $3.3 million, $3.0 million and $2.8 million for the years ended December 31, 2021, 2020 and 2019, respectively.

The entire disclosure for retirement benefits.

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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(03)
-URI http://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (q)
-URI http://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (r)(1)
-URI http://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (d)(iii)
-URI http://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (l)
-URI http://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (r)(2)
-URI http://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Divestiture of Non-Regulated Business Subsidiary

Summary Of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Nature of Operations

—

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

with those contracts.

non-regulated

—

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

$9.8

million on this divestiture in the first quarter of 2019. The pre-tax net gain of approximately

$13.4

$3.6

million are included in the Provision For Income Taxes.

Principles of Consolidation

—

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

Use of Estimates

—

Fair Value

—


Level 1—		Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—		Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly.

Level 3—		Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.

There have been no changes in the valuation techniques used during the current period.

Utility Revenue Recognition

—

The Company’s billed and unbilled rev

In the following tables, revenue is classified by the types of goods/services rendered and market/customer type.


	Twelve Months Ended December 31, 2021
Electric and Gas Operating Revenues (millions):	Electric		Gas		Total
Billed and Unbilled Revenue:
Residential	$	135.1	$	83.9	$	219.0
Commercial & Industrial		103.3		124.1		227.4
Other		10.1		9.6		19.7

Total Billed and Unbilled Revenue		248.5		217.6		466.1
Rate Adjustment Mechanism Revenue		—		7.2		7.2

Total Electric and Gas Operating Revenues	$	248.5	$	224.8	$	473.3


	Twelve Months Ended December 31, 2020
Electric and Gas Operating Revenues (millions):	Electric		Gas		Total
Billed and Unbilled Revenue:
Residential	$	128.7	$	73.1	$	201.8
Commercial & Industrial		91.4		104.5		195.9
Other		6.6		7.6		14.2

Total Billed and Unbilled Revenue		226.7		185.2		411.9
Rate Adjustment Mechanism Revenue		0.5		6.2		6.7

Total Electric and Gas Operating Revenues	$	227.2	$	191.4	$	418.6


	Twelve Months Ended December 31, 2019
Electric and Gas Operating Revenues (millions):	Electric		Gas			Total
Billed and Unbilled Revenue:
Residential	$	121.5	$	81.4		$	202.9
Commercial & Industrial		93.8		120.1			213.9
Other		7.8		10.6			18.4

Total Billed and Unbilled Revenue		223.1		212.1			435.2
Rate Adjustment Mechanism Revenue		10.8		(8.7	)		2.1

Total Electric and Gas Operating Revenues	$	233.9	$	203.4		$	437.3

The

difference

Other Operating Revenue - Non-regulated

Other Operating Revenue—Non-regulated

—

Depreciation and Amortization

—

Stock-based Employee Compensation

—

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

Income Taxes

—

Provisions

Dividends

—The Company’s dividend policy is reviewed periodically b

Cash and Cash Equivalents

(ISO-NE)

Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to

ISO-NE.

Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately

2-1/2

ISO-NE

obligations.

Financial Instruments

—In June 2016, the Financial Accounting Standards Board issued ASU

2016-13,

Allowance for Doubtful Accounts

—

Accrued Revenue

Accrued Revenue—


Accrued Revenue (millions)	December 31,
Accrued Revenue (millions)	2021		2020
Regulatory Assets—Current	$	47.4	$	37.3
Unbilled Revenues		13.8		13.6

Total Accrued Revenue	$	61.2	$	50.9

Exchange Gas Receivable

—

through March. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of December 31, 2021 and 2020.


Exchange Gas Receivable (millions)	December 31,
Exchange Gas Receivable (millions)	2021		2020
Northern Utilities	$	6.7	$	4.4
Fitchburg		0.7		0.5

Total Exchange Gas Receivable	$	7.4	$	4.9

Gas Inventory

—The Company uses the weighted average cost methodology to value natural gas inventory. The following table shows the components of Gas Inventory as of December 31, 2021 and 2020.


Gas Inventory (millions)	December 31,
Gas Inventory (millions)	2021		2020
Natural Gas	$	0.5	$	0.2
Propane		0.4		0.3
Liquefied Natural Gas & Other		0.1		0.1

Total Gas Inventory	$	1.0	$	0.6

Utility Plant

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

Cost of additions consists of

ets in Cost of Removal Obligations.

Regulatory Accounting

—

$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)	December 31,
Regulatory Assets consist of the following (millions)	2021		2020
Retirement Benefits	$	86.4	$	103.7
Energy Supply & Other Rate Adjustment Mechanisms		44.1		34.1
Deferred Storm Charges		3.3		4.1
Environmental		4.6		5.2
Income Taxes		2.6		3.4
Other Deferred Charges		15.3		14.2

Total Regulatory Assets		156.3		164.7
Less: Current Portion of Regulatory Assets (1)		47.4		37.3

Regulatory Assets—noncurrent	$	108.9	$	127.4

(1)

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


Regulatory Liabilities consist of the following (millions)	December 31,
Regulatory Liabilities consist of the following (millions)	2021		2020
Rate Adjustment Mechanisms	$	7.7	$	4.1
Income Taxes		44.3		45.5
Other		0.1		0.2

Total Regulatory Liabilities		52.1		49.8
Less: Current Portion of Regulatory Liabilities		9.5		5.5

Regulatory Liabilities—noncurrent	$	42.6	$	44.3

ted

Leases

non-lease

er the lease term. See additional discussion in the “Leases” section of Note

(Debt and Financing Arrangements).

Derivatives

—

Investments in Marketable Securities

—

following table.


Fair Value of Marketable Securities (millions)	December 31,
	2021		2020
Money Market Funds	$	5.7	$	5.7

Total Marketable Securities	$	5.7	$	5.7

The Company also sponsors the Unitil Corporation Deferred Compensation Plan (the DC Plan). The DC Plan is a

non-qualified

deferred compensation plan that provides a vehicle for participants to accumulate

tax-deferred

At December

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


Fair Value of Marketable Securities (millions)	December 31,
	2021		2020
Equity Funds	$	0.2	$	0.2
Money Market Funds		0.4		0.3

Total Marketable Securities	$	0.6	$	0.5

Energy Supply Obligations

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


	December 31,
Energy Supply Obligations consist of the following: (millions)	2021		2020
Renewable Energy Portfolio Standards	$	7.8	$	5.7
Exchange Gas Obligation		6.7		4.4
Power Supply Contract Divestitures		—		0.3

Total Energy Supply Obligations	$	14.5	$	10.4

Renewable Energy Portfolio Standards

Fitchburg has e

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 ch

Retirement Benefit Obligations

—The Company sponsors the Pension Plan, which is a defined benefit pension plan. Effective January 1, 2010, the Pension Plan was closed to new

non-union

non-qualified

Commitments and Contingencies

(Commitments and Contingencies).

Environmental Matters

t recoverable in regulatory rate mechanisms.

Subsequent Events

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2021

Components of Gas and Electric Operating Revenue

In the following tables, revenue is classified by the types of goods/services rendered and market/customer type.


	Twelve Months Ended December 31, 2021
Electric and Gas Operating Revenues (millions):	Electric		Gas		Total
Billed and Unbilled Revenue:
Residential	$	135.1	$	83.9	$	219.0
Commercial & Industrial		103.3		124.1		227.4
Other		10.1		9.6		19.7

Total Billed and Unbilled Revenue		248.5		217.6		466.1
Rate Adjustment Mechanism Revenue		—		7.2		7.2

Total Electric and Gas Operating Revenues	$	248.5	$	224.8	$	473.3


	Twelve Months Ended December 31, 2020
Electric and Gas Operating Revenues (millions):	Electric		Gas		Total
Billed and Unbilled Revenue:
Residential	$	128.7	$	73.1	$	201.8
Commercial & Industrial		91.4		104.5		195.9
Other		6.6		7.6		14.2

Total Billed and Unbilled Revenue		226.7		185.2		411.9
Rate Adjustment Mechanism Revenue		0.5		6.2		6.7

Total Electric and Gas Operating Revenues	$	227.2	$	191.4	$	418.6


	Twelve Months Ended December 31, 2019
Electric and Gas Operating Revenues (millions):	Electric		Gas			Total
Billed and Unbilled Revenue:
Residential	$	121.5	$	81.4		$	202.9
Commercial & Industrial		93.8		120.1			213.9
Other		7.8		10.6			18.4

Total Billed and Unbilled Revenue		223.1		212.1			435.2
Rate Adjustment Mechanism Revenue		10.8		(8.7	)		2.1

Total Electric and Gas Operating Revenues	$	233.9	$	203.4		$	437.3

Components of Accrued Revenue

The following table shows the components of Accrued Revenue as of December 31, 2021 and 2020.


Accrued Revenue (millions)	December 31,
Accrued Revenue (millions)	2021		2020
Regulatory Assets—Current	$	47.4	$	37.3
Unbilled Revenues		13.8		13.6

Total Accrued Revenue	$	61.2	$	50.9

Components of Exchange Gas Receivable

The following table shows the components of Exchange Gas Receivable as of December 31, 2021 and 2020.


Exchange Gas Receivable (millions)	December 31,
Exchange Gas Receivable (millions)	2021		2020
Northern Utilities	$	6.7	$	4.4
Fitchburg		0.7		0.5

Total Exchange Gas Receivable	$	7.4	$	4.9

Components of Gas Inventory

The following table shows the components of Gas Inventory as of December 31, 2021 and 2020.


Gas Inventory (millions)	December 31,
Gas Inventory (millions)	2021		2020
Natural Gas	$	0.5	$	0.2
Propane		0.4		0.3
Liquefied Natural Gas & Other		0.1		0.1

Total Gas Inventory	$	1.0	$	0.6


Regulatory Assets consist of the following (millions)	December 31,
Regulatory Assets consist of the following (millions)	2021		2020
Retirement Benefits	$	86.4	$	103.7
Energy Supply & Other Rate Adjustment Mechanisms		44.1		34.1
Deferred Storm Charges		3.3		4.1
Environmental		4.6		5.2
Income Taxes		2.6		3.4
Other Deferred Charges		15.3		14.2

Total Regulatory Assets		156.3		164.7
Less: Current Portion of Regulatory Assets (1)		47.4		37.3

Regulatory Assets—noncurrent	$	108.9	$	127.4

(1)

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

Fair Value of Marketable Securities


Regulatory Liabilities consist of the following (millions)	December 31,
Regulatory Liabilities consist of the following (millions)	2021		2020
Rate Adjustment Mechanisms	$	7.7	$	4.1
Income Taxes		44.3		45.5
Other		0.1		0.2

Total Regulatory Liabilities		52.1		49.8
Less: Current Portion of Regulatory Liabilities		9.5		5.5

Regulatory Liabilities—noncurrent	$	42.6	$	44.3


Fair Value of Marketable Securities (millions)	December 31,
	2021		2020
Money Market Funds	$	5.7	$	5.7

Total Marketable Securities	$	5.7	$	5.7

Components of Energy Supply Obligations


	December 31,
Energy Supply Obligations consist of the following: (millions)	2021		2020
Renewable Energy Portfolio Standards	$	7.8	$	5.7
Exchange Gas Obligation		6.7		4.4
Power Supply Contract Divestitures		—		0.3

Total Energy Supply Obligations	$	14.5	$	10.4

Deferred Compensation Plan [Member]

Components of Energy Supply Obligations


Fair Value of Marketable Securities (millions)	December 31,
	2021		2020
Equity Funds	$	0.2	$	0.2
Money Market Funds		0.4		0.3

Total Marketable Securities	$	0.6	$	0.5

Segment Information (Tables)

12 Months Ended

Dec. 31, 2021

Significant Segment Financial Data

The following tables provide significant segment financial data for the years ended December 31, 2021, 2020 and 2019 (millions)


Year Ended December 31, 2021	Electric		Gas			Non- Regulated			Other			Total

Revenues:

Billed and Unbilled Revenue	$	248.5	$	217.6		$	—		$	—		$	466.1

Rate Adjustment Mechanism Revenue		—		7.2			—			—			7.2


Total Operating Revenues		248.5		224.8			—			—			473.3


Interest Income		0.8		0.5			—			0.3			1.6

Interest Expense		9.0		15.3			—			2.9			27.2

Depreciation & Amortization Expense		25.9		32.6			—			1.0			59.5

Income Tax Expense (Benefit)		4.5		7.7			(0.1	)		(0.6	)		11.5

Segment Profit (Loss)		14.0		23.2			0.1			(1.2	)		36.1

Segment Assets		584.0		935.9			—			20.4			1,540.3

Capital Expenditures		38.1		75.8			—			1.1			115.0

Year Ended December 31, 2020

Revenues:

Billed and Unbilled Revenue	$	226.7	$	185.2		$	—		$	—		$	411.9

Rate Adjustment Mechanism Revenue		0.5		6.2			—			—			6.7


Total Operating Revenues		227.2		191.4			—			—			418.6


Interest Income		1.1		1.1			—			0.4			2.6

Interest Expense		8.7		14.2			—			3.5			26.4

Depreciation & Amortization Expense		23.8		29.8			—			0.9			54.5

Income Tax Expense (Benefit)		4.7		7.3			—			(1.8	)		10.2

Segment Profit		12.9		19.3			—			—			32.2

Segment Assets		571.8		886.3			—			19.8			1,477.9

Capital Expenditures		45.5		71.1			—			6.0			122.6

Year Ended December 31, 2019

Revenues:

Billed and Unbilled Revenue	$	223.1	$	212.1		$	—		$	—		$	435.2

Rate Adjustment Mechanism Revenue		10.8		(8.7	)		—			—			2.1

Other Operating Revenue—Non-Regulated		—		—			0.9			—			0.9


Total Operating Revenues		233.9		203.4			0.9			—			438.2


Interest Income		0.9		1.2			0.2			0.6			2.9

Interest Expense		9.4		14.4			—			2.8			26.6

Depreciation & Amortization Expense		22.6		28.5			—			0.9			52.0

Income Tax Expense (Benefit)		4.2		7.2			3.8			(1.4	)		13.8

Segment Profit		11.5		19.1			10.2			3.4			44.2

Segment Assets		529.3		823.3			0.3			17.9			1,370.8

Capital Expenditures		39.6		74.0			—			5.6			119.2

Allowance for Doubtful Accounts (Tables)

12 Months Ended

Dec. 31, 2021

Allowance For Doubtful Accounts [Abstract]

Allowance for Doubtful Accounts

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


	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Regulatory Deferrals*		Balance at End of Period
Year Ended December 31, 2021
Electric	$	1.6	$	3.3	$	0.4	$	3.4	$	0.1	$	2.0
Gas		1.7		2.3		0.4		3.1		—		1.3
Other		—		—		—		—		—		—

	$	3.3	$	5.6	$	0.8	$	6.5	$	0.1	$	3.3

Year Ended December 31, 2020
Electric	$	0.6	$	2.9	$	0.3	$	2.6	$	0.4	$	1.6
Gas		0.4		2.6		0.3		1.8		0.2		1.7
Other		—		—		—		—		—		—

	$	1.0	$	5.5	$	0.6	$	4.4	$	0.6	$	3.3

Year Ended December 31, 2019
Electric	$	0.5	$	3.0	$	0.3	$	3.2	$	—	$	0.6
Gas		0.8		1.9		0.5		2.8		—		0.4
Other		—		—		—		—		—		—

	$	1.3	$	4.9	$	0.8	$	6.0	$	—	$	1.0

Debt and Financing Arrangements (Tables)

12 Months Ended

Dec. 31, 2021

Details on Long Term Debt

Details on long-term debt at December 31, 2021 and 2020 are shown below:


Long-Term Debt (millions)	December 31,
Long-Term Debt (millions)	2021		2020
Unitil Corporation:
6.33% Senior Notes, Due May 1, 2022	$	—	$	15.0
3.70% Senior Notes, Due August 1, 2026		30.0		30.0
3.43% Senior Notes, Due December 18, 2029		30.0		30.0

Unitil Energy First Mortgage Bonds:
8.49% Senior Secured Notes, Due October 14, 2024		1.5		3.0
6.96% Senior Secured Notes, Due September 1, 2028		14.0		16.0
8.00% Senior Secured Notes, Due May 1, 2031		15.0		15.0
6.32% Senior Secured Notes, Due September 15, 2036		15.0		15.0
3.58% Senior Secured Notes, Due September 15, 2040		27.5		27.5
4.18% Senior Secured Notes, Due November 30, 2048		30.0		30.0

Fitchburg:
6.75% Senior Notes, Due November 30, 2023		—		1.9
6.79% Senior Notes, Due October 15, 2025		6.0		10.0
3.52% Senior Notes, Due November 1, 2027		10.0		10.0
7.37% Senior Notes, Due January 15, 2029		9.6		10.8
5.90% Senior Notes, Due December 15, 2030		15.0		15.0
7.98% Senior Notes, Due June 1, 2031		14.0		14.0
3.78% Senior Notes, Due September 15, 2040		27.5		27.5
4.32% Senior Notes, Due November 1, 2047		15.0		15.0

Northern Utilities:
3.52% Senior Notes, Due November 1, 2027		20.0		20.0
7.72% Senior Notes, Due December 3, 2038		50.0		50.0
3.78% Senior Notes, Due September 15, 2040		40.0		40.0
4.42% Senior Notes, Due October 15, 2044		50.0		50.0
4.32% Senior Notes, Due November 1, 2047		30.0		30.0
4.04% Senior Notes, Due September 12, 2049		40.0		40.0

Granite State:
3.72% Senior Notes, Due November 1, 2027		15.0		15.0

Unitil Realty Corp.:
2.64% Senior Secured Notes, Due December 18, 2030		4.5		4.7

Total Long-Term Debt		509.6		535.4
Less: Unamortized Debt Issuance Costs		3.6		3.8

Total Long-Term Debt, net of Unamortized Debt Issuance Costs		506.0		531.6
Less: Current Portion (1)		8.2		8.5

Total Long-Term Debt, Less Current Portion	$	497.8	$	523.1

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

Fair Value of Long Term Debt


Estimated Fair Value of Long-Term Debt (millions)	December 31,
	2021		2020
Estimated Fair Value of Long-Term Debt	$	584.9	$	633.1

Summary of Interest Expense and Interest Income

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


Interest Expense, Net (millions)
	2021			2020			2019
Interest Expense
Long-Term Debt	$	26.0		$	24.8		$	22.9
Short-Term Debt		0.8			1.4			3.0
Regulatory Liabilities		0.4			0.2			0.7

Subtotal Interest Expense		27.2			26.4			26.6

Interest Income
Regulatory Assets		(0.5	)		(0.8	)		(0.8	)
AFUDC (1) and Other		(1.1	)		(1.8	)		(2.1	)

Subtotal Interest Income		(1.6	)		(2.6	)		(2.9	)

Total Interest Expense, Net	$	25.6		$	23.8		$	23.7

(1)

AFUDC—Allowance for Funds Used During Construction

Borrowing Limits Amounts Outstanding and Amounts Available under Credit Facility

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2021 and December 31, 2020:


Revolving Credit Facility (millions)
	December 31,
	2021		2020
Limit	$	120.0	$	120.0
Short-Term Borrowings Outstanding	$	64.1	$	54.7
Letters of Credit Outstanding	$	—	$	0.1
Available	$	55.9	$	65.2

Summary of Company's Contractual Obligations for Log-term Debt

The following table lists the Company’s contractual obligations for long-term debt as of December 31, 2021.


			Payments Due by Period
Long-Term Debt Contractual Obligations (millions) as of December 31, 2021	Total		2022		2023		2024		2025		2026		2027 & Beyond
Long-Term Debt	$	509.6	$	8.4	$	6.9	$	6.9	$	5.0	$	38.0	$	444.4
Interest on Long-Term Debt		360.5		24.5		23.9		23.4		22.9		22.6		243.2

Total	$	870.1	$	32.9	$	30.8	$	30.3	$	27.9	$	60.6	$	687.6

Classification of the Company Lease Obligations

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


	December 31,
Lease Obligations (millions)	2021		2020
Operating Lease Obligations:
Other Current Liabilities (current portion)	$	1.6	$	1.5
Other Noncurrent Liabilities (long-term portion)		3.1		3.7

Total Operating Lease Obligations		4.7		5.2

Capital Lease Obligations:
Other Current Liabilities (current portion)		0.1		0.2
Other Noncurrent Liabilities (long-term portion)		0.2		0.2

Total Capital Lease Obligations		0.3		0.4

Total Lease Obligations	$	5.0	$	5.6

Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases


Lease Payments ($000’s) Year Ending December 31,	Operating Leases		Capital Leases
2022	$	1,695	$	150
2023		1,399		107
2024		1,069		52
2025		503		19
2026		199		—
2027-2031		121		—

Total Payments		4,986		328

Less: Interest		316		12

Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$	4,670	$	316

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

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Table Text Block Supplement [Abstract]

Equity (Tables)

12 Months Ended

Dec. 31, 2021

Restricted Shares Issued in Conjunction with Stock Plan

Restricted Shares issued for 2019 – 2021 in conjunction with the Stock Plan are presented in the following table:


Issuance Date	Shares	Aggregate Market Value (millions)
1/29/19	33,150	$1.6
1/28/20	28,630	$1.8
7/28/20	3,000	$0.1
1/26/21	23,140	$0.9

Restricted Stock Units Issued

The equity portion of Restricted Stock Units activity during 2021 and 2020 in conjunction with the Stock Plan are presented in the following table:


Restricted Stock Units (Equity Portion)
	2021				2020
	Units		Weighted Average Stock Price		Units			Weighted Average Stock Price
Beginning Restricted Stock Units		43,192	$	41.34		70,364		$	41.20
Restricted Stock Units Granted		4,519	$	43.35		3,743		$	39.26
Dividend Equivalents Earned		1,471	$	46.34		1,507		$	47.34
Restricted Stock Units Settled		—	$	—		(32,422	)	$	41.09

Ending Restricted Stock Units		49,182	$	41.67		43,192		$	41.34

Reconciliation of Basic and Diluted Earnings Per Share

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


(Millions except shares and per share data)	2021		2020		2019
Earnings Available to Common Shareholders	$	36.1	$	32.2	$	44.2

Weighted Average Common Shares Outstanding—Basic (000’s)		15,373		14,951		14,894
Plus: Diluted Effect of Incremental Shares (000’s)		3		1		6

Weighted Average Common Shares Outstanding—Diluted (000’s)		15,376		14,952		14,900

Earnings per Share—Basic and Diluted	$	2.35	$	2.15	$	2.97

Weighted Average Non Vested Restricted Shares Excluded from Computation of Earnings Per Share

The following table shows the number of weighted average

non-vested

restricted shares that were not included in the above computation of EPS because the effect would have been antidilutive.


	2021		2020		2019
Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation		23,636		42,813		—

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

Gas And Electric Supply Contractual Obligations

The following table lists the Company’s known specified gas and electric supply contractual obligations as of December 31, 2021.


			Payments Due by Period
Gas and Electric Supply Contractual Obligations (millions) as of December 31, 2021	Total		2022		2023		2024		2025		2026		2027 & Beyond
Gas Supply Contracts	$	523.9	$	58.5	$	50.6	$	38.8	$	37.3	$	36.9	$	301.8
Electric Supply Contracts		14.2		1.2		1.2		1.2		1.3		1.3		8.0

Total	$	538.1	$	59.7	$	51.8	$	40.0	$	38.6	$	38.2	$	309.8

Environmental Obligations Recognized by Company

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)


	December 31,
	2021		2020
Total Balance at Beginning of Period	$	2.1	$	2.7
Additions		0.9		0.2
Less: Payments / Reductions		0.3		0.8

Total Balance at End of Period		2.7		2.1

Less: Current Portion		0.5		0.3

Noncurrent Balance at End of Period	$	2.2	$	1.8

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Provisions for Federal and State Income Taxes

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)
	2021		2020		2019
Current Income Tax Provision
Federal	$	—	$	0.3	$	—
State		0.7		0.6		0.3

Total Current Income Taxes	$	0.7	$	0.9	$	0.3

Deferred Income Tax Provision
Federal	$	7.3	$	6.5	$	9.4
State		3.5		2.8		4.1

Total Deferred Income Taxes		10.8		9.3		13.5

Total Income Tax Expense	$	11.5	$	10.2	$	13.8

Differences Between Provisions for Income Taxes and Provisions Calculated at Statutory Federal Tax Rate

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


	2021			2020			2019
Statutory Federal Income Tax Rate		21	%		21	%		21	%
Income Tax Effects of:
State Income Taxes, net		6			6			6
Utility Plant Differences		(3	)		(4	)		(3	)
Other, net		—			1			—

Effective Income Tax Rate		24	%		24	%		24	%

Deferred Tax Assets and Liabilities

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


Temporary Differences (in millions)	2021		2020
Deferred Tax Assets
Retirement Benefit Obligations	$	34.1	$	40.7
Net Operating Loss Carryforwards		4.1		—
Tax Credit Carryforwards		0.7		0.3
Other, net		1.3		1.3

Total Deferred Tax Assets	$	40.2	$	42.3

Deferred Tax Liabilities
Utility Plant Differences		157.4	$	143.8
Regulatory Assets & Liabilities		9.4		6.2
Other, net		1.1		1.3

Total Deferred Tax Liabilities		167.9		151.3

Net Deferred Tax Liabilities	$	127.7	$	109.0

Retirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2021

Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations

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


	2021			2020			2019
Used to Determine Plan costs for years ended December 31:


Discount Rate		2.50	%		3.25	%		4.25	%

Rate of Compensation Increase		3.00	%		3.00	%		3.00	%

Expected Long-term rate of return on plan assets		7.50	%		7.40	%		7.50	%

Health Care Cost Trend Rate Assumed for Next Year		6.60	%		7.00	%		7.00	%

Ultimate Health Care Cost Trend Rate		4.50	%		4.50	%		4.50	%

Year that Ultimate Health Care Cost Trend Rate is reached		2029			2029			2024


Used to Determine Benefit Obligations at December 31:

Discount Rate	2.85	%	2.50	%	3.25	%

Rate of Compensation Increase	3.00	%	3.00	%	3.00	%

Health Care Cost Trend Rate Assumed for Next Year	6.20	%	6.60	%	7.00	%

Ultimate Health Care Cost Trend Rate	4.50	%	4.50	%	4.50	%

Year that Ultimate Health Care Cost Trend Rate is reached	2029		2029		2029

Components of Retirement Plan Costs

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


	Pension Plan									PBOP Plan									SERP
	2021			2020			2019			2021			2020			2019			2021			2020			2019

Service Cost	$	3,472		$	3,322		$	3,104		$	3,034		$	2,698		$	2,304		$	354		$	283		$	247

Interest Cost		5,003			5,776			6,484			2,740			3,121			3,426			458			549			567

Expected Return on Plan Assets		(9,693	)		(9,019	)		(8,475	)		(2,508	)		(2,063	)		(1,645	)		—			—			—

Prior Service Cost Amortization		301			320			320			1,208			1,210			1,213			56			57			56

Actuarial Loss Amortization		8,089			6,472			4,324			1,045			744			227			1,489			1,036			628


Sub-total		7,172			6,871			5,757			5,519			5,710			5,525			2,357			1,925			1,498

Amounts Capitalized or Deferred		(3,384	)		(3,083	)		(2,227	)		(3,136	)		(2,865	)		(2,317	)		(712	)		(579	)		(430	)

NPBC Recognized	$	3,788		$	3,788		$	3,530		$	2,383		$	2,845		$	3,208		$	1,645		$	1,346		$	1,068

Plans' Assets, Projected Benefit Obligations (PBO), and Funded Status

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


	Pension Plan						PBOP Plan						SERP
Change in Plan Assets:	2021			2020			2021			2020			2021			2020


Plan Assets at Beginning of Year	$	137,406		$	125,755		$	32,847		$	27,280		$	—		$	—

Actual Return on Plan Assets		16,989			13,024			3,586			3,739			—			—

Employer Contributions		4,100			4,665			8,903			4,156			637			654

Participant Contributions		—			—			220			240			—			—

Benefits Paid		(6,489	)		(6,038	)		(2,905	)		(2,568	)		(637	)		(654	)

Plan Assets at End of Year	$	152,006		$	137,406		$	42,651		$	32,847		$	—		$	—


Change in PBO:

PBO at Beginning of Year	$	206,092		$	182,135		$	106,831		$	95,657		$	20,225		$	17,759

Service Cost		3,472			3,322			3,034			2,698			354			283

Interest Cost		5,003			5,776			2,740			3,121			458			549

Participant Contributions		—			—			220			240			—			—

Plan Amendments		674			732			—			—			—			—

Benefits Paid		(6,489	)		(6,038	)		(2,905	)		(2,568	)		(637	)		(654	)

Actuarial (Gain) or Loss		(9,334	)		20,165			2,167			7,683			(2,686	)		2,288

PBO at End of Year	$	199,418		$	206,092		$	112,087		$	106,831		$	17,714		$	20,225

Funded Status: Assets vs PBO	$	(47,412	)	$	(68,686	)	$	(69,436	)	$	(73,984	)	$	(17,714	)	$	(20,225	)

Employer Contributions, Participant Contributions and Benefit Payments

The following table represents employer contributions, participant contributions and benefit payments (

000

’s)


	Pension Plan						PBOP Plan						SERP
	2021		2020		2019		2021		2020		2019		2021		2020		2019

Employer Contributions	$	4,100	$	4,665	$	6,916	$	8,903	$	4,156	$	4,000	$	637	$	654	$	610
Participant Contributions	$	—	$	—	$	—	$	220	$	240	$	121	$	—	$	—	$	—
Benefit Payments	$	6,489	$	6,038	$	6,877	$	2,905	$	2,568	$	1,758	$	637	$	654	$	610

Estimated Future Benefit Payments

The following table represents estimated future

benefit

payments (000’s).


Estimated Future Benefit Payments
	Pension		PBOP		SERP
2022	$	7,040	$	3,151	$	637
2023		8,046		3,448		636
2024		8,497		3,559		635
2025		8,702		3,862		1,090
2026		9,804		4,158		1,144
2027—2031		54,565		23,853		5,583

Pension Plans

Schedule of Allocation of Plan Assets

The actual investment allocations are shown in the following tables.


Pension Plan	Target Allocation 2022			Actual Allocation at December 31,
	Target Allocation 2022			2021			2020			2019

Equity Funds		56	%		57	%		58	%		54	%
Debt Funds		39	%		38	%		37	%		36	%
Real Estate Fund		5	%		4	%		4	%		9	%
Other (1)		—			1	%		1	%		1	%

Total					100	%		100	%		100	%

(1)

Represents investments being held in cash equivalents as of December 31, 2021, December 31, 2020 and December 31, 2019 pending payment of benefits.


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2021
Pension Plan Assets:
Mutual Funds:

Equity Funds	$	86,356	$	86,356	$	—	$	—
Fixed Income Funds		57,883		57,883		—		—

Total Mutual Funds		144,239		144,239		—		—
Cash Equivalents		912		912

Total Assets in the Fair Value Hierarchy	$	145,151	$	145,151	$	—	$	—

Real Estate Fund–Measured at Net Asset Value		6,855

Total Assets	$	152,006


2020
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	79,690	$	79,690	$	—	$	—
Fixed Income Funds		50,622		50,622		—		—

Total Mutual Funds		130,312		130,312		—		—
Cash Equivalents		1,277		1,277

Total Assets in the Fair Value Hierarchy	$	131,589	$	131,589	$	—	$	—

Real Estate Fund–Measured at Net Asset Value		5,817

Total Assets	$	137,406

Other Postretirement Benefit Plans, Defined Benefit

Schedule of Allocation of Plan Assets

The actual investment allocations are shown in the following tables.


PBOP Plan	Target Allocation 2022			Actual Allocation at December 31,
PBOP Plan	Target Allocation 2022			2021			2020			2019

Equity Funds		55	%		56	%		55	%		56	%
Debt Funds		45	%		44	%		45	%		44	%

Total					100	%		100	%		100	%

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2021 and 2020 are as follows (000’s):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2021
PBOP Plan Assets:
Mutual Funds:

Fixed Income Funds	$	18,882	$	18,882	$	—	$	—
Equity Funds		23,769		23,769		—		—

Total Assets	$	42,651	$	42,651	$	—	$	—


2020
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	14,716	$	14,716	$	—	$	—
Equity Funds		18,131		18,131		—		—

Total Assets	$	32,847	$	32,847	$	—	$	—

Summary of Significant Accounting Policies - Additional Information (Detail) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2022 $ / shares	Dec. 31, 2021 USD ($) Subsidiary mi $ / shares	Dec. 31, 2020 USD ($) $ / shares	Dec. 31, 2019 USD ($) $ / shares	Dec. 31, 2018 USD ($)
Significant Accounting Policies [Line Items]
Length Of Pipeline \| mi		86
Gain on divestiture of business, pretax				$ 13.4
Gain on divestiture of business, net				9.8
Provision for income taxes				3.6
Cost of removal obligation		$ 107.5	$ 105.2
Regulatory assets		156.3	164.7
Investments in trading securities		$ 5.7	5.7
Number of Subsidiaries \| Subsidiary		3
Allowance for doubtful accounts		$ 3.3	$ 3.3	$ 1.0	$ 1.3
Depreciation rate based on average depreciable property balance		3.29%	3.34%	3.41%
Common stock dividend per share, declared \| $ / shares		$ 1.52	$ 1.50	$ 1.48
Increase in dividend declared amount per share \| $ / shares		$ 1.52
Inventory of materials and supplies		$ 1.0	$ 0.6
Average Interest Rate On Debt		1.71%	3.12%	3.90%
Other Deferred Charges [Member]
Significant Accounting Policies [Line Items]
Regulatory assets		$ 15.3	$ 14.2
Electric and Gas Division [Member] \| Other Deferred Charges [Member]
Significant Accounting Policies [Line Items]
Hardship accounts in regulatory assets		7.9	6.8
Materials And Supplies [Member]
Significant Accounting Policies [Line Items]
Inventory of materials and supplies		8.6	8.5
Subsequent Event [Member]
Significant Accounting Policies [Line Items]
Increase in dividend declared amount per share \| $ / shares	$ 1.56
Unbilled Revenues
Significant Accounting Policies [Line Items]
Allowance for doubtful accounts		0.2	0.2
Accounts Receivable
Significant Accounting Policies [Line Items]
Allowance for doubtful accounts		$ 3.1	$ 3.1
Quarterly Payment [Member]
Significant Accounting Policies [Line Items]
Common stock dividend paid per share \| $ / shares			$ 0.375	$ 0.37
Common stock dividend per share, declared \| $ / shares		$ 0.38
Quarterly Payment [Member] \| Subsequent Event [Member]
Significant Accounting Policies [Line Items]
Common stock dividend paid per share \| $ / shares	0.39
Increase in dividend declared amount per share \| $ / shares	$ 0.01
Annual Electric Sales Volume
Significant Accounting Policies [Line Items]
Percentage of total sales volumes revenue subject to RDM		27.00%
Annual Natural Gas Sales Volume
Significant Accounting Policies [Line Items]
Percentage of total sales volumes revenue subject to RDM		11.00%
Environmental and Rate Case Costs and Other Expenditures \| Recovered over the next seven years
Significant Accounting Policies [Line Items]
Regulatory assets		$ 8.5
ISO-NE Obligations
Significant Accounting Policies [Line Items]
Cash Deposits		$ 2.7	$ 2.4
Maximum
Significant Accounting Policies [Line Items]
Lease term		12 months
Deferred Compensation Plan [Member]
Significant Accounting Policies [Line Items]
Investments in trading securities		$ 0.6	$ 0.5

Components of Gas and Electric Operating Revenue (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ 473.3	$ 418.6	$ 437.3
Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	466.1	411.9	435.2
Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	7.2	6.7	2.1
Gas Segment
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	224.8	191.4	203.4
Gas Segment \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	217.6	185.2	212.1
Gas Segment \| Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	7.2	6.2	(8.7)
Electric
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	248.5	227.2	233.9
Electric \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	248.5	226.7	223.1
Electric \| Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	0.0	0.5	10.8
Residential \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	219.0	201.8	202.9
Residential \| Gas Segment \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	83.9	73.1	81.4
Residential \| Electric \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	135.1	128.7	121.5
C&I \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	227.4	195.9	213.9
C&I \| Gas Segment \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	124.1	104.5	120.1
C&I \| Electric \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	103.3	91.4	93.8
Other \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	19.7	14.2	18.4
Other \| Gas Segment \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	9.6	7.6	10.6
Other \| Electric \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ 10.1	$ 6.6	$ 7.8

Amount, including tax collected from customer, of revenue from satisfaction of performance obligation by transferring promised good or service to customer. Tax collected from customer is tax assessed by governmental authority that is both imposed on and concurrent with specific revenue-producing transaction, including, but not limited to, sales, use, value-added and excise.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=123359005&loc=d3e9038-108599

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130545-203045

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=123359005&loc=d3e8933-108599

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=123359005&loc=d3e8933-108599

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=123359005&loc=d3e8906-108599

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=123359005&loc=d3e8736-108599

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=123359005&loc=d3e8736-108599

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 4
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130543-203045

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 42
-URI http://asc.fasb.org/extlink&oid=123359005&loc=d3e9054-108599

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 40
-URI http://asc.fasb.org/extlink&oid=123359005&loc=d3e9031-108599

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 924
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SAB Topic 11.L)
-URI http://asc.fasb.org/extlink&oid=6472922&loc=d3e499488-122856

Deferred Revenue Arrangement [Line Items]

Components of Accrued Revenue (Detail) - USD ($)
$ in Millions

Dec. 31, 2021

Dec. 31, 2020

Regulatory Assets – Current

^[1]

$ 47.4

$ 37.3

Total Accrued Revenue

61.2

50.9

Unbilled Revenues

Deferred Revenue Arrangement [Line Items]

Regulatory Assets – Current

13.8

13.6

Deferred Revenue Arrangement [Line Items]

Regulatory Assets – Current

$ 47.4

$ 37.3

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

Components of Exchange Gas Receivable (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Receivables [Line Items]
Total Exchange Gas Receivable	$ 0.7	$ 0.5

Components of Gas Inventory (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 1.0	$ 0.6
Liquefied Natural Gas & Other
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.1	0.1
Natural Gas
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.5	0.2
Propane
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.4	$ 0.3

Regulatory Assets (Detail) - USD ($)
$ in Millions

Dec. 31, 2021

Dec. 31, 2020

Less: Current Portion of Regulatory Assets

$ 156.3

$ 164.7

^[1]

47.4

37.3

Regulatory Assets—noncurrent

108.9

127.4

Environmental Matters

4.6

5.2

Other Deferred Charges

15.3

14.2

Retirement Benefits

86.4

103.7

Deferred Storm Charges

3.3

4.1

Income Taxes

Energy Supply & Other Rate Adjustment Mechanisms

2.6

3.4

Accounts, Notes, Loans and Financing Receivable [Line Items]

$ 44.1

$ 34.1

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

Regulatory Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 52.1	$ 49.8
Less: Current Portion of Regulatory Liabilities	9.5	5.5
Regulatory Liabilities-noncurrent	42.6	44.3
Rate Adjustment Mechanisms
Regulatory Liabilities [Line Items]
Regulatory Liabilities	7.7	4.1
Income Taxes
Regulatory Liabilities [Line Items]
Regulatory Liabilities	44.3	45.5	$ 48.9
Other
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 0.1	$ 0.2

Fair Value of Marketable Securities (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	$ 5.7	$ 5.7
Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	0.6	0.5
Fair Value, Inputs, Level 1
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	5.7	5.7
Fair Value, Inputs, Level 1 \| Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	0.6	0.5
Fair Value, Inputs, Level 1 \| Equity Funds \| Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	0.2	0.2
Fair Value, Inputs, Level 1 \| Money Market Funds
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	5.7	5.7
Fair Value, Inputs, Level 1 \| Money Market Funds \| Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	$ 0.4	$ 0.3

Components of Energy Supply Obligations (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 14.5	$ 10.4
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	7.8	5.7
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	0.0	0.3
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 6.7	$ 4.4

Significant Segment Financial Data (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Other Operating Revenue – Non-Regulated			$ 0.9
Total Operating Revenues	$ 473.3	$ 418.6	438.2
Interest Income	1.6	2.6	2.9
Interest Expense	27.2	26.4	26.6
Depreciation & Amortization Expense	59.5	54.5	52.0
Income Tax Expense (Benefit)	11.5	10.2	13.8
Segment Profit (Loss)	36.1	32.2	44.2
Segment Assets	1,540.3	1,477.9	1,370.8
Capital Expenditures	115.0	122.6	119.2
Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	466.1	411.9	435.2
Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	7.2	6.7	2.1
Electric
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	248.5	227.2	233.9
Interest Income	0.8	1.1	0.9
Interest Expense	9.0	8.7	9.4
Depreciation & Amortization Expense	25.9	23.8	22.6
Income Tax Expense (Benefit)	4.5	4.7	4.2
Segment Profit (Loss)	14.0	12.9	11.5
Segment Assets	584.0	571.8	529.3
Capital Expenditures	38.1	45.5	39.6
Electric \| Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	248.5	226.7	223.1
Electric \| Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	0.0	0.5	10.8
Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	224.8	191.4	203.4
Interest Income	0.5	1.1	1.2
Interest Expense	15.3	14.2	14.4
Depreciation & Amortization Expense	32.6	29.8	28.5
Income Tax Expense (Benefit)	7.7	7.3	7.2
Segment Profit (Loss)	23.2	19.3	19.1
Segment Assets	935.9	886.3	823.3
Capital Expenditures	75.8	71.1	74.0
Gas Segment \| Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	217.6	185.2	212.1
Gas Segment \| Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	7.2	6.2
All Other Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Interest Income	0.3	0.4	0.6
Interest Expense	2.9	3.5	2.8
Depreciation & Amortization Expense	1.0	0.9	0.9
Income Tax Expense (Benefit)	(0.6)	(1.8)	(1.4)
Segment Profit (Loss)	(1.2)		3.4
Segment Assets	20.4	19.8	17.9
Capital Expenditures	1.1	$ 6.0	5.6
Unregulated Operation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Other Operating Revenue – Non-Regulated			0.9
Total Operating Revenues			0.9
Interest Income			0.2
Income Tax Expense (Benefit)	(0.1)		3.8
Segment Profit (Loss)	$ 0.1		10.2
Segment Assets			$ 0.3

Allowance for Doubtful Accounts - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Financing Receivable, Impaired [Line Items]
Recoveries	$ 0.8	$ 0.6	$ 0.8
Provision for Bad Debt	5.6	5.5	4.9
Allowance for doubtful accounts	3.3	3.3	1.0	$ 1.3
Unbilled Revenues
Financing Receivable, Impaired [Line Items]
Allowance for doubtful accounts	0.2	0.2
Accounts Receivable
Financing Receivable, Impaired [Line Items]
Allowance for doubtful accounts	3.1	3.1
Regulatory Assets Harship Accounts
Financing Receivable, Impaired [Line Items]
Recoveries	7.9	6.8
Energy Commodity
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 2.4	$ 1.6	$ 2.3

Activity in Company's Allowance for Doubtful Accounts (Detail) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2021

Dec. 31, 2020

Dec. 31, 2019

Balance at Beginning of Period

$ 3.3

$ 1.0

$ 1.3

Provision

5.6

5.5

4.9

Recoveries

0.8

0.6

0.8

Accounts Written Off

6.5

4.4

6.0

Regulatory Defferals

^[1]

0.1

0.6

Balance at End of Period

3.3

1.0

Electric

Accounts, Notes, Loans and Financing Receivable [Line Items]

Balance at Beginning of Period

1.6

0.6

0.5

Provision

3.3

2.9

3.0

Recoveries

0.4

0.3

Accounts Written Off

3.4

2.6

3.2

Regulatory Defferals

^[1]

0.1

0.4

Balance at End of Period

2.0

1.6

0.6

Gas

Accounts, Notes, Loans and Financing Receivable [Line Items]

Balance at Beginning of Period

1.7

0.4

0.8

Provision

2.3

2.6

1.9

Recoveries

0.4

0.3

0.5

Accounts Written Off

3.1

1.8

2.8

Regulatory Defferals

^[1]

0.2

Balance at End of Period

$ 1.3

$ 1.7

$ 0.4

[1]

The Company has incurred greater than normal bad debt expense due to the coronavirus pandemic. 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 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.

Debt and Financing Arrangements - Additional Information (Detail) - USD ($)		1 Months Ended	12 Months Ended
	Dec. 18, 2020	Jul. 25, 2018	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Sep. 15, 2020	Dec. 18, 2019	Sep. 12, 2019	Oct. 30, 2015
Line of Credit Facility [Line Items]
Issuance of long-term debt	$ 100,000					$ 500,000	$ 200,000	$ 200,000
Weighted average interest rate on short term borrowings			1.20%	1.70%	3.40%
Capital lease obligation, total capitalized cost									$ 13,400,000
Guarantee outstanding			$ 700,000
Capital lease obligation, current			100,000
Accounts Payable			1,600,000	$ 33,200,000
Total rental expense under operating leases			1,900,000	1,800,000	$ 1,400,000
Operating lease obligations			1,900,000	1,800,000
Net Utility Plant			1,257,200,000	$ 1,193,200,000
Other current operating lease obligation			$ 1,600,000
Long-term debt, aggregate principal amount						40,000,000
Long-term debt, stated interest rate								4.04%
Operating lease, weighted average remaining lease term			3 years 6 months	3 years 9 months 18 days
Operating lease, weighted average discount rate percentage			3.90%	4.40%
Total funded indebtedness as percentage of capitalization			65.00%
Restriction on retained earnings for dividend payments			Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2021 for the payment of dividends.
Amount available for the payment of dividends			$ 166,900,000
Retained Earnings			116,200,000	$ 103,700,000
Long term debt repayments			$ 25,800,000	$ 24,800,000	18,800,000
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]			Other current operating lease obligation
Lease Obligations [Member]
Line of Credit Facility [Line Items]
Capital lease obligation, noncurrent			$ 200,000
Other noncurrent operating lease obligation			$ 3,100,000
Maximum [Member]
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization			70.00%
Unitil Energy, Fitchburg, Northern Utilities and Granite State
Line of Credit Facility [Line Items]
Amount available for the payment of dividends			$ 358,700,000
Credit Facility [Member] \| Second Amended Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility		$ 120,000,000
Sublimit for the issuance of standby letters of credit		$ 25,000,000
Revolving credit facility termination date		Jul. 25, 2023
Increase in borrowing limit		$ 50,000,000
Credit Facility [Member] \| London Interbank Offered Rate \| Second Amended Credit Facility
Line of Credit Facility [Line Items]
Credit facility, daily fluctuating rate of interest		1.125%
3.43% Senior Notes, Due December 18, 2029
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount							$ 30,000,000
Long-term debt, stated interest rate			3.43%	3.43%			3.43%
Long-term debt, maturity date			Dec. 18, 2029	Dec. 18, 2029
4.04% Senior Notes, Due September 12, 2049
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount								$ 40,000,000
Long-term debt, stated interest rate			4.04%	4.04%
Long-term debt, maturity date			Sep. 12, 2049	Sep. 12, 2049
3.78% Senior Notes, Due September 15, 2040
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount						$ 27,500,000
Long-term debt, stated interest rate						3.78%
3.58% Mortgage Bonds, Due September 12, 2040
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount						$ 27,500,000
Long-term debt, stated interest rate						3.58%
Bonds [Member]
Line of Credit Facility [Line Items]
Long term debt repayments			$ 25,800,000	$ 24,800,000	$ 18,800,000
Debt repayment, 2022			8,400,000
Debt repayment, 2023			6,900,000
Debt repayment, 2024			6,900,000
Debt repayment, 2025			5,000,000.0
Debt repayment, 2026			38,000,000.0
Debt repayment, Thereafter			444,400,000
2.64% Senior Secured Notes, Due December 18, 2030
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount	$ 4,700,000
Long-term debt, stated interest rate	2.64%
Long-term debt, maturity date	Dec. 18, 2030
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility			120,000,000.0	120,000,000.0
Proceeds from lines of credit			239,100,000	248,900,000
Repayments of lines of credit			$ 229,700,000	252,800,000
Revolving Credit Facility [Member] \| Credit Facility [Member]
Line of Credit Facility [Line Items]
Percentage of capitalization			The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis.
Accounts Payable				1,000,000.0
Natural gas storage inventory			$ 8,300,000	5,400,000
Assets under Capital Leases [Member]
Line of Credit Facility [Line Items]
Net Utility Plant			700,000	1,000,000.0
Net Utility Plant, accumulated amortization			$ 300,000	$ 500,000

Estimated Fair Value of Long Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Inputs, Level 2
Debt Instrument [Line Items]
Estimated Fair Value of Long-Term Debt	$ 584.9	$ 633.1

Details on Long Term Debt (Detail) - USD ($)
$ in Millions

Dec. 31, 2021

Dec. 31, 2020

Less: Unamortized Debt Issuance Costs

$ 509.6

$ 535.4

3.6

3.8

Long-Term Debt

506.0

531.6

Less: Current Portion

^[1]

8.2

8.5

Total Long-Term Debt, Less Current Portion

497.8

523.1

6.33% Senior Notes, Due May 1, 2022

3.70% Senior Notes, Due August 1, 2026

15.0

3.43% Senior Notes, Due December 18, 2029

30.0

First Mortgage Bonds 8.49% Senior Secured Notes, Due October 14, 2024

30.0

First Mortgage Bonds 6.96% Senior Secured Notes, Due September 1, 2028

1.5

3.0

First Mortgage Bonds 8.00% Senior Secured Notes, Due May 1, 2031

14.0

16.0

First Mortgage Bonds 6.32% Senior Secured Notes, Due September 15, 2036

15.0

First Mortgage Bonds 3.58% Senior Secured Notes Due September 15, 2040

15.0

First Mortgage Bonds 4.18% Senior Secured Notes Due November 30, 2048

27.5

6.75% Senior Notes, Due November 30, 2023

30.0

6.79% Senior Notes, Due October 15, 2025

1.9

3.52% Senior Notes, Due November 1, 2027

6.0

10.0

7.37% Senior Notes, Due January 15, 2029

20.0

5.90% Notes, Due December 15, 2030

9.6

10.8

7.98% Notes, Due June 1, 2031

15.0

3.78% Senior Notes, Due September 15, 2040

14.0

4.32% Senior Notes, Due November 1, 2047

40.0

7.72% Senior Notes, Due December 3, 2038

30.0

4.42% Senior Notes, Due October 15, 2044

50.0

4.04% Senior Notes, Due September 12, 2049

50.0

3.72% Senior Notes, Due November 1, 2027

40.0

2.64% Senior Notes, Due December 18, 2030

15.0

$ 4.5

$ 4.7

[1]	The Current Portion of Long-Term Debt includes sinking fund payments.

Details on Long Term Debt (Parenthetical) (Detail)	12 Months Ended
Details on Long Term Debt (Parenthetical) (Detail)	Dec. 31, 2021	Dec. 31, 2020	Dec. 18, 2019	Sep. 12, 2019
Debt Instrument [Line Items]
Stated interest rate				4.04%
6.33% Senior Notes, Due May 1, 2022
Debt Instrument [Line Items]
Stated interest rate	6.33%	6.33%
Debt instrument due date	May 01, 2022	May 01, 2022
3.70% Senior Notes, Due August 1, 2026
Debt Instrument [Line Items]
Stated interest rate	3.70%	3.70%
Debt instrument due date	Aug. 01, 2026	Aug. 01, 2026
3.43% Senior Notes, Due December 18, 2029
Debt Instrument [Line Items]
Stated interest rate	3.43%	3.43%	3.43%
Debt instrument due date	Dec. 18, 2029	Dec. 18, 2029
First Mortgage Bonds 8.49% Senior Secured Notes, Due October 14, 2024
Debt Instrument [Line Items]
Stated interest rate	8.49%	8.49%
Debt instrument due date	Oct. 14, 2024	Oct. 14, 2024
First Mortgage Bonds 6.96% Senior Secured Notes, Due September 1, 2028
Debt Instrument [Line Items]
Stated interest rate	6.96%	6.96%
Debt instrument due date	Sep. 01, 2028	Sep. 01, 2028
First Mortgage Bonds 8.00% Senior Secured Notes, Due May 1, 2031
Debt Instrument [Line Items]
Stated interest rate	8.00%	8.00%
Debt instrument due date	May 01, 2031	May 01, 2031
First Mortgage Bonds 6.32% Senior Secured Notes, Due September 15, 2036
Debt Instrument [Line Items]
Stated interest rate	6.32%	6.32%
Debt instrument due date	Sep. 15, 2036	Sep. 15, 2036
First Mortgage Bonds 3.58% Senior Secured Notes Due September 15, 2040
Debt Instrument [Line Items]
Stated interest rate	3.58%	3.58%
Debt instrument due date	Sep. 15, 2040	Sep. 15, 2040
First Mortgage Bonds 4.18% Senior Secured Notes Due November 30, 2048
Debt Instrument [Line Items]
Stated interest rate	4.18%	4.18%
Debt instrument due date	Nov. 30, 2048	Nov. 30, 2048
6.75% Senior Notes, Due November 30, 2023
Debt Instrument [Line Items]
Stated interest rate	6.75%	6.75%
Debt instrument due date	Nov. 30, 2023	Nov. 30, 2023
6.79% Senior Notes, Due October 15, 2025
Debt Instrument [Line Items]
Stated interest rate	6.79%	6.79%
Debt instrument due date	Oct. 15, 2025	Oct. 15, 2025
3.52% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Stated interest rate	3.52%	3.52%
Debt instrument due date	Nov. 01, 2027	Nov. 01, 2027
7.37% Senior Notes, Due January 15, 2029
Debt Instrument [Line Items]
Stated interest rate	7.37%	7.37%
Debt instrument due date	Jan. 15, 2029	Jan. 15, 2029
5.90% Notes, Due December 15, 2030
Debt Instrument [Line Items]
Stated interest rate	5.90%	5.90%
Debt instrument due date	Dec. 15, 2030	Dec. 15, 2030
7.98% Notes, Due June 1, 2031
Debt Instrument [Line Items]
Stated interest rate	7.98%	7.98%
Debt instrument due date	Jun. 01, 2031	Jun. 01, 2031
3.78% Senior Notes, Due September 15, 2040
Debt Instrument [Line Items]
Stated interest rate	3.78%	3.78%
Debt instrument due date	Sep. 15, 2040	Sep. 15, 2040
4.32% Senior Notes, Due November 1, 2047
Debt Instrument [Line Items]
Stated interest rate	4.32%	4.32%
Debt instrument due date	Nov. 01, 2047	Nov. 01, 2047
7.72% Senior Notes, Due December 3, 2038
Debt Instrument [Line Items]
Stated interest rate	7.72%	7.72%
Debt instrument due date	Dec. 03, 2038	Dec. 03, 2038
4.42% Senior Notes, Due October 15, 2044
Debt Instrument [Line Items]
Stated interest rate	4.42%	4.42%
Debt instrument due date	Oct. 15, 2044	Oct. 15, 2044
4.04% Senior Notes, Due September 12, 2049
Debt Instrument [Line Items]
Stated interest rate	4.04%	4.04%
Debt instrument due date	Sep. 12, 2049	Sep. 12, 2049
3.72% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Stated interest rate	3.72%	3.72%
Debt instrument due date	Nov. 01, 2027	Nov. 01, 2027
2.64% Senior Notes, Due December 18, 2030
Debt Instrument [Line Items]
Stated interest rate	2.64%	2.64%
Debt instrument due date	Dec. 18, 2030	Dec. 18, 2030

Summary of Interest Expense and Interest Income (Detail) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2021

Dec. 31, 2020

Dec. 31, 2019

Interest Expense

Long-Term Debt

$ 26.0

$ 24.8

$ 22.9

Short-Term Debt

0.8

1.4

3.0

Subtotal Interest Expense

0.4

0.2

0.7

27.2

26.4

26.6

Interest Income

Interest and Other Income

(1.6)

(2.6)

(2.9)

Total Interest Expense, Net

25.6

23.8

23.7

Interest and Other Income

Interest Income

(0.5)

(0.8)

AFUDC and Other

Interest Income

Interest and Other Income

^[1]

$ (1.1)

$ (1.8)

$ (2.1)

[1]	AFUDC—Allowance for Funds Used During Construction

Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Short-Term Borrowings Outstanding	$ 64.1	$ 54.7
Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility, limit	120.0	120.0
Short-Term Borrowings Outstanding	64.1	54.7
Letters of Credit Outstanding		0.1
Available revolving credit facility	$ 55.9	$ 65.2

Summary of Contractual Obligations for Long-term Debt (Detail) $ in Millions	Dec. 31, 2021 USD ($)
Contractual Obligation Fiscal Year Maturity Schedule [Line Items]
Total	$ 538.1
2022	59.7
2023	51.8
2024	40.0
2025	38.6
2026	38.2
2027 & Beyond	309.8
Long Term Debt Comprising Principal And Interest [Member]
Contractual Obligation Fiscal Year Maturity Schedule [Line Items]
Total	870.1
2022	32.9
2023	30.8
2024	30.3
2025	27.9
2026	60.6
2027 & Beyond	687.6
Long-Term Debt [Member] \| Long Term Debt Comprising Principal And Interest [Member]
Contractual Obligation Fiscal Year Maturity Schedule [Line Items]
Total	509.6
2022	8.4
2023	6.9
2024	6.9
2025	5.0
2026	38.0
2027 & Beyond	444.4
Interest on Long-Term Debt [Member] \| Long Term Debt Comprising Principal And Interest [Member]
Contractual Obligation Fiscal Year Maturity Schedule [Line Items]
Total	360.5
2022	24.5
2023	23.9
2024	23.4
2025	22.9
2026	22.6
2027 & Beyond	$ 243.2

Debt and Financing Arrangements - Classification of the Company Lease Obligations (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Oct. 30, 2015
Operating Lease Obligations:
Other Current Liabilities (current portion)	$ 1,600
Capital Lease Obligations:
Other Current Liabilities (current portion)	100
Total Capital Lease Obligations			$ 13,400
Lease Obligations [Member]
Operating Lease Obligations:
Other Current Liabilities (current portion)	1,600	$ 1,500
Other Noncurrent Liabilities (long-term portion)	3,100	3,700
Total Operating Lease Obligations	4,670	5,200
Capital Lease Obligations:
Other Current Liabilities (current portion)	100	200
Other Noncurrent Liabilities (long-term portion)	200	200
Total Capital Lease Obligations	316	400
Total Lease Obligations	$ 5,000	$ 5,600

Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Oct. 30, 2015
Capital lease
Amount of Lease Obligations Recorded on Consolidated Balance Sheets			$ 13,400
Lease Obligations [Member]
Operating leases
2022	$ 1,695
2023	1,399
2024	1,069
2025	503
2026	199
2027-2031	121
Total Payments	4,986
Less: Interest	316
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	4,670	$ 5,200
Capital lease
2022	150
2023	107
2024	52
2025	19
Total Payments	328
Less: Interest	12
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$ 316	$ 400

Equity - Additional Information (Detail) - USD ($)			12 Months Ended
Equity - Additional Information (Detail) - USD ($)	Jan. 25, 2022	Aug. 06, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Class of Stock [Line Items]
Common stock, shares outstanding			15,977,766	15,012,310
Common stock, shares issued		800,000	942,316	23,658	20,065
Common stock, shares authorized			25,000,000	25,000,000
Common stock price per share		$ 50.80
Proceeds from Issuance of Common Stock			$ 45,500,000	$ 1,100,000	$ 1,100,000
Percentage of fully-vested restricted stock units that directors will receive in common shares when settled			70.00%
Common stock shares repurchase			8,012	13,194	2,911
Fair value of liabilities associated with fully vested RSUs that will be settled in cash			$ 1,000,000.0	$ 800,000
Share based compensation expense			$ 1,400,000	2,200,000	$ 2,300,000
Percentage of fully-vested restricted stock units that directors will receive in cash when settled			30.00%
Preferred Stock			$ 200,000	$ 200,000
Proceeds from Issuance Initial Public Offering		$ 38,600,000
Restricted Stock
Class of Stock [Line Items]
Restricted stock vesting period			4 years
Restricted stock non-vested			37,621	39,426
Restricted stock weighted average grant date fair value			$ 49.72	$ 55.46
Unrecognized share based compensation			$ 600,000
Share compensation recognition period			2 years 6 months
Cancellations under the stock plan			0
Restricted Stock \| Subsequent Event
Class of Stock [Line Items]
Restricted Stock Units Granted	36,770
Aggregate Market Value	$ 1,700,000
Restricted Stock \| Vesting Annually
Class of Stock [Line Items]
Restricted stock vesting percentage annually				25.00%
Series 6
Class of Stock [Line Items]
Preferred stock, outstanding			1,861	1,887
Preferred Stock			$ 200,000	$ 200,000
Dividend rate			6.00%	6.00%
Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Proceeds from Issuance of Common Stock			$ 1,000,000.0	$ 1,100,000	$ 1,100,000
Dividend and Distribution Reinvestment and Share Purchase Plan \| Common Stock
Class of Stock [Line Items]
Common stock, shares issued			22,316	23,658	20,065
Over-Allotment Option [Member]
Class of Stock [Line Items]
Number Of Shares Granted Overallotment Option To Purchase Additional Shares		30 days
Sale of Stock, Number of Shares Issued in Transaction		120,000
Proceeds from Issuance of Private Placement		$ 5,900,000
Maximum
Class of Stock [Line Items]
Dividend declared			$ 100,000	$ 100,000
Repurchase expense			$ 400,000	$ 500,000	$ 200,000
Maximum \| Restricted Stock
Class of Stock [Line Items]
Restricted stock available for awards			677,500
Restricted stock that may be awarded in any one calendar year to any one participant			20,000
Average \| Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Common stock price per share			$ 46.98

Restricted Shares Issued in Conjunction with Stock Plan (Detail) - Restricted Stock $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) shares
Period 1
Class of Stock [Line Items]
Issuance Date	Jan. 29, 2019
Shares \| shares	33,150
Aggregate Market Value \| $	$ 1.6
Period 2
Class of Stock [Line Items]
Issuance Date	Jan. 28, 2020
Shares \| shares	28,630
Aggregate Market Value \| $	$ 1.8
Period 3
Class of Stock [Line Items]
Issuance Date	Jul. 28, 2020
Shares \| shares	3,000
Aggregate Market Value \| $	$ 0.1
Period 4
Class of Stock [Line Items]
Issuance Date	Jan. 26, 2021
Shares \| shares	23,140
Aggregate Market Value \| $	$ 0.9

Restricted Stock Units Issued (Detail) - Restricted Stock Units (RSUs) - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Restricted Stock Units
Beginning Restricted Stock Units	43,192	70,364
Restricted Stock Units Granted	4,519	3,743
Dividend Equivalents Earned	1,471	1,507
Restricted Stock Units Settled		(32,422)
Ending Restricted Stock Units	49,182	43,192
Weighted-Average Stock Price
Beginning Restricted Stock Units	$ 41.34	$ 41.20
Restricted Stock Units Granted	43.35	39.26
Dividend Equivalents Earned	46.34	47.34
Restricted Stock Units Settled		41.09
Ending Restricted Stock Units	$ 41.67	$ 41.34

Reconciliation of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Schedule Of Computation Of Basic And Diluted Earnings Per Common Share [Line Items]
Earnings Available to Common Shareholders	$ 36.1	$ 32.2	$ 44.2
Weighted Average Common Shares Outstanding—Basic	15,373	14,951	14,894
Plus: Diluted Effect of Incremental Shares	3	1	6
Weighted Average Common Shares Outstanding—Diluted	15,376	14,952	14,900
Earnings per Share—Basic and Diluted	$ 2.35	$ 2.15	$ 2.97

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

Weighted Average Non Vested Restricted Shares Excluded from Computation of Earnings Per Share (Detail) - shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Non Vested Restricted Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation	23,636	42,813

Energy Supply - Additional Information (Detail)	12 Months Ended
Energy Supply - Additional Information (Detail)	Dec. 31, 2021 MMBTU Bcf
Gas and Oil Acreage [Line Items]
Natural gas available under firm contract per day of year-round and seasonal transportation and underground storage capacity to distribution facilities \| MMBTU	14,439
Natural gas, underground storage \| Bcf	0.4
Percentage of power supply requirement	50.00%
Power supply contract duration	12 months
Maximum
Gas and Oil Acreage [Line Items]
Purchases of natural gas, contract duration	1 year

Gas And Electric Supply Contractual Obligations (Detail) $ in Millions	Dec. 31, 2021 USD ($)
Total	$ 538.1
2022	59.7
2023	51.8
2024	40.0
2025	38.6
2026	38.2
2027 & Beyond	309.8
Gas Supply Contracts
Total	523.9
2022	58.5
2023	50.6
2024	38.8
2025	37.3
2026	36.9
2027 & Beyond	301.8
Electric Supply Contracts
Total	14.2
2022	1.2
2023	1.2
2024	1.2
2025	1.3
2026	1.3
2027 & Beyond	$ 8.0

Commitments and Contingencies - Additional Information (Detail)																1 Months Ended	12 Months Ended
	Nov. 02, 2021 USD ($)	Oct. 01, 2021 USD ($)	Aug. 24, 2021 USD ($)	Aug. 02, 2021 USD ($)	May 27, 2021 USD ($)	May 01, 2021 USD ($)	Apr. 02, 2021 USD ($)	Jan. 31, 2021 USD ($)	Nov. 30, 2020 USD ($)	Nov. 02, 2020 USD ($)	Mar. 26, 2020 USD ($)	Feb. 28, 2020 USD ($)	Oct. 29, 2019 USD ($)	Jun. 25, 2019	Nov. 01, 2018 USD ($)	Mar. 31, 2021 USD ($)	Dec. 31, 2021 USD ($) Bcf	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 17, 2021 Bcf	Oct. 29, 2021 USD ($)	Oct. 30, 2020 USD ($)	Jan. 10, 2020 MWh	May 23, 2019 MWh	Jul. 31, 2018 MW MWh	Jun. 30, 2017 MW MWh
Commitments And Contingencies [Line Items]
Corporate income tax rate																	21.00%	21.00%	21.00%
Increase (decrease) in annual revenue	$ 1,600,000		$ 100,000						$ 1,300,000	$ 1,400,000
Spending cap																	$ 538,100,000
Power generation facility \| Bcf																						1,600
Power generation capacity \| MWh																												9,450,000
Percentage of approved return on equity, reflecting on equity								52.45%				52.45%
Percentage of approved return on equity, reflecting on debt								47.55%				47.55%
Percentage of approved return on equity								9.70%				9.70%
Revenue Impact Threshold								$ 100,000				$ 40,000
Regulatory assets approved increase in revenue due to be recovered																							$ 3,300,000	$ 2,200,000
Approved annual increase in rates					$ 4,500,000	$ 900,000	$ 12,000,000.0	$ 1,100,000			$ 3,600,000	$ 4,600,000				$ 3,700,000
Increase in annual base rate							4.40%				3.60%
Requested annual increase in rates						$ 1,100,000							$ 1,100,000		$ 900,000
Approved annual increase in rates																	900,000
Apporved annual decrease in rates																	$ 200,000
Tax Year 2018
Commitments And Contingencies [Line Items]
Corporate income tax rate																				21.00%	21.00%
Other Restructuring
Commitments And Contingencies [Line Items]
Cost recovery period, years																	2 years
Offshore Wind Energy
Commitments And Contingencies [Line Items]
Power generation facility \| MW																											400	1,600
Remuneration Percentage														2.75%
Offshore Wind Energy \| First Solicitation [Member]
Commitments And Contingencies [Line Items]
Power generation facility																	800								800
Offshore Wind Energy \| Second Solicitation [Member]
Commitments And Contingencies [Line Items]
Power generation facility \| MWh																										800
Offshore Wind Energy \| Third Solicitation [Member]
Commitments And Contingencies [Line Items]
Power generation facility \| Bcf																	1,600
Facility power capacity to be procured in the future \| Bcf																	2,400
Offshore Wind Energy \| Maximum [Member] \| Third Solicitation [Member]
Commitments And Contingencies [Line Items]
Power generation facility \| Bcf																	5,600
Qualified Clean Energy
Commitments And Contingencies [Line Items]
Power generation capacity \| MWh																											9,554,940
Remuneration Percentage														2.75%
Vinyard Wind Energy [Member]
Commitments And Contingencies [Line Items]
Power generation facility \| Bcf																						1,200
Mayflower Wind energy [Member]
Commitments And Contingencies [Line Items]
Power generation facility \| Bcf																						400
New Hampshire
Commitments And Contingencies [Line Items]
Approved annual increase in rates		$ 2,600,000
Requested annual increase in rates				$ 7,800,000
Percentage of change in revenue over previous year				8.10%
Maine
Commitments And Contingencies [Line Items]
Percentage of approved return on equity, reflecting on equity											50.00%
Percentage of approved return on equity, reflecting on debt											50.00%
Percentage of approved return on equity											9.48%

Company's Liability for Environmental Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	$ 2.1	$ 2.7
Additions	0.9	0.2
Less: Payments / Reductions	0.3	0.8
Total Balance at End of Period	2.7	2.1
Less: Current Portion	0.5	0.3
Noncurrent Balance at End of Period	$ 2.2	$ 1.8

Provisions for Federal and State Income Taxes (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current Income Tax Provision
Federal		$ 0.3
State	$ 0.7	0.6	$ 0.3
Total Current Income Taxes	0.7	0.9	0.3
Deferred Income Tax Provision
Federal	7.3	6.5	9.4
State	3.5	2.8	4.1
Total Deferred Income Taxes	10.8	9.3	13.5
Total Income Tax Expense	$ 11.5	$ 10.2	$ 13.8

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

+ References + Details

Differences Between Provisions for Income Taxes and Provisions Calculated at Statutory Federal Tax Rate (Detail)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Examination [Line Items]
Statutory Federal Income Tax Rate	21.00%	21.00%	21.00%
State Income Taxes, net	6.00%	6.00%	6.00%
Utility Plant Differences	(3.00%)	(4.00%)	(3.00%)
Other, net		1.00%
Effective Income Tax Rate	24.00%	24.00%	24.00%

Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Deferred Tax Assets
Retirement Benefit Obligations	$ 34.1	$ 40.7
Net Operating Loss Carryforwards	4.1
Tax Credit Carryforwards	0.7	0.3
Other, net	1.3	1.3
Total Deferred Tax Assets	40.2	42.3
Deferred Tax Liabilities
Utility Plant Differences	157.4	143.8
Regulatory Assets & Liabilities	9.4	6.2
Other, net	1.1	1.3
Total Deferred Tax Liabilities	167.9	151.3
Net Deferred Tax Liabilities	$ 127.7	$ 109.0

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Taxes [Line Items]
Corporate federal income tax		21.00%	21.00%	21.00%
Regulatory Liability	$ 49.8	$ 52.1	$ 49.8
Regulatory liability, expected flow back to customers		47.1				$ 48.9
Regulatory liability, expected pass back to ratepayers		$ 0.7	0.3	$ 1.7		1.8
Net Operating Loss Carryforwards Utilized For Income Taxes			7.7
Percentage of employment retention credit		50.00%
Employment retention duties capacity		100.00%
Employment tax expense		$ 0.4	0.6
Consolidated Appropriations Act 2021 [Member]
Income Taxes [Line Items]
Percentage of employment retention credit	70.00%
Employment retention duties capacity	100.00%
Minimum
Income Taxes [Line Items]
Average Rate Assumption Method estimated flow back period		15 years
Maximum
Income Taxes [Line Items]
Average Rate Assumption Method estimated flow back period		20 years
Income Tax Related Liabilities
Income Taxes [Line Items]
Regulatory Liability	$ 45.5	$ 44.3	$ 45.5			$ 48.9
Gas Ratepayers \| Massachusetts And Maine [Member]
Income Taxes [Line Items]
Regulatory liability, expected flow back to customers		3.1
Net Operating Loss Carryforward Assets
Income Taxes [Line Items]
Regulatory liability, expected pass back to ratepayers		$ 3.6			$ 2.0
Tax Year 2018
Income Taxes [Line Items]
Corporate federal income tax					21.00%	21.00%

Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Benefit Plan Costs
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	2.50%	3.25%	4.25%
Rate of Compensation Increase	3.00%	3.00%	3.00%
Expected Long-term rate of return on plan assets	7.50%	7.40%	7.50%
Health Care Cost Trend Rate Assumed for Next Year	6.60%	7.00%	7.00%
Ultimate Health Care Cost Trend Rate	4.50%	4.50%	4.50%
Year that Ultimate Health Care Cost Trend Rate is reached	2029	2029	2024
Benefit Obligation
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	2.85%	2.50%	3.25%
Rate of Compensation Increase	3.00%	3.00%	3.00%
Health Care Cost Trend Rate Assumed for Next Year	6.20%	6.60%	7.00%
Ultimate Health Care Cost Trend Rate	4.50%	4.50%	4.50%
Year that Ultimate Health Care Cost Trend Rate is reached	2029	2029	2029

Retirement Benefit Obligations - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Change in Discount Rate	0.25%
Increase or decrease of Net Periodic Benefit Cost (NPBC) due to change in the discount rate	$ 679
Pension expense	7,200	$ 6,900	$ 5,800
Regulatory assets	$ 156,300	164,700
Defined Benefit Plan, Expected Long-term Rate-of-Return on Assets Assumption	The desired investment objective is a long-term rate of return on assets that is approximately 5 – 6% greater than the assumed rate of inflation as measured by the Consumer Price Index.
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation	$ 185,100	189,400
Company's contributions	4,100	4,665	6,916
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Company's contributions	8,903	4,156	4,000
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation	17,500	16,700
Company's contributions	637	654	610
Fair Value Of Plan Assets
Defined Benefit Plan Disclosure [Line Items]
Pension expense	6,100	6,500	7,300
Defined Benefit Obligations
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	86,400	103,700
Four Zero One K Plan
Defined Benefit Plan Disclosure [Line Items]
Company's contributions	$ 3,300	$ 3,000	$ 2,800
Benefit Plan Costs
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Long-term Return on Assets	7.50%	7.40%	7.50%
Scenario Forecast \| Pension Plans \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				56.00%
Scenario Forecast \| Pension Plans \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				39.00%
Scenario Forecast \| Other Postretirement Benefit Plans, Defined Benefit \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				55.00%
Scenario Forecast \| Other Postretirement Benefit Plans, Defined Benefit \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				45.00%
Real Estate Funds \| Scenario Forecast \| Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				5.00%

Components of Retirement Plan Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 3,472	$ 3,322	$ 3,104
Interest Cost	5,003	5,776	6,484
Expected Return on Plan Assets	(9,693)	(9,019)	(8,475)
Prior Service Cost Amortization	301	320	320
Actuarial Loss Amortization	8,089	6,472	4,324
Sub-total	7,172	6,871	5,757
Amounts Capitalized or Deferred	(3,384)	(3,083)	(2,227)
NPBC Recognized	3,788	3,788	3,530
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	3,034	2,698	2,304
Interest Cost	2,740	3,121	3,426
Expected Return on Plan Assets	(2,508)	(2,063)	(1,645)
Prior Service Cost Amortization	1,208	1,210	1,213
Actuarial Loss Amortization	1,045	744	227
Sub-total	5,519	5,710	5,525
Amounts Capitalized or Deferred	(3,136)	(2,865)	(2,317)
NPBC Recognized	2,383	2,845	3,208
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	354	283	247
Interest Cost	458	549	567
Prior Service Cost Amortization	56	57	56
Actuarial Loss Amortization	1,489	1,036	628
Sub-total	2,357	1,925	1,498
Amounts Capitalized or Deferred	(712)	(579)	(430)
NPBC Recognized	$ 1,645	$ 1,346	$ 1,068

Summary of Information on Plans' Assets, Projected Benefit Obligations (PBO), and Funded Status (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	$ 137,406	$ 125,755
Actual Return on Plan Assets	16,989	13,024
Employer Contributions	4,100	4,665	$ 6,916
Benefits Paid	(6,489)	(6,038)
Plan Assets at End of Year	152,006	137,406	125,755
PBO at Beginning of Year	206,092	182,135
Service Cost	3,472	3,322	3,104
Interest Cost	5,003	5,776	6,484
Plan Amendments	674	732
Benefits Paid	(6,489)	(6,038)	(6,877)
Actuarial (Gain) or Loss	(9,334)	20,165
PBO at End of Year	199,418	206,092	182,135
Funded Status: Assets vs PBO	(47,412)	(68,686)
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	32,847	27,280
Actual Return on Plan Assets	3,586	3,739
Employer Contributions	8,903	4,156	4,000
Participant Contributions	220	240
Benefits Paid	(2,905)	(2,568)
Plan Assets at End of Year	42,651	32,847	27,280
PBO at Beginning of Year	106,831	95,657
Service Cost	3,034	2,698	2,304
Interest Cost	2,740	3,121	3,426
Benefits Paid	(2,905)	(2,568)	(1,758)
Actuarial (Gain) or Loss	2,167	7,683
PBO at End of Year	112,087	106,831	95,657
Funded Status: Assets vs PBO	(69,436)	(73,984)
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions	637	654	610
Benefits Paid	(637)	(654)
PBO at Beginning of Year	20,225	17,759
Service Cost	354	283	247
Interest Cost	458	549	567
Benefits Paid	(637)	(654)	(610)
Actuarial (Gain) or Loss	(2,686)	2,288
PBO at End of Year	17,714	20,225	$ 17,759
Funded Status: Assets vs PBO	$ (17,714)	$ (20,225)

Employer Contributions, Participant Contributions and Benefit Payments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Plans
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	$ 4,100	$ 4,665	$ 6,916
Benefit Payments	6,489	6,038	6,877
Other Postretirement Benefit Plans, Defined Benefit
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	8,903	4,156	4,000
Participant Contributions	220	240	121
Benefit Payments	2,905	2,568	1,758
Supplemental Employee Retirement Plans, Defined Benefit
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	637	654	610
Benefit Payments	$ 637	$ 654	$ 610

Amount of contribution received by defined benefit plan from employer which increases plan assets.

+ References + Details

Estimated Future Benefit Payments (Detail) $ in Thousands	Dec. 31, 2021 USD ($)
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
2022	$ 7,040
2023	8,046
2024	8,497
2025	8,702
2026	9,804
2027 — 2031	54,565
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
2022	3,151
2023	3,448
2024	3,559
2025	3,862
2026	4,158
2027 — 2031	23,853
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
2022	637
2023	636
2024	635
2025	1,090
2026	1,144
2027 — 2031	$ 5,583

Actual Investment Allocations (Detail)

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Dec. 31, 2019

Pension Plans

Pension Plans | Equity Funds

100.00%

Pension Plans | Fixed Income Securities

57.00%

58.00%

54.00%

38.00%

37.00%

36.00%

Pension Plans | Other

Other Postretirement Benefit Plans, Defined Benefit

^[1]

1.00%

Other Postretirement Benefit Plans, Defined Benefit | Equity Funds

100.00%

Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities

56.00%

55.00%

56.00%

Real Estate Funds | Pension Plans

44.00%

45.00%

44.00%

Scenario Forecast | Pension Plans | Equity Funds

4.00%

9.00%

Scenario Forecast | Pension Plans | Fixed Income Securities

56.00%

Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Equity Funds

39.00%

Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities

55.00%

Scenario Forecast | Real Estate Funds | Pension Plans

45.00%

5.00%

[1]	Represents investments being held in cash equivalents as of December 31, 2021, December 31, 2020 and December 31, 2019 pending payment of benefits.

Assets Measured at Fair Value on Recurring Basis for Pension Plan (Detail) - Pension Plans - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 152,006	$ 137,406	$ 125,755
Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	144,239	130,312
Mutual Fund \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	86,356	79,690
Mutual Fund \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	57,883	50,622
Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	912	1,277
Mutual Fund Including Cash And Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	145,151	131,589
Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	6,855	5,817
Fair Value, Inputs, Level 1 \| Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	144,239	130,312
Fair Value, Inputs, Level 1 \| Mutual Fund \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	86,356	79,690
Fair Value, Inputs, Level 1 \| Mutual Fund \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	57,883	50,622
Fair Value, Inputs, Level 1 \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	912	1,277
Fair Value, Inputs, Level 1 \| Mutual Fund Including Cash And Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 145,151	$ 131,589

Assets Measured at Fair Value on Recurring Basis for PBOP Plan (Detail) - Other Postretirement Benefit Plans, Defined Benefit - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 42,651	$ 32,847	$ 27,280
Mutual Fund \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	18,882	14,716
Mutual Fund \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	23,769	18,131
Fair Value, Inputs, Level 1
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	42,651	32,847
Fair Value, Inputs, Level 1 \| Mutual Fund \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	18,882	14,716
Fair Value, Inputs, Level 1 \| Mutual Fund \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 23,769	$ 18,131