Unitil (UTL) 10-K 14 Feb 23 2022 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2022	Feb. 10, 2023	Jun. 30, 2022
Document Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Transition Report	false
Entity Interactive Data Current	Yes
Amendment Flag	false
Document Period End Date	Dec. 31, 2022
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Entity Registrant Name	UNITIL CORPORATION
Entity Central Index Key	0000755001
Securities Act File Number	1-8858
Entity Tax Identification Number	02-0381573
Entity Incorporation, State or Country Code	NH
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Shell Company	false
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Address, Address Line One	6 Liberty Lane West
Entity Address, City or Town	Hampton
Entity Address, Postal Zip Code	03842-1720
Entity Address, State or Province	NH
City Area Code	603
Local Phone Number	772-0775
Trading Symbol	UTL
Security Exchange Name	NYSE
Entity Common Stock, Shares Outstanding		16,082,501
Title of 12(b) Security	Common Stock
Entity Public Float			$ 926,712,766
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
ICFR Auditor Attestation Flag	true
Documents Incorporated by Reference	Portions of the Proxy Statement relating to the Annual Meeting of Shareholders to be held on April 26, 2023 are incorporated by reference into Part III of this Report.
Auditor Name	Deloitte & Touche LLP
Auditor Firm ID	34
Auditor Location	Boston, MA

CONSOLIDATED STATEMENTS OF EARN

CONSOLIDATED STATEMENTS OF EARNINGS - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating Revenues:
Total Operating Revenues	$ 563.2	$ 473.3	$ 418.6
Operating Expenses:
Operation and Maintenance	73.7	68.7	65.7
Depreciation and Amortization	62.6	59.5	54.5
Taxes Other Than Income Taxes	25.9	24.5	23.9
Total Operating Expenses	482.7	395.5	347.2
Operating Income	80.5	77.8	71.4
Interest Expense, Net	25.5	25.6	23.8
Other Expense (Income), Net	2.4	4.6	5.2
Income Before Income Taxes	52.6	47.6	42.4
Provision for Income Taxes	11.2	11.5	10.2
Net Income Applicable to Common Shares	$ 41.4	$ 36.1	$ 32.2
Earnings per Common Share - Basic	$ 2.59	$ 2.35	$ 2.15
Earnings per Common Share - Diluted	$ 2.59	$ 2.35	$ 2.15
Weighted Average Common Shares Outstanding - Basic	15,991	15,373	14,951
Weighted Average Common Shares Outstanding - Diluted	15,996	15,376	14,952
Electric
Operating Revenues:
Total Operating Revenues	$ 297.9	$ 248.5	$ 227.2
Operating Expenses:
Cost of Sales	199.1	151.1	134.3
Gas
Operating Revenues:
Total Operating Revenues	265.3	224.8	191.4
Operating Expenses:
Cost of Sales	$ 121.4	$ 91.7	$ 68.8

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Current Assets:
Cash and Cash Equivalents		$ 9	$ 6.5
Accounts Receivable, Net		73.8	66.9
Accrued Revenue		72.8	61.2
Exchange Gas Receivable		18	7.4
Gas Inventory		1.8	1
Materials and Supplies		11.4	8.6
Prepayments and Other		8	8.1
Total Current Assets		194.8	159.7
Utility Plant:
Electric		627.5	602.4
Gas		1,043.6	972.6
Common		67.6	66.4
Construction Work in Progress		52.6	47.5
Utility Plant		1,791.3	1,688.9
Less: Accumulated Depreciation		459.6	431.7
Net Utility Plant		1,331.7	1,257.2
Other Noncurrent Assets:
Regulatory Assets		47.8	108.9
Operating Lease Right of Use Assets		4.3	4.7
Other Assets		11.8	9.8
Total Other Noncurrent Assets		63.9	123.4
TOTAL ASSETS		1,590.4	1,540.3
Current Liabilities:
Accounts Payable		68.6	52.4
Short-Term Debt		116	64.1
Long-Term Debt, Current Portion	[1]	6.7	8.2
Regulatory Liabilities		15	9.5
Energy Supply Obligations		24.1	14.5
Environmental Obligations		0.6	0.5
Other Current Liabilities		29.1	24.3
Total Current Liabilities		260.1	173.5
Noncurrent Liabilities:
Retirement Benefit Obligations		46.8	133.9
Deferred Income Taxes, net		163.4	127.7
Cost of Removal Obligations		116.1	107.5
Regulatory Liabilities		36.9	42.6
Environmental Obligations		3.8	2.2
Other Noncurrent Liabilities		6.6	6.6
Total Noncurrent Liabilities		373.6	420.5
Capitalization:
Long-Term Debt, Less Current Portion		489.1	497.8
Stockholders' Equity:
Common Equity (Outstanding 16,043,355 and 15,977,766 Shares)		334.9	332.1
Retained Earnings		132.5	116.2
Total Common Stock Equity		467.4	448.3
Preferred Stock		0.2	0.2
Total Stockholders' Equity		467.6	448.5
Total Capitalization		956.7	946.3
Commitments and Contingencies (Note 7)
TOTAL LIABILITIES AND CAPITALIZATION		$ 1,590.4	$ 1,540.3
[1] The Current Portion of Long-Term Debt includes sinking fund payments.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Common Equity Outstanding	16,043,355	15,977,766

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating Activities:
Net Income	$ 41.4	$ 36.1	$ 32.2
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	62.6	59.5	54.5
Deferred Tax Provision	11	10.8	9.3
Changes in Working Capital Items:
Accounts Receivable	(6.9)	(4.9)	(6.9)
Accrued Revenue	(11.6)	(10.3)	(0.9)
Regulatory Liabilities	5.5	4	(1.9)
Exchange Gas Receivable	(10.6)	(2.5)	1.2
Accounts Payable	16.2	19.2	(4.4)
Other Changes in Working Capital Items	1.4	0.7	(2.4)
Deferred Regulatory and Other Charges	(6.5)	(2.7)	(9.3)
Other, net	(4.8)	(2.1)	4.3
Cash Provided by Operating Activities	97.7	107.8	75.7
Investing Activities:
Property, Plant and Equipment Additions	(122.1)	(115)	(122.6)
Cash Used In Investing Activities	(122.1)	(115)	(122.6)
Financing Activities:
Proceeds from (Repayment of) Short-Term Debt, net	51.9	9.4	(3.9)
Issuance of Long-Term Debt	0	0	99.7
Repayment of Long-Term Debt	(10.4)	(25.8)	(24.8)
Long-Term Debt Issuance Costs	0	0	(0.6)
Decrease in Capital Lease Obligations	(0.1)	(0.1)	(0.1)
Net Increase (Decrease) in Exchange Gas Financing	9.6	2.3	(1.1)
Dividends Paid	(25.1)	(23.6)	(22.6)
Proceeds from Issuance of Common Stock	1	45.5	1.1
Cash Provided by (Used In) Financing Activities	26.9	7.7	47.7
Net Increase (Decrease) in Cash and Cash Equivalents	2.5	0.5	0.8
Cash and Cash Equivalents at Beginning of Year	6.5	6	5.2
Cash and Cash Equivalents at End of Year	9	6.5	6
Supplemental Information:
Interest Paid	26	26	23.7
Income Taxes Paid	1.2	1.4	0.9
Payments on Capital Leases	0.2	0.2	0.3
Capital Expenditures Included in Accounts Payable	7.3	4.9	1.7
Right-of-Use Assets Obtained in Exchange for Lease Obligations	$ 1.1	$ 0.7	$ 1.2

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY - USD ($) $ in Millions	Total	Common Equity	Retained Earnings
Beginning Balance at Dec. 31, 2019	$ 376.6	$ 282.5	$ 94.1
Net Income	32.2		32.2
Dividends	(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	285.3	103.7
Net Income	36.1		36.1
Dividends	(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
Net Income	41.4		41.4
Dividends	(25.1)		(25.1)
Shares Issued Under Stock Plans	1.8	1.8
Issuance of Common Shares	1	1
Ending Balance at Dec. 31, 2022	$ 467.4	$ 334.9	$ 132.5

CONSOLIDATED STATEMENTS OF CH_2

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Dividends per Common Share	$ 1.56	$ 1.52	$ 1.50
Common stock, shares issued	18,853	942,316	23,658

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	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 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 Resources and Unitil Realty. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary, which currently does not have any activity. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. 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 revenue meets the definition of “revenues from contracts with customers” as defined in Accounting Standards Codification (ASC) 606. Revenue recognized in connection with rate adjustment mechanisms is consistent with the definition of alternative revenue programs in ASC 980, as the Company has the ability to adjust rates in the future as a result of past activities or completed events. 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, 2022 Electric and Gas Operating Revenues (millions): Electric Gas Total Billed and Unbilled Revenue: Residential $ 159.9 $ 98.2 $ 258.1 Commercial & Industrial 112.6 153.8 266.4 Other 17.7 11.3 29.0 Total Billed and Unbilled Revenue 290.2 263.3 553.5 Rate Adjustment Mechanism Revenue 7.7 2.0 9.7 Total Electric and Gas Operating Revenues $ 297.9 $ 265.3 $ 563.2 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 Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or gas sales. The difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recognized as an increase or a decrease in Accrued Revenue, which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases and other authorized adjustments that the Company files with the MDPU and NHPUC. Fitchburg has been subject to revenue decoupling since 2011. Unitil Energy is subject to revenue decoupling as of June 1, 2022. As a result of Unitil Energy now being subject to revenue decoupling, as of June 1, 2022, revenue decoupling now applies to substantially all of Unitil’s total annual electric sales volumes. As a result of the recently received final order in Northern Utilities’ base rate case in New Hampshire, substantially all of Northern Utilities’ gas sales volumes in New Hampshire are subject to decoupling as of August 1, 2022. As of August 1, 2022, the Company estimates that revenue decoupling applies to approximately 43 % of Unitil’s total annual gas sales volumes. The Company's electric and gas sales in New Hampshire and Massachusetts are now largely decoupled. The following table shows the estimated percentages of electric and gas sales that are subject to revenue decoupling for the periods presented. Revenue Decoupling Estimated Percentage of Decoupled Sales For Periods Presented Electric Before June 1, 2022 27 % After June 1, 2022 Substantially All Gas Before August 1, 2022 11 % After August 1, 2022 43 % The Company bills its customers for sales tax in Massachusetts and Maine. These taxes are remitted to the appropriate departments of revenue in each state and are excluded from revenues on the Company’s Consolidated Statements of Earnings. Depreciation and Amortization - Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets, and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company’s fixed assets. A change in the estimated useful lives of these assets could have a material effect on the Company’s consolidated financial statements. Provisions for depreciation were equivalent to the following composite rates, based on the average depreciable property balances at the beginning and end of each year: 2022 - 3.26 %, 2021 - 3.29 % and 2020 - 3.34 %. 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 by the Board of Directors. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. For the year ended December 31, 2022 the Company paid quarterly dividends of $ 0.39 per share, resulting in an annualized dividend rate of $ 1.56 per common share. For the years ended December 31, 2021 and 2020, the Company paid quarterly dividends of $ 0.38 and $ 0.375 per common share, respectively, resulting in annualized dividend rates of $ 1.52 and $ 1.50 per common share, respectively. At its January 2023 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $ 0.405 per share, an increase of $ 0.015 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $ 1.62 per share from $ 1.56 per share. 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, 2022 and 2021, the Unitil subsidiaries had deposited $ 6.0 million and $ 2.7 million, respectively, to satisfy their ISO-NE obligations. Allowance for Doubtful Accounts - The Company recognizes a provision for doubtful accounts that reflects the Company’s estimate of expected credit losses for electric and gas utility service accounts receivable. The allowance for doubtful accounts is calculated by applying a historical loss rate to customer account balances and management’s assessment of current and expected economic conditions, customer trends, or other factors. The Company also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of the energy commodity portion of bad debts through rate mechanisms. 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 $ 2.5 million and $ 3.1 million of the Allowance for Doubtful Accounts at December 31, 2022 and December 31, 2021, respectively. Unbilled Revenues, net (a component of Accrued Revenue) includes $ 0.1 million and $ 0.2 million of the Allowance for Doubtful Accounts at December 31, 2022 and December 31, 2021, 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, 2022 and 2021. December 31, Accrued Revenue (millions) 2022 2021 Regulatory Assets—Current $ 66.5 $ 47.4 Unbilled Revenues 6.3 13.8 Total Accrued Revenue $ 72.8 $ 61.2 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, 2022 and 2021. December 31, Exchange Gas Receivable (millions) 2022 2021 Northern Utilities $ 16.3 $ 6.7 Fitchburg 1.7 0.7 Total Exchange Gas Receivable $ 18.0 $ 7.4 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, 2022 and 2021. December 31, Gas Inventory (millions) 2022 2021 Natural Gas $ 1.0 $ 0.5 Propane 0.4 0.4 Liquefied Natural Gas & Other 0.4 0.1 Total Gas Inventory $ 1.8 $ 1.0 The Company also has an inventory of Materials and Supplies in the amounts of $ 11.4 million and $ 8.6 million as of December 31, 2022 and December 31, 2021, 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 2.50 %, 1.71 % and 3.12 % in 2022, 2021 and 2020, 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, 2022 and 2021, the Company has recorded cost of removal amounts of $ 116.1 million and $ 107.5 million, respectively, that have been collected in depreciation rates but have not yet been expended, and which represent regulatory liabilities. These amounts are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations. Regulatory Accounting - The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. 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, 2022 and December 31, 2021, the Company has recorded $ 5.8 million and $ 7.9 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. December 31, Regulatory Assets consist of the following (millions) 2022 2021 Retirement Benefits $ 29.1 $ 86.4 Energy Supply & Other Rate Adjustment Mechanisms 63.0 44.1 Deferred Storm Charges 3.4 3.3 Environmental 5.9 4.6 Income Taxes 1.8 2.6 Other Deferred Charges 11.1 15.3 Total Regulatory Assets 114.3 156.3 Less: Current Portion of Regulatory Assets (1) 66.5 47.4 Regulatory Assets—noncurrent $ 47.8 $ 108.9 (1) Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets. December 31, Regulatory Liabilities consist of the following (millions) 2022 2021 Rate Adjustment Mechanisms $ 10.9 $ 7.7 Income Taxes 41.0 44.3 Other — 0.1 Total Regulatory Liabilities 51.9 52.1 Less: Current Portion of Regulatory Liabilities 15.0 9.5 Regulatory Liabilities—noncurrent $ 36.9 $ 42.6 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, 2022 are $ 7.2 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years. Regulators have authorized recovery of these expenditures, but without a return. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material effect on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. 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 in the Consolidated Statements of Earnings on a straight-line basis over the lease term. See additional discussion in the “Leases” section of Note 4 (Debt and Financing Arrangements). Derivatives - The Company’s regulated energy subsidiaries enter into energy supply contracts to serve their electric and gas customers. 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. Fitchburg has entered into power purchase agreements for which contingencies exist (see “Fitchburg – Massachusetts RFP’s” section of Note 7 (Commitments and Contingencies). Until these contingencies are satisfied, these contracts will not qualify for derivative accounting. The Company believes that the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg. Investments in Marketable Securities - The Company maintains a trust through which it invests in a money market fund. This fund is intended to satisfy obligations under the Company’s Supplemental Executive Retirement Plan (SERP) (See additional discussion of the SERP in Note 9 Retirement Benefit Plans). At December 31, 2022 and 2021, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $ 5.8 million and $ 5.7 million, respectively, as shown in the following table. 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. December 31, Fair Value of Marketable Securities (millions) 2022 2021 Money Market Funds $ 5.8 $ 5.7 Total Marketable Securities $ 5.8 $ 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, 2022 and 2021, the fair value of the Company’s investments in these trading securities related to the DC Plan, which are recorded on the Consolidated Balance Sheets in Other Assets, were $ 0.6 million and $ 0.6 million, respectively. 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. December 31, Fair Value of Marketable Securities (millions) 2022 2021 Equity Funds $ 0.5 $ 0.2 Money Market Funds 0.1 0.4 Total Marketable Securities $ 0.6 $ 0.6 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) 2022 2021 Renewable Energy Portfolio Standards $ 7.8 $ 7.8 Exchange Gas Obligation 16.3 6.7 Power Supply Contract Divestitures — — Total Energy Supply Obligations $ 24.1 $ 14.5 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 entered into long-term renewable contracts for the purchase of clean energy and/or RECs pursuant to Massachusetts legislation, specifically, An Act Relative to Green Communities (Green Communities Act, 2008), An Act Relative to Competitively Priced Electricity in the Commonwealth (2012) and An Act to Promote Energy Diversity (Energy Diversity Act, 2016). The generating facilities associated with ten of these contracts have been constructed and are now operating. Three approved contracts are currently under development. These incl

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2022
Segment Information	Note 2: Segment Information Unitil reports two segments: utility electric operations and utility gas operations. Unitil previously reported a non-regulated segment. Unitil divested its non-regulated business in the first quarter of 2019. Since 2019 information is no longer presented, the Company has restated prior periods to remove the non-regulated segment as that segment did not have any continuing significance in the periods presented. Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capital regions of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire, Fitchburg, which operates in Massachusetts and Northern Utilities, which operates in New Hampshire and Maine. 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 Service, Unitil Resources, Unitil Realty and the holding company are included in Other. Unitil Service provides centralized management and administrative services, including information systems management and financial record keeping. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary, which currently does not have any activity. Unitil Realty owns certain real estate, principally the Company’s corporate headquarters. The earnings of the holding company are principally derived from income earned on short-term investments and real property owned for Unitil and its subsidiaries’ use. The 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, 2022, 2021 and 2020 (millions): Year Ended December 31, 2022 Electric Gas Other Total Revenues: Billed and Unbilled Revenue $ 290.2 $ 263.3 $ — $ 553.5 Rate Adjustment Mechanism Revenue 7.7 2.0 — 9.7 Total Operating Revenues 297.9 265.3 — 563.2 Interest Income 0.9 1.0 0.9 2.8 Interest Expense 9.1 16.8 2.4 28.3 Depreciation & Amortization Expense 25.4 36.3 0.9 62.6 Income Tax Expense (Benefit) 3.1 8.2 ( 0.1 ) 11.2 Segment Profit (Loss) 15.7 26.5 ( 0.8 ) 41.4 Segment Assets 580.9 988.8 20.7 1,590.4 Capital Expenditures 33.8 87.6 0.7 122.1 Year Ended December 31, 2021 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 ( 0.7 ) 11.5 Segment Profit (Loss) 14.0 23.2 ( 1.1 ) 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

Allowance for Doubtful Accounts

Allowance for Doubtful Accounts	12 Months Ended
	Dec. 31, 2022
Allowance For Doubtful Accounts [Abstract]
Allowance for Doubtful Accounts	Note 3: Allowance for Doubtful Accounts Unitil’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. In 2022, 2021 and 2020, the Company recorded provisions for the energy commodity portion of bad debts of $ 3.8 million, $ 2.4 million and $ 1.6 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, 2022 and 2021, the Company has recorded $ 5.8 million and $ 7.9 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 $ 2.5 million and $ 3.1 million of the Allowance for Doubtful Accounts at December 31, 2022 and December 31, 2021, respectively. Unbilled Revenues, net (a component of Accrued Revenue) includes $ 0.1 million and $ 0.2 million of the Allowance for Doubtful Accounts at December 31, 2022 and December 31, 2021, respectively. The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2022, 2021 and 2020 (millions): ALLOWANCE FOR DOUBTFUL ACCOUNTS Balance at Provision Recoveries Accounts Regulatory Balance at Year Ended December 31, 2022 Electric $ 2.0 $ 4.2 $ 0.3 $ 4.4 $ ( 0.5 ) $ 1.6 Gas 1.3 2.5 0.6 3.2 ( 0.2 ) 1.0 Other — — — — — — $ 3.3 $ 6.7 $ 0.9 $ 7.6 $ ( 0.7 ) $ 2.6 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 * In 2021 and 2020, the Company recorded higher than normal expected bad debt expense due to the coronavirus pandemic. The incremental bad debt expense amounts were previously deferred as regulatory assets based on certain regulatory proceedings and management’s view that such amounts were probable of recovery. Based on actual billing and collections experience, the Company has not deferred any incremental bad debt expense as a regulatory asset as of December 31, 2022.

Debt and Financing Arrangements

Debt and Financing Arrangements	12 Months Ended
	Dec. 31, 2022
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 has total funded indebtedness less than 70 % of total capitalization, and earnings available for interest equal to at least two times the interest charges for funded indebtedness. Each future senior long-term debt issuance of Unitil will rank pari passu with all other senior unsecured long-term debt issuances. The Unitil long-term debt agreement requires that if Unitil defaults on any other future long-term debt agreement(s), it would constitute a default under Unitil’s present long-term debt agreement. Furthermore, the default provisions are triggered by the defaults of certain Unitil subsidiaries or certain other actions against Unitil subsidiaries. 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, 2022, in accordance with the covenants, these subsidiary companies had a combined amount of $ 386.4 million available for the payment of dividends and Unitil Corporation had $ 184.2 million available for the payment of dividends. As of December 31, 2022, the Company’s balance in Retained Earnings was $ 132.5 million. Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2022 for the payment of dividends. Issuance of Long-Term Debt - On December 18, 2020, Unitil Realty Corp. entered into a loan agreement in the amount of $ 4.7 million at 2.64 %, with a maturity date of December 18, 2030 . Less than $ 0.1 million of costs associated with this loan have been recorded as a reduction to the proceeds. Unitil Realty Corp. used the net proceeds from this loan for general corporate purposes. On September 15, 2020, Northern Utilities issued $ 40 million of Notes due 2040 at 3.78 %. Fitchburg issued $ 27.5 million of Notes due 2040 at 3.78 %. Unitil Energy issued $ 27.5 million of Bonds due 2040 at 3.58 %. Northern Utilities, Fitchburg and Unitil Energy used the net proceeds from these offerings to repay short-term debt and for general corporate purposes. Approximately $ 0.5 million of costs associated with these issuances have been recorded as a reduction to Long-Term Debt for presentation purposes on the Consolidated Balance Sheets. Debt Repayment - The total aggregate amount of debt repayments relating to bond issues and normal scheduled long-term debt repayments amounted to $ 10.4 million, $ 25.8 million and $ 24.8 million in 2022, 2021, and 2020, respectively. The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2022 is: 2023 – $ 6.9 million; 2024 – $ 4.9 million; 2025 – $ 4.9 million; 2026 – $ 37.9 million; 2027 – $ 55.7 million and thereafter $ 388.8 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. December 31, Estimated Fair Value of Long-Term Debt (millions) 2022 2021 Estimated Fair Value of Long-Term Debt $ 455.3 $ 584.9 Details on long-term debt at December 31, 2022 and 2021 are shown below: December 31, Long-Term Debt (millions) 2022 2021 Unitil Corporation: 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 6.96 % Senior Secured Notes, Due September 1, 2028 12.0 14.0 8.00 % Senior Secured Notes, Due May 1, 2031 13.5 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: 6.79 % Senior Notes, Due October 15, 2025 2.0 6.0 3.52 % Senior Notes, Due November 1, 2027 10.0 10.0 7.37 % Senior Notes, Due January 15, 2029 8.4 9.6 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 4.2 4.5 Total Long-Term Debt 499.1 509.6 Less: Unamortized Debt Issuance Costs 3.3 3.6 Total Long-Term Debt, net of Unamortized Debt Issuance Costs 495.8 506.0 Less: Current Portion (1) 6.7 8.2 Total Long-Term Debt, Less Current Portion $ 489.1 $ 497.8 (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 calculated. Unitil’s utility subsidiaries operate a number of reconciling rate mechanisms to recover specifically identified costs on a pass-through basis. These reconciling rate mechanisms track costs and revenue on a monthly basis. In any given month, this monthly tracking and reconciling process will produce either an under-collected or an over-collected balance of costs. 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) 2022 2021 2020 Interest Expense Long-Term Debt $ 24.7 $ 26.0 $ 24.8 Short-Term Debt 3.0 0.8 1.4 Regulatory Liabilities 0.6 0.4 0.2 Subtotal Interest Expense 28.3 27.2 26.4 Interest Income Regulatory Assets ( 1.0 ) ( 0.5 ) ( 0.8 ) AFUDC (1) and Other ( 1.8 ) ( 1.1 ) ( 1.8 ) Subtotal Interest Income ( 2.8 ) ( 1.6 ) ( 2.6 ) Total Interest Expense, Net $ 25.5 $ 25.6 $ 23.8 (1) AFUDC—Allowance for Funds Used During Construction Credit Arrangements On September 29, 2022, the Company entered into a Third Amended and Restated Credit Agreement with a syndicate of lenders (collectively, the “Credit Facility”), which amended and restated in its entirety the prior credit facility. Unitil may borrow under the Credit Facility until September 29, 2027 , subject to two one-year extensions under certain circumstances. The Credit Facility terminates and all amounts outstanding thereunder are due and payable on September 29, 2027, subject to the potential extension discussed in the prior sentence. The Credit Facility has a borrowing limit of $ 200 million, which includes a $ 25 million sublimit for the issuance of standby letters of credit. Unitil may increase the borrowing limit under the Credit Facility by up to $75 million under certain circumstances. The Credit Facility generally provides Unitil with the ability to elect that borrowings under the Credit Facility bear interest under several options, including a daily fluctuating rate equal to (a) the forward-looking secured overnight financing rate (as administered by the Federal Reserve Bank of New York) term rate with a term equivalent to one month beginning on that date, plus (b) 0.1000 %, plus (c) a margin of 1.125 % to 1.375 % (based on Unitil’s credit rating). The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $ 295.9 million and $ 239.1 million for the years ended December 31, 2022 and December 31, 2021, respectively. Total gross repayments were $ 244.0 million and $ 229.7 million for the years ended December 31, 2022 and December 31, 2021, respectively. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2022 and December 31, 2021: December 31, Revolving Credit Facility (millions) 2022 2021 Limit $ 200.0 $ 120.0 Short-Term Borrowings Outstanding $ 116.0 $ 64.1 Available $ 84.0 $ 55.9 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, 2022 and December 31, 2021, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date. The Company believes it has sufficient sources of working capital to fund its operations. The weighted average interest rates on all short-term borrowings were 3.3 %, 1.2 %, and 1.7 % during 2022, 2021, and 2020, 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. Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There was $ 20.1 million and $ 8.3 million of natural gas storage inventory at December 31, 2022 and 2021, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2022, which was payable in January 2023, was $ 3.8 million and was recorded in Accounts Payable at December 31, 2022. 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. Contractual Obligations The following table lists the Company’s contractual obligations for long-term debt as of December 31, 2022. Payments Due by Period Long-Term Debt Contractual Obligations (millions) as of December 31, 2022 Total 2023 2024 2025 2026 2027 2028 & Beyond Long-Term Debt $ 499.1 $ 6.9 $ 4.9 $ 4.9 $ 37.9 $ 55.7 $ 388.8 Interest on Long-Term Debt 335.7 23.8 23.3 22.9 22.5 20.8 222.4 Total $ 834.8 $ 30.7 $ 28.2 $ 27.8 $ 60.4 $ 76.5 $ 611.2 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, 2022, 2021 and 2020 amounted to $ 1.8 million, $ 1.9 million and $ 1.8 million respectively. The balance sheet classification of the Company’s lease obligations was as follows: December 31, Lease Obligations (millions) 2022 2021 Operating Lease Obligations: Other Current Liabilities (current portion) $ 1.5 $ 1.6 Other Noncurrent Liabilities (long-term portion) 2.8 3.1 Total Operating Lease Obligations 4.3 4.7 Capital Lease Obligations: Other Current Liabilities (current portion) 0.1 0.1 Other Noncurrent Liabilities (long-term portion) 0.1 0.2 Total Capital Lease Obligations 0.2 0.3 Total Lease Obligations $ 4.5 $ 5.0 Cash paid for amounts included in the measurement of operating lease obligations for the twelve months ended December 31, 2022 and 2021 was $ 1.8 million and $ 1.9 million, respectively and was included in Cash Provided by Operating Activities on the Consolidated Statements of Cash Flows. Assets under capital leases amounted to approximately $ 0.6 million and $ 0.7 million as of December 31, 2022 and 2021, respectively, less accumulated amortization of $ 0.4 million and $ 0.3 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheets. The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2022. The payments for operating leases consist of $ 1.5 million of current operating lease obligations, which are included in Other Current Liabilities and $ 2.8 million of noncurrent operating lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2022. The payments for capital leases consist of $ 0.1 million of current Capital Lease Obligations, which are included in Other Current Liabilities, and $ 0.1 million of noncurrent Capital Lease Obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2022. Lease Payments ($000’s) Year Ending December 31, Operating Capital 2023 $ 1,676 $ 114 2024 1,354 59 2025 783 26 2026 483 6 2027 206 3 2028-2032 104 — Total Payments 4,606 208 Less: Interest 293 4 Amount of Lease Obligations Recorded on Consolidated Balance Sheets $ 4,313 $ 204 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, 2022, the weighted average remaining lease term is 3.4 years and the weighted average operating discount rate used to determine the operating lease obligations was 3.9 %. As of December 31, 2021, the weighted average remaining lease term was 3.5 years and the weighted average operating discount rate used to determine the operating lease obligations was 3.9 %. 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, 2022, there were approximately $ 1.2 million of guarantees outstanding with a duration of less than one year.

Equity

Equity	12 Months Ended
	Dec. 31, 2022
Equity [Abstract]
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 16,043,355 and 15,977,766 shares of common stock outstanding at December 31, 2022 and December 31, 2021, respectively. The Company has 25,000,000 shares of common stock authorized as of December 31, 2022 and December 31, 2021. Unitil Corporation Common Stock Offering— On August 6, 2021, the Company issued and sold 800,000 shares of its common stock at a price of $ 50.80 per share in a registered public offering (Offering). The Company’s net increase to Common Equity and Cash proceeds from the Offering was approximately $ 38.6 million. The proceeds were used to make equity capital contributions to the Company’s regulated utility subsidiaries, to repay debt and for other general corporate purposes. As part of the Offering, the Company granted the underwriters a 30 -day option to purchase additional shares. The underwriters exercised the option and purchased an additional 120,000 shares of the Company’s common stock on September 8, 2021. The Company’s net increase to Common Equity and Cash proceeds from the exercise of the option was approximately $ 5.9 million. The proceeds were used to make equity capital contributions to the Company’s regulated utility subsidiaries, to repay debt and for other general corporate purposes. Dividend Reinvestment and Stock Purchase Plan— During 2022, the Company sold 18,853 shares of its common stock, at an average price of $ 52.18 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $ 1.0 million. The DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock. During 2021 and 2020, the Company raised $ 1.0 million and $ 1.1 million, respectively, through the issuance of 22,316 and 23,658 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 2022, 2021 and 2020, the Company repurchased 9,449 , 8,012 and 13,194 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, $ 0.4 million, and $ 0.5 million in 2022, 2021 and 2020, respectively. During 2022, 2021 and 2020, 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 grant date. 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: (i) awards of restricted shares that vest based on time (Time Restricted Shares); (ii) awards of restricted shares that vest based on performance (Performance Restricted Shares), effective January 24, 2023; or (iii) awards 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 certain changes in capitalization of the Company, the Compensation Committee is authorized to make an equitable adjustment to the number and kind of shares of common stock that may be delivered under the Stock Plan and, in addition, may authorize and make an equitable adjustment to the Stock Plan’s annual individual award limit. Time Restricted Shares Outstanding awards of Time Restricted Shares fully vest over a period of four years at a rate of 25 % each year. During the vesting period, dividends on Time Restricted Shares underlying the award may be credited to a participant’s account. The Company may deduct or withhold, or require a participant to remit to the Company, an amount sufficient to satisfy any taxes required by federal, state, or local law or regulation to be withheld with respect to any taxable event arising in connection with an award. Prior to the end of the vesting period, the Time Restricted Shares are subject to forfeiture if the participant ceases to be employed by the Company other than due to the participant’s death, disability or retirement. Time Restricted Shares issued for 2020 – 2022 in conjunction with the Stock Plan are presented in the following table: Issuance Date Shares Aggregate 1/28/20 28,630 $ 1.8 7/28/20 3,000 $ 0.1 1/26/21 23,140 $ 0.9 1/25/22 36,770 $ 1.7 There were 45,473 and 37,621 non-vested Time Restricted Shares under the Stock Plan as of December 31, 2022 and 2021, respectively. The weighted average grant date fair value of these shares was $ 46.45 per share and $ 49.72 per share, respectively. The compensation expense associated with the issuance of Time Restricted Shares under the Stock Plan is being recorded over the vesting period and was $ 2.1 million, $ 1.4 million and $ 2.2 million in 2022, 2021 and 2020, respectively. At December 31, 2022, there was approximately $ 0.8 million of total unrecognized compensation cost for Time Restricted Shares under the Stock Plan which is expected to be recognized over approximately 2.5 years. There were 270 Time Restricted Shares forfeited and zero Time Restricted Shares cancelled under the Stock Plan during 2022. On January 24, 2023, there were 18,770 Time Restricted Shares issued under the Stock Plan with an aggregate market value of $ 1.0 million. Performance Restricted Shares Outstanding awards of Performance Restricted Shares vest after a performance period of three years based on the attainment of certain goals set by the Compensation Committee at the beginning of the performance period. If goals are met, awards of Performance Restricted Shares may vest fully; if goals are exceeded, awards of Performance Restricted Shares may vest fully and additional shares of common stock may be awarded; if goals are not met, a portion of the Performance Restricted Shares may vest and/or all or a portion of the Performance Restricted Shares may be forfeited. During the performance period, dividends on Performance Restricted Shares underlying the award may be credited to a participant’s account. 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 performance period, the Performance Restricted Shares are subject to forfeiture if the participant ceases to be employed by the Company other than due to the participant’s death, disability or retirement. Initial awards of Performance Restricted Shares were granted January 24, 2023. No Performance Restricted Shares were awarded in 2022, 2021 or 2020. On January 24, 2023, there were 18,770 Performance Restricted Shares issued under the Stock Plan with an aggregate market value of $ 1.0 million. 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 2022 and 2021 in conjunction with the Stock Plan are presented in the following table: Restricted Stock Units (Equity Portion) 2022 2021 Units Weighted Units Weighted Beginning Restricted Stock Units 49,182 $ 41.67 43,192 $ 41.34 Restricted Stock Units Granted 3,595 $ 46.72 4,519 $ 43.35 Dividend Equivalents Earned 1,258 $ 53.20 1,471 $ 46.34 Restricted Stock Units Settled ( 10,236 ) $ 51.28 — $ — Ending Restricted Stock Units 43,799 $ 40.17 49,182 $ 41.67 Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2022 and 2021 include $ 1.0 million and $ 1.0 million, respectively, representing the fair value of liabilities associated with the portion of fully vested RSUs that will be settled in cash. Preferred Stock There were $ 0.2 million, or 1,861 shares, of Unitil Energy’s 6.00 % Series Preferred Stock outstanding as of December 31, 2022 and December 31, 2021. There were less than $ 0.1 million of total dividends declared on Preferred Stock in each of the twelve month periods ended December 31, 2022 and December 31, 2021, respectively. Earnings Per Share The following table reconciles basic and diluted earnings per share (EPS). (Millions except shares and per share data) 2022 2021 2020 Earnings Available to Common Shareholders $ 41.4 $ 36.1 $ 32.2 Weighted Average Common Shares Outstanding—Basic (000’s) 15,991 15,373 14,951 Plus: Diluted Effect of Incremental Shares (000’s) 5 3 1 Weighted Average Common Shares Outstanding—Diluted (000’s) 15,996 15,376 14,952 Earnings per Share—Basic and Diluted $ 2.59 $ 2.35 $ 2.15 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. 2022 2021 2020 Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation 12,086 23,636 42,813

Energy Supply

Energy Supply	12 Months Ended
	Dec. 31, 2022
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 2022, 80% of Unitil’s largest New Hampshire customers, representing 24% of Unitil’s New Hampshire electric kilowatt-hour (kWh) sales, and 86% of Unitil’s largest Massachusetts customers, representing 34% of Unitil’s Massachusetts electric kWh sales, purchased their electric power supply in the competitive market. Additionally, cities and towns in Massachusetts may, with approval from the MDPU, implement municipal aggregations whereby the municipality purchases electric power on behalf of all citizens and businesses that do not opt out of the aggregation. The Towns of Lunenburg and Ashby have active municipal aggregations. Customers in Lunenburg comprise about 17% of Fitchburg’s customer base, and customers in Ashby comprise another 4%. On December 31, 2020, the city of Fitchburg filed with the MDPU for approval of its Aggregation Plan. The aggregation is expected to be implemented in March 2023. Customers located in the city of Fitchburg comprise about 69% of Fitchburg’s sales. Most residential and small commercial customers continue to purchase their electric supply through Unitil’s electric distribution utilities under regulated energy rates and tariffs. As of December 2022, 28% of Unitil’s residential customers in Massachusetts purchased their electricity from a third-party supplier, up 1% from December 2021. In New Hampshire, the percentage of residential customers purchasing electricity from a third-party supplier in 2022 was 9% which is an increase of 1% from December 2021. Municipal aggregation is now provided for in New Hampshire, but no aggregations have begun in Unitil Energy’s service area. 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 typically maintains power supply contracts with various wholesale suppliers for the provision of Basic Service electric supply. Pursuant to MDPU policy, Basic Service power supply contracts for residential and for small and medium general service customers are acquired every six months, are 12 months in duration and provide 50 percent of the supply requirements. On June 13, 2012, the MDPU approved Fitchburg’s request to discontinue the procurement process for Fitchburg’s large customers and become the load-serving entity for these customers. As such, Fitchburg procures electric power supply for large account customers directly through ISO-NE’s markets. Starting in 2021, the impending City of Fitchburg municipal aggregation limited Fitchburg’s ability to purchase Basic Service supply from wholesale suppliers for terms longer than six months for residential and small commercial customers. As a result of uncertainty around the timing of the Fitchburg aggregation launch as well as energy price volatility, Fitchburg received no supply offers in its most recent solicitation, conducted in late 2022. As such, beginning December 1, 2022, Fitchburg began procuring electric supply for residential and small commercial customers directly from the ISO New England markets. The NHPUC and MDPU regularly review alternatives to their procurement policy, and currently have open investigations in procurements processes, which may lead to future changes in this regulated power supply procurement structure. 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 2022, 73% of Unitil’s largest New Hampshire gas customers, representing 38% of Unitil’s New Hampshire gas therm sales, and 54% of Unitil’s largest Maine customers, representing 23% of Unitil’s Maine gas therm sales, purchased their gas supply from a third-party supplier. Fitchburg’s residential and C&I business customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many of Fitchburg’s large, and some of its medium, C&I customers, purchase their gas supply from third-party suppliers. Most of Fitchburg’s residential and small C&I customers continue to purchase their supplies at regulated rates from Fitchburg. As of December 2022, 70% of Unitil’s largest Massachusetts gas customers, representing 28% of Unitil’s Massachusetts gas therm sales, purchased their gas supply from third-party suppliers. 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 85,500 million British Thermal Units (MMBtu) per day of year-round and an additional 44,000 MMBtu of winter seasonal transportation capacity to its distribution facilities, and 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

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 7: Commitments and Contingencies Regulatory Matters Overview— Unitil’s distribution utilities deliver electricity and/or natural gas to customers in the Company’s service territories at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil Energy, Fitchburg, and Northern Utilities are provided the opportunity to recover the cost of providing distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets. Unitil Energy, Northern Utilities' New Hampshire division, and Fitchburg’s electric and gas divisions operate under revenue decoupling mechanisms. Most of Unitil’s customers are entitled to purchase their electric or natural gas supplies from third-party suppliers. 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. Rate Case Activity Northern Utilities - Base Rates - Maine - On March 26, 2020, the MPUC approved an increase to base revenue of $ 3.6 million, a 3.6 % increase over the Company’s test year operating revenues, effective April 1, 2020. The order approved a Return on Equity of 9.48 %, and a hypothetical capital structure of 50 % equity and 50 % debt. As part of the order and increase in base revenue, the MPUC provided for recovery of some, but not all, of the Company’s implementation costs associated with its customer information system pending the completion of an investigation, including a third-party audit. On March 9, 2021, the MPUC opened a new docket to investigate the amount of customer information system costs that will be allowed in rates. On January 27, 2022, the Company and the Maine Office of the Public Advocate filed a stipulation in this docket. The stipulation includes no finding of imprudence or asset disallowance. The terms of the stipulation provide for recovery of the revenue requirement related to the Company’s customer information system in base rates starting November 1, 2022, which coincides with the timing of the Company’s winter cost of gas rate change. On February 9, 2022, the MPUC approved the stipulation. On September 30, 2022, the Company filed revised distribution rates to recover the annual revenue requirement of $ 0.6 million for effect November 1, 2022. Northern Utilities - Targeted Infrastructure Replacement Adjustment (TIRA) - Maine - The settlement in Northern Utilities’ Maine division’s 2013 rate case authorized the Company to implement a TIRA rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects, including the Company’s Cast Iron Replacement Program (CIRP). In its Final Order issued on February 28, 2018 for Northern Utilities’ 2017 base rate case, the MPUC approved an extension of the TIRA mechanism for an additional eight-year period, which will allow for annual rate adjustments through the end of the CIRP program. The Company’s most recent request under the TIRA mechanism, to increase annual base rates by $ 1.5 million for 2021 eligible facilities, was filed with the MPUC on February 28, 2022. On April 27, 2022, the MPUC issued an order approving the filing, for rates effective May 1, 2022. Northern Utilities - Base Rates - New Hampshire - On July 20, 2022, the NHPUC issued an Order in the distribution base rate case filed with the NHPUC on August 2, 2021 by Northern Utilities. The Order approves a comprehensive Settlement Agreement between the Company, the New Hampshire Department of Energy (DOE), and the Office of the Consumer Advocate (OCA). As provided in the Settlement Agreement, in addition to authorizing an increase to permanent distribution rates of $ 6.1 million, effective August 1, 2022, the Order (1) approves a revenue decoupling mechanism and (2) allows for a step adjustment effective September 1, 2022 covering the additional revenue requirement resulting from changes in Net Plant in Service associated with non-growth investments for the period January 1, 2021, through December 31, 2021. This distribution base rate case reflects the Company’s operating costs and investments in utility plant for a test year ended December 31, 2020 as adjusted for known and measurable changes. The Order provides for a return on equity of 9.3 % and a capital structure reflecting 52 % equity and 48 % long-term debt. In light of the Step Adjustment, the Company shall not file a distribution rate case with the Commission before January 1, 2024 (the Stay-Out Period). However, during the term of the Stay-Out Period, the Company will be allowed to adjust distribution rates upward or downward resulting from a singular (not collective) exogenous event that exceeds $ 200,000 . On June 8, 2022, the Company filed for its step increase of approximately $ 1.6 million of annual revenue, for rates effective as of September 1, 2022, to recover eligible 2021 capital investments. On August 31, 2022, the NHPUC approved the Company’s filing. The increase in permanent rates was reconciled back to October 1, 2021, the effective date of temporary rates previously approved in this docket. Unitil Energy - Base Rates - On May 3, 2022, the NHPUC issued an Order in the distribution base rate case filed with the NHPUC on April 2, 2021 by Unitil Energy. The Order approves, in part, a comprehensive Settlement Agreement between the Company, the New Hampshire DOE, the OCA, the New Hampshire Department of Environmental Services, Clean Energy New Hampshire, and ChargePoint, Inc. In addition to authorizing an increase to permanent distribution rates of $ 6.3 million, effective June 1, 2022, the Order approves the following components of the Settlement Agreement: (1) a multi-year rate plan, (2) a revenue decoupling mechanism, (3) time-of-use rates, (4) resiliency programs to support the Company’s commitment to reliability, and (5) other rate design and tariff changes. On May 10, 2022, the Company filed a request for clarification with the NHPUC to clarify that the authorized revenue requirement should exclude expenses related to the Company’s proposed Arrearage Management Program (AMP), which was not approved in the Order. On May 12, 2022, the Commission issued an Order, which clarified that because the Company will not incur the expenses associated with the AMP, those costs should be removed from the revenue requirement, and that the adjusted increase of $ 5.9 million will result in reasonable rates. The increase in permanent rates was reconciled back to June 1, 2021, the effective date of temporary rates previously approved in this docket. This distribution base rate case reflects the Company’s operating costs and investments in utility plant for a test year ended December 31, 2020 as adjusted for known and measurable changes. The Order provides for a return on equity of 9.2 % and a capital structure reflecting 52 % equity and 48 % long-term debt. On July 28, 2022, the NHPUC approved, subject to reconciliation, the Company’s first step increase of approximately $ 1.3 million of annual revenue to recover eligible 2021 capital investments, effective August 1, 2022. Fitchburg - Base Rates - Electric - Fitchburg’s base rates are decoupled and subject to an annual revenue decoupling adjustment mechanism, which includes a cap on the amount that rates may be increased in any year. In addition, Fitchburg has an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions. On November 2, 2021, Fitchburg filed its cumulative revenue requirement of $ 1.6 million associated with its 2019 and 2020 capital expenditures. The MDPU allowed the associated rate increase to become effective on January 1, 2022, subject to further investigation and reconciliation. On June 24, 2022, the MDPU issued an Order approving the Company’s filing. On November 2, 2022, Fitchburg filed its cumulative revenue requirement of $ 3.1 million associated with its 2019-2021 capital expenditures. The MDPU allowed the associated rate increase to become effective on January 1, 2023, subject to further investigation and reconciliation. On April 17, 2020, the MDPU approved a settlement agreement entered into by the Company and the Massachusetts Office of the Attorney General providing for a distribution increase of $ 1.1 million, effective November 1, 2020. The Company’s subsequent Compliance Filing reflected an adjusted distribution increase of $ 0.9 million, a decrease of $ 0.2 million from the original settlement amount due to the finalization of actual rate case expenses. On May 21, 2020, the MDPU approved the Company’s Compliance Filing. The agreement provides for a Return on Equity of 9.7 % and a capital structure reflecting 52.45 % equity and 47.55 % long-term debt. Under the agreement, the Company will not increase or redesign base distribution rates to become effective prior to November 1, 2023, though the Company may seek cost recovery for certain exogenous events that meet a revenue threshold of $ 0.1 million. The agreement also provides for the implementation of a major storm reserve fund, whereby the Company may recover the costs of restoration for qualifying storm events. In addition, the agreement provides for the extension of the annual capital cost recovery mechanism, modified to allow the recovery of property tax on the cumulative net capital expenditures. On September 22, 2022, Fitchburg filed a petition with the MDPU to adjust its base distribution rates by $ 0.7 million effective January 1, 2023 to recover costs due to the exogenous event described below. The filing also includes a request to recover the exogenous costs incurred from July 2021 through December 2022 through a reconciling mechanism over a 24 month period, beginning January 1, 2023. The Massachusetts Department of Revenue has determined that the “net book value” or “NBV” of utility plant is no longer the basis of valuation for utility property. Most of the municipalities that levy property taxes on Fitchburg have adopted a hybrid valuation approach that increases property tax expense over and above what it would be if NBV was used as the basis of valuation. The change in valuation is a regulatory change that is outside the Company’s control and it uniquely affects the electric and gas industries, thus it is an exogenous event. On December 30, 2022, the MDPU approved the Company’s request to adjust its base distribution rates effective January 1, 2023 and to recover deferred costs of $ 1.1 million incurred from July 2021 through December 2022 through a reconciling mechanism over a 24 month period, also beginning January 1, 2023. Fitchburg - Base Rates - Gas - Pursuant to its revenue decoupling adjustment clause tariff, as approved in its last base rate case, the Company is allowed to modify, on a semi-annual basis, its base distribution rates to an established revenue per customer target in order to mitigate economic, weather, and energy efficiency effects to the Company’s revenues. The MDPU consistently has found the Company’s filings are in accord with its approved tariffs, applicable law and precedent, and that they result in just and reasonable rates. On February 28, 2020, the MDPU approved a settlement agreement between the Company and the Massachusetts Office of the Attorney General. The agreement provides for an annual distribution revenue increase of $ 4.6 million to be phased in over two years : (1) an increase of $ 3.7 million, which became effective on March 1, 2020; and (2) an increase of $ 0.9 million, which became effective on March 1, 2021. Under the agreement, the Company will not increase or redesign base distribution rates to become effective prior to March 1, 2023, though the Company may seek cost recovery for certain exogenous events that meet a revenue effect threshold of $ 40,000 . The agreement provides for a Return on Equity of 9.7 % and a capital structure reflecting 52.45 % equity and 47.55 % long-term debt. In its September 22, 2022 exogenous cost filing as discussed above, the Company also requested to adjust its gas base distribution rates by $ 0.7 million effective March 1, 2023 to recover these exogenous costs. The filing also includes a request to recover the exogenous costs incurred from July 2021 through February 2023 through a reconciling mechanism over a 24 month period, beginning March 1, 2023. On December 30, 2022, the MDPU approved the Company’s request to adjust its base distribution rates effective March 1, 2023 and to recover deferred costs of $ 1.2 million incurred from July 2021 through February 2023 through a reconciling mechanism over a 24 month period, also beginning March 1, 2023. 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 cumulative revenue requirement filing submitted on October 29, 2021 requested recovery of approximately $ 3.3 million, and received final approval on April 28, 2022, effective May 1, 2022. The Company’s most recent forward-looking cumulative revenue requirement filing, filed on October 31, 2022, requested recovery of approximately $ 4.5 million. 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 investment cap of approximately $ 14.6 million on the capital cost recoverable under such filings during the term of the Settlement. Under the Settlement Agreement, Granite may not file a new general rate case earlier than April 30, 2024 with rates to be effective no earlier than November 1, 2024 based on a test year ending no earlier than December 31, 2023. On August 24, 2021, the FERC accepted Granite State’s first limited Section 4 rate adjustment pursuant to the Settlement Agreement, for an annual revenue increase of $ 0.1 million, effective September 1, 2021. On August 19, 2022, the FERC accepted Granite State’s second limited Section 4 rate adjustment pursuant to the Settlement Agreement, for an annual revenue increase of $ 0.3 million, effective September 1, 2022. Other Matters Unitil Energy - Proposal to Construct Utility-Scale Solar Facility ­ - On October 31, 2022, Unitil Energy submitted a petition to the NHPUC for review of Unitil Energy’s proposal to construct, own, and operate a 4.99 MW utility-scale photovoltaic generating facility. The Company has requested a finding from the NHPUC within six months of the filing date that the project, as proposed, is in the public interest. This matter is subject to review by the NHPUC and remains pending. Fitchburg - Grid Modernization - On July 1, 2021, Fitchburg submitted its Grid Modernization Plan (GMP) to the MDPU. The GMP includes a five year strategic plan, including a plan for the full deployment of advanced metering functionality, and a four-year short-term investment plan, which focuses on foundational investments to facilitate the interconnection and integration of distributed energy resources, optimizing system performance through command and control and self-healing measures, and optimizing system demand by facilitating consumer price-responsiveness. On October 7, 2022, the MDPU issued a “Track 1” Order approving a budget cap of $ 9.3 million through 2025 for previously deployed or preauthorized grid modernization investments. On November 30, 2022, the MDPU issued its “Track 2” Order addressing new technologies and Advanced Metering Infrastructure (AMI) proposals. The MDPU preauthorizes a four-year $ 1.5 million budget for Fitchburg’s additional grid-facing investments. Any spending over the total budget cap is not eligible for targeted cost recovery through its Grid Modernization Factor (GMF), and instead, may be recovered by the Company in a base distribution rate proceeding subsequent to a prudency finding by the MDPU in a GMF filing or term review Order. The MDPU also preauthorized the Company’s AMI meter replacement investments, with a budget of $ 11.2 million through 2025. Additionally, the MDPU provided preliminary approval for the Company’s customer engagement and experience and data sharing platform investments, with a combined budget of $ 2.3 million through 2025. The Company may recover eligible costs incurred for preauthorized grid-facing investments and customer-facing investments that will be made during the 2022-2025 GMP term through the GMFs, subject to certain modifications to the Company’s GMF tariff and a final prudence review. The MDPU also directed the Company to submit a proposed AMI opt-out tariff with full support for any proposed opt-out fees as a compliance filing by April 1, 2023. On September 7, 2022, in docket DPU 15-121, the MDPU directed the electric distribution companies (EDCs) to apply a protocol for identifying and tracking incremental grid modernization O&M expense for recovery through the GMFs. Fitchburg - Grid Modernization Cost Recovery Factor - On April 15, 2022, Fitchburg filed its GMF rate adjustment and reconciliation filing pursuant to the Company’s GMF Tariff, for recovery of the costs incurred as a result of implementing the Company’s 2018-2021 GMP, previously approved by the MDPU on February 7, 2019. The proposed GMF of $ 0.4 million was approved on May 27, 2022, effective June 1, 2022, 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, engaged an independent consultant to conduct a study and prepare a report (Consultant Report), including a detailed study of each LDC, that analyzes the feasibility of all identified pathways to help the Commonwealth achieve its net-zero GHG goal. The study includes an examination of the potential pathways identified in the 2050 Decarbonization Roadmap developed by the MA Executive Office of Energy and Environmental Affairs, in consultation with the Massachusetts Department of Environmental Protection and the Massachusetts Department of Energy Resources (DOER). Following an active stakeholder process, on March 18, 2022, Consultant Reports on decarbonization pathways, regulatory designs and stakeholder engagement were submitted to the MDPU. Also on March 18, 2022, the LDCs, including Fitchburg, submitted proposals to the MDPU that include the LDCs’ recommendations and plans for helping the Commonwealth achieve its 2050 climate goals, supported by the Consultant Reports. The MDPU held a technical session on the Consultant Report on March 30, 2022 and a technical session on the LDC proposals on April 15, 2022. Discovery by the MDPU is complete, and the LDCs responded to stakeholder comments on July 29, 2022. Final comments from stakeholders replying to the LDCs’ comments and making any other final remarks for the MDPU’s consideration were filed on October 14, 2022. Fitchburg – Electric Vehicle (EV) Proceeding – On December 30, 2022, the MDPU issued an order approving Fitchburg’s five-year EV program with a $ 1.0 million budget consisting of: (1) public infrastructure offering ($ 0.5 million); (2) Electric Vehicle Supply Equipment (EVSE) incentives for residential segment ($ 0.3 million); and (3) marketing and outreach ($ 0.2 million). The Company may shift spending between program segments and between years over the five-year term of its program, subject to a 15 percent cap. Any spending above the approved EV program budget or above the 15 percent cap for each program segment is not eligible for targeted cost recovery through the GMF and, instead, may be recovered in a base distribution rate proceeding subsequent to a prudency finding by the MDPU. Further, the MDPU will convene an EV stakeholder process to finalize EV program performance metrics. Once performance metrics are finalized, the MDPU will require the electric companies to develop a joint state-wide program evaluation plan for MDPU approval and stakeholder input and will determine next steps at that time. The MDPU directs the Companies to submit annual reports that document their performance and these reports will be due on or before May 15th of each year. The first EV annual report is due May 15, 2024. The Company shall file annual rate adjustment and reconciliation filings on or before April 15, with rates effective June 1. The MDPU accepted the Company’s Demand Charge Alternative proposal and directed implementation within six months. The Demand Charge Alternative is offered for a ten-year period with tiered rates to separately-metered EV general delivery service customers. Finally, the MDPU accepted the Company’s proposed residential EV TOU rate. Northern Utilities / Granite State - Firm Capacity Contract - Northern Utilities relies on the transportation of gas supply over its affiliate Granite State pipeline to serve its customers in the Maine and New Hampshire service territories. Granite State facilitates critical upstream interconnections with interstate pipelines and third party suppliers essential to Northern Utilities’ service to its customers. 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 April 1, 2022, Northern Utilities submitted an annual informational report requesting approval on a one-year extension for the period of November 1, 2022 through October 31, 2023. The MPUC issued an Order on June 14, 2022 approving the one-year extension. Reconciliation Filings - Fitchburg, Unitil Energy and Northern Utilities each have a number of regulatory reconciling accounts that require annual or semi-annual filings with the MDPU, NHPUC and MPUC, respectively, to reconcile costs and revenues, and to seek approval of any rate changes. 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 Section 83C of “An Act to Promote Energy Diversity” (2016) (the Act), the Massachusetts EDCs, including Fitchburg, are required to jointly procure a total of 1,600 MW of offshore wind by June 30, 2027. Under Section 83D of the Act, the EDCs are required to jointly seek proposals for cost-effective clean energy (hydroelectric, solar and land-based wind) long-term contracts via one or more staggered solicitations for a total of 9,450,000 megawatt-hours (MWh) by December 31, 2022. Fitchburg’s pro rata share of these contracts is approximately 1%. The EDCs issued the RFP for Section 83D Long-Term Contracts in March 2017, and power purchase agreements (PPAs) for 9,554,940 MWh of hydroelectric generation and associated environmental attributes from Hydro-Quebec Energy Services (U.S.), Inc. were filed in July 2018 for approval by the MDPU. On June 25, 2019, the MDPU approved the PPAs, including the EDCs’ proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market costs to customers. The MDPU also approved the EDCs’ request for remuneration equal to 2.75 % of the contract payments, as well as the EDCs’ proposal to recover costs associated with the contracts. The EDCs issued an initial RFP pursuant to Section 83C in June 2017. On July 23, 2018, the EDCs, filed two long-term contracts with Vineyard Wind, each for 400 MW of offshore wind energy generation, for approval by the MDPU. On April 12, 2019, the MDPU approved the offshore wind energy generation PPAs, including the EDCs’ proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market costs to customers. The EDCs issued a second RFP pursuant to Section 83C to procure an additional 800 MW of offshore wind energy generation in May 2019. The EDCs filed for approval of two PPAs with Mayflower Wind Energy LLC, each for 400 MW of offshore wind energy generation, in February 10, 2020. On November 5, 2020, the MDPU approved the second RFP PPAs. In both cases, the MDPU approved the EDCs’ request for remuneration equal to 2.75 % of the contract payments, as well as the EDCs’ proposal to recover costs associated with the contracts. In accordance with “An Act to Advance Clean Energy” (2018) the Massachusetts Department of Energy Resources (DOER) recommended that the EDCs solicit up to 1,600 MW in additional offshore wind in 2022 and 2024. On May 7, 2021, the EDCs issued a third RFP for up to an additional 1,600 MW of off shore wind generation. On May 25, 2022, the EDCs sought approval of PPAs with Commonwealth Wind for 1,200 MW and with Mayflower Wind for 400 MW. On December 16, 2022, Commonwealth Wind filed a motion requesting that the MDPU dismiss proceedings related to the approval of its contract, arguing that, due to various economic conditions, its contracts with the EDCs would no longer facilitate the financing of offshore wind energy generation. On December 30, 2022, the MDPU denied Commonwealth’s motion and approved the PPAs. The MDPU also approved the EDCs’ request for remuneration equal to 2.25 % as reasonable and in the public interest. On January 19, 2023, Commonwealth Wind filed a Petition for Appeal with the Massachusetts Supreme Judicial Court seeking to set aside and vacate the MDPU’s Order approving the PPAs. On the same day, Mayflower Wind submitted a motion to the MDPU requesting that it extend the period for filing an appeal (which otherwise expired on January 19, 2023) by five business days from the date that the motion is approved. The appeal and the motion are pending. In 2021, the MA legislature increased the total solicitation target (including future solicitations) for offshore wind energy generation to 5,600 MW by June 30, 2027; an additional 2,400 MW of offshore wind capacity remains to be procured in the future. The next RFP for offshore wind is expected to be released in May 2023 for at least 400 MW and up to 2,400 MW of additional offshore wind capacity. Section 82 of the Acts of 2022 authorizes DOER to coordinate with other New England states to consider projects for long-term clean energy generation, transmission or capacity for the benefit of residents of the Commonwealth and the region. If DOER, in consultation with the Attorney General, determines that a project would satisfy all of the benefits listed in Section 82, the EDCs shall enter into cost-effective long-term contracts. On October 26, 2022, the Maine PUC announced its selection of a Transmission Project and a Generation Project to promote renewable energy development in northern Maine. On December 30, 2022, the DOER made a determination that the selected projects would have benefits to Massachusetts and the region. Pursuant to Section 82, Massachusetts EDCs shall enter into cost-effective long-term contracts with a maximum term of twenty years upon such a finding by the DOER. Fitchburg is in the process of evaluating potential contractual commitments under Section 82. FERC Transmission Formula Rate Proceedings - Pursuant to Section 206 of the Federal Power Act, there are several pending proceedings before the FERC concerning the justness and reasonableness of the Return on Equity (ROE) component of the ISO-New England, Inc. Participating Transmission Owners’ (PTOs) Regional Network Service and Local Network Service formula rates. In August 2013, FERC had found that the Transmission Owners existing ROE was unlawful, and set a new ROE. On April 14, 2017, the U.S. Court of Appeals for the D.C. Circuit (the Court) issued an opinion vacating and remanding FERC’s decision, finding that FERC had failed to articulate a satisfactory explanation for its orders. At this time, the ROE set in the vacated order will remain in place until further FERC action is taken. 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. The New England Transmission Owners (NETOs) thereafter filed a motion to reopen the record in their pending ROE dockets, 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. On December 13, 2022, RENEW Northeast, Inc., a non-profit entity that advocates for the business interests of renewable power generators in New England filed a complaint with FERC against ISO-NE and the PTOs requesting a determination that certain open-access transmission tariff schedules are unjust and unreasonable to the extent they permit PTOs to directly assign to interconnection customers O&M costs associated with network upgrades. Fitchburg and Unitil Energy are PTOs, although Unitil Energy does not own transmission plant. The PTOs answered the complaint on January 23, 2023. This matter remains pending. Contractual Obligations The following table lists the Company’s known specified gas and electric supply contractual obligations as of December 31, 2022. Payments Due by Period Gas and Electric Supply Contractual Obligations (millions) as of December 31, 2022 Total 2023 2024 2025 2026 2027 2028 & Beyond Gas Supply Contracts $ 514.6 $ 66.5 $ 47.4 $ 45.2 $ 44.3 $ 43.8 $ 267.4 Electric Supply Contracts 12.5 1.2 1.2 1.2 1.2 1.2 6.5 Total $ 527.1 $ 67.7 $ 48.6 $ 46.4 $ 45.5 $ 45.0 $ 273.9 The Company a

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2022
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, 2022, 2021, and 2020 are shown in the following table: (in millions) 2022 2021 2020 Current Income Tax Provision Federal $ — $ — $ 0.3 State 0.2 0.7 0.6 Total Current Income Taxes $ 0.2 $ 0.7 $ 0.9 Deferred Income Tax Provision Federal $ 6.6 $ 7.3 $ 6.5 State 4.4 3.5 2.8 Total Deferred Income Taxes 11.0 10.8 9.3 Total Income Tax Expense $ 11.2 $ 11.5 $ 10.2 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: 2022 2021 2020 Statutory Federal Income Tax Rate 21 % 21 % 21 % Income Tax Effects of: State Income Taxes, net 6 % 6 % 6 % Utility Plant Differences ( 6 )% ( 3 )% ( 4 )% Other, net — % — % 1 % Effective Income Tax Rate 21 % 24 % 24 % Temporary differences which gave rise to deferred tax assets and liabilities in 2022 and 2021 are shown in the following table: Temporary Differences (in millions) 2022 2021 Deferred Tax Assets Retirement Benefit Obligations $ 11.0 $ 34.1 Net Operating Loss Carryforwards 3.5 4.1 Tax Credit Carryforwards 1.0 0.7 Other, net 1.4 1.3 Total Deferred Tax Assets $ 16.9 $ 40.2 Deferred Tax Liabilities Utility Plant Differences 168.3 $ 157.4 Regulatory Assets & Liabilities 11.3 9.4 Other, net 0.7 1.1 Total Deferred Tax Liabilities 180.3 167.9 Net Deferred Tax Liabilities $ 163.4 $ 127.7 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, 2022 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, 2021; December 31, 2020; and December 31, 2019. Income tax filings for the year ended December 31, 2021 have been filed with the IRS, Massachusetts Department of Revenue, the Maine Revenue Service, and the New Hampshire Department of Revenue Administration. In the Company’s federal tax returns for the year ended December 31, 2021 which were filed with the IRS in October 2022, the Company utilized federal Net Operating Loss Carryforward (NOLC) assets of $ 2.4 million. As of December 31, 2022, the Company recognized the utilization of approximately $ 2.8 million of the NOLC asset to offset current taxes payable. In addition, at December 31, 2022, the Company had $ 1.0 million of cumulative state tax credit carryforwards to offset future income taxes payable. If unused, the Company’s state tax credit carryforwards will begin to expire in 2027. In March 2020, the Coronavirus Aid, Relief and Economic Security (CARES) Act was signed into law. The CARES Act included several tax changes as part of its economic package. These changes principally related to expanded Net Operating Loss carryback periods, increases to interest deductibility limitations, and accelerated Alternative Minimum Tax refunds. The Company has evaluated these items and determined that the items do not have a material effect on the Company’s financial statements as of December 31, 2021. Additionally, the CARES Act enacted the Employee Retention Credit (ERC) to incentivize companies to retain employees. The ERC is a 50 % credit on employee wages for employees that are retained and cannot perform their job duties at 100 % capacity as a result of coronavirus pandemic restrictions. In December 2020, the Consolidated Appropriations Act, 2021 (CAA) was signed into law. The CAA included additional funding through tax credits as part of its economic package for 2021. These changes include the temporary removal of deduction limitations on business meals through December 2022 and additional funding for the ERC with expanded benefits extended through June 30, 2021. The expanded ERC is a 70 % credit on employee wages for employees that are retained and cannot perform their job duties at 100 % capacity as a result of coronavirus pandemic restrictions. In March 2021, the American Rescue Plan Act of 2021 (ARPA) was signed into law. The ARPA included certain provisions that provide economic relief for the ongoing COVID-19 pandemic, such as extending the ERC through December 31, 2021, and other future governmental revenue producing provisions, such as expanding the scope for deduction limitations on executive compensation in future years. In August 2022, the Inflation Reduction Act of 2022 (IRA) was signed into law. The IRA included new taxes on corporations, including the Corporate Alternative Minimum Tax (AMT) and the Excise Tax on Repurchase of Corporate Stock. The AMT is equal to 15 % of a corporation’s adjusted financial statement income (AFSI). The AMT applies to companies that have a 3 year average AFSI of greater than $ 1 billion. The IRA also extended and modified certain renewable energy related credits. The Company has evaluated each of the CARES, CAA, ARPA and IRA provisions and determined that they do not have a material effect on the Company’s financial statements as of December 31, 2022. The Company has recorded a reduction in payroll taxes related to the ERC for $ 0.4 million in 2021 and $ 0.6 million in 2020. These credits were recorded as a reduction to payroll tax expense which is recorded in Taxes Other Than Income Taxes in the Consolidated Statements of Earnings. In December 2017, the Tax Cuts and Jobs Act (TCJA), which included a reduction of the corporate federal income tax rate to 21 % effective January 1, 2018, was signed into law. In accordance with FASB Codification Topic 740, the Company revalued its Accumulated Deferred Income Taxes (ADIT) and recorded a net Regulatory Liability in the amount of $ 48.9 million at December 31, 2017. The Company expects to flow through to customers $ 47.1 million of excess ADIT in utility base rates. Approximately $ 1.8 million of excess ADIT was created through reconciling mechanisms at December 31, 2017, which had not been previously collected from customers through utility rates. The Company reconciled these excess ADIT amounts through the specific reconciliation mechanisms in each of those individual reconciling mechanisms which were reviewed by state regulators. The benefit of protected excess ADIT amounts will be subject to flow back to customers in utility rates according to the Average Rate Assumption Method (ARAM). 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. As of December 31, 2022, the Company flowed back $ 6.4 million to customers in its Massachusetts, Maine, New Hampshire and federal jurisdictions.

Retirement Benefit Plans

Retirement Benefit Plans	12 Months Ended
	Dec. 31, 2022
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: 2022 2021 2020 Used to Determine Plan costs for years ended December 31: Discount Rate 2.85 % 2.50 % 3.25 % Rate of Compensation Increase 3.00 % 3.00 % 3.00 % Expected Long-term rate of return on plan assets 7.50 % 7.50 % 7.40 % 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 Used to Determine Benefit Obligations at December 31: Discount Rate 5.25 % 2.85 % 2.50 % Rate of Compensation Increase 3.00 % 3.00 % 3.00 % The health care cost trend rate used to determine benefit obligations at December 31, 2022 for pre-65 retirees is 8.00 %, with an ultimate rate of 4.50 % in 2030 , and for post-65 retirees, the health care cost trend rate is 6.25 %, with an ultimate rate of 4.50 % in 2030 . The health care cost trend rate used to determine benefit obligations at December 31, 2021 for both pre-65 and post-65 retirees is 6.20 %, with an ultimate rate 4.50 % in 2029 . The health care cost trend rate used to determine benefit obligations at December 31, 2020 for both pre-65 and post-65 retirees is 6.60 %, with an ultimate rate 4.50 % in 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 2022, a change in the discount rate of 0.25 % would have resulted in an increase or decrease of approximately $ 672,000 in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2022 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 2022 2021 2020 2022 2021 2020 2022 2021 2020 Service Cost $ 3,165 $ 3,472 $ 3,322 $ 2,890 $ 3,034 $ 2,698 $ 273 $ 354 $ 283 Interest Cost 5,486 5,003 5,776 3,194 2,740 3,121 472 458 549 Expected Return on Plan Assets ( 10,883 ) ( 9,693 ) ( 9,019 ) ( 3,415 ) ( 2,508 ) ( 2,063 ) — — — Prior Service Cost Amortization 356 301 320 1,092 1,208 1,210 55 56 57 Actuarial Loss Amortization 5,507 8,089 6,472 1,020 1,045 744 794 1,489 1,036 Sub-total 3,631 7,172 6,871 4,781 5,519 5,710 1,594 2,357 1,925 Amounts Capitalized or Deferred ( 1,085 ) ( 3,384 ) ( 3,083 ) ( 2,388 ) ( 3,136 ) ( 2,865 ) ( 472 ) ( 712 ) ( 579 ) NPBC Recognized $ 2,546 $ 3,788 $ 3,788 $ 2,393 $ 2,383 $ 2,845 $ 1,122 $ 1,645 $ 1,346 The Company bases the actuarial determination of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a three-year period from the year in which they occur. 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 2022, 2021 and 2020 before capitalization and deferral was $ 3.6 million, $ 7.2 million and $ 6.9 million, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2022, 2021 and 2020 would have been $ 2.4 million, $ 6.1 million and $ 6.5 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: 2022 2021 2022 2021 2022 2021 Plan Assets at Beginning of Year $ 152,006 $ 137,406 $ 42,651 $ 32,847 $ — $ — Actual Return on Plan Assets ( 19,984 ) 16,989 ( 6,810 ) 3,586 — — Employer Contributions 3,800 4,100 12,153 8,903 637 637 Participant Contributions — — 279 220 — — Benefits Paid ( 9,724 ) ( 6,489 ) ( 3,503 ) ( 2,905 ) ( 637 ) ( 637 ) Plan Assets at End of Year $ 126,098 $ 152,006 $ 44,770 $ 42,651 $ — $ — Change in PBO: PBO at Beginning of Year $ 199,418 $ 206,092 $ 112,087 $ 106,831 $ 17,714 $ 20,225 Service Cost 3,165 3,472 2,890 3,034 273 354 Interest Cost 5,486 5,003 3,194 2,740 472 458 Participant Contributions — — 279 220 — — Plan Amendments — 674 — — — — Benefits Paid ( 9,724 ) ( 6,489 ) ( 3,503 ) ( 2,905 ) ( 637 ) ( 637 ) Actuarial (Gain) or Loss ( 51,392 ) ( 9,334 ) ( 58,437 ) 2,167 ( 3,012 ) ( 2,686 ) PBO at End of Year $ 146,953 $ 199,418 $ 56,510 $ 112,087 $ 14,810 $ 17,714 Funded Status: Assets vs PBO $ ( 20,855 ) $ ( 47,412 ) $ ( 11,740 ) $ ( 69,436 ) $ ( 14,810 ) $ ( 17,714 ) The decrease in the PBO for the Pension, PBOP and SERP plans as of December 31, 2022 compared to December 31, 2021 primarily reflects an increase in the assumed discount rate as of December 31, 2022. Additionally, as of the end of 2022, the Company changed from a Medicare Supplement plan to a Medicare Advantage plan, which resulted in a significant reduction in the PBO for the PBOP plan as of December 31, 2022. The 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 $ 29.1 million and $ 86.4 million at December 31, 2022 and 2021, respectively, to account for the future collection of these plan obligations in electric and gas rates. These amounts are recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. 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 $ 138.3 million and $ 185.1 million as of December 31, 2022 and 2021, respectively. The ABO for the SERP was $ 13.9 million and $ 17.5 million as of December 31, 2022 and 2021, 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 2023 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension Plan costs. The following table represents employer contributions, participant contributions and benefit payments (000’s). Pension Plan PBOP Plan SERP 2022 2021 2020 2022 2021 2020 2022 2021 2020 Employer Contributions $ 3,800 $ 4,100 $ 4,665 $ 12,153 $ 8,903 $ 4,156 $ 637 $ 637 $ 654 Participant Contributions $ — $ — $ — $ 279 $ 220 $ 240 $ — $ — $ — Benefit Payments $ 9,724 $ 6,489 $ 6,038 $ 3,503 $ 2,905 $ 2,568 $ 637 $ 637 $ 654 The following table represents estimated future benefit payments (000’s). Estimated Future Benefit Payments Pension PBOP SERP 2023 $ 7,952 $ 2,624 $ 637 2024 8,458 2,752 636 2025 8,569 2,935 1,167 2026 9,608 3,170 1,241 2027 10,317 3,317 1,233 2028-2032 55,402 18,141 6,006 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 Actual Allocation at 2023 2022 2021 2020 Equity Funds 56 % 53 % 57 % 58 % Debt Funds 39 % 38 % 38 % 37 % Real Estate Fund 5 % 7 % 4 % 4 % Other (1) — 2 % 1 % 1 % Total 100 % 100 % 100 % (1) Represents investments being held in cash equivalents as of December 31, 2022, December 31, 2021 and December 31, 2020 pending payment of benefits. PBOP Plan Target Actual Allocation at 2023 2022 2021 2020 Equity Funds 55 % 55 % 56 % 55 % Debt Funds 45 % 45 % 44 % 45 % 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 2022. The Company evaluates the actuarial assumptions, including the expected rate of return, at least annually. The primary financial objective of the plans is to earn their expected long-term returns without assuming undue risks of funded status volatility. The 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, 2022 and 2021. 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, 2022 and 2021 are as follows (000’s): Fair Value Measurements at Reporting Date Using Description Balance as of Quoted Significant Significant 2022 Pension Plan Assets: Mutual Funds: Equity Funds $ 67,332 $ 67,332 $ — $ — Fixed Income Funds 47,646 47,646 — — Total Mutual Funds 114,978 114,978 — — Cash Equivalents 2,598 2,598 Total Assets in the Fair Value Hierarchy $ 117,576 $ 117,576 $ — $ — Real Estate Fund–Measured at Net Asset Value 8,522 Total Assets $ 126,098 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 Redemptions of the Real Estate Fund are subject to a sixty-five day notice period and the fund is valued quarterly. There are no unfunded commitments. Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2022 and 2021 are as follows (000’s): Fair Value Measurements at Reporting Date Using Description Balance as of Quoted Significant Significant 2022 PBOP Plan Assets: Mutual Funds: Fixed Income Funds $ 20,156 $ 20,156 $ — $ — Equity Funds 24,614 24,614 — — Total Assets $ 44,770 $ 44,770 $ — $ — 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 $ — $ — Employee 401(k) Tax Deferred Savings Plan— The Company sponsors the Unitil Corporation Tax Deferred Savings and Investment Plan (the 401(k) Plan) under Section 401(k) of the Internal Revenue Code and covering substantially all of the Company’s employees. Participants may elect to defer current compensation by contributing to the plan. Employees may direct, at their sole discretion, the investment of their savings plan balances (both the employer and employee portions) into a variety of investment options, including a Company common stock fund. The Company’s contributions to the 401(k) Plan were $ 3.5 million, $ 3.3 million and $ 3.0 million for the years ended December 31, 2022, 2021 and 2020, respectively.

Summary Of Significant Accoun_2

Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Nature of Operations	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 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 Resources and Unitil Realty. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary, which currently does not have any activity. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement.
Principles of Consolidation	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	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	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	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 revenue meets the definition of “revenues from contracts with customers” as defined in Accounting Standards Codification (ASC) 606. Revenue recognized in connection with rate adjustment mechanisms is consistent with the definition of alternative revenue programs in ASC 980, as the Company has the ability to adjust rates in the future as a result of past activities or completed events. 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, 2022 Electric and Gas Operating Revenues (millions): Electric Gas Total Billed and Unbilled Revenue: Residential $ 159.9 $ 98.2 $ 258.1 Commercial & Industrial 112.6 153.8 266.4 Other 17.7 11.3 29.0 Total Billed and Unbilled Revenue 290.2 263.3 553.5 Rate Adjustment Mechanism Revenue 7.7 2.0 9.7 Total Electric and Gas Operating Revenues $ 297.9 $ 265.3 $ 563.2 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 Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or gas sales. The difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recognized as an increase or a decrease in Accrued Revenue, which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases and other authorized adjustments that the Company files with the MDPU and NHPUC. Fitchburg has been subject to revenue decoupling since 2011. Unitil Energy is subject to revenue decoupling as of June 1, 2022. As a result of Unitil Energy now being subject to revenue decoupling, as of June 1, 2022, revenue decoupling now applies to substantially all of Unitil’s total annual electric sales volumes. As a result of the recently received final order in Northern Utilities’ base rate case in New Hampshire, substantially all of Northern Utilities’ gas sales volumes in New Hampshire are subject to decoupling as of August 1, 2022. As of August 1, 2022, the Company estimates that revenue decoupling applies to approximately 43 % of Unitil’s total annual gas sales volumes. The Company's electric and gas sales in New Hampshire and Massachusetts are now largely decoupled. The following table shows the estimated percentages of electric and gas sales that are subject to revenue decoupling for the periods presented. Revenue Decoupling Estimated Percentage of Decoupled Sales For Periods Presented Electric Before June 1, 2022 27 % After June 1, 2022 Substantially All Gas Before August 1, 2022 11 % After August 1, 2022 43 % The Company bills its customers for sales tax in Massachusetts and Maine. These taxes are remitted to the appropriate departments of revenue in each state and are excluded from revenues on the Company’s Consolidated Statements of Earnings.
Depreciation and Amortization	Depreciation 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: 2022 - 3.26 %, 2021 - 3.29 % and 2020 - 3.34 %.
Stock-based Employee Compensation	Stock-based Employee Compensation - Unitil accounts for stock-based employee compensation using the fair value method (See Note 5 Equity).
Income Taxes	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	Dividends - The Company’s dividend policy is reviewed periodically by the Board of Directors. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. For the year ended December 31, 2022 the Company paid quarterly dividends of $ 0.39 per share, resulting in an annualized dividend rate of $ 1.56 per common share. For the years ended December 31, 2021 and 2020, the Company paid quarterly dividends of $ 0.38 and $ 0.375 per common share, respectively, resulting in annualized dividend rates of $ 1.52 and $ 1.50 per common share, respectively. At its January 2023 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $ 0.405 per share, an increase of $ 0.015 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $ 1.62 per share from $ 1.56 per share.
Cash and Cash Equivalents	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, 2022 and 2021, the Unitil subsidiaries had deposited $ 6.0 million and $ 2.7 million, respectively, to satisfy their ISO-NE obligations.
Allowance for Doubtful Accounts	Allowance for Doubtful Accounts - The Company recognizes a provision for doubtful accounts that reflects the Company’s estimate of expected credit losses for electric and gas utility service accounts receivable. The allowance for doubtful accounts is calculated by applying a historical loss rate to customer account balances and management’s assessment of current and expected economic conditions, customer trends, or other factors. The Company also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of the energy commodity portion of bad debts through rate mechanisms. 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 $ 2.5 million and $ 3.1 million of the Allowance for Doubtful Accounts at December 31, 2022 and December 31, 2021, respectively. Unbilled Revenues, net (a component of Accrued Revenue) includes $ 0.1 million and $ 0.2 million of the Allowance for Doubtful Accounts at December 31, 2022 and December 31, 2021, respectively.
Accrued Revenue	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, 2022 and 2021. December 31, Accrued Revenue (millions) 2022 2021 Regulatory Assets—Current $ 66.5 $ 47.4 Unbilled Revenues 6.3 13.8 Total Accrued Revenue $ 72.8 $ 61.2
Exchange Gas Receivable	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, 2022 and 2021. December 31, Exchange Gas Receivable (millions) 2022 2021 Northern Utilities $ 16.3 $ 6.7 Fitchburg 1.7 0.7 Total Exchange Gas Receivable $ 18.0 $ 7.4
Gas Inventory	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, 2022 and 2021. December 31, Gas Inventory (millions) 2022 2021 Natural Gas $ 1.0 $ 0.5 Propane 0.4 0.4 Liquefied Natural Gas & Other 0.4 0.1 Total Gas Inventory $ 1.8 $ 1.0 The Company also has an inventory of Materials and Supplies in the amounts of $ 11.4 million and $ 8.6 million as of December 31, 2022 and December 31, 2021, respectively. These amounts are recorded at weighted average cost.
Utility Plant	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 2.50 %, 1.71 % and 3.12 % in 2022, 2021 and 2020, 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, 2022 and 2021, the Company has recorded cost of removal amounts of $ 116.1 million and $ 107.5 million, respectively, that have been collected in depreciation rates but have not yet been expended, and which represent regulatory liabilities. These amounts are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations.
Regulatory Accounting	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, 2022 and December 31, 2021, the Company has recorded $ 5.8 million and $ 7.9 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. December 31, Regulatory Assets consist of the following (millions) 2022 2021 Retirement Benefits $ 29.1 $ 86.4 Energy Supply & Other Rate Adjustment Mechanisms 63.0 44.1 Deferred Storm Charges 3.4 3.3 Environmental 5.9 4.6 Income Taxes 1.8 2.6 Other Deferred Charges 11.1 15.3 Total Regulatory Assets 114.3 156.3 Less: Current Portion of Regulatory Assets (1) 66.5 47.4 Regulatory Assets—noncurrent $ 47.8 $ 108.9 (1) Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets. December 31, Regulatory Liabilities consist of the following (millions) 2022 2021 Rate Adjustment Mechanisms $ 10.9 $ 7.7 Income Taxes 41.0 44.3 Other — 0.1 Total Regulatory Liabilities 51.9 52.1 Less: Current Portion of Regulatory Liabilities 15.0 9.5 Regulatory Liabilities—noncurrent $ 36.9 $ 42.6 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, 2022 are $ 7.2 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years. Regulators have authorized recovery of these expenditures, but without a return. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material effect on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.
Leases	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 in the Consolidated Statements of Earnings on a straight-line basis over the lease term. See additional discussion in the “Leases” section of Note 4 (Debt and Financing Arrangements).
Derivatives	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. 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	Investments in Marketable Securities - The Company maintains a trust through which it invests in a money market fund. This fund is intended to satisfy obligations under the Company’s Supplemental Executive Retirement Plan (SERP) (See additional discussion of the SERP in Note 9 Retirement Benefit Plans). At December 31, 2022 and 2021, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $ 5.8 million and $ 5.7 million, respectively, as shown in the following table. 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. December 31, Fair Value of Marketable Securities (millions) 2022 2021 Money Market Funds $ 5.8 $ 5.7 Total Marketable Securities $ 5.8 $ 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, 2022 and 2021, the fair value of the Company’s investments in these trading securities related to the DC Plan, which are recorded on the Consolidated Balance Sheets in Other Assets, were $ 0.6 million and $ 0.6 million, respectively. 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. December 31, Fair Value of Marketable Securities (millions) 2022 2021 Equity Funds $ 0.5 $ 0.2 Money Market Funds 0.1 0.4 Total Marketable Securities $ 0.6 $ 0.6
Energy Supply Obligations	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) 2022 2021 Renewable Energy Portfolio Standards $ 7.8 $ 7.8 Exchange Gas Obligation 16.3 6.7 Power Supply Contract Divestitures — — Total Energy Supply Obligations $ 24.1 $ 14.5 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 entered into long-term renewable contracts for the purchase of clean energy and/or RECs pursuant to Massachusetts legislation, specifically, An Act Relative to Green Communities (Green Communities Act, 2008), An Act Relative to Competitively Priced Electricity in the Commonwealth (2012) and An Act to Promote Energy Diversity (Energy Diversity Act, 2016). The generating facilities associated with 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, both of which were approved in 2019, and another for offshore wind generation filed with the MDPU during the first quarter of 2020 and approved in 2021. In compliance with An Act to Promote a Clean Energy Future (2018), in 2021 in coordination with the other electric utilities in Massachusetts, the Company issued its most recent long-term renewable solicitation seeking up to an additional 1,600 megawatts (MW) of offshore wind generation. In December 2021, a portfolio of projects comprising 1,600 MW of offshore wind capacity was selected for negotiation. Those contracts were approved by the MDPU on December 30, 2022. Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism, and has received remuneration for entering into them. Exchange Gas Obligation - Northern Utilities enters into gas exchange agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. The gas inventory related to these agreements is recorded in Exchange Gas Receivable on the Company’s Consolidated Balance Sheets while the corresponding obligations are recorded in Energy Supply Obligations. Power Supply Contract Divestitures - Unitil Energy’s and Fitchburg’s customers are entitled to purchase their electric or natural gas supplies from third-party suppliers. In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in rates all costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs. As of December 31, 2022 and December 31, 2021, Fitchburg and Unitil Energy have fully recovered their power supply-related stranded costs.
Retirement Benefit Obligations	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	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, 2022, the Company is not aware of any material commitments or contingencies other than those disclosed in Note 7 (Commitments and Contingencies).
Environmental Matters	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, 2022, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 7 (Commitments and Contingencies). Changes in future environmental compliance regulations or in future cost estimates of environmental remediation costs could have a material effect on the Company’s financial position if those amounts are not recoverable in regulatory rate mechanisms.
Subsequent Events	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.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 Electric and Gas Operating Revenues (millions): Electric Gas Total Billed and Unbilled Revenue: Residential $ 159.9 $ 98.2 $ 258.1 Commercial & Industrial 112.6 153.8 266.4 Other 17.7 11.3 29.0 Total Billed and Unbilled Revenue 290.2 263.3 553.5 Rate Adjustment Mechanism Revenue 7.7 2.0 9.7 Total Electric and Gas Operating Revenues $ 297.9 $ 265.3 $ 563.2 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
Estimated Percentage of Decoupled Sales	The following table shows the estimated percentages of electric and gas sales that are subject to revenue decoupling for the periods presented. Revenue Decoupling Estimated Percentage of Decoupled Sales For Periods Presented Electric Before June 1, 2022 27 % After June 1, 2022 Substantially All Gas Before August 1, 2022 11 % After August 1, 2022 43 %
Components of Accrued Revenue	The following table shows the components of Accrued Revenue as of December 31, 2022 and 2021. December 31, Accrued Revenue (millions) 2022 2021 Regulatory Assets—Current $ 66.5 $ 47.4 Unbilled Revenues 6.3 13.8 Total Accrued Revenue $ 72.8 $ 61.2
Components of Exchange Gas Receivable	The following table shows the components of Exchange Gas Receivable as of December 31, 2022 and 2021. December 31, Exchange Gas Receivable (millions) 2022 2021 Northern Utilities $ 16.3 $ 6.7 Fitchburg 1.7 0.7 Total Exchange Gas Receivable $ 18.0 $ 7.4
Components of Gas Inventory	The following table shows the components of Gas Inventory as of December 31, 2022 and 2021. December 31, Gas Inventory (millions) 2022 2021 Natural Gas $ 1.0 $ 0.5 Propane 0.4 0.4 Liquefied Natural Gas & Other 0.4 0.1 Total Gas Inventory $ 1.8 $ 1.0
Regulatory Assets	The Company currently receives recovery in rates or expects to receive recovery of these hardship accounts in future rate cases. December 31, Regulatory Assets consist of the following (millions) 2022 2021 Retirement Benefits $ 29.1 $ 86.4 Energy Supply & Other Rate Adjustment Mechanisms 63.0 44.1 Deferred Storm Charges 3.4 3.3 Environmental 5.9 4.6 Income Taxes 1.8 2.6 Other Deferred Charges 11.1 15.3 Total Regulatory Assets 114.3 156.3 Less: Current Portion of Regulatory Assets (1) 66.5 47.4 Regulatory Assets—noncurrent $ 47.8 $ 108.9 (1) Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets.
Regulatory Liabilities	December 31, Regulatory Liabilities consist of the following (millions) 2022 2021 Rate Adjustment Mechanisms $ 10.9 $ 7.7 Income Taxes 41.0 44.3 Other — 0.1 Total Regulatory Liabilities 51.9 52.1 Less: Current Portion of Regulatory Liabilities 15.0 9.5 Regulatory Liabilities—noncurrent $ 36.9 $ 42.6
Fair Value of Marketable Securities	Changes in the fair value of these investments are recorded in Other (Income) Expense, Net. December 31, Fair Value of Marketable Securities (millions) 2022 2021 Money Market Funds $ 5.8 $ 5.7 Total Marketable Securities $ 5.8 $ 5.7
Components of 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) 2022 2021 Renewable Energy Portfolio Standards $ 7.8 $ 7.8 Exchange Gas Obligation 16.3 6.7 Power Supply Contract Divestitures — — Total Energy Supply Obligations $ 24.1 $ 14.5
Deferred Compensation Plan [Member]
Fair Value of Marketable Securities	Changes in the fair value of these investments are recorded in Other (Income) Expense, Net. December 31, Fair Value of Marketable Securities (millions) 2022 2021 Equity Funds $ 0.5 $ 0.2 Money Market Funds 0.1 0.4 Total Marketable Securities $ 0.6 $ 0.6

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2022
Significant Segment Financial Data	The following tables provide significant segment financial data for the years ended December 31, 2022, 2021 and 2020 (millions): Year Ended December 31, 2022 Electric Gas Other Total Revenues: Billed and Unbilled Revenue $ 290.2 $ 263.3 $ — $ 553.5 Rate Adjustment Mechanism Revenue 7.7 2.0 — 9.7 Total Operating Revenues 297.9 265.3 — 563.2 Interest Income 0.9 1.0 0.9 2.8 Interest Expense 9.1 16.8 2.4 28.3 Depreciation & Amortization Expense 25.4 36.3 0.9 62.6 Income Tax Expense (Benefit) 3.1 8.2 ( 0.1 ) 11.2 Segment Profit (Loss) 15.7 26.5 ( 0.8 ) 41.4 Segment Assets 580.9 988.8 20.7 1,590.4 Capital Expenditures 33.8 87.6 0.7 122.1 Year Ended December 31, 2021 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 ( 0.7 ) 11.5 Segment Profit (Loss) 14.0 23.2 ( 1.1 ) 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

Allowance for Doubtful Accoun_2

Allowance for Doubtful Accounts (Tables)	12 Months Ended
	Dec. 31, 2022
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 2022, 2021 and 2020 (millions): ALLOWANCE FOR DOUBTFUL ACCOUNTS Balance at Provision Recoveries Accounts Regulatory Balance at Year Ended December 31, 2022 Electric $ 2.0 $ 4.2 $ 0.3 $ 4.4 $ ( 0.5 ) $ 1.6 Gas 1.3 2.5 0.6 3.2 ( 0.2 ) 1.0 Other — — — — — — $ 3.3 $ 6.7 $ 0.9 $ 7.6 $ ( 0.7 ) $ 2.6 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

Debt and Financing Arrangemen_2

Debt and Financing Arrangements (Tables)	12 Months Ended
	Dec. 31, 2022
Details on Long Term Debt	Details on long-term debt at December 31, 2022 and 2021 are shown below: December 31, Long-Term Debt (millions) 2022 2021 Unitil Corporation: 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 6.96 % Senior Secured Notes, Due September 1, 2028 12.0 14.0 8.00 % Senior Secured Notes, Due May 1, 2031 13.5 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: 6.79 % Senior Notes, Due October 15, 2025 2.0 6.0 3.52 % Senior Notes, Due November 1, 2027 10.0 10.0 7.37 % Senior Notes, Due January 15, 2029 8.4 9.6 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 4.2 4.5 Total Long-Term Debt 499.1 509.6 Less: Unamortized Debt Issuance Costs 3.3 3.6 Total Long-Term Debt, net of Unamortized Debt Issuance Costs 495.8 506.0 Less: Current Portion (1) 6.7 8.2 Total Long-Term Debt, Less Current Portion $ 489.1 $ 497.8 The Current Portion of Long-Term Debt includes sinking fund payments.
Fair Value of Long Term Debt	December 31, Estimated Fair Value of Long-Term Debt (millions) 2022 2021 Estimated Fair Value of Long-Term Debt $ 455.3 $ 584.9
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) 2022 2021 2020 Interest Expense Long-Term Debt $ 24.7 $ 26.0 $ 24.8 Short-Term Debt 3.0 0.8 1.4 Regulatory Liabilities 0.6 0.4 0.2 Subtotal Interest Expense 28.3 27.2 26.4 Interest Income Regulatory Assets ( 1.0 ) ( 0.5 ) ( 0.8 ) AFUDC (1) and Other ( 1.8 ) ( 1.1 ) ( 1.8 ) Subtotal Interest Income ( 2.8 ) ( 1.6 ) ( 2.6 ) Total Interest Expense, Net $ 25.5 $ 25.6 $ 23.8 (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, 2022 and December 31, 2021: December 31, Revolving Credit Facility (millions) 2022 2021 Limit $ 200.0 $ 120.0 Short-Term Borrowings Outstanding $ 116.0 $ 64.1 Available $ 84.0 $ 55.9
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, 2022. Payments Due by Period Long-Term Debt Contractual Obligations (millions) as of December 31, 2022 Total 2023 2024 2025 2026 2027 2028 & Beyond Long-Term Debt $ 499.1 $ 6.9 $ 4.9 $ 4.9 $ 37.9 $ 55.7 $ 388.8 Interest on Long-Term Debt 335.7 23.8 23.3 22.9 22.5 20.8 222.4 Total $ 834.8 $ 30.7 $ 28.2 $ 27.8 $ 60.4 $ 76.5 $ 611.2
Classification of the Company Lease Obligations	The balance sheet classification of the Company’s lease obligations was as follows: December 31, Lease Obligations (millions) 2022 2021 Operating Lease Obligations: Other Current Liabilities (current portion) $ 1.5 $ 1.6 Other Noncurrent Liabilities (long-term portion) 2.8 3.1 Total Operating Lease Obligations 4.3 4.7 Capital Lease Obligations: Other Current Liabilities (current portion) 0.1 0.1 Other Noncurrent Liabilities (long-term portion) 0.1 0.2 Total Capital Lease Obligations 0.2 0.3 Total Lease Obligations $ 4.5 $ 5.0
Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases	The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2022. The payments for operating leases consist of $ 1.5 million of current operating lease obligations, which are included in Other Current Liabilities and $ 2.8 million of noncurrent operating lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2022. The payments for capital leases consist of $ 0.1 million of current Capital Lease Obligations, which are included in Other Current Liabilities, and $ 0.1 million of noncurrent Capital Lease Obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2022. Lease Payments ($000’s) Year Ending December 31, Operating Capital 2023 $ 1,676 $ 114 2024 1,354 59 2025 783 26 2026 483 6 2027 206 3 2028-2032 104 — Total Payments 4,606 208 Less: Interest 293 4 Amount of Lease Obligations Recorded on Consolidated Balance Sheets $ 4,313 $ 204

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2022
Table Text Block Supplement [Abstract]
Restricted Shares Issued in Conjunction with Stock Plan	Restricted Shares issued for 2020 – 2022 in conjunction with the Stock Plan are presented in the following table: Issuance Date Shares Aggregate 1/28/20 28,630 $ 1.8 7/28/20 3,000 $ 0.1 1/26/21 23,140 $ 0.9 1/25/22 36,770 $ 1.7
Restricted Stock Units Issued	The equity portion of Restricted Stock Units activity during 2022 and 2021 in conjunction with the Stock Plan are presented in the following table: Restricted Stock Units (Equity Portion) 2022 2021 Units Weighted Units Weighted Beginning Restricted Stock Units 49,182 $ 41.67 43,192 $ 41.34 Restricted Stock Units Granted 3,595 $ 46.72 4,519 $ 43.35 Dividend Equivalents Earned 1,258 $ 53.20 1,471 $ 46.34 Restricted Stock Units Settled ( 10,236 ) $ 51.28 — $ — Ending Restricted Stock Units 43,799 $ 40.17 49,182 $ 41.67
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) 2022 2021 2020 Earnings Available to Common Shareholders $ 41.4 $ 36.1 $ 32.2 Weighted Average Common Shares Outstanding—Basic (000’s) 15,991 15,373 14,951 Plus: Diluted Effect of Incremental Shares (000’s) 5 3 1 Weighted Average Common Shares Outstanding—Diluted (000’s) 15,996 15,376 14,952 Earnings per Share—Basic and Diluted $ 2.59 $ 2.35 $ 2.15
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. 2022 2021 2020 Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation 12,086 23,636 42,813

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022. Payments Due by Period Gas and Electric Supply Contractual Obligations (millions) as of December 31, 2022 Total 2023 2024 2025 2026 2027 2028 & Beyond Gas Supply Contracts $ 514.6 $ 66.5 $ 47.4 $ 45.2 $ 44.3 $ 43.8 $ 267.4 Electric Supply Contracts 12.5 1.2 1.2 1.2 1.2 1.2 6.5 Total $ 527.1 $ 67.7 $ 48.6 $ 46.4 $ 45.5 $ 45.0 $ 273.9
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, 2022 and 2021. December 31, Environmental Obligations (millions) 2022 2021 Total Balance at Beginning of Period $ 2.7 $ 2.1 Additions 2.0 0.9 Less: Payments / Reductions 0.3 0.3 Total Balance at End of Period 4.4 2.7 Less: Current Portion 0.6 0.5 Noncurrent Balance at End of Period $ 3.8 $ 2.2

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022, 2021, and 2020 are shown in the following table: (in millions) 2022 2021 2020 Current Income Tax Provision Federal $ — $ — $ 0.3 State 0.2 0.7 0.6 Total Current Income Taxes $ 0.2 $ 0.7 $ 0.9 Deferred Income Tax Provision Federal $ 6.6 $ 7.3 $ 6.5 State 4.4 3.5 2.8 Total Deferred Income Taxes 11.0 10.8 9.3 Total Income Tax Expense $ 11.2 $ 11.5 $ 10.2
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: 2022 2021 2020 Statutory Federal Income Tax Rate 21 % 21 % 21 % Income Tax Effects of: State Income Taxes, net 6 % 6 % 6 % Utility Plant Differences ( 6 )% ( 3 )% ( 4 )% Other, net — % — % 1 % Effective Income Tax Rate 21 % 24 % 24 %
Deferred Tax Assets and Liabilities	Temporary differences which gave rise to deferred tax assets and liabilities in 2022 and 2021 are shown in the following table: Temporary Differences (in millions) 2022 2021 Deferred Tax Assets Retirement Benefit Obligations $ 11.0 $ 34.1 Net Operating Loss Carryforwards 3.5 4.1 Tax Credit Carryforwards 1.0 0.7 Other, net 1.4 1.3 Total Deferred Tax Assets $ 16.9 $ 40.2 Deferred Tax Liabilities Utility Plant Differences 168.3 $ 157.4 Regulatory Assets & Liabilities 11.3 9.4 Other, net 0.7 1.1 Total Deferred Tax Liabilities 180.3 167.9 Net Deferred Tax Liabilities $ 163.4 $ 127.7

Retirement Benefit Plans (Table

Retirement Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2022
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: 2022 2021 2020 Used to Determine Plan costs for years ended December 31: Discount Rate 2.85 % 2.50 % 3.25 % Rate of Compensation Increase 3.00 % 3.00 % 3.00 % Expected Long-term rate of return on plan assets 7.50 % 7.50 % 7.40 % 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 Used to Determine Benefit Obligations at December 31: Discount Rate 5.25 % 2.85 % 2.50 % Rate of Compensation Increase 3.00 % 3.00 % 3.00 %
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 2022 2021 2020 2022 2021 2020 2022 2021 2020 Service Cost $ 3,165 $ 3,472 $ 3,322 $ 2,890 $ 3,034 $ 2,698 $ 273 $ 354 $ 283 Interest Cost 5,486 5,003 5,776 3,194 2,740 3,121 472 458 549 Expected Return on Plan Assets ( 10,883 ) ( 9,693 ) ( 9,019 ) ( 3,415 ) ( 2,508 ) ( 2,063 ) — — — Prior Service Cost Amortization 356 301 320 1,092 1,208 1,210 55 56 57 Actuarial Loss Amortization 5,507 8,089 6,472 1,020 1,045 744 794 1,489 1,036 Sub-total 3,631 7,172 6,871 4,781 5,519 5,710 1,594 2,357 1,925 Amounts Capitalized or Deferred ( 1,085 ) ( 3,384 ) ( 3,083 ) ( 2,388 ) ( 3,136 ) ( 2,865 ) ( 472 ) ( 712 ) ( 579 ) NPBC Recognized $ 2,546 $ 3,788 $ 3,788 $ 2,393 $ 2,383 $ 2,845 $ 1,122 $ 1,645 $ 1,346
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: 2022 2021 2022 2021 2022 2021 Plan Assets at Beginning of Year $ 152,006 $ 137,406 $ 42,651 $ 32,847 $ — $ — Actual Return on Plan Assets ( 19,984 ) 16,989 ( 6,810 ) 3,586 — — Employer Contributions 3,800 4,100 12,153 8,903 637 637 Participant Contributions — — 279 220 — — Benefits Paid ( 9,724 ) ( 6,489 ) ( 3,503 ) ( 2,905 ) ( 637 ) ( 637 ) Plan Assets at End of Year $ 126,098 $ 152,006 $ 44,770 $ 42,651 $ — $ — Change in PBO: PBO at Beginning of Year $ 199,418 $ 206,092 $ 112,087 $ 106,831 $ 17,714 $ 20,225 Service Cost 3,165 3,472 2,890 3,034 273 354 Interest Cost 5,486 5,003 3,194 2,740 472 458 Participant Contributions — — 279 220 — — Plan Amendments — 674 — — — — Benefits Paid ( 9,724 ) ( 6,489 ) ( 3,503 ) ( 2,905 ) ( 637 ) ( 637 ) Actuarial (Gain) or Loss ( 51,392 ) ( 9,334 ) ( 58,437 ) 2,167 ( 3,012 ) ( 2,686 ) PBO at End of Year $ 146,953 $ 199,418 $ 56,510 $ 112,087 $ 14,810 $ 17,714 Funded Status: Assets vs PBO $ ( 20,855 ) $ ( 47,412 ) $ ( 11,740 ) $ ( 69,436 ) $ ( 14,810 ) $ ( 17,714 )
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 2022 2021 2020 2022 2021 2020 2022 2021 2020 Employer Contributions $ 3,800 $ 4,100 $ 4,665 $ 12,153 $ 8,903 $ 4,156 $ 637 $ 637 $ 654 Participant Contributions $ — $ — $ — $ 279 $ 220 $ 240 $ — $ — $ — Benefit Payments $ 9,724 $ 6,489 $ 6,038 $ 3,503 $ 2,905 $ 2,568 $ 637 $ 637 $ 654
Estimated Future Benefit Payments	The following table represents estimated future benefit payments (000’s). Estimated Future Benefit Payments Pension PBOP SERP 2023 $ 7,952 $ 2,624 $ 637 2024 8,458 2,752 636 2025 8,569 2,935 1,167 2026 9,608 3,170 1,241 2027 10,317 3,317 1,233 2028-2032 55,402 18,141 6,006
Pension Plans
Schedule of Allocation of Plan Assets	The actual investment allocations are shown in the following tables. Pension Plan Target Actual Allocation at 2023 2022 2021 2020 Equity Funds 56 % 53 % 57 % 58 % Debt Funds 39 % 38 % 38 % 37 % Real Estate Fund 5 % 7 % 4 % 4 % Other (1) — 2 % 1 % 1 % Total 100 % 100 % 100 % Represents investments being held in cash equivalents as of December 31, 2022, December 31, 2021 and December 31, 2020 pending payment of benefits. Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2022 and 2021 are as follows (000’s): Fair Value Measurements at Reporting Date Using Description Balance as of Quoted Significant Significant 2022 Pension Plan Assets: Mutual Funds: Equity Funds $ 67,332 $ 67,332 $ — $ — Fixed Income Funds 47,646 47,646 — — Total Mutual Funds 114,978 114,978 — — Cash Equivalents 2,598 2,598 Total Assets in the Fair Value Hierarchy $ 117,576 $ 117,576 $ — $ — Real Estate Fund–Measured at Net Asset Value 8,522 Total Assets $ 126,098 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
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 Actual Allocation at 2023 2022 2021 2020 Equity Funds 55 % 55 % 56 % 55 % Debt Funds 45 % 45 % 44 % 45 % Total 100 % 100 % 100 % Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2022 and 2021 are as follows (000’s): Fair Value Measurements at Reporting Date Using Description Balance as of Quoted Significant Significant 2022 PBOP Plan Assets: Mutual Funds: Fixed Income Funds $ 20,156 $ 20,156 $ — $ — Equity Funds 24,614 24,614 — — Total Assets $ 44,770 $ 44,770 $ — $ — 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 $ — $ —

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Additional Information (Detail) $ / shares in Units, $ in Millions	1 Months Ended		12 Months Ended
	Jan. 31, 2023 $ / shares	Aug. 31, 2022	Dec. 31, 2022 USD ($) Subsidiary mi $ / shares	Dec. 31, 2021 USD ($) $ / shares	Dec. 31, 2020 USD ($) $ / shares	Dec. 31, 2019 USD ($)
Significant Accounting Policies [Line Items]
Length Of Pipeline | mi			86
Cost of removal obligation			$ 116.1	$ 107.5
Regulatory assets			114.3	156.3
Investments in trading securities			$ 5.8	5.7
Percentage of total sales volumes revenue subject to RDM		43%
Number of Subsidiaries | Subsidiary			3
Allowance for doubtful accounts			$ 2.6	$ 3.3	$ 3.3	$ 1
Depreciation rate based on average depreciable property balance			3.26%	3.29%	3.34%
Dividends per Common Share | $ / shares			$ 1.56	$ 1.52	$ 1.50
Increase in dividend declared amount per share | $ / shares			$ 1.56
Weighted average cost inventory amount			$ 1.8	$ 1
Average Interest Rate On Debt			2.50%	1.71%	3.12%
Other Deferred Charges
Significant Accounting Policies [Line Items]
Regulatory assets			$ 11.1	$ 15.3
Materials And Supplies
Significant Accounting Policies [Line Items]
Weighted average cost inventory amount			11.4	8.6
Subsequent Event
Significant Accounting Policies [Line Items]
Increase in dividend declared amount per share | $ / shares	$ 1.62
Unbilled Revenues
Significant Accounting Policies [Line Items]
Allowance for doubtful accounts			0.1	0.2
Accounts Receivable
Significant Accounting Policies [Line Items]
Allowance for doubtful accounts			$ 2.5	3.1
Utilities
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Subsidiary			3
Unitil Service; Unitil Realty; and Unitil Resources
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Subsidiary			3
Fitchburg Gas and Electric Light Company | Electric and Gas Division | Other Deferred Charges
Significant Accounting Policies [Line Items]
Hardship accounts in regulatory assets			$ 5.8	$ 7.9
Quarterly Payment
Significant Accounting Policies [Line Items]
Dividends per Common Share | $ / shares			$ 0.39	$ 0.38	$ 0.375
Quarterly Payment | Subsequent Event
Significant Accounting Policies [Line Items]
Common stock dividend paid per share | $ / shares	0.405
Increase in dividend declared amount per share | $ / shares	$ 0.015
Environmental and Rate Case Costs and Other Expenditures | Recovered over the next seven years
Significant Accounting Policies [Line Items]
Regulatory assets			$ 7.2
ISO-NE Obligations
Significant Accounting Policies [Line Items]
Cash Deposits			$ 6	$ 2.7
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	$ 0.6

Components of Gas and Electric

Components of Gas and Electric Operating Revenue (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ 563.2	$ 473.3	$ 418.6
Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	553.5	466.1	411.9
Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	9.7	7.2	6.7
Gas Segment
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	265.3	224.8	191.4
Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	263.3	217.6	185.2
Gas Segment | Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	2	7.2	6.2
Electric
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	297.9	248.5	227.2
Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	290.2	248.5	226.7
Electric | Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	7.7	0	0.5
Residential | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	258.1	219	201.8
Residential | Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	98.2	83.9	73.1
Residential | Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	159.9	135.1	128.7
C&I | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	266.4	227.4	195.9
C&I | Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	153.8	124.1	104.5
C&I | Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	112.6	103.3	91.4
Other | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	29	19.7	14.2
Other | Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	11.3	9.6	7.6
Other | Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ 17.7	$ 10.1	$ 6.6

Estimated Percentage of Decoupl

Estimated Percentage of Decoupled Sales (Details)	1 Months Ended	12 Months Ended
	Aug. 31, 2022	Dec. 31, 2022
Operating Revenues [Line Items]
Percentage of total sales volumes revenue subject to RDM	43%
Electric | Before June 1, 2022
Operating Revenues [Line Items]
Percentage of total sales volumes revenue subject to RDM		27%
Gas | Before August 1, 2022
Operating Revenues [Line Items]
Percentage of total sales volumes revenue subject to RDM		11%
Gas | After August 1, 2022
Operating Revenues [Line Items]
Percentage of total sales volumes revenue subject to RDM		43%

Components of Accrued Revenue (

Components of Accrued Revenue (Detail) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Deferred Revenue Arrangement [Line Items]
Regulatory Assets – Current	[1]	$ 66.5	$ 47.4
Total Accrued Revenue		72.8	61.2
Unbilled Revenues
Deferred Revenue Arrangement [Line Items]
Regulatory Assets – Current		6.3	13.8
Regulatory Assets
Deferred Revenue Arrangement [Line Items]
Regulatory Assets – Current		$ 66.5	$ 47.4
[1] Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets.

Components of Exchange Gas Rece

Components of Exchange Gas Receivable (Detail) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Receivables [Line Items]
Total Exchange Gas Receivable	$ 18	$ 7.4
Northern Utilities Inc
Receivables [Line Items]
Total Exchange Gas Receivable	16.3	6.7
Fitchburg
Receivables [Line Items]
Total Exchange Gas Receivable	$ 1.7	$ 0.7

Components of Gas Inventory (De

Components of Gas Inventory (Detail) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 1.8	$ 1
Liquefied Natural Gas & Other
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.4	0.1
Natural Gas
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	1	0.5
Propane
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.4	$ 0.4

Regulatory Assets (Detail)

Regulatory Assets (Detail) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Regulatory Asset [Line Items]
Regulatory Assets		$ 114.3	$ 156.3
Less: Current Portion of Regulatory Assets	[1]	66.5	47.4
Regulatory Assets—noncurrent		47.8	108.9
Environmental Matters
Regulatory Asset [Line Items]
Regulatory Assets		5.9	4.6
Other Deferred Charges
Regulatory Asset [Line Items]
Regulatory Assets		11.1	15.3
Other Postretirement Benefits Plan [Member]
Regulatory Asset [Line Items]
Regulatory Assets		29.1	86.4
Deferred Storm Charges
Regulatory Asset [Line Items]
Regulatory Assets		3.4	3.3
Income Taxes
Regulatory Asset [Line Items]
Regulatory Assets		1.8	2.6
Energy Supply & Other Rate Adjustment Mechanisms
Regulatory Asset [Line Items]
Regulatory Assets		$ 63	$ 44.1
[1] Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets.

Regulatory Liabilities (Detail)

Regulatory Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2017
Regulatory Liability [Line Items]
Regulatory Liabilities	$ 51.9	$ 52.1
Less: Current Portion of Regulatory Liabilities	15	9.5
Regulatory Liabilities-noncurrent	36.9	42.6
Rate Adjustment Mechanisms
Regulatory Liability [Line Items]
Regulatory Liabilities	10.9	7.7
Income Taxes
Regulatory Liability [Line Items]
Regulatory Liabilities	41	44.3	$ 48.9
Other
Regulatory Liability [Line Items]
Regulatory Liabilities	$ 0	$ 0.1

Fair Value of Marketable Securi

Fair Value of Marketable Securities (Detail) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	$ 5.8	$ 5.7
Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	0.6	0.6
Fair Value, Inputs, Level 1
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	5.8	5.7
Fair Value, Inputs, Level 1 | Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	0.6	0.6
Fair Value, Inputs, Level 1 | Equity Funds | Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	0.5	0.2
Fair Value, Inputs, Level 1 | Money Market Funds
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	5.8	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	$ 0.1	$ 0.4

Components of Energy Supply Obl

Components of Energy Supply Obligations (Detail) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 24.1	$ 14.5
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	7.8	7.8
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	0	0
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 16.3	$ 6.7

Significant Segment Financial D

Significant Segment Financial Data (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	$ 563.2	$ 473.3	$ 418.6
Interest Income	2.8	1.6	2.6
Interest Expense	28.3	27.2	26.4
Depreciation & Amortization Expense	62.6	59.5	54.5
Income Tax Expense (Benefit)	11.2	11.5	10.2
Segment Profit (Loss)	41.4	36.1	32.2
Segment Assets	1,590.4	1,540.3	1,477.9
Capital Expenditures	122.1	115	122.6
Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	553.5	466.1	411.9
Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	9.7	7.2	6.7
Electric
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	297.9	248.5	227.2
Interest Income	0.9	0.8	1.1
Interest Expense	9.1	9	8.7
Depreciation & Amortization Expense	25.4	25.9	23.8
Income Tax Expense (Benefit)	3.1	4.5	4.7
Segment Profit (Loss)	15.7	14	12.9
Segment Assets	580.9	584	571.8
Capital Expenditures	33.8	38.1	45.5
Electric | Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	290.2	248.5	226.7
Electric | Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	7.7		0.5
Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	265.3	224.8	191.4
Interest Income	1	0.5	1.1
Interest Expense	16.8	15.3	14.2
Depreciation & Amortization Expense	36.3	32.6	29.8
Income Tax Expense (Benefit)	8.2	7.7	7.3
Segment Profit (Loss)	26.5	23.2	19.3
Segment Assets	988.8	935.9	886.3
Capital Expenditures	87.6	75.8	71.1
Gas Segment | Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	263.3	217.6	185.2
Gas Segment | Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	2	7.2	6.2
All Other Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Interest Income	0.9	0.3	0.4
Interest Expense	2.4	2.9	3.5
Depreciation & Amortization Expense	0.9	1	0.9
Income Tax Expense (Benefit)	(0.1)	(0.7)	(1.8)
Segment Profit (Loss)	(0.8)	(1.1)
Segment Assets	20.7	20.4	19.8
Capital Expenditures	$ 0.7	$ 1.1	$ 6

Allowance for Doubtful Accoun_3

Allowance for Doubtful Accounts - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Financing Receivable, Impaired [Line Items]
Recoveries	$ 0.9	$ 0.8	$ 0.6
Provision for Bad Debt	6.7	5.6	5.5
Allowance for doubtful accounts	2.6	3.3	3.3	$ 1
Unbilled Revenues
Financing Receivable, Impaired [Line Items]
Allowance for doubtful accounts	0.1	0.2
Accounts Receivable
Financing Receivable, Impaired [Line Items]
Allowance for doubtful accounts	2.5	3.1
Regulatory Assets Harship Accounts
Financing Receivable, Impaired [Line Items]
Recoveries	5.8	7.9
Energy Commodity
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 3.8	$ 2.4	$ 1.6

Activity in Company's Allowance

Activity in Company's Allowance for Doubtful Accounts (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period		$ 3.3	$ 3.3	$ 1
Provision		6.7	5.6	5.5
Recoveries		0.9	0.8	0.6
Accounts Written Off		7.6	6.5	4.4
Regulatory Defferals	[1]	(0.7)	0.1	0.6
Balance at End of Period		2.6	3.3	3.3
Electric
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period		2	1.6	0.6
Provision		4.2	3.3	2.9
Recoveries		0.3	0.4	0.3
Accounts Written Off		4.4	3.4	2.6
Regulatory Defferals	[1]	(0.5)	0.1	0.4
Balance at End of Period		1.6	2	1.6
Gas
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period		1.3	1.7	0.4
Provision		2.5	2.3	2.6
Recoveries		0.6	0.4	0.3
Accounts Written Off		3.2	3.1	1.8
Regulatory Defferals	[1]	(0.2)		0.2
Balance at End of Period		$ 1	$ 1.3	$ 1.7
[1] In 2021 and 2020, the Company recorded higher than normal expected bad debt expense due to the coronavirus pandemic. The incremental bad debt expense amounts were previously deferred as regulatory assets based on certain regulatory proceedings and management’s view that such amounts were probable of recovery. Based on actual billing and collections experience, the Company has not deferred any incremental bad debt expense as a regulatory asset as of December 31, 2022.

Debt and Financing Arrangemen_3

Debt and Financing Arrangements - Additional Information (Detail) - USD ($) $ in Millions				12 Months Ended
	Sep. 29, 2022	Sep. 22, 2022	Dec. 18, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Sep. 15, 2020
Line of Credit Facility [Line Items]
Issuance of long-term debt			$ 0.1				$ 0.5
Weighted average interest rate on short term borrowings				3.30%	1.20%	1.70%
Guarantee outstanding				$ 1.2
Total rental expense under operating leases				1.8	$ 1.9	$ 1.8
Accounts Payable				68.6	52.4
Operating lease obligations				1.8	1.9
Net Utility Plant				1,331.7	1,257.2
Other current operating lease obligation				1.5	1.6
Other noncurrent operating lease obligation				$ 2.8	$ 3.1
Operating lease, weighted average remaining lease term				3 years 4 months 24 days	3 years 6 months
Operating lease, weighted average discount rate percentage				3.90%	3.90%
Restriction on retained earnings for dividend payments				Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2022 for the payment of dividends.
Amount available for the payment of dividends				$ 184.2
Retained Earnings				132.5	$ 116.2
Long term debt repayments				10.4	25.8	24.8
Finance Lease, Liability, Current				0.1	0.1
Finance Lease Liability Noncurrent				0.1	0.2
Subsidiaries [Member]
Line of Credit Facility [Line Items]
Amount available for the payment of dividends				$ 386.4
Credit Facility [Member] | Third Amendment Credit Facility Member [Member]
Line of Credit Facility [Line Items]
Revolving credit facility	$ 200
Sublimit for the issuance of standby letters of credit	$ 25
3.43% Senior Notes, Due December 18, 2029
Line of Credit Facility [Line Items]
Long-term debt, stated interest rate				3.43%
Long-term debt, maturity date				Dec. 18, 2029
Bonds [Member]
Line of Credit Facility [Line Items]
Long term debt repayments				$ 10.4	25.8	$ 24.8
Debt repayment, 2023				6.9
Debt repayment, 2024				4.9
Debt repayment, 2025				4.9
Debt repayment, 2026				37.9
Debt repayment, 2027				55.7
Debt repayment, Thereafter				388.8
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility				200	120
Proceeds from lines of credit				295.9	239.1
Repayments of lines of credit				$ 244	229.7
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					1.6
Natural gas storage inventory				$ 20.1	8.3
Revolving Credit Facility [Member] | Credit Facility [Member] | Third Amendment Credit Facility Member [Member]
Line of Credit Facility [Line Items]
Revolving credit facility termination date	Sep. 29, 2027
Northern Utilities Inc
Line of Credit Facility [Line Items]
Accounts Payable				$ 3.8
Long-term debt, aggregate principal amount							40
Total funded indebtedness as percentage of capitalization				65%
Northern Utilities Inc | 4.04% Senior Notes, Due September 12, 2049
Line of Credit Facility [Line Items]
Long-term debt, stated interest rate				4.04%
Long-term debt, maturity date				Sep. 12, 2049
Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization				65%
Fitchburg Gas and Electric Light Company | 3.78% Senior Notes, Due September 15, 2040
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount							$ 27.5
Long-term debt, stated interest rate							3.78%
Unitil Corporation | Maximum [Member]
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization				70%
Northern Utilities And Fitchburg | 3.78% Senior Notes, Due September 15, 2040
Line of Credit Facility [Line Items]
Long-term debt, stated interest rate							3.78%
Unitil Energy Systems Inc | 3.58% Mortgage Bonds, Due September 12, 2040
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount							$ 27.5
Long-term debt, stated interest rate							3.58%
Unitil Reality Corp | 2.64% Senior Secured Notes, Due December 18, 2030
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount			$ 4.7
Long-term debt, stated interest rate			2.64%
Long-term debt, maturity date			Dec. 18, 2030
Secured Overnight Financing Rate [Member] | Revolving Credit Facility [Member] | Credit Facility [Member] | Third Amendment Credit Facility Member [Member]
Line of Credit Facility [Line Items]
Credit facility, daily fluctuating rate of interest	0.10%
Secured Overnight Financing Rate [Member] | Revolving Credit Facility [Member] | Credit Facility [Member] | Third Amendment Credit Facility Member [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt instrument variable interest rate additional spread		1.375%
Secured Overnight Financing Rate [Member] | Revolving Credit Facility [Member] | Credit Facility [Member] | Third Amendment Credit Facility Member [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt instrument variable interest rate additional spread		1.125%
Assets under Capital Leases [Member]
Line of Credit Facility [Line Items]
Net Utility Plant				$ 0.6	0.7
Net Utility Plant, accumulated amortization				$ 0.4	$ 0.3

Debt and Financing Arrangemen_4

Debt and Financing Arrangements - Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Debt Disclosure [Abstract]
Long-Term Debt, Fair Value	$ 455.3	$ 584.9

Debt and Financing Arrangemen_5

Debt and Financing Arrangements - Details on Long Term Debt (Detail) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Total Long-Term Debt		$ 499.1	$ 509.6
Less: Unamortized Debt Issuance Costs		3.3	3.6
Long-Term Debt		495.8	506
Less: Current Portion	[1]	6.7	8.2
Total Long-Term Debt, Less Current Portion		489.1	497.8
3.70% Senior Notes, Due August 1, 2026
Debt Instrument [Line Items]
Total Long-Term Debt		30	30
3.43% Senior Notes, Due December 18, 2029
Debt Instrument [Line Items]
Total Long-Term Debt		30	30
Unitil Energy Systems Inc | First Mortgage Bonds 8.49% Senior Secured Notes, Due October 14, 2024
Debt Instrument [Line Items]
Total Long-Term Debt			1.5
Unitil Energy Systems Inc | First Mortgage Bonds 6.96% Senior Secured Notes, Due September 1, 2028
Debt Instrument [Line Items]
Total Long-Term Debt		12	14
Unitil Energy Systems Inc | First Mortgage Bonds 8.00% Senior Secured Notes, Due May 1, 2031
Debt Instrument [Line Items]
Total Long-Term Debt		13.5	15
Unitil Energy Systems Inc | First Mortgage Bonds 6.32% Senior Secured Notes, Due September 15, 2036
Debt Instrument [Line Items]
Total Long-Term Debt		15	15
Unitil Energy Systems Inc | First Mortgage Bonds 3.58% Senior Secured Notes Due September 15, 2040
Debt Instrument [Line Items]
Total Long-Term Debt		27.5	27.5
Unitil Energy Systems Inc | First Mortgage Bonds 4.18% Senior Secured Notes Due November 30, 2048
Debt Instrument [Line Items]
Total Long-Term Debt		30	30
Fitchburg Gas and Electric Light Company | 6.79% Senior Notes, Due October 15, 2025
Debt Instrument [Line Items]
Total Long-Term Debt		2	6
Fitchburg Gas and Electric Light Company | 3.52% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt		10	10
Fitchburg Gas and Electric Light Company | 7.37% Senior Notes, Due January 15, 2029
Debt Instrument [Line Items]
Total Long-Term Debt		8.4	9.6
Fitchburg Gas and Electric Light Company | 5.90% Notes, Due December 15, 2030
Debt Instrument [Line Items]
Total Long-Term Debt		15	15
Fitchburg Gas and Electric Light Company | 7.98% Notes, Due June 1, 2031
Debt Instrument [Line Items]
Total Long-Term Debt		14	14
Fitchburg Gas and Electric Light Company | 3.78% Senior Notes, Due September 15, 2040
Debt Instrument [Line Items]
Total Long-Term Debt		27.5	27.5
Fitchburg Gas and Electric Light Company | 4.32% Senior Notes, Due November 1, 2047
Debt Instrument [Line Items]
Total Long-Term Debt		15	15
Northern Utilities Inc | 3.52% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt		20	20
Northern Utilities Inc | 3.78% Senior Notes, Due September 15, 2040
Debt Instrument [Line Items]
Total Long-Term Debt		40	40
Northern Utilities Inc | 4.32% Senior Notes, Due November 1, 2047
Debt Instrument [Line Items]
Total Long-Term Debt		30	30
Northern Utilities Inc | 7.72% Senior Notes, Due December 3, 2038
Debt Instrument [Line Items]
Total Long-Term Debt		50	50
Northern Utilities Inc | 4.42% Senior Notes, Due October 15, 2044
Debt Instrument [Line Items]
Total Long-Term Debt		50	50
Northern Utilities Inc | 4.04% Senior Notes, Due September 12, 2049
Debt Instrument [Line Items]
Total Long-Term Debt		40	40
Granite State Gas Transmission Inc | 3.72% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt		15	15
Unitil Realty Corp Member | 2.64% Senior Notes, Due December 18, 2030
Debt Instrument [Line Items]
Total Long-Term Debt		$ 4.2	$ 4.5
[1] The Current Portion of Long-Term Debt includes sinking fund payments.

Details on Long Term Debt (Pare

Details on Long Term Debt (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2022
3.70% Senior Notes, Due August 1, 2026
Debt Instrument [Line Items]
Stated interest rate	3.70%
Debt instrument due date	Aug. 01, 2026
3.43% Senior Notes, Due December 18, 2029
Debt Instrument [Line Items]
Stated interest rate	3.43%
Debt instrument due date	Dec. 18, 2029
First Mortgage Bonds 8.49% Senior Secured Notes, Due October 14, 2024 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	8.49%
Debt instrument due date	Oct. 14, 2024
First Mortgage Bonds 6.96% Senior Secured Notes, Due September 1, 2028 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	6.96%
Debt instrument due date	Sep. 01, 2028
First Mortgage Bonds 8.00% Senior Secured Notes, Due May 1, 2031 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	8%
Debt instrument due date	May 01, 2031
First Mortgage Bonds 6.32% Senior Secured Notes, Due September 15, 2036 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	6.32%
Debt instrument due date	Sep. 15, 2036
First Mortgage Bonds 3.58% Senior Secured Notes Due September 15, 2040 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	3.58%
Debt instrument due date	Sep. 15, 2040
First Mortgage Bonds 4.18% Senior Secured Notes Due November 30, 2048 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	4.18%
Debt instrument due date	Nov. 30, 2048
6.79% Senior Notes, Due October 15, 2025 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	6.79%
Debt instrument due date	Oct. 15, 2025
3.52% Senior Notes, Due November 1, 2027 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	3.52%
Debt instrument due date	Nov. 01, 2027
3.52% Senior Notes, Due November 1, 2027 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	3.52%
Debt instrument due date	Nov. 01, 2027
7.37% Senior Notes, Due January 15, 2029 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	7.37%
Debt instrument due date	Jan. 15, 2029
5.90% Notes, Due December 15, 2030 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	5.90%
Debt instrument due date	Dec. 15, 2030
7.98% Notes, Due June 1, 2031 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	7.98%
Debt instrument due date	Jun. 01, 2031
3.78% Senior Notes, Due September 15, 2040 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	3.78%
Debt instrument due date	Sep. 15, 2040
3.78% Senior Notes, Due September 15, 2040 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	3.78%
Debt instrument due date	Sep. 15, 2040
4.32% Senior Notes, Due November 1, 2047 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	4.32%
Debt instrument due date	Nov. 01, 2047
4.32% Senior Notes, Due November 1, 2047 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	4.32%
Debt instrument due date	Nov. 01, 2047
7.72% Senior Notes, Due December 3, 2038 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	7.72%
Debt instrument due date	Dec. 03, 2038
4.42% Senior Notes, Due October 15, 2044 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	4.42%
Debt instrument due date	Oct. 15, 2044
4.04% Senior Notes, Due September 12, 2049 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	4.04%
Debt instrument due date	Sep. 12, 2049
3.72% Senior Notes, Due November 1, 2027 | Granite State Gas Transmission Inc
Debt Instrument [Line Items]
Stated interest rate	3.72%
Debt instrument due date	Nov. 01, 2027
2.64% Senior Notes, Due December 18, 2030 | Unitil Realty Corp Member
Debt Instrument [Line Items]
Stated interest rate	2.64%
Debt instrument due date	Dec. 18, 2030

Summary of Interest Expense and

Summary of Interest Expense and Interest Income (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Interest Expense
Long-Term Debt	$ 24.7	$ 26	$ 24.8
Short-Term Debt	3	0.8	1.4
Regulatory Liabilities	0.6	0.4	0.2
Subtotal Interest Expense	28.3	27.2	26.4
Interest Income
Interest and Other Income	(2.8)	(1.6)	(2.6)
Interest Expense, Net	25.5	25.6	23.8
Regulatory Assets
Interest Income
Interest and Other Income	(1)	(0.5)	(0.8)
AFUDC and Other
Interest Income
Interest and Other Income	$ (1.8)	$ (1.1)	$ (1.8)

Borrowing Limits Amounts Outsta

Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility (Detail) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Short-Term Borrowings Outstanding	$ 116	$ 64.1
Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility, limit	200	120
Short-Term Borrowings Outstanding	116	64.1
Available revolving credit facility	$ 84	$ 55.9

Summary of Contractual Obligati

Summary of Contractual Obligations for Long-term Debt (Detail) $ in Millions	Dec. 31, 2022 USD ($)
Contractual Obligation Fiscal Year Maturity Schedule [Line Items]
Total	$ 527.1
2023	67.7
2024	48.6
2025	46.4
2026	45.5
2027	45
2028 & Beyond	273.9
Long Term Debt Comprising Principal And Interest [Member]
Contractual Obligation Fiscal Year Maturity Schedule [Line Items]
Total	834.8
2023	30.7
2024	28.2
2025	27.8
2026	60.4
2027	76.5
2028 & Beyond	611.2
Long-Term Debt [Member] | Long Term Debt Comprising Principal And Interest [Member]
Contractual Obligation Fiscal Year Maturity Schedule [Line Items]
Total	499.1
2023	6.9
2024	4.9
2025	4.9
2026	37.9
2027	55.7
2028 & Beyond	388.8
Interest on Long-Term Debt [Member] | Long Term Debt Comprising Principal And Interest [Member]
Contractual Obligation Fiscal Year Maturity Schedule [Line Items]
Total	335.7
2023	23.8
2024	23.3
2025	22.9
2026	22.5
2027	20.8
2028 & Beyond	$ 222.4

Debt and Financing Arrangemen_6

Debt and Financing Arrangements - Classification of the Company Lease Obligations (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Operating Lease Obligations:
Other Current Liabilities (current portion)	$ 1,500	$ 1,600
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Liabilities, Current	Liabilities, Current
Other Noncurrent Liabilities (long-term portion)	$ 2,800	$ 3,100
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Liabilities, Noncurrent	Liabilities, Noncurrent
Total Operating Lease Obligations	$ 4,300	$ 4,700
Capital Lease Obligations:
Other Current Liabilities (current portion)	$ 100	$ 100
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Current	Other Liabilities, Current
Other Noncurrent Liabilities (long-term portion)	$ 100	$ 200
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Noncurrent	Other Liabilities, Noncurrent
Total Capital Lease Obligations	$ 200	$ 300
Total Lease Obligations	4,500	$ 5,000
Lease Obligations [Member]
Operating Lease Obligations:
Total Operating Lease Obligations	$ 4,313

Future Operating Lease Payment

Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Operating leases
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$ 4,300	$ 4,700
Lease Obligations [Member]
Operating leases
2023	1,676
2024	1,354
2025	783
2026	483
2027	206
2028-2032	104
Total Payments	4,606
Less: Interest	293
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	4,313
Capital lease
2023	114
2024	59
2025	26
2026	6
2027	3
2028-2032	0
Total Payments	208
Less: Interest	4
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$ 204

Equity - Additional Information

Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions			12 Months Ended
	Jan. 24, 2023	Aug. 06, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Class of Stock [Line Items]
Common Stock, Shares, Outstanding			16,043,355	15,977,766
Common stock, shares issued			18,853	942,316	23,658
Common stock, shares authorized			25,000,000	25,000,000
Proceeds from Issuance of Common Stock			$ 1	$ 45.5	$ 1.1
Restricted stock weighted average grant date fair value			$ 46.45	$ 49.72
Percentage of fully-vested restricted stock units that directors will receive in common shares when settled			70%
Common stock shares repurchase			9,449	8,012	13,194
Share based compensation expense			$ 2.1	$ 1.4	$ 2.2
Percentage of fully-vested restricted stock units that directors will receive in cash when settled			30%
Preferred Stock			$ 0.2	$ 0.2
Restricted Stock
Class of Stock [Line Items]
Restricted stock vesting period			4 years
Restricted stock non-vested			45,473	37,621
Fair value of liabilities associated with fully vested RSUs that will be settled in cash			$ 1	$ 1
Unrecognized share based compensation			$ 0.8
Share compensation recognition period			2 years 6 months
Cancellations under the stock plan			0
Restricted forfeited shares			270
Restricted Stock | Subsequent Event
Class of Stock [Line Items]
Restricted Stock Units Granted	18,770
Aggregate Market Value	$ 1
Restricted Stock | Vesting Annually
Class of Stock [Line Items]
Restricted stock vesting percentage annually			25%
Performance Restricted Shares | Subsequent Event
Class of Stock [Line Items]
Restricted Stock Units Granted	18,770
Aggregate Market Value	$ 1
Unitil Energy Systems Inc | Series 6
Class of Stock [Line Items]
Preferred stock, outstanding			1,861	1,861
Preferred Stock			$ 0.2	$ 0.2
Dividend rate			6%	6%
Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Proceeds from Issuance of Common Stock			$ 1	$ 1	$ 1.1
Dividend and Distribution Reinvestment and Share Purchase Plan | Common Stock
Class of Stock [Line Items]
Common stock, shares issued			18,853	22,316	23,658
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		$ 5.9
Public Offering [Member] | Common Stock
Class of Stock [Line Items]
Common stock, shares issued		800,000
Common stock price per share		$ 50.80
Proceeds from Issuance Initial Public Offering		$ 38.6
Maximum
Class of Stock [Line Items]
Dividend declared			$ 0.1
Repurchase expense			$ 0.4	$ 0.4	$ 0.5
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			$ 52.18

Restricted Shares Issued in Con

Restricted Shares Issued in Conjunction with Stock Plan (Detail) - Restricted Stock $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) shares
Period 1
Class of Stock [Line Items]
Issuance Date	Jan. 28, 2020
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period | shares	28,630
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Grants In Period Aggregate Intrinsic Value | $	$ 1.8
Period 2
Class of Stock [Line Items]
Issuance Date	Jul. 28, 2020
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period | shares	3,000
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Grants In Period Aggregate Intrinsic Value | $	$ 0.1
Period 3
Class of Stock [Line Items]
Issuance Date	Jan. 26, 2021
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period | shares	23,140
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Grants In Period Aggregate Intrinsic Value | $	$ 0.9
Period 4
Class of Stock [Line Items]
Issuance Date	Jan. 25, 2022
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period | shares	36,770
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Grants In Period Aggregate Intrinsic Value | $	$ 1.7

Restricted Stock Units Issued (

Restricted Stock Units Issued (Detail) - Restricted Stock Units (RSUs) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Restricted Stock Units
Beginning Restricted Stock Units	49,182	43,192
Restricted Stock Units Granted	3,595	4,519
Dividend Equivalents Earned	1,258	1,471
Restricted Stock Units Settled	10,236
Ending Restricted Stock Units	43,799	49,182
Weighted-Average Stock Price
Beginning Restricted Stock Units	$ 41.67	$ 41.34
Restricted Stock Units Granted	46.72	43.35
Dividend Equivalents Earned	53.20	46.34
Restricted Stock Units Settled	51.28
Ending Restricted Stock Units	$ 40.17	$ 41.67

Reconciliation of Basic and Dil

Reconciliation of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Schedule Of Computation Of Basic And Diluted Earnings Per Common Share [Line Items]
Earnings Available to Common Shareholders	$ 41.4	$ 36.1	$ 32.2
Weighted Average Common Shares Outstanding - Basic	15,991	15,373	14,951
Plus: Diluted Effect of Incremental Shares	5	3	1
Weighted Average Common Shares Outstanding - Diluted	15,996	15,376	14,952
Earnings per Common Share - Basic	$ 2.59	$ 2.35	$ 2.15
Earnings per Common Share - Diluted	$ 2.59	$ 2.35	$ 2.15

Weighted Average Non Vested Res

Weighted Average Non Vested Restricted Shares Excluded from Computation of Earnings Per Share (Detail) - shares	12 Months Ended
	Dec. 31, 2022	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	12,086	23,636	42,813

Energy Supply - Additional Info

Energy Supply - Additional Information (Detail) - 12 months ended Dec. 31, 2022 Bcf in Billions	Total	Total	BTU	Bcf
Northern Utilities Inc
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			85,500,000,000
Natural gas, underground storage			44,000	4.3
Northern Utilities Inc | Maximum
Gas and Oil Acreage [Line Items]
Purchases of natural gas, contract duration	1 year
Fitchburg Gas and Electric Light Company
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			14,439
Natural gas, underground storage | Bcf				0.4
Percentage of power supply requirement		50%
Power supply contract duration	12 months
Unitil Energy Systems Inc
Gas and Oil Acreage [Line Items]
Percentage of power supply requirement		100%
Power supply contract duration	6 months

Gas And Electric Supply Contrac

Gas And Electric Supply Contractual Obligations (Detail) $ in Millions	Dec. 31, 2022 USD ($)
Total	$ 527.1
2023	67.7
2024	48.6
2025	46.4
2026	45.5
2027	45
2028 & Beyond	273.9
Gas Segment [Member]
Total	514.6
2023	66.5
2024	47.4
2025	45.2
2026	44.3
2027	43.8
2028 & Beyond	267.4
Electric [Member]
Total	12.5
2023	1.2
2024	1.2
2025	1.2
2026	1.2
2027	1.2
2028 & Beyond	$ 6.5

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail)

12 Months Ended

Dec. 30, 2022 USD ($)

Nov. 02, 2022 USD ($)

Sep. 30, 2022 USD ($)

Sep. 22, 2022 USD ($)

Aug. 19, 2022 USD ($)

Jul. 28, 2022 USD ($)

Jul. 20, 2022 USD ($)

Jun. 08, 2022 USD ($)

May 12, 2022 USD ($)

May 03, 2022 USD ($)

Feb. 28, 2022 USD ($)

Nov. 02, 2021 USD ($)

Aug. 24, 2021 USD ($)

Mar. 01, 2021 USD ($)

Dec. 30, 2020 USD ($)

Nov. 30, 2020 USD ($)

Nov. 05, 2020

May 21, 2020 USD ($)

Apr. 17, 2020 USD ($)

Mar. 26, 2020 USD ($)

Mar. 01, 2020 USD ($)

Feb. 28, 2020 USD ($)

Jun. 25, 2019

Dec. 31, 2022 USD ($)

Dec. 31, 2021

Dec. 31, 2020

Dec. 31, 2017

Jul. 01, 2027 MW

Jun. 30, 2027 MW

May 31, 2023 MW

Oct. 31, 2022 USD ($)

Oct. 07, 2022 USD ($)

May 27, 2022 USD ($)

May 25, 2022 MW

Oct. 29, 2021 USD ($)

May 07, 2021 MW

Feb. 10, 2020 MW

May 23, 2019 MW

Jul. 31, 2018 MWh

Jul. 23, 2018 MW

Jun. 30, 2017 MW

Commitments And Contingencies [Line Items]

Cost recovery period, years

2 years

Statutory Federal Income Tax Rate

21%

21%

21%

Spending cap

$ 527,100,000

Revenue Impact Threshold

$ 40,000

Approved annual increase in rates

$ 900,000

$ 3,600,000

$ 4,600,000

Increase in annual base rate

3.60%

Requested annual increase in rates

$ 1,500,000

Approved annual increase in rates

$ 3,700,000

Deferred cost related to exogenous event

$ 1,100,000

Approved commitments for purchasing assets

$ 1,000,000

Environmental Remediation Expense, Statement of Income or Comprehensive Income [Extensible Enumeration]

Costs and Expenses

Remediation costs

$ 5,600,000

Environmental Restoration Costs [Member]

Commitments And Contingencies [Line Items]

Estimated Costs Accrued For Remediation

$ 2,500,000

Public Infrastructure Offering [Member]

Commitments And Contingencies [Line Items]

Approved commitments for purchasing assets

500,000

Electric Vehicle Supply Equipment [Member]

Commitments And Contingencies [Line Items]

Approved commitments for purchasing assets

300,000

Marketing And Outreach [Member]

Commitments And Contingencies [Line Items]

Approved commitments for purchasing assets

200,000

Tax Year 2018

Commitments And Contingencies [Line Items]

Statutory Federal Income Tax Rate

21%

Northern Utilities Inc

Commitments And Contingencies [Line Items]

Percentage of approved return on equity, reflecting on equity

52%

Percentage of approved return on equity, reflecting on debt

48%

Percentage of approved return on equity

9.20%

Approved annual increase in rates

$ 6,300,000

Public utilities approved increase amount of annual revenue to recover eligible capital investments

$ 1,300,000

Northern Utilities Inc | Arrearage Management Program

Commitments And Contingencies [Line Items]

Expenses associated with the program excluded from the revenue requirement as per order and adjusted increase amount will result in reasonable rates

$ 5,900,000

Northern Utilities Inc | New Hampshire

Commitments And Contingencies [Line Items]

Percentage of approved return on equity, reflecting on equity

52%

Percentage of approved return on equity, reflecting on debt

48%

Percentage of approved return on equity

9.30%

Threshold amount that will be allowed to adjust distribution rates upward or downward during the term of stay out period

$ 200,000

Requested annual increase in rates

$ 1,600,000

Northern Utilities Inc | Maine

Commitments And Contingencies [Line Items]

Percentage of approved return on equity, reflecting on equity

50%

Percentage of approved return on equity, reflecting on debt

50%

Percentage of approved return on equity

9.48%

Northern Utilities Inc | Maine | November 1, 2022 [Member]

Commitments And Contingencies [Line Items]

Approved annual increase in rates

$ 600,000

Northern Utilities Inc | Settlement Agreement [Member] | New Hampshire

Commitments And Contingencies [Line Items]

Approved annual increase in rates

$ 6,100,000

Fitchburg Gas and Electric Light Company

Commitments And Contingencies [Line Items]

Increase (decrease) in annual revenue

$ 3,100,000

$ 1,600,000

Power generation capacity | MW

9,450,000

Percentage of approved return on equity, reflecting on equity

52.45%

Percentage of approved return on equity, reflecting on debt

47.55%

Percentage of approved return on equity

9.70%

Revenue Impact Threshold

$ 100,000

Fitchburg Gas and Electric Light Company | Offshore Wind Energy

Commitments And Contingencies [Line Items]

Power generation facility | MW

400

1,600

Remuneration Percentage

2.25%

2.75%

Fitchburg Gas and Electric Light Company | Offshore Wind Energy | First Solicitation [Member]

Commitments And Contingencies [Line Items]

Power generation facility | MW

400

Fitchburg Gas and Electric Light Company | Offshore Wind Energy | Second Solicitation [Member]

Commitments And Contingencies [Line Items]

Power generation facility | MW

1,600

800

Fitchburg Gas and Electric Light Company | Offshore Wind Energy | Forecast [Member]

Commitments And Contingencies [Line Items]

Facility power capacity to be procured in the future | MW

2,400

5,600

Fitchburg Gas and Electric Light Company | Offshore Wind Energy | Forecast [Member] | Maximum [Member]

Commitments And Contingencies [Line Items]

Facility power capacity to be procured in the future | MW

2,400

Fitchburg Gas and Electric Light Company | Offshore Wind Energy | Forecast [Member] | Minimum [Member]

Commitments And Contingencies [Line Items]

Facility power capacity to be procured in the future | MW

400

Fitchburg Gas and Electric Light Company | hydroelectric generation

Commitments And Contingencies [Line Items]

Power generation capacity | MWh

9,554,940

Remuneration Percentage

2.75%

Fitchburg Gas and Electric Light Company | Mayflower Wind energy [Member] | Third Solicitation [Member]

Commitments And Contingencies [Line Items]

Power generation facility | MW

400

Fitchburg Gas and Electric Light Company | Commonwealth Wind [Member] | Third Solicitation [Member]

Commitments And Contingencies [Line Items]

Power generation facility | MW

1,200

Fitchburg Gas Company

Commitments And Contingencies [Line Items]

Percentage of approved return on equity, reflecting on equity

52.45%

Percentage of approved return on equity, reflecting on debt

47.55%

Percentage of approved return on equity

9.70%

Regulatory assets approved increase in revenue due to be recovered

$ 4,500,000

$ 3,300,000

Approved annual increase in rates

$ 1,100,000

Approved annual increase in rates

900,000

Apporved annual decrease in rates

$ 200,000

Recovery of deferred costs

$ 1,200,000

Fitchburg Gas Company | January 1, 2023 [Member]

Commitments And Contingencies [Line Items]

Public utilities interim increase decrease amount

$ 700,000

Fitchburg Gas Company | March 1, 2023 [Member]

Commitments And Contingencies [Line Items]

Public utilities interim increase decrease amount

$ 700,000

Granite State

Commitments And Contingencies [Line Items]

Increase (decrease) in annual revenue

$ 300,000

$ 100,000

$ 1,300,000

Spending cap

14,600,000

Fitchburg Grid Modernization

Commitments And Contingencies [Line Items]

Regulatory assets approved increase in revenue due to be recovered

$ 400,000

Amount of replacement investments approved by regulatory authority

11,200,000

Purchase commitments for data sharing platform investments

2,300,000

Fitchburg Grid Modernization | Track One [Member]

Commitments And Contingencies [Line Items]

Amount of capital expenditure approved by regulatory authority

$ 9,300,000

Fitchburg Grid Modernization | Track Two [Member]

Commitments And Contingencies [Line Items]

Amount of capital expenditure approved by regulatory authority

$ 1,500,000

Company's Liability for Environ

Company's Liability for Environmental Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	$ 2.7	$ 2.1
Additions	2	0.9
Less: Payments / Reductions	0.3	0.3
Total Balance at end of Period	4.4	2.7
Less: Current Portion	0.6	0.5
Noncurrent Balance at End of Period	$ 3.8	$ 2.2

Provisions for Federal and Stat

Provisions for Federal and State Income Taxes (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Current Income Tax Provision
Federal	$ 0	$ 0	$ 0.3
State	0.2	0.7	0.6
Total Current Income Taxes	0.2	0.7	0.9
Deferred Income Tax Provision
Federal	6.6	7.3	6.5
State	4.4	3.5	2.8
Total Deferred Income Taxes	11	10.8	9.3
Total Income Tax Expense	$ 11.2	$ 11.5	$ 10.2

Differences Between Provisions

Differences Between Provisions for Income Taxes and Provisions Calculated at Statutory Federal Tax Rate (Detail)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Examination [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21%	21%	21%
State Income Taxes, net	6%	6%	6%
Utility Plant Differences	(6.00%)	(3.00%)	(4.00%)
Other, net	0%	0%	1%
Effective Income Tax Rate	21%	24%	24%

Deferred Tax Assets and Liabili

Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Deferred Tax Assets
Retirement Benefit Obligations	$ 11	$ 34.1
Net Operating Loss Carryforwards	3.5	4.1
Tax Credit Carryforwards	1	0.7
Other, net	1.4	1.3
Total Deferred Tax Assets	16.9	40.2
Deferred Tax Liabilities
Utility Plant Differences	168.3	157.4
Regulatory Assets & Liabilities	11.3	9.4
Other, net	0.7	1.1
Total Deferred Tax Liabilities	180.3	167.9
Net Deferred Tax Liabilities	$ 163.4	$ 127.7

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Aug. 31, 2022	Dec. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2017
Income Taxes [Line Items]
Statutory Federal Income Tax Rate			21%	21%	21%
Regulatory Liability			$ 51.9	$ 52.1
Regulatory liability, expected flow back to customers					$ 47.1
Regulatory liability, expected pass back to ratepayers			1			$ 1.8
Net Operating Loss Carryforwards Utilized For Income Taxes				2.4
Deferred tax assets, operating loss carryforwards, federal			$ 2.8
Percentage of employment retention credit			50%
Employment retention duties capacity			100%
Employment tax expense				0.4	$ 0.6
Percentage of alternate minimum tax	15%
Number of years used for calculating adjusted financial statement income	3 years
Adjustment financial statement income	$ 1,000
Consolidated Appropriations Act 2021 [Member]
Income Taxes [Line Items]
Percentage of employment retention credit		70%
Employment retention duties capacity		100%
Income Tax Related Liabilities
Income Taxes [Line Items]
Regulatory Liability			$ 41	$ 44.3		$ 48.9
Gas Ratepayers | Massachusetts And Maine [Member]
Income Taxes [Line Items]
Regulatory liability, expected flow back to customers			$ 6.4
Tax Year 2018
Income Taxes [Line Items]
Statutory Federal Income Tax Rate						21%

Key Weighted Average Assumption

Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Benefit Plan Costs [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	2.85%	2.50%	3.25%
Rate of Compensation Increase	3%	3%	3%
Expected Long-term rate of return on plan assets	7.50%	7.50%	7.40%
Health Care Cost Trend Rate Assumed for Next Year	6.20%	6.60%	7%
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
Benefit Obligation
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	5.25%	2.85%	2.50%
Rate of Compensation Increase	3%	3%	3%

Retirement Benefit Obligations

Retirement Benefit Obligations - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2023
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	$ 672,000
Defined benefit plan, assumed health care cost trend rate, description	The health care cost trend rate used to determine benefit obligations at December 31, 2022 for pre-65 retirees is 8.00%, with an ultimate rate of 4.50% in 2030, and for post-65 retirees, the health care cost trend rate is 6.25%, with an ultimate rate of 4.50% in 2030. The health care cost trend rate used to determine benefit obligations at December 31, 2021 for both pre-65 and post-65 retirees is 6.20%, with an ultimate rate 4.50% in 2029. The health care cost trend rate used to determine benefit obligations at December 31, 2020 for both pre-65 and post-65 retirees is 6.60%, with an ultimate rate 4.50% in 2029.
Pension expense	$ 3,600	$ 7,200	$ 6,900
Regulatory assets	114,300	156,300
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation	138,300	185,100
Defined Benefit Plan, Plan Assets, Contributions by Employer	3,800	4,100	4,665
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	12,153	8,903	4,156
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation	13,900	17,500
Defined Benefit Plan, Plan Assets, Contributions by Employer	637	637	654
Fair Value Of Plan Assets
Defined Benefit Plan Disclosure [Line Items]
Pension expense	2,400	6,100	6,500
Defined Benefit Obligations
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	29,100	86,400
Four Zero One K Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 3,500	$ 3,300	$ 3,000
Benefit Plan Costs
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate, ultimate rate	4.50%	4.50%	4.50%
Health care cost trend rate, assumed	6.20%	6.60%	7%
Health care cost trend rate, ultimate rate in year	2029	2029	2029
Defined Benefit Plan, Expected Long-term Return on Assets	7.50%	7.50%	7.40%
Pre-65 retirees
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate, ultimate rate	4.50%	4.50%	4.50%
Health care cost trend rate, assumed	8%	6.20%	6.60%
Health care cost trend rate, ultimate rate in year	2030	2029	2029
Post-65 retirees
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate, ultimate rate	4.50%	4.50%	4.50%
Health care cost trend rate, assumed	6.25%	6.20%	6.60%
Health care cost trend rate, ultimate rate in year	2030	2029	2029
Scenario Forecast | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				56%
Scenario Forecast | Pension Plan [Member] | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				56%
Scenario Forecast | Pension Plan [Member] | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				39%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				55%
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%
Real Estate Funds | Scenario Forecast | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				5%

Components of Retirement Plan C

Components of Retirement Plan Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 3,165	$ 3,472	$ 3,322
Interest Cost	5,486	5,003	5,776
Expected Return on Plan Assets	10,883	9,693	9,019
Prior Service Cost Amortization	356	301	320
Actuarial Loss Amortization	$ (5,507)	(8,089)	(6,472)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) Excluding Service Cost, Statement of Income or Comprehensive Income [Extensible Enumeration]	Other Nonoperating Income (Expense)
Sub-total	$ 3,631	7,172	6,871
Amounts Capitalized or Deferred	1,085	3,384	3,083
NPBC Recognized	2,546	3,788	3,788
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	2,890	3,034	2,698
Interest Cost	3,194	2,740	3,121
Expected Return on Plan Assets	3,415	2,508	2,063
Prior Service Cost Amortization	1,092	1,208	1,210
Actuarial Loss Amortization	(1,020)	(1,045)	$ (744)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) Excluding Service Cost, Statement of Income or Comprehensive Income [Extensible Enumeration]			Other Nonoperating Income (Expense)
Sub-total	4,781	5,519	$ 5,710
Amounts Capitalized or Deferred	2,388	3,136	2,865
NPBC Recognized	2,393	2,383	2,845
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	273	354	283
Interest Cost	472	458	549
Prior Service Cost Amortization	55	56	57
Actuarial Loss Amortization	$ (794)	$ (1,489)	(1,036)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) Excluding Service Cost, Statement of Income or Comprehensive Income [Extensible Enumeration]	Other Nonoperating Income (Expense)	Other Nonoperating Income (Expense)
Sub-total	$ 1,594	$ 2,357	1,925
Amounts Capitalized or Deferred	472	712	579
NPBC Recognized	$ 1,122	$ 1,645	$ 1,346

Summary of Information on Plans

Summary of Information on Plans' Assets, Projected Benefit Obligations (PBO), and Funded Status (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	$ 152,006	$ 137,406
Actual Return on Plan Assets	(19,984)	16,989
Employer Contributions	3,800	4,100	$ 4,665
Benefits Paid	(9,724)	(6,489)
Plan Assets at End of Year	126,098	152,006	137,406
PBO at Beginning of Year	199,418	206,092
Service Cost	3,165	3,472	3,322
Interest Cost	5,486	5,003	5,776
Plan Amendments		674
Benefits Paid	(9,724)	(6,489)	(6,038)
Actuarial (Gain) or Loss	(51,392)	(9,334)
PBO at End of Year	146,953	199,418	206,092
Funded Status: Assets vs PBO	(20,855)	(47,412)
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	42,651	32,847
Actual Return on Plan Assets	(6,810)	3,586
Employer Contributions	12,153	8,903	4,156
Participant Contributions	279	220
Benefits Paid	(3,503)	(2,905)
Plan Assets at End of Year	44,770	42,651	32,847
PBO at Beginning of Year	112,087	106,831
Service Cost	2,890	3,034	2,698
Interest Cost	3,194	2,740	3,121
Benefits Paid	(3,503)	(2,905)	(2,568)
Actuarial (Gain) or Loss	(58,437)	2,167
PBO at End of Year	56,510	112,087	106,831
Funded Status: Assets vs PBO	(11,740)	(69,436)
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions	637	637	654
Benefits Paid	(637)
PBO at Beginning of Year	17,714	20,225
Service Cost	273	354	283
Interest Cost	472	458	549
Benefits Paid	(637)	(637)	(654)
Actuarial (Gain) or Loss	(3,012)	(2,686)
PBO at End of Year	14,810	17,714	$ 20,225
Funded Status: Assets vs PBO	$ (14,810)	$ (17,714)

Employer Contributions, Partici

Employer Contributions, Participant Contributions and Benefit Payments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Plans
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	$ 3,800	$ 4,100	$ 4,665
Benefits Paid	9,724	6,489	6,038
Other Postretirement Benefit Plans, Defined Benefit
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	12,153	8,903	4,156
Participant Contributions	279	220	240
Benefits Paid	3,503	2,905	2,568
Supplemental Employee Retirement Plans, Defined Benefit
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	637	637	654
Benefits Paid	$ 637	$ 637	$ 654

Estimated Future Benefit Paymen

Estimated Future Benefit Payments (Detail) $ in Thousands	Dec. 31, 2022 USD ($)
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
2023	$ 7,952
2024	8,458
2025	8,569
2026	9,608
2027	10,317
2028-2032	55,402
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
2023	2,624
2024	2,752
2025	2,935
2026	3,170
2027	3,317
2028-2032	18,141
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
2023	637
2024	636
2025	1,167
2026	1,241
2027	1,233
2028-2032	$ 6,006

Actual Investment Allocations (

Actual Investment Allocations (Detail)		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			100%	100%	100%
Pension Plans | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			53%	57%	58%
Pension Plans | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			38%	38%	37%
Pension Plans | Other
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation	[1]		2%	1%	1%
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			100%	100%	100%
Other Postretirement Benefit Plans, Defined Benefit | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			55%	56%	55%
Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			45%	44%	45%
Real Estate Funds | Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			7%	4%	4%
Scenario Forecast | Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		56%
Scenario Forecast | Pension Plans | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		56%
Scenario Forecast | Pension Plans | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		39%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		55%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		45%
Scenario Forecast | Real Estate Funds | Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		5%
[1] Represents investments being held in cash equivalents as of December 31, 2022, December 31, 2021 and December 31, 2020 pending payment of benefits.

Assets Measured at Fair Value o

Assets Measured at Fair Value on Recurring Basis for Pension Plan (Detail) - Pension Plans - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 126,098	$ 152,006	$ 137,406
Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	114,978	144,239
Mutual Fund | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	67,332	86,356
Mutual Fund | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	47,646	57,883
Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	2,598	912
Mutual Fund Including Cash And Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	117,576	145,151
Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	8,522	6,855
Fair Value, Inputs, Level 1 | Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	114,978	144,239
Fair Value, Inputs, Level 1 | Mutual Fund | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	67,332	86,356
Fair Value, Inputs, Level 1 | Mutual Fund | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	47,646	57,883
Fair Value, Inputs, Level 1 | Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	2,598	912
Fair Value, Inputs, Level 1 | Mutual Fund Including Cash And Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 117,576	$ 145,151

Assets Measured at Fair Value_2

Assets Measured at Fair Value on Recurring Basis for PBOP Plan (Detail) - Other Postretirement Benefit Plans, Defined Benefit - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 44,770	$ 42,651	$ 32,847
Mutual Fund | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	20,156	18,882
Mutual Fund | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	24,614	23,769
Fair Value, Inputs, Level 1
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	44,770	42,651
Fair Value, Inputs, Level 1 | Mutual Fund | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	20,156	18,882
Fair Value, Inputs, Level 1 | Mutual Fund | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 24,614	$ 23,769