0001193125-26-042983 | 10-K | XBRL Viewer

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Derivatives (Additional Information) (Details) $ in Millions	Dec. 31, 2025 USD ($)
Derivatives, Fair Value [Line Items]
Fair value of derivative	$ 17.7
Prepayments and Other related, current portion
Derivatives, Fair Value [Line Items]
Fair value of derivative	2.8
Other Assets related, noncurrent portion
Derivatives, Fair Value [Line Items]
Fair value of derivative	$ 14.9

Equity - Schedule of Common Shares Activity (Details) - shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Class of Stock [Line Items]
Shares as of December 31, 2024	16,192,345
Shares issued	1,651,497	19,510	21,321
Shares as of December 31, 2025	17,919,191	16,192,345
Common Stock
Class of Stock [Line Items]
Shares as of December 31, 2024	16,192,345
Shares as of December 31, 2025	17,919,191	16,192,345
Common Stock \| Equity Issuance
Class of Stock [Line Items]
Shares issued	1,602,358
Common Stock \| ATM
Class of Stock [Line Items]
Shares issued	27,620
Common Stock \| DRP
Class of Stock [Line Items]
Shares issued	21,519
Common Stock \| Directors
Class of Stock [Line Items]
Shares issued	14,610
Common Stock \| RSU Settlement
Class of Stock [Line Items]
Shares issued	8,525
Common Stock \| Time Restricted
Class of Stock [Line Items]
Shares issued	26,430
Forfeited Shares	(396)
Common Stock \| Performance Restricted
Class of Stock [Line Items]
Shares issued	26,430
Forfeited Shares	(250)

Summary of Significant Accounting Policies - Components of Gas and Electric Operating Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ 536.0	$ 494.8	$ 557.1
Gas Segment
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	299.6	246.5	250.6
Electric
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	236.4	248.3	306.5
Residential
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	242.3	227.6	280.4
Residential \| Gas Segment
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	121.2	92.6	98.8
Residential \| Electric
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	121.1	135.0	181.6
C&I
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	265.9	236.9	267.0
C&I \| Gas Segment
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	171.0	133.5	146.9
C&I \| Electric
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	94.9	103.4	120.1
Other
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	26.9	20.1	18.1
Other \| Gas Segment
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	13.8	9.7	8.1
Other \| Electric
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	13.1	10.4	10.0
Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	535.1	484.6	565.5
Billed and Unbilled Revenue \| Gas Segment
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	306.0	235.8	253.8
Billed and Unbilled Revenue \| Electric
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	229.1	248.8	311.7
Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	0.9	10.2	(8.4)
Rate Adjustment Mechanism Revenue \| Gas Segment
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	(6.4)	10.7	(3.2)
Rate Adjustment Mechanism Revenue \| Electric
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ 7.3	$ (0.5)	$ (5.2)

- Definition

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

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Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
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+ Details

Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands					12 Months Ended
	Jan. 27, 2026	Jan. 28, 2025	Jan. 30, 2024	Jan. 24, 2023	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Jun. 03, 2025	May 01, 2024	Mar. 31, 2024
Class of Stock [Line Items]
Common Equity Outstanding					17,919,191	16,192,345
Shares issued					1,651,497	19,510	21,321
Common stock, shares authorized					25,000,000	25,000,000
Proceeds from Issuance of Common Stock					$ 73,500	$ 1,100	$ 1,100
Common stock shares repurchase					0	0	14,680
Preferred Stock					$ 200	$ 200
Restricted Stock
Class of Stock [Line Items]
Restricted stock vesting period					4 years
Share based compensation expense					$ 1,900	1,400	$ 1,400
Unrecognized share based compensation					$ 800
Share compensation recognition period					2 years 7 months 6 days
Restricted Stock Units Granted		26,430	22,680	18,770
Forfeited under the stock plan					396
Cancellations under the stock plan					0
Aggregate Market Value		$ 1,400	$ 1,100	$ 1,000
Restricted Stock \| Subsequent Event
Class of Stock [Line Items]
Restricted Stock Units Granted	32,330
Aggregate Market Value	$ 1,600
Restricted Stock \| Vesting Annually
Class of Stock [Line Items]
Restricted stock vesting percentage annually					25.00%
Performance Restricted Shares
Class of Stock [Line Items]
Share based compensation expense					$ 1,400	1,000	500
Unrecognized share based compensation					$ 1,700
Share compensation recognition period					1 year 8 months 12 days
Restricted Stock Units Granted		26,430	22,680	18,770
Forfeited under the stock plan					250
Cancellations under the stock plan					0
Aggregate Market Value		$ 1,400	$ 1,100	$ 1,000
Performance Restricted Shares \| Subsequent Event
Class of Stock [Line Items]
Restricted Stock Units Granted	32,330
Aggregate Market Value	$ 1,600
Restricted Stock Units (RSUs)
Class of Stock [Line Items]
Percentage of fully-vested restricted stock units that directors will receive in common shares when settled					70.00%
Fair value of liabilities associated with fully vested RSUs that will be settled in cash					$ 700	$ 900
Restricted Stock Units Granted					6,818	2,215
Percentage of fully-vested restricted stock units that directors will receive in cash when settled					30.00%
Common Stock
Class of Stock [Line Items]
Shares issued					1,602,358
Proceeds From Issuance Initial Public Offering					$ 71,800
Common stock price per share					$ 46.65
Common Stock \| Directors
Class of Stock [Line Items]
Shares issued					14,610
Unitil Energy Systems Inc \| Series 6
Class of Stock [Line Items]
Preferred stock, outstanding					1,727	1,727
Preferred Stock					$ 200	$ 200
Dividend rate					6.00%	6.00%
Unitil Corporation
Class of Stock [Line Items]
Common stock offering price								$ 50,000
Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Proceeds from Issuance of Common Stock					$ 1,100	$ 1,100	$ 1,100
Dividend and Distribution Reinvestment and Share Purchase Plan \| Common Stock
Class of Stock [Line Items]
Shares issued					21,519	19,510	21,321
ATM
Class of Stock [Line Items]
Future sales					$ 48,500
ATM \| Common Stock
Class of Stock [Line Items]
Net Proceeds					1,400
Gross proceeds					$ 1,500
Share sold under ATM program					27,620
Sale of stock, Average price per share					$ 53
Maximum
Class of Stock [Line Items]
Dividend declared					$ 100	$ 100
Repurchase expense					$ 0	$ 0	$ 600
Maximum \| Restricted Stock
Class of Stock [Line Items]
Restricted stock available for awards									1,027,500	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					$ 51.83

Debt and Financing Arrangements - Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Debt Disclosure [Abstract]
Estimated Fair Value of Long-Term Debt	$ 623.4	$ 598.9

- Definition

The fair value amount of long-term debt whether such amount is presented as a separate caption or as a parenthetical disclosure. Additionally, this element may be used in connection with the fair value disclosures required in the footnote disclosures to the financial statements. The element may be used in both the balance sheet and disclosure in the same submission.

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Reference 1: http://www.xbrl.org/2009/role/commonPracticeRef
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+ Details

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Operating Activities:
Net Income	$ 50.2	$ 47.1	$ 45.2
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	88.7	76.1	67.4
Deferred Tax Provision	9.6	13.2	7.4
Changes in Working Capital Items:
Accounts Receivable	(18.4)	0.0	(1.2)
Accrued Revenue	(0.3)	(14.0)	9.4
Regulatory Liabilities	(3.3)	3.7	(1.5)
Exchange Gas Receivable	(3.4)	3.0	8.6
Accounts Payable	7.0	2.0	(20.9)
Other Changes in Working Capital Items	(2.2)	3.7	1.0
Deferred Regulatory and Other Charges	(3.6)	(6.9)	(8.5)
Other, net	7.0	(2.0)	0.1
Cash Provided by Operating Activities	131.3	125.9	107.0
Investing Activities:
Property, Plant and Equipment Additions	(185.1)	(169.9)	(141.0)
Acquisitions, Net of Cash Acquired	(160.4)	0.0	0.0
Cash Used In Investing Activities	(345.5)	(169.9)	(141.0)
Financing Activities:
Proceeds (Repayment of) from Short-Term Debt, net	149.9	(56.2)	46.0
Issuance of Long-Term Debt	32.0	135.0	25.0
Repayment of Long-Term Debt	(4.9)	(4.9)	(6.9)
Long-Term Debt Issuance Costs	(0.2)	(1.1)	(0.2)
Increase in Capital Lease Obligations	0.1	0.0	0.3
Net Increase (Decrease) in Exchange Gas Financing	3.3	(2.6)	(7.6)
Dividends Paid	(30.1)	(27.5)	(26.2)
Proceeds from Issuance of Common Stock	73.5	1.1	1.1
Construction Advances	(0.1)	0.0	0.0
Cash Provided by Financing Activities	223.5	43.8	31.5
Net Increase (Decrease) in Cash and Cash Equivalents	9.3	(0.2)	(2.5)
Cash and Cash Equivalents at Beginning of Year	6.3	6.5	9.0
Cash and Cash Equivalents at End of Year	15.6	6.3	6.5
Supplemental Information:
Interest Paid	39.3	31.2	30.9
Income Taxes Paid	4.9	2.5	0.0
Payments on Capital Leases	0.2	0.2	0.2
Capital Expenditures Included in Accounts Payable	8.1	11.7	7.5
Right-of-Use Assets Obtained in Exchange for Lease Obligations	$ 1.7	$ 2.6	$ 2.7

Segment Information

12 Months Ended

Dec. 31, 2025

Segment Reporting [Abstract]

Segment Information

Note 2: Segment Information

The Company’s Chief Operating Decision Maker (CODM), consists of the Company’s Chairman and Chief Executive Officer, President and Chief Administrative Officer, Chief Financial Officer, and Chief Accounting Officer. These individuals assess financial performance and make decisions, including the allocation of resources to the various operating segments, based on meeting with the managers of each segment and through their review of reports and analyses that are regularly provided to the CODM. The CODM uses Net Income Applicable to Common Shares for each segment predominantly in the annual budget and forecasting process. The CODM considers budget-to-actual variances on a quarterly basis when making decisions about the allocation of operating and capital resources to each segment. Unitil reports two operating and reportable segments: utility electric operations and utility gas operations.

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, portions of central Maine including Augusta and the Bangor area, and in the greater Fitchburg area of north central Massachusetts. Unitil has five distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire, Fitchburg, which operates in Massachusetts, Northern Utilities, which operates in New Hampshire and Maine, Bangor, which operates in Maine and Maine Natural, which operates in Maine. Unitil Energy and the electric division of Fitchburg are included in the electric segment. Northern Utilities, Bangor, Maine Natural and the gas division of Fitchburg are included in the gas segment. Unitil Energy, Fitchburg, Northern Utilities, Bangor

and Maine Natural have a well-diversified customer mix and are not dependent on a single customer, or a few customers, for their electric and natural gas sales. Granite State is an interstate natural gas transmission pipeline company, operating 85 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. 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 Corp. (the holding company), and Unitil Resources are included in the “Other” category (ASC 280-10-50-15). The holding company has no operating income of its own. The earnings of the holding company are principally derived from income earned on short-term investments. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary and currently does not have any activity. Unitil Service provides centralized management and administrative services, including information systems management and financial record keeping to support the affiliated Unitil companies. Unitil Realty owns certain real estate, principally the Company’s corporate headquarters in Hampton, New Hampshire and land in Kingston, New Hampshire on which Unitil Energy’s solar facility is located, which became operational in May 2025. Unitil Service’s and Unitil Realty’s costs are allocated to the Electric and Gas segments based on cost allocation factors. Unitil Water does not have any activity.

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

The following tables provide significant segment financial data for the years ended December 31, 2025, 2024 and 2023 (millions):


Year Ended December 31, 2025	Electric			Gas			Total Reportable Segments			Other			Total
Total Operating Revenues	$	236.4		$	299.6		$	536.0		$	—		$	536.0
Energy Supply Costs		121.8			100.5			222.3			—			222.3
Operation and Maintenance		38.8			48.9			87.7			4.8			92.5
Depreciation and Amortization Expense		31.9			56.8			88.7			—			88.7
Other Segment Expenses (Income)		12.6			18.0			30.6			(0.3	)		30.3
Interest Income		(3.3	)		(3.8	)		(7.1	)		—			(7.1	)
Interest Expense		15.0			25.1			40.1			3.7			43.8
Provision for Income Taxes		3.8			14.0			17.8			(2.5	)		15.3
Net Income Attributable to Commons Shares		15.8			40.1			55.9			(5.7	)		50.2

Segment Assets		733.5			1,367.8			2,101.3			32.9			2,134.2
Capital Expenditures		73.5			110.0			183.5			1.6			185.1


Year Ended December 31, 2024	Electric			Gas			Total Reportable Segments			Other			Total
Total Operating Revenues	$	248.3		$	246.5		$	494.8		$	—		$	494.8
Energy Supply Costs		141.0			79.6			220.6			—			220.6
Operation and Maintenance		34.9			41.7			76.6			1.0			77.6
Depreciation & Amortization Expense		29.3			46.8			76.1			—			76.1
Other Segment Expenses (Income)		12.9			17.3			30.2			(0.1	)		30.1
Interest Income		(3.6	)		(4.6	)		(8.2	)		(0.2	)		(8.4	)
Interest Expense		13.4			23.7			37.1			0.6			37.7
Provision for Income Taxes		3.8			11.2			15.0			(1.0	)		14.0
Net Income Attributable to Commons Shares		16.6			30.8			47.4			(0.3	)		47.1

Segment Assets		647.2			1,115.3			1,762.5			32.0			1,794.5
Capital Expenditures		61.8			103.9			165.7			4.2			169.9


Year Ended December 31, 2023	Electric			Gas			Total Reportable Segments			Other			Total
Total Operating Revenues	$	306.5		$	250.6		$	557.1		$	—		$	557.1
Energy Supply Costs		202.4			96.1			298.5			—			298.5
Operation and Maintenance		34.5			40.7			75.2			0.4			75.6
Depreciation & Amortization Expense		26.0			40.4			66.4			1.0			67.4
Other Segment Expenses (Income)		13.1			16.9			30.0			(1.5	)		28.5
Interest Income		(2.6	)		(2.4	)		(5.0	)		(1.2	)		(6.2	)
Interest Expense		11.2			20.7			31.9			3.0			34.9
Provision for Income Taxes		4.0			9.4			13.4			(0.2	)		13.2
Net Income Attributable to Commons Shares		17.9			28.8			46.7			(1.5	)		45.2

Segment Assets		612.6			1,031.8			1,644.4			26.0			1,670.4
Capital Expenditures		44.2			92.7			136.9			4.1			141.0

- Definition

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

+ References

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+ Details

Debt and Financing Arrangements - Classification of the Company Lease Obligations (Detail) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Operating Lease Obligations:
Other Current Liabilities (current portion)	$ 2.1	$ 1.8
Operating Lease Obligations (current portion)	Liabilities, Current	Liabilities, Current
Other Noncurrent Liabilities (long-term portion)	$ 4.9	$ 4.9
Operating Lease Obligations (long-term portion)	Liabilities, Noncurrent	Liabilities, Noncurrent
Total Operating Lease Obligations	$ 7.0	$ 6.7
Capital Lease Obligations:
Other Current Liabilities (current portion)	$ 0.2	$ 0.1
Other Current Liabilities (current portion)	Other Liabilities, Current	Other Liabilities, Current
Other Noncurrent Liabilities (long-term portion)	$ 0.4	$ 0.4
Other Noncurrent Liabilities (long-term portion)	Other Liabilities, Noncurrent	Other Liabilities, Noncurrent
Total Capital Lease Obligations	$ 0.6	$ 0.5
Total Lease Obligations	7.6	$ 7.2
Lease Obligations [Member]
Operating Lease Obligations:
Total Operating Lease Obligations	$ 7,047.0

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2025	Dec. 31, 2024
Statement of Financial Position [Abstract]
Common stock per value	$ 0	$ 0
Common stock, shares authorized	25,000,000	25,000,000
Common Equity Outstanding	17,919,191	16,192,345
Common Stock Shares Issued Not Disclosed	false	false

Segment Information (Tables)

12 Months Ended

Dec. 31, 2025

Segment Reporting [Abstract]

Significant Segment Financial Data

The following tables provide significant segment financial data for the years ended December 31, 2025, 2024 and 2023 (millions):


Year Ended December 31, 2025	Electric			Gas			Total Reportable Segments			Other			Total
Total Operating Revenues	$	236.4		$	299.6		$	536.0		$	—		$	536.0
Energy Supply Costs		121.8			100.5			222.3			—			222.3
Operation and Maintenance		38.8			48.9			87.7			4.8			92.5
Depreciation and Amortization Expense		31.9			56.8			88.7			—			88.7
Other Segment Expenses (Income)		12.6			18.0			30.6			(0.3	)		30.3
Interest Income		(3.3	)		(3.8	)		(7.1	)		—			(7.1	)
Interest Expense		15.0			25.1			40.1			3.7			43.8
Provision for Income Taxes		3.8			14.0			17.8			(2.5	)		15.3
Net Income Attributable to Commons Shares		15.8			40.1			55.9			(5.7	)		50.2

Segment Assets		733.5			1,367.8			2,101.3			32.9			2,134.2
Capital Expenditures		73.5			110.0			183.5			1.6			185.1


Year Ended December 31, 2024	Electric			Gas			Total Reportable Segments			Other			Total
Total Operating Revenues	$	248.3		$	246.5		$	494.8		$	—		$	494.8
Energy Supply Costs		141.0			79.6			220.6			—			220.6
Operation and Maintenance		34.9			41.7			76.6			1.0			77.6
Depreciation & Amortization Expense		29.3			46.8			76.1			—			76.1
Other Segment Expenses (Income)		12.9			17.3			30.2			(0.1	)		30.1
Interest Income		(3.6	)		(4.6	)		(8.2	)		(0.2	)		(8.4	)
Interest Expense		13.4			23.7			37.1			0.6			37.7
Provision for Income Taxes		3.8			11.2			15.0			(1.0	)		14.0
Net Income Attributable to Commons Shares		16.6			30.8			47.4			(0.3	)		47.1

Segment Assets		647.2			1,115.3			1,762.5			32.0			1,794.5
Capital Expenditures		61.8			103.9			165.7			4.2			169.9


Year Ended December 31, 2023	Electric			Gas			Total Reportable Segments			Other			Total
Total Operating Revenues	$	306.5		$	250.6		$	557.1		$	—		$	557.1
Energy Supply Costs		202.4			96.1			298.5			—			298.5
Operation and Maintenance		34.5			40.7			75.2			0.4			75.6
Depreciation & Amortization Expense		26.0			40.4			66.4			1.0			67.4
Other Segment Expenses (Income)		13.1			16.9			30.0			(1.5	)		28.5
Interest Income		(2.6	)		(2.4	)		(5.0	)		(1.2	)		(6.2	)
Interest Expense		11.2			20.7			31.9			3.0			34.9
Provision for Income Taxes		4.0			9.4			13.4			(0.2	)		13.2
Net Income Attributable to Commons Shares		17.9			28.8			46.7			(1.5	)		45.2

Segment Assets		612.6			1,031.8			1,644.4			26.0			1,670.4
Capital Expenditures		44.2			92.7			136.9			4.1			141.0

Cybersecurity Risk Management, Strategy, and Governance	12 Months Ended
Cybersecurity Risk Management, Strategy, and Governance	Dec. 31, 2025
Cybersecurity Risk Management, Strategy, and Governance [Line Items]
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]	Item 1C. Cybersecurity For purposes of the following disclosure, the terms “cybersecurity incident” and “cybersecurity threat” have the meanings given to such terms in Item 106 of Regulation S-K promulgated under the Exchange Act. Risk management and strategy The Company has a Cybersecurity Plan for assessing, identifying, and managing material risks from cybersecurity threats. The intent of the Cybersecurity Plan is to provide a proactive and systemic approach to meet the evolving requirements for cybersecurity and related compliance in the utility industry. The Cybersecurity Plan’s objectives include: • adopting and using established cybersecurity standards and industry best practices; • protecting personally identifiable information; • protecting infrastructure operations, including Supervisory Control and Data Acquisition (SCADA) systems at electric substations and natural gas plants; • securing customers’, employees’, and the Company’s data; • complying with North American Reliability Corporation Critical Infrastructure Protection Reliability Standards and standards for the protection of Bulk Electric System Cyber Systems; and • continually assessing and, as necessary, enhancing the Company’s cybersecurity through a managed process integrated with the Company’s risk management principles. The Cybersecurity Plan includes annual assessments using (i) the Department of Energy’s Cybersecurity Capability Maturity Model, (ii) the National Institute of Standards and Technology Cybersecurity Framework, and (iii) the Center for Internet Security Controls. The Company uses the results of these assessments to benchmark the Company’s cybersecurity posture, to identify risks from cybersecurity threats, to prioritize any such risks that may have potential material effects on the Company, and to establish effective controls to manage, mitigate and remediate such risks. The Cybersecurity Plan is part of the Company’s corporate Enterprise Risk Management (ERM) program. The Company’s ERM program includes an annual review of new or emerging risks (including risks from cybersecurity threats), the assessment of such risks and their potential effects on the Company, the velocity of potential cybersecurity incidents resulting from such risks, and risk mitigation strategies. The Company maintains a Cybersecurity Employee Awareness Program, which provides targeted education and mandatory quarterly training to employees. The Cybersecurity Employee Awareness Program also conducts monthly phishing test exercises with employees, which includes an escalation procedure for repeated failures. Additionally, the Company performs an annual cyber knowledge assessment of all employees to address any identified knowledge gaps. The Company engages or otherwise collaborates with cybersecurity consultants, cybersecurity experts, energy sector leaders, and other third parties in connection with the Cybersecurity Plan. Unitil Corporation is also a member of the cyber committees of both the American Gas Association and the Edison Electric Institute. Third-party entities that provide hardware, software or related support services to the Company or hold the Company’s customer data represent material cybersecurity risks to the Company. To help mitigate those risks, the Company has robust procurement processes and requirements for such third-parties (which include a formal assessment of the third-party’s cyber posture, cyber liability insurance, and breach reporting protocols) that help the Company to oversee and identify cybersecurity risks associated with its use of such third-party entities. During the fiscal year ended, and as of, December 31, 2025, there were no risks from cybersecurity threats (including as a result of previous cybersecurity incidents) that have materially affected or are reasonably likely to materially affect the Company (including its business strategy, results of operations, or financial condition). Governance The Board is responsible for oversight of the Company’s ERM program, including risks from cybersecurity threats. The Board has not assigned that responsibility to any committee or subcommittee of the Board. The Company’s management generally provides the Board with updates on and assessments of ongoing and emerging risks from cybersecurity threats at regularly scheduled Board meetings. The Company’s cybersecurity management team is responsible for assessing and managing the Company’s material risks from cybersecurity threats, including implementing the Cybersecurity Plan. The team includes the Company’s Senior Vice President of Shared Services and Director of Information Security and Infrastructure Operations, all of whom have an educational background relevant to, professional experience in, or other expertise in cybersecurity. The Senior Vice President, Shared Services holds a Master of Business Administration and Bachelor of Arts with over 25 years of professional experience leading teams in Human Resources, Supply Chain and Information Technology. The Senior Vice President of Shared Services has overall management responsibility for the Company’s cybersecurity. The Senior Vice President of Shared Services reports to the Company’s President and Chief Administrative Officer. The Director of Information Security and Cyber Operations holds CISSP and ITIL certifications, a Bachelor of Science in Computer Science and a Master’s Certificate in Cybersecurity with a concentration in Power Systems and has over 30 years of experience in the information technology field. The Director of Information Security and Infrastructure Operations also assumes responsibilities as the Company’s Chief Information Security Officer (CISO). The Director of Information Security and Infrastructure Operations has primary responsibility for the cybersecurity program including threat and vulnerability management, vendor security posture assessment, Industrial Control System (ICS) and SCADA infrastructure cybersecurity protection at electric substations and natural gas plants, as well as leading the Cyber Incident Response Team. The Company’s cybersecurity management team assesses and manages the Company’s material risks from cybersecurity threats through or by: • active monitoring of cyber threat alerts, warnings, advisories, notices, vulnerability assessments, incident bulletins, security briefings, reports and white papers from industry and national organizations, including: downstream Natural Gas Information Sharing and Analysis Center; Electricity Information Sharing and Analysis Center; Cybersecurity and Infrastructure Security Agency; and Federal Bureau of Investigation; • threat and vulnerability management; • vendor security posture assessment; • Industrial Control System and Supervisory Control and Data Acquisition infrastructure cybersecurity protection at electric substations and natural gas plants; and • leading the Company’s Cyber Incident Response Team. In addition, the Company uses (i) a Security Operations Center vendor with 24x7 monitoring and response capabilities to identify any suspicious activity on the Company’s networks and (ii) a security consulting firm for assessments, penetration testing and incident response. In the event of a cybersecurity threat, the CISO and these parties would collaborate to assess and manage the risk with ultimate responsibility residing with the Board. Also, in the event of a cybersecurity threat or cybersecurity incident, the Company’s cybersecurity management team will investigate and perform impact analysis and, as necessary, the CISO will activate the Company’s Cyber Incident Response Team. The Cyber Incident Response Team is a subset of the Company’s Crisis Response Team, which has responsibility for operational and business resilience, as well as tactical and strategic response. A foundational aspect of the Crisis Response Team is prompt and comprehensive communications to all concerned parties, both internal and external, including direction for management to inform the Board about risks from cybersecurity threats. The Company’s determination of the materiality of a cybersecurity incident would generally include an evaluation of the incident’s effect on the Company (including (i) its business strategy, results of operations, or financial condition, (ii) the integrity, confidentiality, resiliency, and security of the Company’s networks and systems, and (iii) the Company’s operations).
Cybersecurity Risk Management Processes Integrated [Flag]	true
Cybersecurity Risk Management Processes Integrated [Text Block]	The Company has a Cybersecurity Plan for assessing, identifying, and managing material risks from cybersecurity threats. The intent of the Cybersecurity Plan is to provide a proactive and systemic approach to meet the evolving requirements for cybersecurity and related compliance in the utility industry. The Cybersecurity Plan’s objectives include: • adopting and using established cybersecurity standards and industry best practices; • protecting personally identifiable information; • protecting infrastructure operations, including Supervisory Control and Data Acquisition (SCADA) systems at electric substations and natural gas plants; • securing customers’, employees’, and the Company’s data; • complying with North American Reliability Corporation Critical Infrastructure Protection Reliability Standards and standards for the protection of Bulk Electric System Cyber Systems; and • continually assessing and, as necessary, enhancing the Company’s cybersecurity through a managed process integrated with the Company’s risk management principles.
Cybersecurity Risk Management Third Party Engaged [Flag]	true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag]	true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]	false
Cybersecurity Risk Board of Directors Oversight [Text Block]	The Board is responsible for oversight of the Company’s ERM program, including risks from cybersecurity threats. The Board has not assigned that responsibility to any committee or subcommittee of the Board. The Company’s management generally provides the Board with updates on and assessments of ongoing and emerging risks from cybersecurity threats at regularly scheduled Board meetings. The Company’s cybersecurity management team is responsible for assessing and managing the Company’s material risks from cybersecurity threats, including implementing the Cybersecurity Plan. The team includes the Company’s Senior Vice President of Shared Services and Director of Information Security and Infrastructure Operations, all of whom have an educational background relevant to, professional experience in, or other expertise in cybersecurity. The Senior Vice President, Shared Services holds a Master of Business Administration and Bachelor of Arts with over 25 years of professional experience leading teams in Human Resources, Supply Chain and Information Technology. The Senior Vice President of Shared Services has overall management responsibility for the Company’s cybersecurity. The Senior Vice President of Shared Services reports to the Company’s President and Chief Administrative Officer. The Director of Information Security and Cyber Operations holds CISSP and ITIL certifications, a Bachelor of Science in Computer Science and a Master’s Certificate in Cybersecurity with a concentration in Power Systems and has over 30 years of experience in the information technology field. The Director of Information Security and Infrastructure Operations also assumes responsibilities as the Company’s Chief Information Security Officer (CISO). The Director of Information Security and Infrastructure Operations has primary responsibility for the cybersecurity program including threat and vulnerability management, vendor security posture assessment, Industrial Control System (ICS) and SCADA infrastructure cybersecurity protection at electric substations and natural gas plants, as well as leading the Cyber Incident Response Team. The Company’s cybersecurity management team assesses and manages the Company’s material risks from cybersecurity threats through or by: • active monitoring of cyber threat alerts, warnings, advisories, notices, vulnerability assessments, incident bulletins, security briefings, reports and white papers from industry and national organizations, including: downstream Natural Gas Information Sharing and Analysis Center; Electricity Information Sharing and Analysis Center; Cybersecurity and Infrastructure Security Agency; and Federal Bureau of Investigation; • threat and vulnerability management; • vendor security posture assessment; • Industrial Control System and Supervisory Control and Data Acquisition infrastructure cybersecurity protection at electric substations and natural gas plants; and • leading the Company’s Cyber Incident Response Team. In addition, the Company uses (i) a Security Operations Center vendor with 24x7 monitoring and response capabilities to identify any suspicious activity on the Company’s networks and (ii) a security consulting firm for assessments, penetration testing and incident response. In the event of a cybersecurity threat, the CISO and these parties would collaborate to assess and manage the risk with ultimate responsibility residing with the Board. Also, in the event of a cybersecurity threat or cybersecurity incident, the Company’s cybersecurity management team will investigate and perform impact analysis and, as necessary, the CISO will activate the Company’s Cyber Incident Response Team. The Cyber Incident Response Team is a subset of the Company’s Crisis Response Team, which has responsibility for operational and business resilience, as well as tactical and strategic response. A foundational aspect of the Crisis Response Team is prompt and comprehensive communications to all concerned parties, both internal and external, including direction for management to inform the Board about risks from cybersecurity threats. The Company’s determination of the materiality of a cybersecurity incident would generally include an evaluation of the incident’s effect on the Company (including (i) its business strategy, results of operations, or financial condition, (ii) the integrity, confidentiality, resiliency, and security of the Company’s networks and systems, and (iii) the Company’s operations).
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]	The Board is responsible for oversight of the Company’s ERM program, including risks from cybersecurity threats. The Board has not assigned that responsibility to any committee or subcommittee of the Board. The Company’s cybersecurity management team is responsible for assessing and managing the Company’s material risks from cybersecurity threats, including implementing the Cybersecurity Plan. The team includes the Company’s Senior Vice President of Shared Services and Director of Information Security and Infrastructure Operations, all of whom have an educational background relevant to, professional experience in, or other expertise in cybersecurity. The Senior Vice President, Shared Services holds a Master of Business Administration and Bachelor of Arts with over 25 years of professional experience leading teams in Human Resources, Supply Chain and Information Technology. The Senior Vice President of Shared Services has overall management responsibility for the Company’s cybersecurity. The Senior Vice President of Shared Services reports to the Company’s President and Chief Administrative Officer. The Director of Information Security and Cyber Operations holds CISSP and ITIL certifications, a Bachelor of Science in Computer Science and a Master’s Certificate in Cybersecurity with a concentration in Power Systems and has over 30 years of experience in the information technology field. The Director of Information Security and Infrastructure Operations also assumes responsibilities as the Company’s Chief Information Security Officer (CISO). The Director of Information Security and Infrastructure Operations has primary responsibility for the cybersecurity program including threat and vulnerability management, vendor security posture assessment, Industrial Control System (ICS) and SCADA infrastructure cybersecurity protection at electric substations and natural gas plants, as well as leading the Cyber Incident Response Team.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]	The Company’s management generally provides the Board with updates on and assessments of ongoing and emerging risks from cybersecurity threats at regularly scheduled Board meetings. The Company’s cybersecurity management team is responsible for assessing and managing the Company’s material risks from cybersecurity threats, including implementing the Cybersecurity Plan. The team includes the Company’s Senior Vice President of Shared Services and Director of Information Security and Infrastructure Operations, all of whom have an educational background relevant to, professional experience in, or other expertise in cybersecurity. The Senior Vice President, Shared Services holds a Master of Business Administration and Bachelor of Arts with over 25 years of professional experience leading teams in Human Resources, Supply Chain and Information Technology. The Senior Vice President of Shared Services has overall management responsibility for the Company’s cybersecurity. The Senior Vice President of Shared Services reports to the Company’s President and Chief Administrative Officer. The Director of Information Security and Cyber Operations holds CISSP and ITIL certifications, a Bachelor of Science in Computer Science and a Master’s Certificate in Cybersecurity with a concentration in Power Systems and has over 30 years of experience in the information technology field. The Director of Information Security and Infrastructure Operations also assumes responsibilities as the Company’s Chief Information Security Officer (CISO). The Director of Information Security and Infrastructure Operations has primary responsibility for the cybersecurity program including threat and vulnerability management, vendor security posture assessment, Industrial Control System (ICS) and SCADA infrastructure cybersecurity protection at electric substations and natural gas plants, as well as leading the Cyber Incident Response Team.
Cybersecurity Risk Role of Management [Text Block]	The Company’s cybersecurity management team is responsible for assessing and managing the Company’s material risks from cybersecurity threats, including implementing the Cybersecurity Plan. The team includes the Company’s Senior Vice President of Shared Services and Director of Information Security and Infrastructure Operations, all of whom have an educational background relevant to, professional experience in, or other expertise in cybersecurity. The Senior Vice President, Shared Services holds a Master of Business Administration and Bachelor of Arts with over 25 years of professional experience leading teams in Human Resources, Supply Chain and Information Technology. The Senior Vice President of Shared Services has overall management responsibility for the Company’s cybersecurity. The Senior Vice President of Shared Services reports to the Company’s President and Chief Administrative Officer. The Director of Information Security and Cyber Operations holds CISSP and ITIL certifications, a Bachelor of Science in Computer Science and a Master’s Certificate in Cybersecurity with a concentration in Power Systems and has over 30 years of experience in the information technology field. The Director of Information Security and Infrastructure Operations also assumes responsibilities as the Company’s Chief Information Security Officer (CISO). The Director of Information Security and Infrastructure Operations has primary responsibility for the cybersecurity program including threat and vulnerability management, vendor security posture assessment, Industrial Control System (ICS) and SCADA infrastructure cybersecurity protection at electric substations and natural gas plants, as well as leading the Cyber Incident Response Team. The Company’s cybersecurity management team assesses and manages the Company’s material risks from cybersecurity threats through or by: • active monitoring of cyber threat alerts, warnings, advisories, notices, vulnerability assessments, incident bulletins, security briefings, reports and white papers from industry and national organizations, including: downstream Natural Gas Information Sharing and Analysis Center; Electricity Information Sharing and Analysis Center; Cybersecurity and Infrastructure Security Agency; and Federal Bureau of Investigation; • threat and vulnerability management; • vendor security posture assessment; • Industrial Control System and Supervisory Control and Data Acquisition infrastructure cybersecurity protection at electric substations and natural gas plants; and • leading the Company’s Cyber Incident Response Team. In addition, the Company uses (i) a Security Operations Center vendor with 24x7 monitoring and response capabilities to identify any suspicious activity on the Company’s networks and (ii) a security consulting firm for assessments, penetration testing and incident response. In the event of a cybersecurity threat, the CISO and these parties would collaborate to assess and manage the risk with ultimate responsibility residing with the Board. Also, in the event of a cybersecurity threat or cybersecurity incident, the Company’s cybersecurity management team will investigate and perform impact analysis and, as necessary, the CISO will activate the Company’s Cyber Incident Response Team. The Cyber Incident Response Team is a subset of the Company’s Crisis Response Team, which has responsibility for operational and business resilience, as well as tactical and strategic response. A foundational aspect of the Crisis Response Team is prompt and comprehensive communications to all concerned parties, both internal and external, including direction for management to inform the Board about risks from cybersecurity threats. The Company’s determination of the materiality of a cybersecurity incident would generally include an evaluation of the incident’s effect on the Company (including (i) its business strategy, results of operations, or financial condition, (ii) the integrity, confidentiality, resiliency, and security of the Company’s networks and systems, and (iii) the Company’s operations).
Cybersecurity Risk Management Positions or Committees Responsible [Flag]	true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	The Director of Information Security and Infrastructure Operations also assumes responsibilities as the Company’s Chief Information Security Officer (CISO). The Director of Information Security and Infrastructure Operations has primary responsibility for the cybersecurity program including threat and vulnerability management, vendor security posture assessment, Industrial Control System (ICS) and SCADA infrastructure cybersecurity protection at electric substations and natural gas plants, as well as leading the Cyber Incident Response Team.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]	The Senior Vice President, Shared Services holds a Master of Business Administration and Bachelor of Arts with over 25 years of professional experience leading teams in Human Resources, Supply Chain and Information Technology. The Senior Vice President of Shared Services has overall management responsibility for the Company’s cybersecurity. The Senior Vice President of Shared Services reports to the Company’s President and Chief Administrative Officer. The Director of Information Security and Cyber Operations holds CISSP and ITIL certifications, a Bachelor of Science in Computer Science and a Master’s Certificate in Cybersecurity with a concentration in Power Systems and has over 30 years of experience in the information technology field.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]	The Cybersecurity Plan includes annual assessments using (i) the Department of Energy’s Cybersecurity Capability Maturity Model, (ii) the National Institute of Standards and Technology Cybersecurity Framework, and (iii) the Center for Internet Security Controls. The Company uses the results of these assessments to benchmark the Company’s cybersecurity posture, to identify risks from cybersecurity threats, to prioritize any such risks that may have potential material effects on the Company, and to establish effective controls to manage, mitigate and remediate such risks.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]	true

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY - USD ($) $ in Millions	Total	Common Equity	Retained Earnings
Beginning Balance at Dec. 31, 2022		$ 334.9	$ 132.5
Beginning Balance at Dec. 31, 2022	$ 467.4
Net Income	45.2		45.2
Dividends	(26.2)		(26.2)
Shares Issued Under Stock Plans	1.6	1.6
Issuance of Common Shares	1.1	1.1
Ending Balance at Dec. 31, 2023		337.6	151.5
Ending Balance at Dec. 31, 2023	489.1
Net Income	47.1		47.1
Dividends	(27.5)		(27.5)
Shares Issued Under Stock Plans	2.5	2.5
Issuance of Common Shares	1.1	1.1
Ending Balance at Dec. 31, 2024	512.5	341.2	171.1
Ending Balance at Dec. 31, 2024	512.3
Net Income	50.2		50.2
Dividends	(30.1)		(30.1)
Shares Issued Under Stock Plans	3.5	3.5
Issuance of Common Shares	73.5	73.5
Ending Balance at Dec. 31, 2025	609.6	$ 418.2	$ 191.2
Ending Balance at Dec. 31, 2025	$ 609.4

- Definition

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

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Equity impact of the value of new stock issued during the period. Includes shares issued in an initial public offering or a secondary public offering.

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Amount of equity (deficit) attributable to parent. Excludes temporary equity and equity attributable to noncontrolling interest.

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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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Reference 14: http://www.xbrl.org/2009/role/commonPracticeRef
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Reference 15: http://www.xbrl.org/2009/role/commonPracticeRef
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-URI https://asc.fasb.org/1943274/2147480418/310-10-S99-2

+ Details

Allowance for Doubtful Accounts - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Financing Receivable, Impaired [Line Items]
Recoveries	$ 0.6	$ 0.5	$ 0.6
Provision for Bad Debt	7.0	4.3	6.4
Allowance for doubtful accounts	2.2	2.4	2.4	$ 2.6
Unbilled Revenues
Financing Receivable, Impaired [Line Items]
Allowance for doubtful accounts	0.1	0.1
Accounts Receivable
Financing Receivable, Impaired [Line Items]
Allowance for doubtful accounts	2.1	2.3
Regulatory Assets Harship Accounts
Financing Receivable, Impaired [Line Items]
Recoveries	8.9	7.9
Energy Commodity
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 2.6	$ 1.6	$ 3.8

Income Taxes - Differences Between Provisions for Income Taxes and Provisions Calculated at Statutory Federal Tax Rate (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Tax Examination [Line Items]
U.S. Federal Statutory Tax Rate Amount	$ 13,754
U.S. Federal Statutory Tax Rate	21.00%	21.00%	21.00%
State Income Taxes, net of Federal Income Tax Amount	$ 4,251
State Income Taxes, net of Federal Income Tax Rate	6.50%	6.00%	6.00%
Production Tax Credit	$ (212)
Production Tax Credit Rate	(0.30%)
Regulatory Amortization of Excess ADIT	$ (2,668)
Regulatory Amortization of Excess ADIT	(4.10%)
Other Amount	$ 187
Other Rate	0.30%	1.00%	1.00%
Effective Income Tax Rate Amount	$ 15,312
Utility Plant Differences		(5.00%)	(5.00%)
Effective Income Tax Rate	23.40%	23.00%	23.00%
Tax Jurisdiction of Domicile [Extensible Enumeration]	us-gaap:ForeignCountryMember

Summary of Significant Accounting Policies - Additional Information (Details) $ / shares in Units, $ in Millions			1 Months Ended	12 Months Ended
	Oct. 31, 2025 USD ($)	Jan. 31, 2025 USD ($)	Jan. 31, 2026 $ / shares	Dec. 31, 2025 USD ($) Subsidiary Customer Megawatts mi $ / shares	Dec. 31, 2024 USD ($) Megawatts $ / shares	Dec. 31, 2023 USD ($) $ / shares	Dec. 31, 2022 USD ($)
Significant Accounting Policies [Line Items]
Length Of Pipeline \| mi				85
Cost of removal obligation				$ 153.0	$ 139.2
Regulatory assets				116.9	112.0
Investments in trading securities				$ 6.7	6.3
Number of Subsidiaries \| Subsidiary				5
Allowance for doubtful accounts				$ 2.2	$ 2.4	$ 2.4	$ 2.6
Depreciation rate based on average depreciable property balance				3.45%	3.49%	3.33%
Dividends per Common Share \| $ / shares				$ 1.8	$ 1.7	$ 1.62
Increase in dividend declared amount per share \| $ / shares			$ 1.8
Weighted average cost inventory amount				$ 1.3	$ 1.1
Average Interest Rate On Debt				5.39%	6.22%	5.48%
Net Utility Plant				$ 1,798.5	$ 1,539.6
Goodwill				4.3	0.0
Regulatory Liability				80.8	64.0
Deductible portion of goodwill				$ 0.4
Amortization period				15 years
Acquisition, Net of Cash Acquired				$ 160.4	0.0	$ 0.0
Net Income				50.2	47.1	$ 45.2
Transition Services Agreement Cost				0.2
Asset Acquisition Consideration Transferred				100.0
Cash And Cash Equivalents Acquired				70.0
Business Acquisition Liabilities Assumed				30.0
Other Deferred Charges
Significant Accounting Policies [Line Items]
Regulatory assets				12.8	14.1
Electric and Gas Division
Significant Accounting Policies [Line Items]
Business Combination, Price of Acquisition, Expected		$ 71.4
Materials And Supplies
Significant Accounting Policies [Line Items]
Weighted average cost inventory amount				15.4	14.2
Subsequent Event
Significant Accounting Policies [Line Items]
Increase in dividend declared amount per share \| $ / shares			1.9
Unbilled Revenues
Significant Accounting Policies [Line Items]
Allowance for doubtful accounts				0.1	0.1
Accounts Receivable
Significant Accounting Policies [Line Items]
Allowance for doubtful accounts				$ 2.1	$ 2.3
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				4
Fitchburg Gas and Electric Light Company
Significant Accounting Policies [Line Items]
Energy storage systems \| Megawatts				1,268	5,000
Mid-Duration Storage \| Megawatts					1,500
Fitchburg Gas and Electric Light Company \| Electric and Gas Division \| Other Deferred Charges
Significant Accounting Policies [Line Items]
Hardship accounts in regulatory assets				$ 8.9	$ 7.9
Bangor Natural Gas
Significant Accounting Policies [Line Items]
Net Utility Plant		66.7
Working Capital		3.8
Goodwill		1.6		1.6
Noncurrent assets		0.2
Regulatory Liability		$ 0.9
Operating Revenue				27.9
Net Income				$ 2.2
Maine Natural Gas Corporation
Significant Accounting Policies [Line Items]
Number of Customer \| Customer				6,300
Net Utility Plant	$ 82.0
Working Capital	7.1
Goodwill	2.7
Noncurrent assets	1.4
Regulatory Liability	3.4
Operating Revenue				$ 8.3
Acquisition, Net of Cash Acquired	86.0
Net Income				$ 2.8
Maine Natural Gas Corporation \| Materials And Supplies
Significant Accounting Policies [Line Items]
Working Capital	$ 10.4
Quarterly Payment
Significant Accounting Policies [Line Items]
Dividends per Common Share \| $ / shares				$ 0.45	$ 0.425	$ 0.405
Quarterly Payment \| Subsequent Event
Significant Accounting Policies [Line Items]
Common stock dividend paid per share \| $ / shares			0.475
Increase in dividend declared amount per share \| $ / shares			$ 0.025
Environmental and Rate Case Costs and Other Expenditures \| Recovered over the next seven years
Significant Accounting Policies [Line Items]
Regulatory assets				$ 6.5
Maximum
Significant Accounting Policies [Line Items]
Lease term				12 months
ISO-NE Obligations
Significant Accounting Policies [Line Items]
Cash Deposits				$ 8.5	$ 5.0
Deferred Compensation Plan
Significant Accounting Policies [Line Items]
Investments in trading securities				$ 3.5	$ 2.2

Summary of Significant Accounting Policies - Regulatory Assets (Detail) - USD ($)
$ in Millions

Dec. 31, 2025

Dec. 31, 2024

Regulatory Asset [Line Items]

Total Regulatory Assets

$ 116.9

$ 112.0

Less: Current Portion of Regulatory Assets

^[1]

78.1

70.1

Regulatory Assets—noncurrent

38.8

41.9

Environmental Matters

Regulatory Asset [Line Items]

Total Regulatory Assets

10.0

9.4

Other Deferred Charges

Regulatory Asset [Line Items]

Total Regulatory Assets

12.8

14.1

Retirement Benefits

Regulatory Asset [Line Items]

Total Regulatory Assets

14.6

14.4

Deferred Storm Charges

Regulatory Asset [Line Items]

Total Regulatory Assets

6.0

8.3

Income Taxes

Regulatory Asset [Line Items]

Total Regulatory Assets

0.4

Energy Supply & Other Rate Adjustment Mechanisms

Regulatory Asset [Line Items]

Total Regulatory Assets

$ 73.1

$ 65.4

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

Cover Page - USD ($)	12 Months Ended
Cover Page - USD ($)	Dec. 31, 2025	Feb. 06, 2026	Jun. 30, 2025
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, 2025
Document Fiscal Year Focus	2025
Document Fiscal Period Focus	FY
Entity Registrant Name	UNITIL CORPORATION
Entity Central Index Key	0000755001
Entity 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
Document Financial Statement Error Correction [Flag]	false
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		17,983,994
Title of 12(b) Security	Common Stock
Entity Public Float			$ 832,805,747
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 2026 Unitil Corporation Annual Meeting of Shareholders to be held on April 29, 2026 are incorporated by reference into Part III of this Report.
Auditor Name	Deloitte & Touche LLP
Auditor Firm ID	34
Auditor Location	Boston, MA
Auditor Opinion	In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO. As described in Management’s Report on Internal Control over Financial Reporting, management excluded from its assessment the internal control over financial reporting at Maine Natural Gas Corporation, which was acquired on October 31, 2025, and whose financial statements constitute approximately 4.9% and 1.5%, respectively, of the Company's consolidated total assets and revenues as of and for the year ended December 31, 2025. Accordingly, our audit of internal control over financial reporting did not include the internal control over financial reporting at Maine Natural Gas Corporation.

Retirement Benefit Plans - Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail)	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Expected Long-term rate of return on plan assets	7.50%
Benefit Plan Costs [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	5.60%	5.00%	5.25%
Rate of Compensation Increase	3.00%	3.00%	3.00%
Expected Long-term rate of return on plan assets	7.50%	7.50%	7.50%
Benefit Obligation
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	5.45%	5.60%	5.00%
Rate of Compensation Increase	3.00%	3.00%	3.00%

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
-Section 50
-Paragraph 5
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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-Paragraph 5
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Equity - Restricted Shares Issued in Conjunction with Stock Plan (Detail) - USD ($) $ in Millions	Jan. 28, 2025	Jan. 30, 2024	Jan. 24, 2023
Restricted Stock
Class of Stock [Line Items]
Issuance Date	Jan. 28, 2025	Jan. 30, 2024	Jan. 24, 2023
Restricted Stock Units Granted	26,430	22,680	18,770
Aggregate Market Value	$ 1.4	$ 1.1	$ 1.0
Performance Shares [Member]
Class of Stock [Line Items]
Issuance Date	Jan. 28, 2025	Jan. 30, 2024	Jan. 24, 2023
Restricted Stock Units Granted	26,430	22,680	18,770
Aggregate Market Value	$ 1.4	$ 1.1	$ 1.0

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

+ Details

Summary of Significant Accounting Policies - Components of Exchange Gas Receivable (Detail) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Receivables [Line Items]
Total Exchange Gas Receivable	$ 9.8	$ 6.4
Northern Utilities Inc
Receivables [Line Items]
Total Exchange Gas Receivable	8.0	6.0
Fitchburg
Receivables [Line Items]
Total Exchange Gas Receivable	0.5	0.4
Bangor Natural Gas
Receivables [Line Items]
Total Exchange Gas Receivable	$ 1.3	$ 0.0

Allowance for Doubtful Accounts

12 Months Ended

Dec. 31, 2025

Allowance For Doubtful Accounts [Abstract]

Allowance for Doubtful Accounts

Note 3: Allowance for Doubtful Accounts

Unitil’s distribution utilities which are under traditional cost of service regulation are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. In 2025, 2024 and 2023, the Company recorded provisions for the energy commodity portion of bad debts of $2.6 million, $1.6 million and $3.8 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, 2025 and 2024, the Company has recorded $8.9 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 $2.1 million and $2.3 million of the Allowance for Doubtful Accounts at December 31, 2025 and December 31, 2024, respectively. Unbilled Revenues, net (a component of Accrued Revenue) includes less than $0.1 million and $0.1 million of the Allowance for Doubtful Accounts at December 31, 2025 and December 31, 2024, respectively.

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2025, 2024 and 2023 (millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS


	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Balance at End of Period
Year Ended December 31, 2025
Electric	$	1.4	$	3.4	$	0.2	$	4.2	$	0.8
Gas		1.0		3.6		0.4		3.6		1.4
	$	2.4	$	7.0	$	0.6	$	7.8	$	2.2
Year Ended December 31, 2024
Electric	$	1.5	$	2.0	$	0.2	$	2.3	$	1.4
Gas		0.9		2.3		0.3		2.5		1.0
	$	2.4	$	4.3	$	0.5	$	4.8	$	2.4
Year Ended December 31, 2023
Electric	$	1.6	$	3.6	$	0.2	$	3.9	$	1.5
Gas		1.0		2.8		0.4		3.3		0.9
	$	2.6	$	6.4	$	0.6	$	7.2	$	2.4

Income Taxes

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Income Taxes

Note 9: 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, 2025, 2024, and 2023 are shown in the following table:


	(in millions)
	2025		2024		2023
Current Income Tax Provision
Federal	$	4.5	$	0.4	$	4.3
State		1.2		0.4		1.5
Total Current Income Taxes		5.7		0.8		5.8
Deferred Income Tax Provision
Federal		5.3		8.6		4.8
State		4.3		4.6		2.6
Total Deferred Income Taxes		9.6		13.2		7.4
Total Income Tax Expense	$	15.3	$	14.0	$	13.2

In December 2023, the FASB issued ASU 2023-09 – Income taxes: Improvements to Income Tax Disclosures which includes amendments that further enhance income tax disclosures and income taxes paid by jurisdiction. The Company has

elected to adopt ASU 2023-09 on a prospective basis. The following table presents the Company’s provisions for Income Taxes and the provisions calculated at the statutory federal tax rate for the year ended December 31, 2025:


	2025
(Dollars in thousands)	Amount			Rate
U.S. Federal Statutory Tax Rate	$	13,754			21.0	%
State Income Taxes, net of Federal Income Tax		4,251			6.5	%
Production Tax Credit		(212	)		(0.3	)%
Nontaxable and Nondeductible Items
Regulatory Amortization of Excess ADIT		(2,668	)		(4.1	)%
Other		187			0.3	%
Income Tax Expense and Effective Income Tax Rate	$	15,312			23.4	%

The differences between the Company’s provision for Income Tax and the provisions calculated at the statutory federal tax rate, expressed in percentages for the years ended December 31, 2024 and 2023, are shown in the following table:


	2024			2023
Statutory Federal Income Tax Rate		21	%		21	%
Income Tax Effects of:
State Income Taxes, net		6	%		6	%
Utility Plant Differences		(5	)%		(5	)%
Other, net		1	%		1	%
Effective Income Tax Rate		23	%		23	%

Income taxes paid, net of refunds are shown in the following table:



(in thousands)	2025
Cash Paid for Income Taxes, net of Refunds
Federal Income Taxes	$	4,218
State Income Taxes
Florida	*
Maine		—
Massachusetts		154
New Hampshire		555
Total State Income Taxes		709
Total Cash Paid for Income Taxes, net of Refunds	$	4,927
* Did not meet the 5% threshold required for separate disclosure

Temporary differences which gave rise to deferred tax assets and liabilities in 2025 and 2024 are shown in the following table:


Temporary Differences (in millions)	2025		2024
Deferred Tax Assets
Retirement Benefit Obligations	$	5.6	$	6.1
Regulatory Assets and Liabilities **		—		5.6
Net Operating Loss Carryforwards		0.2		2.3
Tax Credit Carryforwards		1.8		2.0
Other, net		6.3		2.5
Total Deferred Tax Assets		13.9		18.5
Deferred Tax Liabilities
Utility Plant Differences		208.9		203.6
Regulatory Assets and Liabilities **		0.3		—
Other, net		1.4		1.0
Total Deferred Tax Liabilities		210.6		204.6
Net Deferred Tax Liabilities	$	196.7	$	186.1

** The Company’s Net Deferred Tax Liabilities for Regulatory Assets and Liabilities are shown net. Gross Regulatory Assets were $16.8 million and $16.6 million for the years ended December 31, 2025 and 2024, respectively. Gross Regulatory Liabilities were $17.1 million and $11.0 million for the years ended December 31, 2025 and 2024, respectively.

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, 2025 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.

In August 2025, Unitil Corporation received notice that its Federal Income Tax return filing for the year ending December 31, 2023 is under examination by the IRS. Currently, the Company believes that the ultimate resolution of this examination will not have a material impact on the Company’s financial statements. The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2024; December 31, 2023; and December 31, 2022.

Income tax filings for the year ended December 31, 2024 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, 2024 which were filed with the IRS in October 2025, the Company utilized federal Net Operating Loss Carryforward (NOLC) assets of $5.6 million and $1.0 million of federal tax credit carryforward. As of December 31, 2025, the Company has fully utilized all NOLC and federal tax credits available. In addition, at December 31, 2025, the Company had $1.8 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.

On July 4, 2025, the One Big Beautiful Bill Act (OBBBA) was enacted into law. The OBBBA provided permanent and limited modifications to many provisions that had expired or would soon expire as well as eliminating many green energy provisions. The Company does not expect that the OBBBA will have a material effect on the Company's Consolidated Financial Statements.

On April 14, 2023, the IRS issued Revenue Procedure 2023-15 that provides a safe harbor method of accounting that taxpayers may use to determine whether to deduct or capitalize expenditures to repair, maintain, replace, or improve natural gas transmission and distribution property. Under the revenue procedure, the method of accounting will depend on the property’s classification as linear transmission property, linear distribution property, or non-linear property. The revenue procedure may be adopted in tax years ending after May 1, 2023. The Company elected a change in its tax accounting method on the 2023 consolidated tax return. A 481(a) adjustment was calculated and resulted in an additional $9.4 million in tax expense on the 2023 consolidated tax return.

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 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. 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, 2025, the Company flowed back $13.9 million to customers in its Massachusetts, Maine, New Hampshire and federal jurisdictions.

- Definition

The entire disclosure for income tax.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 740
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477617/942-740-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 740
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478822/944-740-50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 231
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482663/740-10-55-231

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12C
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12C

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12B

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 270
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477891/740-270-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SAB Topic 6.I.5.Q1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479360/740-10-S99-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480990/946-20-50-13

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(h)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/740/tableOfContent

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 14
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-14

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-21

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 17
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-17

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SAB Topic 11.C)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479360/740-10-S99-2

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482603/740-30-50-2

+ Details

Equity - Restricted Stock Units Issued (Detail) - Restricted Stock Units (RSUs) - $ / shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Restricted Stock Units
Beginning Restricted Stock Units	36,636	33,375
Restricted Stock Units Granted	6,818	2,215
Dividend Equivalents Earned	1,123	1,046
Restricted Stock Units Settled	(8,525)
Ending Restricted Stock Units	36,052	36,636
Beginning Restricted Stock Units Liability	15,701	14,304
Restricted Stock Units Granted	2,922	949
Dividend Equivalents Earned	481	448
Restricted Stock Units Settled	(3,654)
Ending Restricted Stock Units Liability	15,450	15,701
Weighted-Average Stock Price
Beginning Restricted Stock Units	$ 44.15	$ 42.73
Restricted Stock Units Granted	47.22	60.02
Dividend Equivalents Earned	51.87	55.77
Restricted Stock Units Settled	43.32
Ending Restricted Stock Units	45.17	44.15
Beginning Liability Weighted Average Stock Price		52.57
Restricted Stock Units Granted	47.22	60.02
Dividend Equivalents Earned	51.87	55.77
Restricted Stock Units Settled	58.97
Ending Liability Weighted Average Stock Price	$ 48.44	$ 54.19

Retirement Benefit Plans - Components of Retirement Plan Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 1,743	$ 1,990	$ 2,091
Interest Cost	8,065	7,546	7,480
Expected Return on Plan Assets	(10,497)	(10,597)	(10,689)
Prior Service Cost Amortization	255	323	356
Actuarial Loss Amortization	$ 1,277	1,446	0
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	$ 843	708	(762)
Amounts Capitalized or Deferred	181	227	1,598
NPBC Recognized	1,024	935	836
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	2,006	1,988	1,493
Interest Cost	3,967	3,269	2,899
Expected Return on Plan Assets	(4,342)	(3,877)	(3,408)
Prior Service Cost Amortization	0	0	794
Actuarial Loss Amortization	$ (747)	(874)	(1,464)
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	$ 884	506	314
Amounts Capitalized or Deferred	(135)	191	555
NPBC Recognized	749	697	869
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	158	216	250
Interest Cost	688	723	754
Expected Return on Plan Assets	0	0	0
Prior Service Cost Amortization	9	10	55
Actuarial Loss Amortization	$ 214	0	0
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	$ 641	949	1,059
Amounts Capitalized or Deferred	(203)	(295)	(327)
NPBC Recognized	$ 438	$ 654	$ 732

Activity in Company's Allowance for Doubtful Accounts (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	$ 2.4	$ 2.4	$ 2.6
Provision	7.0	4.3	6.4
Recoveries	0.6	0.5	0.6
Accounts Written Off	7.8	4.8	7.2
Balance at End of Period	2.2	2.4	2.4
Electric
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	1.4	1.5	1.6
Provision	3.4	2.0	3.6
Recoveries	0.2	0.2	0.2
Accounts Written Off	4.2	2.3	3.9
Balance at End of Period	0.8	1.4	1.5
Gas
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	1.0	0.9	1.0
Provision	3.6	2.3	2.8
Recoveries	0.4	0.3	0.4
Accounts Written Off	3.6	2.5	3.3
Balance at End of Period	$ 1.4	$ 1.0	$ 0.9

Retirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2025

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:


	2025			2024			2023
Used to Determine Plan costs for years ended December 31:
Discount Rate		5.60	%		5.00	%		5.25	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		7.50	%		7.50	%		7.50	%


	2025			2024			2023
Used to Determine Benefit Obligations at December 31:
Discount Rate		5.45	%		5.60	%		5.00	%
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
	2025			2024			2023			2025			2024			2023			2025			2024			2023

Service Cost	$	1,743		$	1,990		$	2,091		$	2,006		$	1,988		$	1,493		$	158		$	216		$	250

Interest Cost		8,065			7,546			7,480			3,967			3,269			2,899			688			723			754

Expected Return on Plan Assets		(10,497	)		(10,597	)		(10,689	)		(4,342	)		(3,877	)		(3,408	)		—			—			—

Prior Service Cost Amortization		255			323			356			—			—			794			9			10			55

Actuarial Loss Amortization		1,277			1,446			—			(747	)		(874	)		(1,464	)		(214	)		—			—

Sub-total		843			708			(762	)		884			506			314			641			949			1,059

Amounts Capitalized or Deferred		181			227			1,598			(135	)		191			555			(203	)		(295	)		(327	)

NPBC Recognized	$	1,024		$	935		$	836		$	749		$	697		$	869		$	438		$	654		$	732

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:	2025			2024			2025			2024			2025			2024

Plan Assets at Beginning of Year	$	148,974		$	137,893		$	58,402		$	51,892		$	—		$	—

Actual Return on Plan Assets		18,836			15,146			7,413			6,224			—			—

Employer Contributions		3,950			3,758			2,285			2,552			678			679

Participant Contributions		—			—			317			260			—			—

Benefits Paid		(8,462	)		(7,823	)		(2,936	)		(2,526	)		(678	)		(679	)

Plan Assets at End of Year	$	163,298		$	148,974		$	65,481		$	58,402		$	-		$	-

Change in PBO:

PBO at Beginning of Year	$	148,556		$	154,567		$	72,207		$	66,691		$	12,747		$	14,854

Service Cost		1,743			1,990			2,006			1,988			158			216

Interest Cost		8,065			7,546			3,967			3,269			688			723

Plan Amendments		604			—			—			—			—			—

Participant Contributions		—			—			317			260			—			—

Benefits Paid		(8,462	)		(7,823	)		(2,936	)		(2,526	)		(678	)		(679	)

Actuarial (Gain) or Loss		2,829			(7,724	)		9,987			2,525			589			(2,367	)

PBO at End of Year	$	153,335		$	148,556		$	85,548		$	72,207		$	13,504		$	12,747

Funded Status: Assets vs PBO	$	9,963		$	418		$	(20,067	)	$	(13,805	)	$	(13,504	)	$	(12,747	)

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
	2025		2024		2023		2025		2024		2023			2025		2024		2023
Employer Contributions	$	3,950	$	3,758	$	3,850	$	2,285	$	2,552	$	2,790		$	678	$	679	$	665
Participant Contributions	$	—	$	—	$	—	$	317	$	260	$	234		$	—	$	—	$	—
Benefit Payments	$	8,462	$	7,823	$	8,877	$	2,936	$	2,526	$	(2,767	)	$	678	$	679	$	665

Estimated Future Benefit Payments

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


Estimated Future Benefit Payments
	Pension		PBOP		SERP
2026	$	9,244	$	4,142	$	678
2027		10,322		4,369		677
2028		10,396		4,587		1,190
2029		10,732		5,046		1,181
2030		11,313		5,159		1,172
2031-2035		57,726		26,363		5,658

Pension Plans

Schedule of Allocation of Plan Assets

The actual investment allocations are shown in the following tables.


Pension Plan	Target Allocation			Actual Allocation at December 31,
	2026			2025			2024			2023
Equity Funds		49	%		49	%		53	%		57	%
Debt Funds		45	%		45	%		41	%		36	%
Real Estate Fund		6	%		6	%		5	%		6	%
Other(1)		—			—	%		1	%		1	%
Total					100	%		100	%		100	%

Represents investments being held in cash equivalents as of December 31, 2025, December 31, 2024 and December 31, 2023 pending payment of benefits.

Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2025 and 2024 are as follows (000’s):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2025
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	80,722	$	80,722	$	—	$	—
Fixed Income Funds		72,837		72,837		—		—
Total Mutual Funds		153,559		153,559		—		—
Cash Equivalents		392		392
Total Assets in the Fair Value Hierarchy	$	153,951	$	153,951	$	—	$	—
Real Estate Fund–Measured at Net Asset Value		9,347
Total Assets	$	163,298
2024
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	78,407	$	78,407	$	—	$	—
Fixed Income Funds		61,741		61,741		—		—
Total Mutual Funds		140,148		140,148		—		—
Cash Equivalents		1,504		1,504
Total Assets in the Fair Value Hierarchy	$	141,652	$	141,652	$	—	$	—
Real Estate Fund–Measured at Net Asset Value		7,322
Total Assets	$	148,974

Retirement Benefits

Schedule of Allocation of Plan Assets

The actual investment allocations are shown in the following tables.


PBOP Plan	Target Allocation			Actual Allocation at December 31,
	2026			2025			2024			2023
Equity Funds		55	%		56	%		56	%		56	%
Debt Funds		45	%		44	%		44	%		44	%
Total					100	%		100	%		100	%

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2025 and 2024 are as follows (000’s):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2025
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	28,765	$	28,765	$	—	$	—
Equity Funds		36,716		36,716		—		—
Total Assets	$	65,481	$	65,481	$	—	$	—

2024
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	25,908	$	25,908	$	—	$	—
Equity Funds		32,494		32,494		—		—
Total Assets	$	58,402	$	58,402	$	—	$	—

Debt and Financing Arrangements (Tables)

12 Months Ended

Dec. 31, 2025

Details on Long Term Debt

Details on long-term debt at December 31, 2025 and 2024 are shown below:


	December 31,
Long-Term Debt (millions)	2025		2024
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
5.99% Senior Notes, Due August 21, 2034		20.0		20.0
Unitil Energy First Mortgage Bonds:
6.96% Senior Secured Notes, Due September 1, 2028		6.0		8.0
8.00% Senior Secured Notes, Due May 1, 2031		9.0		10.5
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
5.69% Senior Secured Notes, Due August 21, 2054		40.0		40.0
Fitchburg:
3.52% Senior Notes, Due November 1, 2027		10.0		10.0
7.37% Senior Notes, Due January 15, 2029		4.8		6.0
5.90% Senior Notes, Due December 15, 2030		15.0		15.0
7.98% Senior Notes, Due June 1, 2031		14.0		14.0
5.70% Senior Notes, Due July 2, 2033		12.0		12.0
5.54% Senior Notes, Due August 21, 2034		12.5		12.5
3.78% Senior Notes, Due September 15, 2040		27.5		27.5
5.99% Senior Notes, Due August 21, 2044		12.5		12.5
4.32% Senior Notes, Due November 1, 2047		15.0		15.0
5.96% Senior Notes, Due July 2, 2053		13.0		13.0
Northern Utilities:
3.52% Senior Notes, Due November 1, 2027		20.0		20.0
5.54% Senior Notes, Due August 21, 2034		25.0		25.0
7.72% Senior Notes, Due December 3, 2038		50.0		50.0
5.74% Senior Notes, Due August 21, 2039		15.0		15.0
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
Bangor:
5.70% Senior Notes, Due July 8, 2030		14.0		—
6.31% Senior Notes, Due July 8, 2035		18.0		—
Granite State:
3.72% Senior Notes, Due November 1, 2027		15.0		15.0
5.74% Senior Notes, Due August 21, 2034		10.0		10.0
Unitil Realty Corp.:
2.64% Senior Secured Notes, Due December 18, 2030		3.5		3.8
Total Long-Term Debt		674.3		647.3
Less: Unamortized Debt Issuance Costs		3.8		4.0
Total Long-Term Debt, net of Unamortized Debt Issuance Costs		670.5		643.3
Less: Current Portion(1)		37.9		4.9
Total Long-Term Debt, Less Current Portion	$	632.6	$	638.4

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)	2025		2024
Estimated Fair Value of Long-Term Debt	$	623.4	$	598.9

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)	2025			2024			2023
Interest Expense
Long-Term Debt	$	33.3		$	27.8		$	24.7
Short-Term Debt		8.5			8.4			9.2
Regulatory Liabilities & Other		2.0			1.5			1.0
Subtotal Interest Expense		43.8			37.7			34.9
Interest Income
Regulatory Assets		(3.5	)		(4.1	)		(3.3	)
AFUDC(1) and Other		(3.6	)		(4.3	)		(2.9	)
Subtotal Interest Income		(7.1	)		(8.4	)		(6.2	)
Total Interest Expense, Net	$	36.7		$	29.3		$	28.7

(1)

AFUDC—Allowance for Funds Used During Construction

Borrowing Limits Amounts Outstanding and Amounts Available under Credit Facility


	December 31,
Revolving Credit Facility (millions)	2025		2024
Limit	$	275.0	$	200.0
Short-Term Borrowings Outstanding	$	169.7	$	105.8
Available	$	105.3	$	94.2

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

The following table lists the Company’s contractual obligations for long-term debt as of December 31, 2025.


			Payments Due by Period
Long-Term Debt Contractual Obligations (millions) as of December 31, 2025	Total		2026		2027		2028		2029		2030		2031 & Beyond
Long-Term Debt	$	674.3	$	37.9	$	55.7	$	10.7	$	43.7	$	26.5	$	499.8
Interest on Long-Term Debt		435.2		33.7		31.9		29.6		28.9		26.9		284.2
Total	$	1,109.5	$	71.6	$	87.6	$	40.3	$	72.6	$	53.4	$	784.0

Classification of the Company Lease Obligations

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


	December 31,
Lease Obligations (millions)	2025		2024
Operating Lease Obligations:
Operating Lease Obligations (current portion)	$	2.1	$	1.8
Operating Lease Obligations (long-term portion)		4.9		4.9
Total Operating Lease Obligations		7.0		6.7
Capital Lease Obligations:
Other Current Liabilities (current portion)		0.2		0.1
Other Noncurrent Liabilities (long-term portion)		0.4		0.4
Total Capital Lease Obligations		0.6		0.5
Total Lease Obligations	$	7.6	$	7.2

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, 2025. The payments for operating leases consist of $2.1 million of current operating lease obligations and $4.9 million of noncurrent operating lease obligations on the Company’s Consolidated Balance Sheets as of December 31, 2025. The payments for capital leases consist of $0.2 million of current Capital Lease Obligations, which are included in Other Current Liabilities, and $0.4 million of noncurrent Capital Lease Obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2025.


Lease Payments ($000’s) Year Ending December 31,	Operating Leases		Capital Leases
2026	$	2,439	$	208
2027		2,070		208
2028		1,520		112
2029		1,150		89
2030		478		42
2031-2035		161		—
Total Payments		7,818		659
Less: Interest		771		57
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$	7,047	$	602

- Definition

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

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(22))
-SubTopic 10
-Topic 210
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480566/210-10-S99-1

Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477314/942-235-S99-2

Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 4
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-4

Reference 4: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.12-04(a))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-3

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 69B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481568/470-20-55-69B

Reference 6: http://www.xbrl.org/2003/role/exampleRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 69E
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481568/470-20-55-69E

Reference 7: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 835
-SubTopic 30
-Name Accounting Standards Codification
-Section 45
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482925/835-30-45-2

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-3

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477734/942-470-50-3

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-8

Reference 11: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-6

Reference 12: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-7

+ Details

Insider Trading Arrangements	3 Months Ended
Insider Trading Arrangements	Dec. 31, 2025
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Equity

12 Months Ended

Dec. 31, 2025

Equity [Abstract]

Equity

Note 5: Equity

The Company has common stock outstanding and one of the Company’s 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 17,919,191 and 16,192,345 shares of common stock outstanding at December 31, 2025 and December 31, 2024, respectively. The Company has 25,000,000 shares of common stock authorized as of December 31, 2025 and December 31, 2024.

The following table summarizes the Company’s common shares activity for the year ended December 31, 2025:


Common Stock	Shares
Shares as of December 31, 2024		16,192,345
Shares Issued - Equity Issuance		1,602,358
Shares Issued - ATM		27,620
Shares Issued - DRP		21,519
Shares Issued - Directors		14,610
Shares Issued - RSU Settlement		8,525
Shares Issued - Time Restricted		26,430
Shares Issued - Performance Restricted		26,430
Forfeited Shares - Time Restricted		(396	)
Forfeited Shares - Performance Restricted		(250	)
Shares as of December 31, 2025		17,919,191

Unitil Corporation Underwritten Common Stock Offering—On August 18, 2025, the Company issued and sold 1,602,358 shares of its common stock at a price of $46.65 per share in an underwritten registered public offering (Offering). The Company’s net increase to Common Equity and Cash proceeds from the Offering was approximately $71.8 million. The proceeds will be used to make equity capital contributions to the Company’s regulated utility subsidiaries, to repay debt and for other general corporate purposes. Overall, the results of operations and earnings in 2025 reflect the higher number of average shares outstanding.

At-the-Market Equity Offering Program—On June 3, 2025, the Company entered into an at-the-market equity offering program (ATM program) with sales agents under which the Company may, from time to time, offer and sell shares of its common stock having an aggregate offering price of up to $50 million. Sales of common stock under the ATM program are made pursuant to a shelf registration statement on Form S-3 (File No. File No. 333-287753) and a related prospectus supplement filed with the Securities and Exchange Commission.

During the year ended December 31, 2025, the Company sold 27,620 shares of common stock under the ATM program at an average price of $53.00 per share, resulting in gross proceeds of $1.5 million and net proceeds of $1.4 million after deducting commissions and offering expenses. As of December 31, 2025, $48.5 million remains available for future sales under the program.

The Company intends to use the net proceeds from the ATM program for general corporate purposes, including capital contributions to the Company's utility subsidiaries, repayment of debt, acquisitions, capital expenditures and working capital, as described in the prospectus supplement relating to the ATM program.

Dividend Reinvestment and Stock Purchase Plan—During 2025, the Company sold 21,519 shares of its common stock, at an average price of $51.83 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $1.1 million. The DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock.

During 2024 and 2023, the Company raised $1.1 million and $1.1 million, respectively, through the issuance of 19,510 and 21,321 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 (trading plan), until October 3, 2024, the Company periodically repurchased shares of its common stock on the open market related to the stock portion of the annual retainer for the members of the Company’s Board of Directors. Until December 1, 2018, the Company also periodically repurchased shares of its common stock on the open market related to Employee Length of Service Awards. On May 31, 2024, the Company’s 2023 trading plan terminated in accordance with its terms. The Company did not adopt a new written trading plan under Rule 10b5-1 and does not anticipate doing so in the near term. (See Part II, Item 5, for additional information). During 2025, 2024 and 2023, the Company repurchased zero, zero and 14,680 shares of its common stock, respectively, pursuant to the Rule 10b5-1 trading plan. The expense recognized by the Company for these repurchases was zero, zero, and $0.6 million in 2025, 2024 and 2023, respectively.

During 2025, 2024 and 2023, 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.

The Company maintains the Unitil Corporation Third Amended and Restated 2003 Stock Plan (as amended, the “Stock Plan”). Participants in the Stock Plan are selected by the Compensation Committee of the Board of Directors to receive awards under the Stock Plan, including: (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 and May 1, 2024, the Company’s shareholders approved amendments to the Stock Plan to, among other things, increase the maximum number of shares of common stock available for awards to plan participants.

The maximum number of shares available for awards to participants under the Stock Plan was 677,500 as of March 31, 2024, and was increased on May 1, 2024 to 1,027,500. The maximum number of shares that may be awarded in any one calendar year to any one participant is 20,000. 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 in the years ended 2023, 2024, and 2025 in conjunction with the Stock Plan are presented in the following table:


Issuance Date	Shares	Aggregate Market Value (millions)
1/24/2023	18,770	$1.0
1/30/2024	22,680	$1.1
1/28/2025	26,430	$1.4

The compensation expense associated with the issuance of Time Restricted Shares under the Stock Plan is being recorded over the vesting period and was $1.9 million, $1.4 million and $1.4 million in 2025, 2024 and 2023, respectively. At December 31, 2025, 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 2.6 years. During 2025, there were 396 Time Restricted Shares forfeited and zero Time Restricted Shares cancelled under the Stock Plan. On January 27, 2026, there were 32,330 Time Restricted Shares issued under the Stock Plan with an aggregate market value of $1.6 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.

Performance Restricted Shares issued in the years ended 2023, 2024 and 2025 in conjunction with the Stock Plan are presented in the following table:


Issuance Date	Shares	Aggregate Market Value (millions)
1/24/2023	18,770	$1.0
1/30/2024	22,680	$1.1
1/28/2025	26,430	$1.4

The compensation expense associated with the issuance of Performance Restricted Shares under the Stock Plan is being recognized over the vesting period and was $1.4 million, $1.0 million and $0.5 million in 2025, 2024 and 2023, respectively. At December 31, 2025, there was approximately $1.7 million of total unrecognized compensation cost for Performance Restricted Shares under the Stock Plan which is expected to be recognized over approximately 1.7 years. During 2025, there were 250 Performance Restricted Shares forfeited and zero Performance Restricted Shares cancelled under the Stock Plan. On January 27, 2026, there were 32,330 Performance Restricted Shares issued under the Stock Plan with an aggregate market value of $1.6 million.

The Time Restricted Shares and Performance Restricted Shares unvested activity during the year ended December 31, 2025 in conjunction with the Stock Plan is presented in the following table:


Restricted Shares	Time Restricted Shares					Performance Restricted Shares
	Units			Weighted Average Stock Price		Units			Weighted Average Stock Price
Restricted Shares as of December 31, 2024		19,933		$	48.09		41,200		$	50.28
Granted		26,430		$	52.65		26,430		$	52.65
Shares Issued		(28,084	)	$	50.58		—		$	—
Forfeited		(396	)	$	47.42		(250	)	$	50.35
Restricted Shares as of December 31, 2025		17,883		$	50.94		67,380		$	51.21

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 and liability portions of Restricted Stock Units activity during 2025 and 2024 in conjunction with the Stock Plan are presented in the following table:


Restricted Stock Units	(Equity Portion)					(Liability Portion)
	Units			Weighted Average Stock Price		Units			Weighted Average Stock Price
Restricted Stock Units as of December 31, 2023		33,375		$	42.73		14,304		$	52.57
Restricted Stock Units Granted		2,215		$	60.02		949		$	60.02
Dividend Equivalents Earned		1,046		$	55.77		448		$	55.77
Restricted Stock Units as of December 31, 2024		36,636		$	44.15		15,701		$	54.19
Restricted Stock Units Granted		6,818		$	47.22		2,922		$	47.22
Dividend Equivalents Earned		1,123		$	51.87		481		$	51.87
Restricted Stock Units Settled		(8,525	)	$	43.32		(3,654	)	$	58.97
Restricted Stock Units as of December 31, 2025		36,052		$	45.17		15,450		$	48.44

Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2025 and 2024 include $0.7 million and $0.9 million, respectively, representing the fair value of liabilities associated with the portion of fully vested RSUs that will be settled in cash.

Directors Stock

Members of the Company’s Board of Directors who do not elect to receive Restricted Stock Units are issued shares of common stock. During the year ended December 31, 2025, 14,610 shares of common stock were issued to Directors.

Preferred Stock

There were $0.2 million, or 1,727 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of December 31, 2025 and December 31, 2024. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the twelve month periods ended December 31, 2025 and December 31, 2024, respectively.

Earnings Per Share

Unitil has granted restricted stock awards and restricted stock units with non-forfeitable dividend rights, which are considered participating securities. Accordingly, earnings per share are computed using the two-class method as required by FASB ASC 260-10-45. Basic earnings per common share is calculated by dividing net income allocated to common shareholders by the weighted average number of common shares outstanding during the period, which excludes the participating securities. Diluted earnings per common share are adjusted for the dilutive effects of restricted stock.

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


Earnings Per Share (millions, except shares and per share data)	2025		2024		2023
Net Income	$	50.2	$	47.1	$	45.2
Less allocation of earnings and dividends to participating securities		0.3		—		—
Net income allocated to common shareholders	$	49.9	$	47.1	$	45.2

Weighted average common shares outstanding, gross		16,886,642		16,098,267		16,045,300
Less average participating securities		100,561		—		—
Weighted average number of shares outstanding used in the calculation of basic earnings per share		16,786,081		16,098,267		16,045,300
Add dilutive effect of:
Restricted stock and restricted stock units		1,672		10,803		7,447
Adjusted weighted average number of shares outstanding used in the calculation of diluted earnings per common share		16,787,753		16,109,070		16,052,747

Earnings per common share:
Basic	$	2.97	$	2.93	$	2.82
Diluted	$	2.97	$	2.93	$	2.82

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.


	2025		2024		2023
Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation		100,561		6,675		12,204

- Definition

The entire disclosure for equity.

+ References

+ Details

Summary of Significant Accounting Policies - Fair Value of Marketable Securities (Detail) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	$ 6.7	$ 6.3
Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	3.5	2.2
Fair Value, Inputs, Level 1
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	6.7	6.3
Fair Value, Inputs, Level 1 \| Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	3.5	2.2
Fair Value, Inputs, Level 1 \| Equity Funds \| Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	3.1	2.0
Fair Value, Inputs, Level 1 \| Money Market Funds
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	3.2	2.5
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	0.1
Fair Value, Inputs, Level 1 \| Fixed Income Funds
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	3.5	3.8
Fair Value, Inputs, Level 1 \| Fixed Income Funds \| Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	$ 0.3	$ 0.1

Retirement Benefit Plans - Summary of Information on Plans' Assets, Projected Benefit Obligations (PBO), and Funded Status (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	$ 148,974	$ 137,893
Actual Return on Plan Assets	18,836	15,146
Employer Contributions	3,950	3,758	$ 3,850
Participant Contributions	0	0
Benefits Paid	(8,462)	(7,823)
Plan Assets at End of Year	163,298	148,974	137,893
PBO at Beginning of Year	148,556	154,567
Service Cost	1,743	1,990	2,091
Interest Cost	8,065	7,546	7,480
Plan Amendments	604	0
Benefits Paid	(8,462)	(7,823)	(8,877)
Actuarial (Gain) or Loss	2,829	(7,724)
PBO at End of Year	153,335	148,556	154,567
Funded Status: Assets vs PBO	9,963	418
Retirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	58,402	51,892
Actual Return on Plan Assets	7,413	6,224
Employer Contributions	2,285	2,552	2,790
Participant Contributions	317	260
Benefits Paid	(2,936)	(2,526)
Plan Assets at End of Year	65,481	58,402	51,892
PBO at Beginning of Year	72,207	66,691
Service Cost	2,006	1,988	1,493
Interest Cost	3,967	3,269	2,899
Plan Amendments	0	0
Benefits Paid	(2,936)	(2,526)	(2,767)
Actuarial (Gain) or Loss	9,987	2,525
PBO at End of Year	85,548	72,207	66,691
Funded Status: Assets vs PBO	(20,067)	(13,805)
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	0	0
Actual Return on Plan Assets	0	0
Employer Contributions	678	679	665
Participant Contributions	0	0
Benefits Paid	(678)	(679)
Plan Assets at End of Year	0	0	0
PBO at Beginning of Year	12,747	14,854
Service Cost	158	216	250
Interest Cost	688	723	754
Plan Amendments	0	0
Benefits Paid	(678)	(679)	(665)
Actuarial (Gain) or Loss	589	(2,367)
PBO at End of Year	13,504	12,747	$ 14,854
Funded Status: Assets vs PBO	$ (13,504)	$ (12,747)

Income Taxes - Provisions for Federal and State Income Taxes (Detail) - USD ($) $ in Millions		12 Months Ended
	Apr. 14, 2023	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Current Income Tax Provision
Federal		$ 4.5	$ 0.4	$ 4.3
State		1.2	0.4	1.5
Total Current Income Taxes		5.7	0.8	5.8
Deferred Income Tax Provision
Federal		5.3	8.6	4.8
State		4.3	4.6	2.6
Total Deferred Income Taxes		9.6	13.2	7.4
Total Income Tax Expense	$ 9.4	$ 15.3	$ 14.0	$ 13.2

- Definition

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

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+ Details

Derivatives

12 Months Ended

Dec. 31, 2025

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

Note 7: Derivatives

In 2018, Fitchburg entered into a long-term power purchase agreement (PPA) with H.Q. Energy Services (U.S.) Inc. (HQUS) to procure bundled clean energy and associated environmental attributes pursuant to Section 83D of “An Act to Promote Energy Diversity” (2016). The PPA requires Fitchburg to purchase specified quantities of electric energy over the 20-year contract term and provides for the transfer of associated environmental attributes. (See Note 8 Commitments and Contingencies: Fitchburg - Massachusetts Request for Proposals.)

During 2025, based on the status of the NECEC Transmission Line and the Company’s assessment that the contingency related to the commencement of deliveries was substantially resolved as of December 31, 2025, the Company concluded that the PPA met the definition of a derivative. The Company evaluated the PPA under ASC 815 and concluded that (i) the host contract includes environmental attributes that do not meet the definition of a derivative and (ii) the PPA contains an embedded derivative related to the energy component that requires bifurcation.

The Company has not designated the derivative as a hedging instrument. Additionally, the derivative does not qualify for the normal purchase normal sale scope exception. Accordingly, the Company accounts for the embedded energy derivative at fair value, with subsequent changes in fair value recognized as a regulatory offset. Please see Note 1 (Summary of Significant Accounting Policies - Derivatives) for a discussion of the Company’s regulatory accounting treatment of derivatives.

The PPA provides a bundled price for energy and environmental attributes. In connection with bifurcation and fair value measurement of the embedded energy derivative, the Company applied an allocation approach to separate the embedded energy derivative from the non-derivative environmental attribute component. The fair value of the embedded energy derivative is estimated using a discounted cash flow model that compares forward market prices to the adjusted fixed price for the energy component of the PPA, multiplied by expected delivery volumes, and discounted using a rate that reflects the relevant counterparty’s credit risk. Observable inputs include on-peak and off-peak forward electricity prices and the Company incorporates an adjustment to estimate the pricing through the term of the PPA. As of December 31, 2025, the Company classified the embedded derivative within Level 3 of the fair value hierarchy due to the use of significant unobservable inputs in estimating the value of the embedded derivative. Please also see Note 1 (Summary of Significant Accounting Policies) for a discussion of the Company’s fair value accounting policy.

The fair value of the derivative was $17.7 million as of December 31, 2025, with $2.8 million recorded in Prepayments and Other related to the current portion and $14.9 million in Other Assets related to the noncurrent portion. The Company has recorded corresponding Current and Noncurrent Regulatory Liabilities related to the fair value of the derivative. No derivative assets or liabilities were recognized as of December 31, 2024. The Company does not offset derivative assets and liabilities in the balance sheet.

The Company entered into a long-term energy procurement arrangement primarily to comply with regulatory clean energy requirements. The Company does not enter into such arrangements for trading or speculative purposes.

The Company is exposed to credit risk related to possible nonperformance by its counterparty. The Company manages this risk through ongoing credit monitoring and, as applicable, the use of collateral or other credit enhancements.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

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+ Details

Debt and Financing Arrangements - Additional Information (Detail) - USD ($) $ in Millions			12 Months Ended
	Oct. 31, 2025	Sep. 29, 2022	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Jul. 08, 2025	Jan. 31, 2025	Jan. 29, 2025	Aug. 21, 2024
Line of Credit Facility [Line Items]
Issuance of long-term debt									$ 1.0
Description of variable rate basis	The facility provides that the Company has an option for determining whether interest on loans under the facility will bear interest based on a Base Rate plus an applicable margin of 0.25% or based on a one month Term SOFR plus a SOFR adjustment of 0.10% plus an applicable margin of 1.25%. The Base Rate is equal to the highest of the (a) Federal Funds Rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by The Bank of Nova Scotia as its "prime rate", or (c) one month Term SOFR plus a SOFR adjustment of 0.10% plus 1.00%.
Weighted average interest rate on short term borrowings			5.40%	6.50%	6.40%
Total rental expense under operating leases			$ 2.3	$ 2.2	$ 2.1
Accounts Payable			62.9	49.7
Operating lease obligations			2.3	2.2
Debt instrument due date	Oct. 31, 2026
Net Utility Plant			1,798.5	1,539.6
Operating Lease Obligations			2.1	1.8
Operating Lease Obligations			$ 4.9	$ 4.9
Operating lease, weighted average remaining lease term			3 years 9 months 18 days	4 years 2 months 12 days
Operating lease, weighted average discount rate percentage			5.30%	5.10%
Guarantees outstanding			$ 50.3
Restriction on retained earnings for dividend payments			Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2025 for the payment of dividends.
Amount available for the payment of dividends			$ 318.5
Retained Earnings			191.2	$ 171.1
Long term debt repayments			4.9	4.9	6.9
Other Current Liabilities (current portion)			0.2	0.1
Finance Lease Liability Noncurrent			0.4	0.4
Subsidiaries [Member]
Line of Credit Facility [Line Items]
Amount available for the payment of dividends			563.1
Credit Facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility		$ 75.0
Credit Facility [Member] \| Third Amendment Credit Facility Member [Member]
Line of Credit Facility [Line Items]
Revolving credit facility			200.0					$ 275.0
Sublimit for the issuance of standby letters of credit		$ 25.0
Bonds [Member]
Line of Credit Facility [Line Items]
Long term debt repayments			4.9	4.9	$ 6.9
Debt repayment, 2026			37.9
Debt repayment, 2027			55.7
Debt repayment, 2028			10.7
Debt repayment, 2029			43.7
Debt repayment, 2030			26.5
Debt repayment, Thereafter			499.8
Base Rate [Member]
Line of Credit Facility [Line Items]
Debt instrument variable interest rate additional spread	0.25%
Secured Overnight Financing Rate (SOFR) [Member]
Line of Credit Facility [Line Items]
Credit facility, daily fluctuating rate of interest	0.10%
Debt instrument variable interest rate additional spread	1.25%
Fed Funds Effective Rate Overnight Index Swap Rate [Member]
Line of Credit Facility [Line Items]
Credit facility, daily fluctuating rate of interest	0.50%
Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility			275.0	200.0
Proceeds from lines of credit			476.4	308.4
Repayments of lines of credit			$ 412.5	364.6
Revolving Credit Facility \| 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.
Natural gas storage inventory			$ 9.3
Senior Unsecured Delayed Draw Term Loan Facility [Member]
Line of Credit Facility [Line Items]
Acquisition amount	$ 86.0
Northern Utilities Inc
Line of Credit Facility [Line Items]
Accounts Payable			$ 3.0
Total funded indebtedness as percentage of capitalization			65.00%
Northern Utilities Inc \| 5.54% Senior Note Due to 2034
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount									$ 25.0
Long-term debt, stated interest rate									5.54%
Northern Utilities Inc \| 5.74% Senior Note Due to 2039
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount									$ 15.0
Long-term debt, stated interest rate									5.74%
Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization			65.00%
Granite State Gas Transmission Inc \| 5.74% Senior Note Due to 2034
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount									$ 10.0
Long-term debt, stated interest rate									5.74%
Fitchburg Gas and Electric Light Company \| 5.70 % Senior Note Due to July 2, 2033
Line of Credit Facility [Line Items]
Debt instrument due date			Jul. 02, 2033
Long-term debt, stated interest rate			5.70%
Fitchburg Gas and Electric Light Company \| 5.96% Senior Note Due to July 2, 2053
Line of Credit Facility [Line Items]
Debt instrument due date			Jul. 02, 2053
Long-term debt, stated interest rate			5.96%
Fitchburg Gas and Electric Light Company \| 5.54% Senior Note Due to 2034
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount									$ 12.5
Long-term debt, stated interest rate									5.54%
Fitchburg Gas and Electric Light Company \| 5.99% Senior Note Due to 2044
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount									$ 12.5
Long-term debt, stated interest rate									5.99%
Unitil Corporation \| Maximum
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization			70.00%
Unitil Corporation \| 5.99% Senior Note Due to 2034
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount									$ 20.0
Long-term debt, stated interest rate									5.99%
Bangor Natural Gas
Line of Credit Facility [Line Items]
Issuance of long-term debt						$ 0.2
Net Utility Plant							$ 66.7
Bangor Natural Gas \| 6.31 % Senior Note Due to 2035
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount						$ 18.0
Long-term debt, stated interest rate						6.31%
Bangor Natural Gas \| 5.70 % Senior Note Due to 2030
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount						$ 14.0
Long-term debt, stated interest rate						5.70%
Unitil Energy Systems Inc \| 5.69% Senior Note Due to 2054
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount									$ 40.0
Long-term debt, stated interest rate									5.69%
Secured Overnight Financing Rate [Member] \| Revolving Credit Facility \| Credit Facility [Member] \| Third Amendment Credit Facility Member [Member]
Line of Credit Facility [Line Items]
Credit facility, daily fluctuating rate of interest		0.00001%
Secured Overnight Financing Rate [Member] \| Revolving Credit Facility \| Credit Facility [Member] \| Third Amendment Credit Facility Member [Member] \| Maximum
Line of Credit Facility [Line Items]
Debt instrument variable interest rate additional spread		1.375%
Secured Overnight Financing Rate [Member] \| Revolving Credit Facility \| Credit Facility [Member] \| Third Amendment Credit Facility Member [Member] \| Minimum
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			$ 0.9	0.6
Net Utility Plant, accumulated amortization			$ 0.3	$ 0.1

CONSOLIDATED STATEMENTS OF EARNINGS - USD ($) $ in Millions	12 Months Ended
CONSOLIDATED STATEMENTS OF EARNINGS - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Operating Revenues:
Total Operating Revenues	$ 536.0	$ 494.8	$ 557.1
Operating Expenses:
Operation and Maintenance	92.5	77.6	75.6
Depreciation and Amortization	88.7	76.1	67.4
Taxes Other Than Income Taxes	31.3	29.9	28.5
Total Operating Expenses	434.8	404.2	470.0
Operating Income	101.2	90.6	87.1
Interest Expense, Net	36.7	29.3	28.7
Other Expense (Income), Net	(1.0)	0.2	0.0
Income Before Income Taxes	65.5	61.1	58.4
Provision for Income Taxes	15.3	14.0	13.2
Net Income Applicable to Common Shares	$ 50.2	$ 47.1	$ 45.2
Earnings per Common Share - Basic	$ 2.97	$ 2.93	$ 2.82
Earnings per Common Share - Diluted	$ 2.97	$ 2.93	$ 2.82
Weighted Average Common Shares Outstanding - Basic	16,786,081	16,098,267	16,045,300
Weighted Average Common Shares Outstanding - Diluted	16,787,753	16,109,070	16,052,747
Electric
Operating Revenues:
Total Operating Revenues	$ 236.4	$ 248.3	$ 306.5
Operating Expenses:
Cost of Electric Sales	121.8	141.0	202.4
Gas
Operating Revenues:
Total Operating Revenues	299.6	246.5	250.6
Operating Expenses:
Cost of Electric Sales	$ 100.5	$ 79.6	$ 96.1

Retirement Benefit Plans

12 Months Ended

Dec. 31, 2025

Retirement Benefits [Abstract]

Retirement Benefit Plans

Note 10: 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:


	2025			2024			2023
Used to Determine Plan costs for years ended December 31:
Discount Rate		5.60	%		5.00	%		5.25	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		7.50	%		7.50	%		7.50	%


	2025			2024			2023
Used to Determine Benefit Obligations at December 31:
Discount Rate		5.45	%		5.60	%		5.00	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%

The health care cost trend rate used to determine plan costs for 2025 for pre-65 retirees is 8.50%, with an ultimate rate of 4.50% in 2034, and for post-65 retirees, the health care cost trend rate is 7.50%, with an ultimate rate of 4.50% in 2034. The health care cost trend rate used to determine plan costs for 2024 for pre-65 retirees was 8.00%, with an ultimate rate of 4.50% in 2033, and for post-65 retirees, the health care cost trend rate was 6.00%, with an ultimate rate of 4.50% in 2033. The health care cost trend rate used to determine plan costs for 2023 for pre-65 retirees was 8.00%, with an ultimate rate of 4.50% in 2030, and for post-65 retirees was 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, 2025 for pre-65 retirees is 8.05%, with an ultimate rate of 4.50% in 2034, and for post-65 retirees, the health care cost trend rate is 7.15%, with an ultimate rate of 4.50% in 2034. The health care cost trend rate used to determine benefit obligations at December 31, 2024 for pre-65 retirees was 8.50%, with an ultimate rate of 4.50% in 2034, and for post-65 retirees, the health care cost trend rate was 7.50%, with an ultimate rate of 4.50% in 2034. The health care cost trend rate used to determine benefit obligations at December 31, 2023 for pre-65 retirees was 8.00%, with an ultimate rate of 4.50% in 2033, and for post-65 retirees, the health care cost trend rate was 6.00%, with an ultimate rate of 4.50% in 2033.

The 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 2025, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $428,700 in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2025 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
	2025			2024			2023			2025			2024			2023			2025			2024			2023

Service Cost	$	1,743		$	1,990		$	2,091		$	2,006		$	1,988		$	1,493		$	158		$	216		$	250

Interest Cost		8,065			7,546			7,480			3,967			3,269			2,899			688			723			754

Expected Return on Plan Assets		(10,497	)		(10,597	)		(10,689	)		(4,342	)		(3,877	)		(3,408	)		—			—			—

Prior Service Cost Amortization		255			323			356			—			—			794			9			10			55

Actuarial Loss Amortization		1,277			1,446			—			(747	)		(874	)		(1,464	)		(214	)		—			—

Sub-total		843			708			(762	)		884			506			314			641			949			1,059

Amounts Capitalized or Deferred		181			227			1,598			(135	)		191			555			(203	)		(295	)		(327	)

NPBC Recognized	$	1,024		$	935		$	836		$	749		$	697		$	869		$	438		$	654		$	732

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. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2025, 2024 and 2023 would have been ($0.5) million, $1.8 million and $2.8 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:	2025			2024			2025			2024			2025			2024

Plan Assets at Beginning of Year	$	148,974		$	137,893		$	58,402		$	51,892		$	—		$	—

Actual Return on Plan Assets		18,836			15,146			7,413			6,224			—			—

Employer Contributions		3,950			3,758			2,285			2,552			678			679

Participant Contributions		—			—			317			260			—			—

Benefits Paid		(8,462	)		(7,823	)		(2,936	)		(2,526	)		(678	)		(679	)

Plan Assets at End of Year	$	163,298		$	148,974		$	65,481		$	58,402		$	-		$	-

Change in PBO:

PBO at Beginning of Year	$	148,556		$	154,567		$	72,207		$	66,691		$	12,747		$	14,854

Service Cost		1,743			1,990			2,006			1,988			158			216

Interest Cost		8,065			7,546			3,967			3,269			688			723

Plan Amendments		604			—			—			—			—			—

Participant Contributions		—			—			317			260			—			—

Benefits Paid		(8,462	)		(7,823	)		(2,936	)		(2,526	)		(678	)		(679	)

Actuarial (Gain) or Loss		2,829			(7,724	)		9,987			2,525			589			(2,367	)

PBO at End of Year	$	153,335		$	148,556		$	85,548		$	72,207		$	13,504		$	12,747

Funded Status: Assets vs PBO	$	9,963		$	418		$	(20,067	)	$	(13,805	)	$	(13,504	)	$	(12,747	)

The increase in the PBO for the Pension and SERP plans as of December 31, 2025 compared to December 31, 2024 primarily reflects a decrease in the assumed discount rate as of December 31, 2025 and normal changes in service cost, interest cost and demographic data. The increase in the PBO for the PBOP plan as of December 31, 2025 compared to December 31, 2024 primarily reflects an increase in medical costs, a decrease in the assumed discount rate and normal changes in service cost and interest cost, partially offset by a decrease in demographic data as of December 31, 2025.

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 $13.7 million and $14.4 million at December 31, 2025 and 2024, 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 $146.7 million and $141.6 million as of December 31, 2025 and 2024, respectively. The ABO for the SERP was $13.3 million and $12.4 million as of December 31, 2025 and 2024, 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 2025 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
	2025		2024		2023		2025		2024		2023			2025		2024		2023
Employer Contributions	$	3,950	$	3,758	$	3,850	$	2,285	$	2,552	$	2,790		$	678	$	679	$	665
Participant Contributions	$	—	$	—	$	—	$	317	$	260	$	234		$	—	$	—	$	—
Benefit Payments	$	8,462	$	7,823	$	8,877	$	2,936	$	2,526	$	(2,767	)	$	678	$	679	$	665

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


Estimated Future Benefit Payments
	Pension		PBOP		SERP
2026	$	9,244	$	4,142	$	678
2027		10,322		4,369		677
2028		10,396		4,587		1,190
2029		10,732		5,046		1,181
2030		11,313		5,159		1,172
2031-2035		57,726		26,363		5,658

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 49% in common stock equities, 45% in fixed income securities and 6% in real estate securities. The Company’s Expected Long-Term Rate of Return on PBOP Plan assets is based on target investment allocation of 55% in common stock equities and 45% in fixed income securities. The actual investment allocations are shown in the following tables.


Pension Plan	Target Allocation			Actual Allocation at December 31,
	2026			2025			2024			2023
Equity Funds		49	%		49	%		53	%		57	%
Debt Funds		45	%		45	%		41	%		36	%
Real Estate Fund		6	%		6	%		5	%		6	%
Other(1)		—			—	%		1	%		1	%
Total					100	%		100	%		100	%

(1)

Represents investments being held in cash equivalents as of December 31, 2025, December 31, 2024 and December 31, 2023 pending payment of benefits.


PBOP Plan	Target Allocation			Actual Allocation at December 31,
	2026			2025			2024			2023
Equity Funds		55	%		56	%		56	%		56	%
Debt Funds		45	%		44	%		44	%		44	%
Total					100	%		100	%		100	%

The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 7.50% for 2025. 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, 2025 and 2024. 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, 2025 and 2024 are as follows (000’s):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2025
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	80,722	$	80,722	$	—	$	—
Fixed Income Funds		72,837		72,837		—		—
Total Mutual Funds		153,559		153,559		—		—
Cash Equivalents		392		392
Total Assets in the Fair Value Hierarchy	$	153,951	$	153,951	$	—	$	—
Real Estate Fund–Measured at Net Asset Value		9,347
Total Assets	$	163,298
2024
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	78,407	$	78,407	$	—	$	—
Fixed Income Funds		61,741		61,741		—		—
Total Mutual Funds		140,148		140,148		—		—
Cash Equivalents		1,504		1,504
Total Assets in the Fair Value Hierarchy	$	141,652	$	141,652	$	—	$	—
Real Estate Fund–Measured at Net Asset Value		7,322
Total Assets	$	148,974

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, 2025 and 2024 are as follows (000’s):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2025
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	28,765	$	28,765	$	—	$	—
Equity Funds		36,716		36,716		—		—
Total Assets	$	65,481	$	65,481	$	—	$	—

2024
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	25,908	$	25,908	$	—	$	—
Equity Funds		32,494		32,494		—		—
Total Assets	$	58,402	$	58,402	$	—	$	—

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 $5.0 million, $4.5 million and $4.0 million for the years ended December 31, 2025, 2024 and 2023, respectively.

- Definition

The entire disclosure for retirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (o)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (p)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (q)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 60
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480266/715-60-50-3

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480126/715-20-S99-2

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 70
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480794/715-70-50-1

Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 17
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480482/715-20-55-17

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(03)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(i)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (l)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/715/tableOfContent

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (r)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (r)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

+ Details

Equity (Tables)

12 Months Ended

Dec. 31, 2025

Table Text Block Supplement [Abstract]

Restricted Shares Issued in Conjunction with Stock Plan

Time Restricted Shares issued in the years ended 2023, 2024, and 2025 in conjunction with the Stock Plan are presented in the following table:


Issuance Date	Shares	Aggregate Market Value (millions)
1/24/2023	18,770	$1.0
1/30/2024	22,680	$1.1
1/28/2025	26,430	$1.4


Issuance Date	Shares	Aggregate Market Value (millions)
1/24/2023	18,770	$1.0
1/30/2024	22,680	$1.1
1/28/2025	26,430	$1.4

Schedule of Common Shares Activity

The following table summarizes the Company’s common shares activity for the year ended December 31, 2025:


Common Stock	Shares
Shares as of December 31, 2024		16,192,345
Shares Issued - Equity Issuance		1,602,358
Shares Issued - ATM		27,620
Shares Issued - DRP		21,519
Shares Issued - Directors		14,610
Shares Issued - RSU Settlement		8,525
Shares Issued - Time Restricted		26,430
Shares Issued - Performance Restricted		26,430
Forfeited Shares - Time Restricted		(396	)
Forfeited Shares - Performance Restricted		(250	)
Shares as of December 31, 2025		17,919,191

Schedule of Time Restricted Shares and Performance Restricted Share

The Time Restricted Shares and Performance Restricted Shares unvested activity during the year ended December 31, 2025 in conjunction with the Stock Plan is presented in the following table:


Restricted Shares	Time Restricted Shares					Performance Restricted Shares
	Units			Weighted Average Stock Price		Units			Weighted Average Stock Price
Restricted Shares as of December 31, 2024		19,933		$	48.09		41,200		$	50.28
Granted		26,430		$	52.65		26,430		$	52.65
Shares Issued		(28,084	)	$	50.58		—		$	—
Forfeited		(396	)	$	47.42		(250	)	$	50.35
Restricted Shares as of December 31, 2025		17,883		$	50.94		67,380		$	51.21

Restricted Stock Units Issued

The equity and liability portions of Restricted Stock Units activity during 2025 and 2024 in conjunction with the Stock Plan are presented in the following table:


Restricted Stock Units	(Equity Portion)					(Liability Portion)
	Units			Weighted Average Stock Price		Units			Weighted Average Stock Price
Restricted Stock Units as of December 31, 2023		33,375		$	42.73		14,304		$	52.57
Restricted Stock Units Granted		2,215		$	60.02		949		$	60.02
Dividend Equivalents Earned		1,046		$	55.77		448		$	55.77
Restricted Stock Units as of December 31, 2024		36,636		$	44.15		15,701		$	54.19
Restricted Stock Units Granted		6,818		$	47.22		2,922		$	47.22
Dividend Equivalents Earned		1,123		$	51.87		481		$	51.87
Restricted Stock Units Settled		(8,525	)	$	43.32		(3,654	)	$	58.97
Restricted Stock Units as of December 31, 2025		36,052		$	45.17		15,450		$	48.44

Reconciles Basic and Diluted Earnings Per Share

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


Earnings Per Share (millions, except shares and per share data)	2025		2024		2023
Net Income	$	50.2	$	47.1	$	45.2
Less allocation of earnings and dividends to participating securities		0.3		—		—
Net income allocated to common shareholders	$	49.9	$	47.1	$	45.2

Weighted average common shares outstanding, gross		16,886,642		16,098,267		16,045,300
Less average participating securities		100,561		—		—
Weighted average number of shares outstanding used in the calculation of basic earnings per share		16,786,081		16,098,267		16,045,300
Add dilutive effect of:
Restricted stock and restricted stock units		1,672		10,803		7,447
Adjusted weighted average number of shares outstanding used in the calculation of diluted earnings per common share		16,787,753		16,109,070		16,052,747

Earnings per common share:
Basic	$	2.97	$	2.93	$	2.82
Diluted	$	2.97	$	2.93	$	2.82

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.


	2025		2024		2023
Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation		100,561		6,675		12,204

Retirement Benefit Plans - Assets Measured at Fair Value on Recurring Basis for Pension Plan (Detail) - Pension Plans - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 163,298	$ 148,974	$ 137,893
Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	153,559	140,148
Mutual Fund \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	80,722	78,407
Mutual Fund \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	72,837	61,741
Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	392	1,504
Mutual Fund Including Cash And Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	153,951	141,652
Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	9,347	7,322
Fair Value Inputs Level 1 \| Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	153,559	140,148
Fair Value Inputs Level 1 \| Mutual Fund \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	80,722	78,407
Fair Value Inputs Level 1 \| Mutual Fund \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	72,837	61,741
Fair Value Inputs Level 1 \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	392	1,504
Fair Value Inputs Level 1 \| Mutual Fund Including Cash And Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	153,951	141,652
Fair Value Inputs Level 2 \| Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	0	0
Fair Value Inputs Level 2 \| Mutual Fund \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	0	0
Fair Value Inputs Level 2 \| Mutual Fund \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	0	0
Fair Value Inputs Level 2 \| Mutual Fund Including Cash And Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	0	0
Fair Value Inputs Level 3 \| Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	0	0
Fair Value Inputs Level 3 \| Mutual Fund \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	0	0
Fair Value Inputs Level 3 \| Mutual Fund \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	0	0
Fair Value Inputs Level 3 \| Mutual Fund Including Cash And Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 0	$ 0

Summary of Significant Accounting Policies - Components of Energy Supply Obligations (Detail) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 11.6	$ 10.0
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	2.3	4.0
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 9.3	$ 6.0

Retirement Benefit Plans - Actual Investment Allocations (Detail)

Dec. 31, 2026

Dec. 31, 2025

Dec. 31, 2024

Dec. 31, 2023

Pension Plans

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

6.00%

Actual Allocation

100.00%

Pension Plans | Equity Funds

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

49.00%

Actual Allocation

49.00%

53.00%

57.00%

Pension Plans | Fixed Income Securities

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

45.00%

Actual Allocation

45.00%

41.00%

36.00%

Pension Plans | Other

Defined Benefit Plan Disclosure [Line Items]

Actual Allocation

^[1]

0.00%

1.00%

Retirement Benefits

Defined Benefit Plan Disclosure [Line Items]

Actual Allocation

100.00%

Retirement Benefits | Equity Funds

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

55.00%

Actual Allocation

56.00%

Retirement Benefits | Fixed Income Securities

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

45.00%

Actual Allocation

44.00%

Real Estate Funds | Pension Plans

Defined Benefit Plan Disclosure [Line Items]

Actual Allocation

6.00%

5.00%

6.00%

Scenario Forecast | Pension Plans

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

6.00%

Scenario Forecast | Pension Plans | Equity Funds

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

49.00%

Scenario Forecast | Pension Plans | Fixed Income Securities

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

45.00%

Scenario Forecast | Pension Plans | Other

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

^[1]

0.00%

Scenario Forecast | Retirement Benefits | Equity Funds

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

55.00%

Scenario Forecast | Retirement Benefits | Fixed Income Securities

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

45.00%

[1]	Represents investments being held in cash equivalents as of December 31, 2025, December 31, 2024 and December 31, 2023 pending payment of benefits.

Commitments and Contingencies - Company's Liability for Environmental Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	$ 7.8	$ 4.6
Additions	1.0	3.6
Less: Payments / Reductions	0.7	0.4
Total Balance at end of Period	8.1	7.8
Less: Current Portion	0.8	0.7
Noncurrent Balance at End of Period	$ 7.3	$ 7.1

Income Taxes - Deferred Tax Assets and Liabilities (Parenthetical) (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Regulatory Asset [Line Items]
Gross Regulatory Assets	$ 13.9	$ 18.5
Gross Regulatory Liabilities	210.6	204.6
Other Regulatory Assets (Liabilities) [Member]
Regulatory Asset [Line Items]
Gross Regulatory Assets	16.8	16.6
Gross Regulatory Liabilities	$ 17.1	$ 11.0

Summary of Significant Accounting Policies - Regulatory Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2017
Regulatory Liability [Line Items]
Total Regulatory Liabilities	$ 80.8	$ 64.0
Less: Current Portion of Regulatory Liabilities	16.7	17.2
Regulatory Liabilities-noncurrent	64.1	46.8
Rate Adjustment Mechanisms and Other
Regulatory Liability [Line Items]
Total Regulatory Liabilities	11.1	13.6
Income Taxes
Regulatory Liability [Line Items]
Total Regulatory Liabilities	51.1	50.4	$ 48.9
Derivative Assets
Regulatory Liability [Line Items]
Total Regulatory Liabilities	17.7	0.0
Retirement Benefits
Regulatory Liability [Line Items]
Total Regulatory Liabilities	$ 0.9	$ 0.0

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2025

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, 2025
Electric and Gas Operating Revenues (millions):	Electric		Gas			Total
Billed and Unbilled Revenue:
Residential	$	121.1	$	121.2		$	242.3
Commercial & Industrial		94.9		171.0			265.9
Other		13.1		13.8			26.9
Total Billed and Unbilled Revenue		229.1		306.0			535.1
Rate Adjustment Mechanism Revenue		7.3		(6.4	)		0.9
Total Electric and Gas Operating Revenues	$	236.4	$	299.6		$	536.0


	Twelve Months Ended
	December 31, 2024
Electric and Gas Operating Revenues (millions):	Electric			Gas		Total
Billed and Unbilled Revenue:
Residential	$	135.0		$	92.6	$	227.6
Commercial & Industrial		103.4			133.5		236.9
Other		10.4			9.7		20.1
Total Billed and Unbilled Revenue		248.8			235.8		484.6
Rate Adjustment Mechanism Revenue		(0.5	)		10.7		10.2
Total Electric and Gas Operating Revenues	$	248.3		$	246.5	$	494.8


	Twelve Months Ended
	December 31, 2023
Electric and Gas Operating Revenues (millions):	Electric			Gas			Total
Billed and Unbilled Revenue:
Residential	$	181.6		$	98.8		$	280.4
Commercial & Industrial		120.1			146.9			267.0
Other		10.0			8.1			18.1
Total Billed and Unbilled Revenue		311.7			253.8			565.5
Rate Adjustment Mechanism Revenue		(5.2	)		(3.2	)		(8.4	)
Total Electric and Gas Operating Revenues	$	306.5		$	250.6		$	557.1

Components of Accrued Revenue

The following table shows the components of Accrued Revenue as of December 31, 2025 and 2024.


	December 31,
Accrued Revenue (millions)	2025		2024
Regulatory Assets—Current	$	78.1	$	70.1
Unbilled Revenues		8.9		7.3
Total Accrued Revenue	$	87.0	$	77.4

Components of Exchange Gas Receivable

The following table shows the components of Exchange Gas Receivable as of December 31, 2025 and 2024.


	December 31,
Exchange Gas Receivable (millions)	2025		2024
Northern Utilities	$	8.0	$	6.0
Fitchburg		0.5		0.4
Bangor		1.3		—
Total Exchange Gas Receivable	$	9.8	$	6.4

Components of Gas Inventory

The following table shows the components of Gas Inventory as of December 31, 2025 and 2024.


	December 31,
Gas Inventory (millions)	2025		2024
Natural Gas	$	0.4	$	0.2
Propane		0.4		0.4
Liquefied Natural Gas & Other		0.5		0.5
Total Gas Inventory	$	1.3	$	1.1

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)	2025		2024
Retirement Benefits	$	14.6	$	14.4
Energy Supply & Other Rate Adjustment Mechanisms		73.1		65.4
Deferred Storm Charges		6.0		8.3
Environmental		10.0		9.4
Income Taxes		0.4		0.4
Other Deferred Charges		12.8		14.1
Total Regulatory Assets		116.9		112.0
Less: Current Portion of Regulatory Assets(1)		78.1		70.1
Regulatory Assets—noncurrent	$	38.8	$	41.9

(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)	2025		2024
Rate Adjustment Mechanisms and Other	$	11.1	$	13.6
Income Taxes		51.1		50.4
Derivative Assets		17.7		—
Retirement Benefits		0.9		—
Total Regulatory Liabilities		80.8		64.0
Less: Current Portion of Regulatory Liabilities		16.7		17.2
Regulatory Liabilities—noncurrent	$	64.1	$	46.8

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)	2025		2024
Money Market Funds	$	3.2	$	2.5
Fixed Income Funds		3.5		3.8
Total Marketable Securities	$	6.7	$	6.3

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)	2025		2024
Renewable Energy Portfolio Standards	$	2.3	$	4.0
Exchange Gas Obligation		9.3		6.0
Total Energy Supply Obligations	$	11.6	$	10.0

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)	2025		2024
Equity Funds	$	3.1	$	2.0
Fixed Income Funds		0.3		0.1
Money Market Funds		0.1		0.1
Total Marketable Securities	$	3.5	$	2.2

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

12 Months Ended

Dec. 31, 2025

Dec. 31, 2024

Dec. 31, 2023

Interest Expense

Long-Term Debt

$ 33.3

$ 27.8

$ 24.7

Short-Term Debt

8.5

8.4

9.2

Regulatory Liabilities

2.0

1.5

1.0

Subtotal Interest Expense

43.8

37.7

34.9

Interest Income

Interest and Other Income

(7.1)

(8.4)

(6.2)

Interest Expense, Net

36.7

29.3

28.7

Regulatory Assets

Interest Income

Interest and Other Income

(3.5)

(4.1)

(3.3)

AFUDC and Other

Interest Income

Interest and Other Income

^[1]

$ (3.6)

$ (4.3)

$ (2.9)

[1]	AFUDC—Allowance for Funds Used During Construction

Summary of Significant Accounting Policies - Components of Gas Inventory (Detail) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 1.3	$ 1.1
Liquefied Natural Gas & Other
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.5	0.5
Natural Gas
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.4	0.2
Propane
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.4	$ 0.4

Retirement Benefit Plans - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2026
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	$ 428,700
Defined benefit plan, assumed health care cost trend rate, description	The health care cost trend rate used to determine benefit obligations at December 31, 2025 for pre-65 retirees is 8.05%, with an ultimate rate of 4.50% in 2034, and for post-65 retirees, the health care cost trend rate is 7.15%, with an ultimate rate of 4.50% in 2034. The health care cost trend rate used to determine benefit obligations at December 31, 2024 for pre-65 retirees was 8.50%, with an ultimate rate of 4.50% in 2034, and for post-65 retirees, the health care cost trend rate was 7.50%, with an ultimate rate of 4.50% in 2034. The health care cost trend rate used to determine benefit obligations at December 31, 2023 for pre-65 retirees was 8.00%, with an ultimate rate of 4.50% in 2033, and for post-65 retirees, the health care cost trend rate was 6.00%, with an ultimate rate of 4.50% in 2033.	The health care cost trend rate used to determine benefit obligations at December 31, 2024 for pre-65 retirees was 8.50%, with an ultimate rate of 4.50% in 2034, and for post-65 retirees, the health care cost trend rate was 7.50%, with an ultimate rate of 4.50% in 2034.	The health care cost trend rate used to determine benefit obligations at December 31, 2023 for pre-65 retirees was 8.00%, with an ultimate rate of 4.50% in 2033, and for post-65 retirees, the health care cost trend rate was 6.00%, with an ultimate rate of 4.50% in 2033.
Regulatory assets	$ 116,900,000	$ 112,000,000
Defined Benefit Plan, Expected Long-term Return on Assets	7.50%
Health Care Cost Trend Rate, Description	The health care cost trend rate used to determine plan costs for 2025 for pre-65 retirees is 8.50%, with an ultimate rate of 4.50% in 2034, and for post-65 retirees, the health care cost trend rate is 7.50%, with an ultimate rate of 4.50% in 2034. The health care cost trend rate used to determine plan costs for 2024 for pre-65 retirees was 8.00%, with an ultimate rate of 4.50% in 2033, and for post-65 retirees, the health care cost trend rate was 6.00%, with an ultimate rate of 4.50% in 2033. The health care cost trend rate used to determine plan costs for 2023 for pre-65 retirees was 8.00%, with an ultimate rate of 4.50% in 2030, and for post-65 retirees was 6.25%, with an ultimate rate of 4.50% in 2030.	The health care cost trend rate used to determine plan costs for 2024 for pre-65 retirees was 8.00%, with an ultimate rate of 4.50% in 2033, and for post-65 retirees, the health care cost trend rate was 6.00%, with an ultimate rate of 4.50% in 2033.	The health care cost trend rate used to determine plan costs for 2023 for pre-65 retirees was 8.00%, with an ultimate rate of 4.50% in 2030, and for post-65 retirees was 6.25%, with an ultimate rate of 4.50% in 2030.
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation	$ 146,700,000	$ 141,600,000
Defined Benefit Plan, Target Plan Asset Allocations	6.00%
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 3,950,000	3,758,000	$ 3,850,000
Pension Plan [Member] \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	49.00%
Pension Plan [Member] \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	45.00%
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 2,285,000	2,552,000	2,790,000
Other Postretirement Benefit Plans, Defined Benefit \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	55.00%
Other Postretirement Benefit Plans, Defined Benefit \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	45.00%
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation	$ 13,300,000	12,400,000
Defined Benefit Plan, Plan Assets, Contributions by Employer	678,000	679,000	665,000
Fair Value Of Plan Assets
Defined Benefit Plan Disclosure [Line Items]
Pension expense	(500,000)	1,800,000	2,800,000
Defined Benefit Obligations
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	13,700,000	14,400,000
Four Zero One K Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 5,000,000	$ 4,500,000	$ 4,000,000
Benefit Plan Costs
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Long-term Return on Assets	7.50%	7.50%	7.50%
Pre-65 retirees
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate, ultimate rate	4.50%	4.50%	4.50%
Determine plan costs ultimate rate		4.50%	4.50%
Health care cost trend rate, assumed	8.05%	8.50%	8.00%
Health care cost trend rate determine plan costs		8.00%
Health care cost trend rate, ultimate rate in year	2034	2034	2030
Reaches Ultimate Trend Rate Year		2033
Post-65 retirees
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate, ultimate rate	4.50%	4.50%	4.50%
Determine plan costs ultimate rate		4.50%
Health care cost trend rate, assumed	7.15%	7.50%	6.00%
Health care cost trend rate determine plan costs		6.00%	6.25%
Health care cost trend rate, ultimate rate in year	2034	2034	2033
Reaches Ultimate Trend Rate Year		2033	2030
Pre-65 retirees and Post -65 retirees
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate, assumed	7.50%
Scenario Forecast \| Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				6.00%
Scenario Forecast \| Pension Plan [Member] \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				49.00%
Scenario Forecast \| Pension Plan [Member] \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				45.00%
Scenario Forecast \| Other Postretirement Benefit Plans, Defined Benefit \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				55.00%
Scenario Forecast \| Other Postretirement Benefit Plans, Defined Benefit \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				45.00%

Segment Information - Significant Segment Financial Data (Detail) - USD ($) $ in Millions		12 Months Ended
	Apr. 14, 2023	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Operation and Maintenance		$ 92.5	$ 77.6	$ 75.6
Depreciation & Amortization Expense		88.7	76.1	67.4
Interest Income		(7.1)	(8.4)	(6.2)
Interest Expense		43.8	37.7	34.9
Provision for Income Taxes	$ 9.4	15.3	14.0	13.2
Net Income Attributable to Commons Shares		49.9	47.1	45.2
Segment Assets		2,134.2	1,794.5
Capital Expenditures		185.1	169.9	141.0
Operating Segments \| Electric
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues		236.4	248.3	306.5
Energy Supply Costs		121.8	141.0	202.4
Operation and Maintenance		38.8	34.9	34.5
Depreciation & Amortization Expense		31.9	29.3	26.0
Other Segment Expenses (Income)		12.6	12.9	13.1
Interest Income		(3.3)	(3.6)	(2.6)
Interest Expense		15.0	13.4	11.2
Provision for Income Taxes		3.8	3.8	4.0
Net Income Attributable to Commons Shares		15.8	16.6	17.9
Segment Assets		733.5	647.2	612.6
Capital Expenditures		73.5	61.8	44.2
Operating Segments \| Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues		299.6	246.5	250.6
Energy Supply Costs		100.5	79.6	96.1
Operation and Maintenance		48.9	41.7	40.7
Depreciation & Amortization Expense		56.8	46.8	40.4
Other Segment Expenses (Income)		18.0	17.3	16.9
Interest Income		(3.8)	(4.6)	(2.4)
Interest Expense		25.1	23.7	20.7
Provision for Income Taxes		14.0	11.2	9.4
Net Income Attributable to Commons Shares		40.1	30.8	28.8
Segment Assets		1,367.8	1,115.3	1,031.8
Capital Expenditures		110.0	103.9	92.7
Operating Segments \| Total Reportable Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues		536.0	494.8	557.1
Energy Supply Costs		222.3	220.6	298.5
Operation and Maintenance		87.7	76.6	75.2
Depreciation & Amortization Expense		88.7	76.1	66.4
Other Segment Expenses (Income)		30.6	30.2	30.0
Interest Income		(7.1)	(8.2)	(5.0)
Interest Expense		40.1	37.1	31.9
Provision for Income Taxes		17.8	15.0	13.4
Net Income Attributable to Commons Shares		55.9	47.4	46.7
Segment Assets		2,101.3	1,762.5	1,644.4
Capital Expenditures		183.5	165.7	136.9
Operating Segments \| Other
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues		0.0	0.0	0.0
Energy Supply Costs		0.0	0.0	0.0
Operation and Maintenance		4.8	1.0	0.4
Depreciation & Amortization Expense		0.0	0.0	1.0
Other Segment Expenses (Income)		(0.3)	(0.1)	(1.5)
Interest Income		0.0	(0.2)	(1.2)
Interest Expense		3.7	0.6	3.0
Provision for Income Taxes		(2.5)	(1.0)	(0.2)
Net Income Attributable to Commons Shares		(5.7)	(0.3)	(1.5)
Segment Assets		32.9	32.0	26.0
Capital Expenditures		1.6	4.2	4.1
Operating Segments \| Total
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues		536.0	494.8	557.1
Energy Supply Costs		222.3	220.6	298.5
Operation and Maintenance		92.5	77.6	75.6
Depreciation & Amortization Expense		88.7	76.1	67.4
Other Segment Expenses (Income)		30.3	30.1	28.5
Interest Income		(7.1)	(8.4)	(6.2)
Interest Expense		43.8	37.7	34.9
Provision for Income Taxes		15.3	14.0	13.2
Net Income Attributable to Commons Shares		50.2	47.1	45.2
Segment Assets		2,134.2	1,794.5	1,670.4
Capital Expenditures		$ 185.1	$ 169.9	$ 141.0

Debt and Financing Arrangements - Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases (Detail) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Operating leases
2026	$ 2,439.0
2027	2,070.0
2028	1,520.0
2029	1,150.0
2030	478.0
2031-2035	161.0
Lessee, Operating Lease, Liability, to be Paid, Total	7,818.0
Less: Interest	771.0
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	7.0	$ 6.7
Capital lease
2026	208.0
2027	208.0
2028	112.0
2029	89.0
2030	42.0
2031-2035	0.0
Finance Lease, Liability, to be Paid, Total	659.0
Less: Interest	57.0
Lease Obligations [Member]
Operating leases
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	7,047.0
Capital lease
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$ 602.0

Energy Supply - Additional Information (Detail) Bcfe in Millions	1 Months Ended	12 Months Ended
	Nov. 30, 2024	Dec. 31, 2025	Dec. 31, 2025	Dec. 31, 2025 BTU	Dec. 31, 2025 Bcfe
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	6,300
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 \| Bcfe					400
Percentage of power supply requirement	100.00%		50.00%
Power supply contract duration		12 months
Percentage Of Purchase Electric Supply	100.00%
Fitchburg Gas and Electric Light Company \| Fitchburg Customers [Member]
Gas and Oil Acreage [Line Items]
Percentage of power supply requirement	100.00%
ISO New England markets
Gas and Oil Acreage [Line Items]
Percentage of power supply requirement			50.00%
Unitil Energy Systems Inc
Gas and Oil Acreage [Line Items]
Percentage of power supply requirement			50.00%
Power supply contract duration		6 months
Bangor
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				35,000
Natural gas, underground storage \| Bcfe					690
Maine Natural 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				6,500

Debt and Financing Arrangements

12 Months Ended

Dec. 31, 2025

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, Bangor 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, Bangor 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, Bangor 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, Bangor 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, Bangor 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, Bangor 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, 2025, in accordance with the covenants, these subsidiary companies had a combined amount of $563.1 million available for the payment of dividends and Unitil Corporation had $318.5 million available for the payment of dividends. As of December 31, 2025, the Company’s balance in Retained Earnings was $191.2 million. Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2025 for the payment of dividends.

Issuance of Long-Term Debt - On July 8, 2025, Bangor issued $14.0 million of Notes due 2030 at 5.70% and $18.0 million of Notes due 2035 at 6.31%. Bangor used the net proceeds to refinance existing debt and for general corporate purposes. Approximately $0.2 million of costs associated with this issuance were recorded as a reduction of Long-Term Debt for presentation purposes on the Consolidated Balance Sheet in the third quarter of 2025.

On August 21, 2024, Unitil Corporation issued $20.0 million of Notes due 2034 at 5.99%. Fitchburg issued $12.5 million of Notes due 2034 at 5.54% and $12.5 million of Notes due 2044 at 5.99%. Unitil Energy issued $40.0 million of Bonds due 2054 at 5.69%. Northern Utilities issued $25.0 million of Notes due 2034 at 5.54% and $15.0 million of Notes due 2039 at 5.74%. Granite State issued $10.0 million of Notes due 2034 at 5.74%. The Company used the net proceeds from these offerings to refinance existing debt and for general corporate purposes. Approximately $1.0 million of costs associated with this issuance were recorded as a reduction of Long-Term Debt for presentation purposes on the Consolidated Balance Sheet in the third quarter of 2024.

Debt Repayment -The total aggregate amount of debt repayments relating to bond issues and normal scheduled long-term debt repayments amounted to $4.9 million, $4.9 million and $6.9 million in 2025, 2024, and 2023, respectively.

The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2025 is: 2026 – $37.9 million; 2027 – $55.7 million; 2028 – $10.7 million; 2029 – $43.7 million; 2030 – $26.5 million and thereafter $499.8 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)	2025		2024
Estimated Fair Value of Long-Term Debt	$	623.4	$	598.9

Details on long-term debt at December 31, 2025 and 2024 are shown below:


	December 31,
Long-Term Debt (millions)	2025		2024
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
5.99% Senior Notes, Due August 21, 2034		20.0		20.0
Unitil Energy First Mortgage Bonds:
6.96% Senior Secured Notes, Due September 1, 2028		6.0		8.0
8.00% Senior Secured Notes, Due May 1, 2031		9.0		10.5
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
5.69% Senior Secured Notes, Due August 21, 2054		40.0		40.0
Fitchburg:
3.52% Senior Notes, Due November 1, 2027		10.0		10.0
7.37% Senior Notes, Due January 15, 2029		4.8		6.0
5.90% Senior Notes, Due December 15, 2030		15.0		15.0
7.98% Senior Notes, Due June 1, 2031		14.0		14.0
5.70% Senior Notes, Due July 2, 2033		12.0		12.0
5.54% Senior Notes, Due August 21, 2034		12.5		12.5
3.78% Senior Notes, Due September 15, 2040		27.5		27.5
5.99% Senior Notes, Due August 21, 2044		12.5		12.5
4.32% Senior Notes, Due November 1, 2047		15.0		15.0
5.96% Senior Notes, Due July 2, 2053		13.0		13.0
Northern Utilities:
3.52% Senior Notes, Due November 1, 2027		20.0		20.0
5.54% Senior Notes, Due August 21, 2034		25.0		25.0
7.72% Senior Notes, Due December 3, 2038		50.0		50.0
5.74% Senior Notes, Due August 21, 2039		15.0		15.0
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
Bangor:
5.70% Senior Notes, Due July 8, 2030		14.0		—
6.31% Senior Notes, Due July 8, 2035		18.0		—
Granite State:
3.72% Senior Notes, Due November 1, 2027		15.0		15.0
5.74% Senior Notes, Due August 21, 2034		10.0		10.0
Unitil Realty Corp.:
2.64% Senior Secured Notes, Due December 18, 2030		3.5		3.8
Total Long-Term Debt		674.3		647.3
Less: Unamortized Debt Issuance Costs		3.8		4.0
Total Long-Term Debt, net of Unamortized Debt Issuance Costs		670.5		643.3
Less: Current Portion(1)		37.9		4.9
Total Long-Term Debt, Less Current Portion	$	632.6	$	638.4

(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)	2025			2024			2023
Interest Expense
Long-Term Debt	$	33.3		$	27.8		$	24.7
Short-Term Debt		8.5			8.4			9.2
Regulatory Liabilities & Other		2.0			1.5			1.0
Subtotal Interest Expense		43.8			37.7			34.9
Interest Income
Regulatory Assets		(3.5	)		(4.1	)		(3.3	)
AFUDC(1) and Other		(3.6	)		(4.3	)		(2.9	)
Subtotal Interest Income		(7.1	)		(8.4	)		(6.2	)
Total Interest Expense, Net	$	36.7		$	29.3		$	28.7

(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 the prior credit facility in full, and on January 29, 2025, the Company executed an amendment that increased the borrowing limit under the Credit Facility from $200 million to $275 million and extended the term of the maturity date from September 29, 2027 until September 29, 2028. Unitil may borrow under the Credit Facility until September 29, 2028, subject to two one-year extensions under certain circumstances. The Credit Facility provides for a borrowing limit of $275 million, including a $25 million sublimit for standby letters of credit, and permits Unitil to increase the borrowing limit by up to $75 million under certain circumstances. Borrowings under the Credit Facility may bear interest at various rate options, including a daily fluctuating rate equal to the forward-looking one-month secured overnight financing rate (SOFR) term rate (as administered by the Federal Reserve Bank of New York), plus 0.1000%, plus a margin of 1.125% to 1.375% based on Unitil’s credit rating.

The Company generally utilizes the Credit Facility for cash management purposes related to its short-term operating activities and may use the Credit Facility for certain acquisition financing. Total gross borrowings were $476.4 million and $308.4 million for the years ended December 31, 2025 and December 31, 2024, respectively. Total gross repayments were $412.5 million and $364.6 million for the years ended December 31, 2025 and December 31, 2024, respectively. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2025 and December 31, 2024:


	December 31,
Revolving Credit Facility (millions)	2025		2024
Limit	$	275.0	$	200.0
Short-Term Borrowings Outstanding	$	169.7	$	105.8
Available	$	105.3	$	94.2

The Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, Unitil’s and its subsidiaries’ ability to permit liens or incur

indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At December 31, 2025 and December 31, 2024, 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 5.4%, 6.5%, and 6.4 % during 2025, 2024, and 2023, respectively.

On October 31, 2025, the Company entered into a senior unsecured delayed-draw term loan facility with The Bank of Nova Scotia. The proceeds of the $86.0 million facility were used to initially fund the acquisition of Maine Natural on October 31, 2025. The facility provides that the Company has an option for determining whether interest on loans under the facility will bear interest based on a Base Rate plus an applicable margin of 0.25% or based on a one month Term SOFR plus a SOFR adjustment of 0.10% plus an applicable margin of 1.25%. The Base Rate is equal to the highest of the (a) Federal Funds Rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by The Bank of Nova Scotia as its "prime rate", or (c) one month Term SOFR plus a SOFR adjustment of 0.10% plus 1.00%. The facility has a maturity date of October 31, 2026.

Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State are currently rated “BBB+” and Bangor is 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 and Bangor enter into asset management agreements under which Northern Utilities and Bangor release certain natural gas pipeline and storage assets, resell the natural gas storage inventory to an asset manager and subsequently repurchase 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 $9.3 million of natural gas storage inventory and corresponding obligations at December 31, 2025, related to these asset management agreements. The amount of natural gas inventory released in December 2025, which was payable in January 2026, was $3.0 million and was recorded in Accounts Payable at December 31, 2025.

Contractual Obligations

The following table lists the Company’s contractual obligations for long-term debt as of December 31, 2025.


			Payments Due by Period
Long-Term Debt Contractual Obligations (millions) as of December 31, 2025	Total		2026		2027		2028		2029		2030		2031 & Beyond
Long-Term Debt	$	674.3	$	37.9	$	55.7	$	10.7	$	43.7	$	26.5	$	499.8
Interest on Long-Term Debt		435.2		33.7		31.9		29.6		28.9		26.9		284.2
Total	$	1,109.5	$	71.6	$	87.6	$	40.3	$	72.6	$	53.4	$	784.0

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, 2025, 2024 and 2023 amounted to $2.3 million, $2.2 million and $2.1 million respectively. The balance sheet classification of the Company’s lease obligations was as follows:


	December 31,
Lease Obligations (millions)	2025		2024
Operating Lease Obligations:
Operating Lease Obligations (current portion)	$	2.1	$	1.8
Operating Lease Obligations (long-term portion)		4.9		4.9
Total Operating Lease Obligations		7.0		6.7
Capital Lease Obligations:
Other Current Liabilities (current portion)		0.2		0.1
Other Noncurrent Liabilities (long-term portion)		0.4		0.4
Total Capital Lease Obligations		0.6		0.5
Total Lease Obligations	$	7.6	$	7.2

Cash paid for amounts included in the measurement of operating lease obligations for the twelve months ended December 31, 2025 and 2024 was $2.3 million and $2.2 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 $0.9 million and $0.6 million as of December 31, 2025 and 2024, respectively, less accumulated amortization of $0.3 million and $0.1 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheets.


Lease Payments ($000’s) Year Ending December 31,	Operating Leases		Capital Leases
2026	$	2,439	$	208
2027		2,070		208
2028		1,520		112
2029		1,150		89
2030		478		42
2031-2035		161		—
Total Payments		7,818		659
Less: Interest		771		57
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$	7,047	$	602

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, 2025, the weighted average remaining lease term is 3.8 years and the weighted average operating discount rate used to determine the operating lease obligations was 5.3%. As of December 31, 2024, the weighted average remaining lease term was 4.2 years and the weighted average operating discount rate used to determine the operating lease obligations was 5.1%.

Guarantees

The Company provides limited guarantees on certain energy and natural gas asset management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of December 31, 2025, there were $50.3 million of guarantees outstanding.

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 8A
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-8A

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(c))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481544/470-10-50-6

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481544/470-10-50-6

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)(3)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1B

Reference 12: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 470
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/470/tableOfContent

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 835
-SubTopic 30
-Name Accounting Standards Codification
-Section 45
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482925/835-30-45-2

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1B

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
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-Subparagraph (g)
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+ Details

Debt and Financing Arrangements - Summary of Contractual Obligations for Long-term Debt (Detail) $ in Millions	Dec. 31, 2025 USD ($)
Contractual Obligation Fiscal Year Maturity Schedule [Line Items]
Total	$ 977.7
2026	122.6
2027	90.3
2028	83.3
2029	77.0
2030	62.5
2031 & Beyond	542.0
Long Term Debt Comprising Principal And Interest [Member]
Contractual Obligation Fiscal Year Maturity Schedule [Line Items]
Total	1,109.5
2026	71.6
2027	87.6
2028	40.3
2029	72.6
2030	53.4
2031 & Beyond	784.0
Long-Term Debt [Member] \| Long Term Debt Comprising Principal And Interest [Member]
Contractual Obligation Fiscal Year Maturity Schedule [Line Items]
Total	674.3
2026	37.9
2027	55.7
2028	10.7
2029	43.7
2030	26.5
2031 & Beyond	499.8
Interest on Long-Term Debt [Member] \| Long Term Debt Comprising Principal And Interest [Member]
Contractual Obligation Fiscal Year Maturity Schedule [Line Items]
Total	435.2
2026	33.7
2027	31.9
2028	29.6
2029	28.9
2030	26.9
2031 & Beyond	$ 284.2

Retirement Benefit Plans - Employer Contributions, Participant Contributions and Benefit Payments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Pension Plans
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	$ 3,950	$ 3,758	$ 3,850
Participant Contributions	0	0	0
Benefits Paid	8,462	7,823	8,877
Retirement Benefits
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	2,285	2,552	2,790
Participant Contributions	317	260	234
Benefits Paid	2,936	2,526	2,767
Supplemental Employee Retirement Plans, Defined Benefit
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	678	679	665
Participant Contributions	0	0	0
Benefits Paid	$ 678	$ 679	$ 665

- Definition

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

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+ Details

Commitments and Contingencies

12 Months Ended

Dec. 31, 2025

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 8: Commitments and Contingencies

Regulatory Matters

Overview—Unitil’s distribution utilities primarily 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, Northern Utilities and Maine Natural’s non-Augusta service area 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. Bangor and Maine Natural’s Augusta Service Area delivery rates to natural gas customers are established under alternative rate plans, which provide multi-year rate changes designed to approximate market-based rates.

Most of Unitil’s customers are entitled to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, Bangor, and Maine Natural, only business customers are entitled to purchase their natural gas supplies from

third-party suppliers. Municipal aggregation has also occurred in a number of towns in Unitil’s New Hampshire and Massachusetts service territories. As the providers of basic or default service, Unitil Energy, Fitchburg, Northern Utilities, Bangor and Maine Natural purchase wholesale electricity or natural gas 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, Northern Utilities, Bangor and Maine Natural to recover their actual wholesale energy costs for electric power and natural gas.

Rate Case Activity

Northern Utilities - Base Rates - Maine - On September 20, 2023, the MPUC issued an order approving a Stipulation filed on August 31, 2023, between Northern Utilities and the Office of the Public Advocate which resolved all matters in the base rate filing made by Northern Utilities with the MPUC on May 1, 2023. The order approves an increase in distribution revenues of $7.6 million effective October 1, 2023. The order reflects a return on equity of 9.35%, an equity ratio of 52.01%, and a weighted average cost of capital of 7.22%.

Northern Utilities - Targeted Infrastructure Replacement Adjustment (TIRA) - Maine - The settlement in Northern Utilities’ Maine division’s 2013 rate case authorized the Company to implement a TIRA rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects, including the Company’s Cast Iron Replacement Program (CIRP). In its Final Order issued on February 28, 2018 for Northern Utilities’ 2017 base rate case, the MPUC approved an extension of the TIRA mechanism for an additional eight-year period, which will allow for annual rate adjustments through the end of the CIRP program. The Company’s most recent request under the TIRA mechanism, to increase annual base rates by $2.1 million for 2024 eligible facilities, was filed with the MPUC on February 28, 2025 for rates effective May 1, 2025. On April 29, 2025, the MPUC issued an order approving the filing, for rates effective May 1, 2025. During 2024, Northern Utilities performed its fourteenth and final year of construction on the 14-year combined CIRP, (Unprotected Steel and Farm Tap project ordered by the MPUC in Docket Nos. 2008-00151 and 2013-00133). As the Cast Iron Replacement Program and related unprotected steel and Farm Tap programs have been completed and all leak-prone pipe has been removed, this is Northern’s final TIRA rate adjustment.

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 approved a comprehensive Settlement Agreement between the Company, the New Hampshire Department of Energy (DOE), and the Office of the Consumer Advocate (OCA). As provided in the Settlement Agreement, in addition to authorizing an increase to permanent distribution rates of $6.1 million, effective August 1, 2022, the Order (1) approved a revenue decoupling mechanism and (2) allowed for a step adjustment effective September 1, 2022 covering the additional revenue requirement resulting from changes in Net Plant in Service associated with non-growth investments for the period January 1, 2021, through December 31, 2021. This distribution base rate case reflected the Company’s operating costs and investments in utility plant for a test year ended December 31, 2020 as adjusted for known and measurable changes. The Order provided for a return on equity of 9.3% and a capital structure reflecting 52% equity and 48% long-term debt. The increase in permanent rates was reconciled back to October 1, 2021, the effective date of temporary rates previously approved in this docket. On June 8, 2022, the Company filed for its step increase of approximately $1.6 million of annual revenue, for rates effective as of September 1, 2022, to recover eligible 2021 capital investments. On August 31, 2022, the NHPUC approved the Company’s filing.

Unitil Energy - Base Rates - On May 1, 2025 Unitil Energy filed for an increase in distribution base rates with the NHPUC. The Company is seeking an increase in base rates of approximately $18.5 million or 7.3% above present rates. Unitil Energy also requested implementation of temporary rates for service rendered on and after July 1, 2025, and until a final order on permanent rates is issued. The requested temporary rates were approved at the requested levels, resulting in an increase in annual revenues of $7.8 million, or a 3.7% increase above present rates. As provided by statute, once a final order on permanent rates is issued, the permanent rate level is reconciled back to the effective date of the temporary rates. The filing includes (1) a proposed multi-year rate plan, (2) a continuation of its revenue decoupling mechanism, (3) an update to the previously approved suite of proposed time of use (TOU) rates including rates for electric vehicles (4) resiliency programs to further the Company’s commitment to reliability, (5) an Arrearage Management Program for financial hardship customers; and (6) other rate design and tariff changes. This matter remains pending.

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 July

26, 2023, the MDPU issued an Order approving the Company's cumulative revenue requirement of $3.1 million associated with its 2019-2021 capital expenditures. On September 11, 2024, the MDPU issued a final order approving the cumulative revenue requirement of $3.5 million associated with its 2019-2022 capital expenditures. On November 1, 2024, Fitchburg filed its cumulative revenue requirement of $0.5 million associated with its 2023 capital expenditures, which reflects the transfer of capital expenditures associated with its 2019-2023 year investments into base distribution rates effective July 1, 2024. On December 23, 2024, the MDPU approved recovery through its capital cost recovery mechanism effective January 1, 2025. On October 31, 2025, Fitchburg submitted its revenue requirement analysis for 2024 capital expenditures. In accordance with its tariff, Fitchburg sought approval to recover $0.2 million effective January 1, 2026. On December 30, 2025, the MDPU approved the proposed recovery, subject to investigation.

On August 17, 2023, Fitchburg filed a petition with the MDPU seeking approval for a $6.8 million increase to base distribution rates, with new rates to be effective July 1, 2024. Fitchburg also requested, among other things, approval for a performance-based ratemaking (PBR) plan for up to a five-year term and continuation of its revenue decoupling mechanism. On June 28, 2024, the MDPU issued an Order providing for a $4.7 million increase to base rates, effective July 1, 2024. This includes a transfer of $2.2 million in costs from certain reconciling mechanisms to base distribution rates. In addition to authorizing an increase to base rates, the Order approved a PBR plan for up to a five-year term and continuation of the Company’s revenue decoupling mechanism. The Order provided for a return on equity of 9.4% and a capital structure reflecting 52% equity and 48% long-term debt. On July 5, 2024, the Company filed its compliance tariff filing and made further revisions as directed by the MDPU on July 15, 2024. On July 16, 2024 the MDPU approved its revised compliance filing. In its Order, the MDPU found that allowing the Company to recover pension and PBOP expense through its Pension/PBOP Adjustment mechanism is no longer warranted. Instead, the MDPU concluded that these expenses should be recovered in base distribution rates, the mechanism should be discontinued and any unrecovered expenses existing as of the effective date of new rates will be recovered over two years. On July 18, 2024, the Company filed a Motion for Reconsideration and Recalculation requesting that the MDPU reconsider its decision to require the Company to absorb $1.4 million in negative excess accumulated deferred income taxes (ADIT) because the effect of the Order was to inappropriately claw back amounts that were previously approved by the MDPU for recovery from customers. On November 26, 2024, the MDPU issued an Order on the Company’s motion holding, in part, that Pension/PBOP expenses shall be recovered in base distribution rates. On December 9, 2024, the Company filed an appeal with Massachusetts Supreme Judicial Court on the grounds that the MDPU’s Order unlawfully denies the Company’s recovery of approximately $1.4 million of negative, excess ADIT. The amount of $1.4 million is disaggregated between the Company’s gas division ($0.6 million) and the electric division ($0.8 million). This appeal is pending. The ruling on November 26, 2024 approved certain other recalculations, resulting in an additional increase to electric base rates of $0.1 million effective December 1, 2024.

Fitchburg - Performance Base Rate Adjustment - Electric - On February 28, 2025, Fitchburg filed its first Performance Based Revenue Adjustment (PBRA) for rates effective July 1, 2025. The calculated PBRA adjustment resulted in a distribution revenue increase of $1.6 million. On June 20, 2025, the MDPU issued an order approving the proposed increase effective July 1, 2025.

Fitchburg - Base Rates - Gas - On August 17, 2023, Fitchburg filed a petition with the MDPU seeking approval for a $10.9 million increase to base distribution rates, with new rates anticipated to be effective July 1, 2024. Fitchburg proposed to transfer $4.2 million in revenue requirements recovered through its Gas System Enhancement Program to base distribution rates. Net of these transfers, the proposed overall increase to distribution revenues was $6.7 million. As part of this filing, Fitchburg requested approval for a PBR plan for up to a five-year term and continuation of its revenue decoupling mechanism. On June 28, 2024, the MDPU issued an Order providing for a $10.1 million increase to base rates, effective July 1, 2024. This includes a transfer of $4.9 million in costs from certain reconciling mechanisms to base distribution rates. In addition to authorizing an increase to base rates, the Order approved a PBR plan for up to a five-year term. The order approves continuation of the Company’s revenue decoupling mechanism but changes the structure from a revenue per customer benchmark to a total revenue cap. The Order provided for a return on equity of 9.4% and a capital structure reflecting 52% equity and 48% long-term debt. On July 5, 2024, the Company filed its compliance tariff filing and made further revisions as directed by the MDPU on July 15, 2024. On July 16, 2024, the MDPU approved its revised compliance filing. In its Order, the MDPU found that allowing the Company to recover pension and PBOP expense through its Pension/PBOP Adjustment mechanism is no longer warranted. Instead, the MDPU concluded that these expenses should be recovered in base distribution rates, the mechanism should be discontinued and any unrecovered expenses existing as of the effective date of new rates will be recovered over two years. On July 18, 2024, the Company filed a Motion for Reconsideration and Recalculation requesting that the MDPU reconsider its decision to require the Company to absorb $1.4 million in negative excess ADIT because the effect of the Order was to inappropriately claw back amounts that were previously approved by the MDPU for recovery from customers. On November

26, 2024, the MDPU issued an Order on the Company’s motion holding, in part, that Pension/PBOP expenses shall be recovered in base distribution rates. On December 9, 2024, the Company filed an appeal with Massachusetts Supreme Judicial Court on the grounds that the MDPU’s Order unlawfully denies the Company’s recovery of approximately $1.4 million of negative, excess ADIT. The amount of $1.4 million is disaggregated between the Company’s Gas Division ($0.6 million) and the Electric Division ($0.8 million). This appeal is pending. The ruling on November 26, 2024 approved certain other recalculations, resulting in an additional increase to gas base rates of $0.1 million effective December 1, 2024.

Fitchburg - Performance Base Rate Adjustment - Gas - On February 28, 2025, Fitchburg filed its first PBRA for rates effective July 1, 2025. The calculated PBRA adjustment resulted in a distribution revenue increase of $0.7 million. On June 20, 2025, the MDPU issued an order approving the proposed increase effective July 1, 2025.

Fitchburg - Gas System Enhancement Program - Pursuant to statute and MDPU order, Fitchburg has an approved Gas System Enhancement Plan (GSEP) tariff through which it may recover certain gas infrastructure replacement and safety related investment costs, subject to an annual cap. 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, filed on October 31, 2024, requested recovery of approximately $3.5 million associated with 2023-2025 year investments. On April 30, 2025, the MDPU issued an Order approving Fitchburg’s 2025 GSEP and associated revenue requirement of approximately $3.5 million with an additional $1.6 million in prior deferrals for a total of approximately $5.1 million to be recovered through the Gas System Enhancement Adjustment Factors for effect May 1, 2025. However, the MDPU also took steps to “substantially reform the GSEP process,” including (but not limited to): reducing the currently applicable revenue cap on recovery from 3.0% to 2.5% for the 2025 GSEPs, with “likely” further reductions to 2.0% for the 2026 GSEPs and 1.5% for the 2027 GSEPs; and eliminating carrying charges on GSEP deferrals. On May 20, 2025, Fitchburg filed a motion for reconsideration and / or clarification regarding application of the reduced cap to a Fitchburg specific project, and joined a joint motion for reconsideration and / or clarification with other Massachusetts Electric Distribution Companies (EDCs) regarding aspects of the Order applicable to all Massachusetts companies. On August 26, 2025, the MDPU issued an order denying the motions for reconsideration and clarification. The Company filed its most recent forward-looking cumulative revenue requirement filing on October 31, 2025, requesting recovery of approximately $5.4 million with an additional $1.0 million in prior deferrals for a total of approximately $6.4 million to be recovered through the Gas System Enhancement Adjustment Factors for effect May 1, 2026. This matter remains pending.

Granite State - Base Rates - On October 4, 2024, Granite State filed an uncontested rate settlement with the FERC which provides for an increase in annual revenues of $3.0 million, effective November 1, 2024. The Settlement Agreement permits the filing of limited Section 4 rate adjustments for capital cost projects eligible for cost recovery in 2025, 2026, and 2027, and sets forth an overall cap of $29.9 million on the capital costs recoverable under such filings. Under the Settlement Agreement, Granite State may not file a new general rate case earlier than April 30, 2028 with rates to be effective no earlier than September 1, 2028 based on a test year ending no earlier than December 31, 2027. On November 25, 2024, the FERC approved Granite State’s filing. As authorized by the Settlement Agreement, on July 29, 2025, Granite State filed a limited Section 4 rate adjustment for an annual revenue increase of $1.2 million, effective September 1, 2025. On August 13, 2025, the FERC approved this filing.

Other Matters

Unitil Energy - Proposal to Construct Utility-Scale Solar Facility - On October 31, 2022, Unitil Energy submitted a petition to the NHPUC for review of Unitil Energy’s proposal to construct, own, and operate a 4.99 MW utility-scale photovoltaic generating facility, which was subsequently revised to a 4.88 MW facility. On May 1, 2023, the NHPUC issued an Order approving the Company's petition.

The facility became fully commissioned in May 2025. Unitil Energy has included a cost recovery proposal associated with the solar facility as part of its pending base rate proceeding filing.

Unitil Energy - Major Storm Cost Reserve Recovery - On February 28, 2025, Unitil Energy filed a request with the NHPUC to increase its Storm Recovery Adjustment Factor (SRAF) effective August 1, 2025. The Company proposed to reduce its Major Storm Cost Reserve deferral balance by transferring its April 2024 Nor’easter costs of approximately $1.8 million into

the SRAF and recover the cost over the next three years. On June 27, 2025, the New Hampshire DOE filed a statement in support of the Company’s request. On August 29, 2025, the NHPUC issued an order approving the Company’s request.

Massachusetts Inquiry into Gas and Electric Delivery Charge and Bill Redesign - On December 15, 2025, the MDPU opened an investigation to conduct a comprehensive review of gas and electric delivery rates and charges with the aims of containing customer costs, reducing utility bill volatility, and increasing utility bill transparency and accessibility. Each Distribution Company has been directed to submit a report that includes certain requested information regarding delivery related reconciling mechanisms and costs by February 13, 2026. The MDPU also seeks written comments from the Distribution Companies and other interested stakeholders responding to a list of questions regarding delivery related reconciling charges on April 14, 2026. Reply comments are due on May 14, 2026.

As a second phase of this investigation, the MDPU will investigate how to redesign utility bills to enhance customer knowledge, agency, and responsiveness to price and policy signals. The MPDU has also indicated its intent to open investigations as follows: 1) in response to the Department of Energy Resources’ (“DOER”) petition requesting an investigation into electric rate design and regulatory mechanisms, 2) to investigate reporting of AMI interval data to ISO New England for load settlement and capacity tag calculations, accelerated switching, and dynamic rate-ready TVR offered by competitive suppliers and municipal aggregators, and 3) to examine the utilities’ current practices and recent performance in customer billing and determine whether the current billing and termination regulations are sufficient to ensure consumer protection.

Massachusetts Solar Massachusetts Renewable Target Program (SMART) 3.0 - On November 21, 2025, the EDCs jointly filed a new tariff (the SMART 3.0 Tariff) with the MDPU to implement the SMART 3.0 Program regulations 225 C.M.R. 28.00, which were filed with the Secretary of State on September 12, 2025 (SMART Regulations). The SMART Program, which was first implemented in 2017, establishes a voluntary statewide solar incentive program under the direction of the DOER. In 2020, the DOER revised its SMART Program regulations, 225 C.M.R. 20.00 -- an update commonly referred to as SMART 2.0. The SMART Program relies on the EDCs to issue incentive payments and alternative on-bill credits to participating customers. Accordingly, the EDCs are seeking approval of revised SMART Tariffs. SMART 3.0 replaces the structure of the initial SMART Program, a declining block incentive program, with a program that contains capacity targets and incentive rates adjusted annually by the DOER. SMART 3.0 Program incentives will be paid over a 20 year term and will vary based on a project’s category and capacity. On January 9, 2026, the EDCs supplemented their filing to provide updated program costs estimates reflecting SMART 3.0 applications received in program year 2025 and assuming full enrollment of all available capacity in program year 2026. Because program year 2025 application levels were significantly lower than the maximum capacity quantities across the EDCs, this resulted in a decrease in estimated maximum statewide costs from $6.7 billion to $4.5 billion over 20 years. Fitchburg’s estimated maximum cost is $191 million over 20 years. The cost projections are illustrative and intended to give the MDPU a sense of scale of the potential long-term costs of the SMART 3.0 Program. The EDCs are not seeking approval of specific costs at this time. The EDCs recover SMART Program costs from all distribution customers through the SMART factor, which is set forth in its current SMART tariff and is updated annually. This matter 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 conducted a hearing on September 26, 2023 on the Company’s then-pending GMF filings and Grid Modernization Term Report. This matter remains pending.

In its Track 2 Order, the MDPU directed the Company and other EDCs to convene a statewide AMI stakeholder working group (AMI Working Group) to address the following issues: (1) customer and third-party access to customer usage data; (2) customer education and engagement; (3) billing of time varying rates (TVR) offered by competitive suppliers; and (4) AMI deployment strategies that may expedite the ability for competitive suppliers to offer TVR products. Additionally, the MDPU directed the EDCs to file quarterly status reports, including a final report that sets forth issues on which a consensus had been reached and those issues that remain to be resolved. On August 1, 2024, the EDCs filed a final report identifying where stakeholders were able and unable to reach consensus.

On November 20, 2024, the MA Legislature enacted the 2024 Climate Act that, among other things, requires the EDCs to jointly establish a centralized data repository in a cost-effective manner as approved by the MDPU, to allow customers and third parties, including competitive suppliers, access to detailed AMI customer data in near-real time, subject to customer approval and protections. The EDCs must submit for MDPU approval a plan for the implementation of AMI data access protocols not later than one year after the effective date of the Act, i.e., by February 18, 2026, in conjunction with the centralized data repository. The Climate Act allows the EDCs to recover prudent and necessary expenses for the implementation of advanced metering data repositories and permits the MDPU to implement penalties for failure by the EDCs to meet implementation goals. The MDPU has opened a docket and provided substantive guidance in anticipation of the Company’s February 2026 filing.

Fitchburg - Grid Modernization Cost Recovery Factor - On April 15, 2023, Fitchburg filed its GMF rate adjustment and reconciliation filing for recovery of the costs incurred as a result of implementing the Company’s 2022-2025 GMP, approved by the MDPU in Orders dated October 7, 2022 and November 30, 2022. On May 31, 2023, the MDPU approved, subject to further investigation and reconciliation, the cumulative recovery of $1.0 million associated with the Company’s 2022 GMP revenue requirement, effective June 1, 2023. The MDPU conducted a hearing on September 26, 2023 regarding the Company’s pending GMF filings and Grid Modernization Term Report. The matter remains pending. On April 15, 2024, Fitchburg filed its GMF rate adjustment and reconciliation filing for recovery of the costs incurred as a result of implementing the Company’s 2022-2025 GMP. On May 31, 2024, the MDPU approved, subject to further investigation and reconciliation, the cumulative recovery of $1.3 million associated with its 2023 revenue requirement, effective June 1, 2024. On June 28, 2024, the MDPU issued an Order in Fitchburg’s electric base rate case providing for the transfer of $1.6 million meter-related costs from base distribution rates to the GMF, effective July 1, 2024. On April 15, 2025, Fitchburg filed its GMF rate adjustment and reconciliation filing for recovery of the costs incurred as a result of implementing the Company’s 2022-2025 GMP and continued recovery of meter-related costs. This filing seeks recovery of $1.4 million associated with its 2024 GMP revenue requirement as well as $1.5 million associated with its 2024 meter-related costs, effective June 1, 2025. On May 30, 2025, the MDPU issued an order approving the Company’s proposed rate changes effective June 1, 2025 subject to further investigation and reconciliation. This matter remains pending.

Fitchburg - Investigation into the role of gas LDCs to achieve Commonwealth 2050 climate goals - On December 6, 2023, the MDPU issued an Order announcing a regulatory framework intended to set forth its role and that of the LDCs in helping the Commonwealth achieve its target of net-zero GHG emissions by 2050. In this proceeding, the MDPU reviewed eight potential decarbonization “pathways” and six regulatory design recommendations intended to facilitate the Commonwealth’s transition. The MDPU made no specific findings as to a preferred pathway or technology, but did make specific findings regarding regulatory design recommendations. The MDPU emphasized that the Order is not intended to jeopardize the rate recovery of existing investments in natural gas infrastructure by Fitchburg. As part of future cost recovery proposals, LDCs will bear the burden of demonstrating that non-gas pipeline alternatives (NPAs) were adequately considered and found to be non-viable or cost prohibitive to receive full cost recovery of investments. The MDPU further found that the “clean energy transition” will require coordinated planning between LDCs and electric distribution companies, monitoring progress through LDC reporting, and aligning existing MDPU practices with climate targets. To that end, the MDPU ordered the LDCs to submit individual Climate Compliance Plans (CCP) every five years beginning in 2025, and to propose climate compliance performance metrics in upcoming performance-based regulation filings, ensuring a proactive approach to achieving climate targets.

On December 29, 2023, the LDCs filed a Joint Motion for Clarification. The Joint Motion requested clarification of three issues: (1) the MDPU’s directive concerning the NPAs analysis; (2) the timetable for establishing ‘incentives and disincentives’ for progress toward compliance with Climate Act mandates as part of a PBR framework and achievement of approved Climate Compliance Plans; and (3) the methodology for emissions reduction accounting for Climate Compliance Plans, with particular attention to Scope 1 and Scope 3 emissions accounting. On April 2, 2024, the MDPU issued an Order on the LDCs’ Joint Motion. In its Order, the MDPU clarified, among other things, that NPA analyses should be applied at the

project level to all investment decisions going forward, and should be considered at project planning stage; that pending an approved NPA framework, LDCs should make all reasonable efforts to incorporate NPA analyses into investment decisions; and that LDCs will have the burden to demonstrate the prudence of implementing a traditional project instead of a NPA. The MDPU did not expressly exempt any category of project from the NPA analysis requirement.

On June 14, 2024, the MDPU directed the LDCs to provide certain information regarding the companies’ line extension policies for customers requesting new service. The LDCs provided responsive information on August 13, 2024; various interested parties provided comments on the companies’ policies on October 11, 2024, and the LDCs, including Fitchburg, provided reply comments on February 27, 2025. On February 5, 2025, the MDPU issued a memorandum setting a draft line extension policy that would require customers seeking new gas service to pay the entire cost of connecting to the distribution system. The Company provided comments on the draft policy on April 3, 2025. On August 8, 2025, the MDPU issued an Interlocutory Order on Policies and Practices for Line Extension Allowances and Contributions In Aid of Construction for Gas Local Distribution Companies setting forth a revised Straw Proposal that would require customers seeking new gas service to pay the entire cost of connecting to the distribution system, subject to certain exceptions and requiring the LDCs to submit model tariffs incorporating the revised policy. The LDCs sought clarification of the Order’s finality and a stay of the Order’s effect. On September 5, 2025, the MDPU issued an Order on the LDCs’ motion, clarifying that the Interlocutory Order is not a final decision, the MDPU has not resolved issues concerning line extension allowance policies, and the LDCs and intervenors will have the opportunity to litigate the line extension allowance issues in the CCP proceedings. The MDPU retained its direction that the LDCs file illustrative tariff revisions.

On April 1, 2025, Fitchburg filed its first CCP. The Company’s plan presents a portfolio of initiatives that will help the Commonwealth meet its decarbonization goals over the next five-to-ten years, while maintaining a focus on customers’ long-term interests in safety, reliability, affordability, and equity. Fitchburg also filed a model CCP Tariff to establish a cost recovery mechanism for the development and implementation of the CCP, including costs associated with assessing and implementing NPAs. This matter remains pending.

Fitchburg - Electric Sector Modernization Plan - Pursuant to M.G.L. c. 164 § 92B, Fitchburg submitted a draft Electric Sector Modernization Plan (ESMP) to the statutorily created Massachusetts Grid Modernization Advisory Council (Council) for the Council’s review, input, and recommendations. The ESMP is a plan intended to upgrade the Company’s distribution system to enable and accommodate increased distributed energy resources (DERs) and electrification technologies, improve grid reliability and resiliency, and assist the Commonwealth in achieving climate goals, among other objectives. The Council provided recommendations on the ESMP in November 2023. The Company submitted its final ESMP to the MDPU on January 29, 2024. The Company concurrently submitted a proposal to recover, among other things, incremental costs associated with ESMP investments through an annual reconciling rate adjustment mechanism. On February 20, 2024, the MDPU issued an interlocutory order finding in part that “to the extent that the MDPU determines that accelerated cost recovery through annual reconciling mechanisms for proposed investments identified in the ESMPs is appropriate, we anticipate establishing the appropriate parameters for those mechanisms through a separate phase of these proceedings to be conducted after August 29, 2024.” On August 29, 2024, the MDPU issued a final order approving Fitchburg’s ESMP. Among other directives, the Order directs Fitchburg and other Massachusetts EDCs to conduct a stakeholder process related to long-term system planning related to forecasted DER interconnection and sets forth the criteria for biannual reports. The MDPU found it appropriate to allow Fitchburg and the other EDCs a short-term targeted cost recovery mechanism for ESMP costs. On December 18, 2024 Fitchburg filed a model ESMP tariff and a company-specific exemplar ESMP mechanism tariff, which describes the parameters of cost-recovery in the second phase of this proceeding. The MDPU conducted an evidentiary hearing on the Company’s proposal on March 12, 2025. On June 13, 2025, the MDPU issued an order which approved the Company’s requested ESMP costs, in part. The MDPU concluded that ESMP substation and distribution feeder investments are ineligible for recovery within the Company’s approved ESMP tariff, but are eligible for recovery under the PBRA. The Company’s resulting approved five year budget is $21.5 million. The Company’s compliance ESMP tariff was approved on July 3, 2025. On September 30, 2025, the Company submitted its first Biannual Report on ESMP investments. The Company informed the MDPU that it is collaborating with the other EDCs to develop a peak demand reduction methodology and template for the next biannual filing to be filed in March 2026.

The MDPU has indicated its intent to investigate how innovative approaches to cost recovery through base distribution rates can further the purpose of G.L. c. 164, § 92B, optimally balance the MDPU’s priorities, and promote efficiency. The MDPU stated that such a proceeding will likely require a lengthy inquiry to identify, analyze, and resolve many complex ratemaking issues. To help inform the subsequent proceeding(s), the MDPU requested comments from interested parties on items and issues that should be considered, including: (1) information and data on innovative approaches to cost recovery, in

particular, to facilitate accelerated electrification and/or grid modernization efforts identified at the federal level and/or successfully implemented or being considered in other states; and (2) discussion and proposals on performance metrics and incentives applicable to longer-term cost recovery considerations. On October 1, 2025, the Company and the other EDCs, at the MDPU’s direction, submitted comments on potential future approaches to cost recovery for Electric Sector Modernization Plan investments and expenses. On October 29, 2025, intervenors submitted comments. Reply comments were filed on November 26, 2025.

Following the stakeholder process related to long-term system planning, Fitchburg and other EDCs submitted a draft Long-Term System Planning Proposal (LTSPP) for MDPU review and approval. On December 16, 2025, the MDPU issued an Order establishing a phased approach to investigate the LTSPP jointly proposed by the electric distribution companies and stakeholders. The MDPU intends to establish a uniform LTSPP for the Distribution Companies to proactively upgrade their respective electric power systems to enable increased, timely interconnection of new distributed generation (DG), which will support the Commonwealth’s energy and climate policies. To expedite the cost-effective deployment and interconnection of DG, Phase I will focus on the establishment of a framework for the LTSPP and other necessary elements for the Distribution Companies to make the first LTSPP filings. The MDPU will investigate additional topics in Phase II, in parallel with Phase I, to ensure effective LTSPP implementation following the MDPU’s review of proposed LTSPP investments. This matter remains pending.

Fitchburg - Electric Vehicle (EV) Proceedings - 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 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% cap. Any spending above the approved EV program budget or above the 15% cap for each program segment is not eligible for targeted cost recovery through the GMF and, instead, may be recovered in a base distribution rate proceeding subsequent to a prudency finding by the MDPU. The MDPU’s Order directs the Companies to submit annual reports that document their performance and these reports are due on or before May 15th of each year. The MDPU accepted the Company’s Demand Charge Alternative proposal and directed implementation within six months. The Demand Charge Alternative is offered for a ten-year period beginning July 1, 2023 with tiered rates to separately-metered EV general delivery service customers. The MDPU also accepted the Company’s proposed residential EV TOU rate, effective April 1, 2023.

In June 2023, the MDPU convened an EV stakeholder process to finalize EV program performance metrics. On April 3, 2023, the electric companies filed comments on the MDPU’s proposed metrics. On December 15, 2023, the MDPU approved EV performance metrics. Following that approval, the MDPU required the electric companies to develop a joint state-wide program evaluation plan for MDPU approval and stakeholder input. On May 15, 2024, Fitchburg submitted its first annual report on the performance of its EV Program, and along with the other Massachusetts EDCs, a proposed statewide program evaluation plan for MDPU approval and stakeholder input. On September 30, 2024, the MDPU stamp approved the Joint Statewide Electric Vehicle Program Evaluation Plan. In addition, on October 1, 2024 the MDPU approved Fitchburg’s request for a supplemental budget increase to engage a consultant to assist with the Joint Statewide Electric Vehicle Program Evaluation Plan. On December 20, 2024, the Company submitted a request for approval to modify certain aspects of the public, residential, and income eligible offers of its EV program. On October 17, 2025, the MDPU approved the Company’s proposed modifications.

On December 31, 2025, Fitchburg submitted to the MDPU a petition for approval of a right-of-way and pole-mounted electric vehicle supply equipment (EVSE) proposal as required by the 2024 Climate Act (Chapter 239, Section 134 of the Acts of 2024). The Company proposes to leverage the program modifications approved on October 17, 2025 to continue to promote public EVSE through its currently approved EV program, which will extend through 2027. This matter remains pending.

Fitchburg - Storm Cost Deferral Petition - On November 3, 2025, Fitchburg filed a request with the MDPU regarding its Storm Reserve Adjustment Factor effective January 1, 2026. The Company requested continued recovery of storm costs resulting from the January and March 2023 winter storms over a three-year period. On December 29, 2025, the MDPU allowed the associated rate increase to become effective January 1, 2026, subject to further investigation and reconciliation. This matter remains pending before the Commission.

Fitchburg- Approval of Gas Supply Agreement with Constellation LNG- On February 16, 2024, Fitchburg filed a petition with the MDPU for approval of a six year agreement with Constellation LNG for the purchase of natural gas in the liquid or vapor form for the period June 1, 2024 through May 31, 2030 heating seasons. This request is for the approval of two

contracts, the first for up to 3,400 Dth per day of natural gas peaking supply to the Company. This first contract will be broken out for 3,000 Dth per Day in the form of LNG for use at the Company’s Westminster LNG facility and 400 Dth per Day will be in the form of natural gas supply delivered to the city-gate connecting the Company’s system to the Tennessee Gas Pipeline. The second contract will provide up to 3,000 Dth per day of LNG trucking from the Everett Marine Terminal to the Company’s Westminster LNG facility.

This Agreement would ensure that the Everett Marine Terminal, which plays a critical role in both the Company’s and the New England energy market’s efficient and reliable operation, will continue to be available for the next six winter seasons. A six year agreement was also requested by Boston Gas Company, Eversource Gas Company, and NSTAR Gas Company. Fitchburg and the other LDCs received an Order on May 17, 2024 approving the agreements.

Unitil Corporation – Merger of Bangor Natural Gas, Inc. - On July 15, 2024, Unitil, Northern Utilities, Hearthstone Holdings, Inc. d/b/a Hope Companies, Inc. (HUI), PHC Utilities, Inc. (PHC), and Bangor Natural Gas Company filed a Joint Petition requesting that the MPUC approve the merger of Bangor into Unitil pursuant to a July 8, 2024 Stock Purchase Agreement among PHC, HUI and Unitil. Furthermore, Unitil requested that the MPUC issue an order excusing Bangor and Unitil from certain regulatory conditions and obligations imposed upon Bangor or its affiliates in conjunction with prior reorganizations of Bangor. Unitil filed a Stipulation supporting the proposed merger, signed by all parties to the docket, on December 4, 2024. Among other provisions, Unitil and Bangor agreed that Bangor would not file a general rate case prior to January 1, 2027. The MPUC issued an Order approving the Stipulation on December 18, 2024. In a separate Order issued January 14, 2025, the MPUC approved the proposed long-term debt facility. Unitil completed the acquisition of Bangor on January 31, 2025.

Unitil Corporation – Merger of Maine Natural Gas Corporation - On May 9, 2025, Unitil, Northern Utilities, Bangor, Avangrid Enterprises, Inc. and Maine Natural filed a Joint Petition requesting that the MPUC approve the merger of Maine Natural into Unitil pursuant to a Stock Purchase Agreement among Avangrid and Unitil. A procedural schedule has been established which includes discovery, technical conferences, testimonies and briefs. To comply with the statutory timeframe of 180 days, deliberations are scheduled to be held no later than early November 2025. The MPUC issued an Order approving the Stipulation on September 12, 2025. In a separate Order issued September 16, 2025, the MPUC approved the proposed long-term debt facility. Unitil completed the acquisition of Maine Natural on October 31, 2025.

Unitil Corporation – Merger of Aquarion Water Companies - On May 6, 2025, Unitil announced that it has entered into a definitive agreement to acquire Aquarion Water Company of Massachusetts Inc., Aquarion Water Company of New Hampshire, Inc., and Abenaki Water Co., Inc. (the Aquarion Companies) from the Aquarion Water Authority (AWA), a quasi-public corporation chartered by the Connecticut General Assembly in 2024 to acquire Aquarion and to operate as a water authority. Unitil’s acquisition of the Aquarion Companies is contingent upon the initial sale of Aquarion by Eversource to the AWA (Initial Transaction), which will then simultaneously convey the Aquarion Companies to Unitil. On November 19, 2025, the Connecticut Public Utilities Regulatory Authority (PURA) denied approval of the Initial Transaction. On December 2, 2025, the joint applicants in the Connecticut proceeding filed a judicial appeal of PURA’s decision denying the Initial Transaction. On January 15, 2026, a decision was issued that remanded the case back to PURA for further deliberations. This case remains pending at PURA.

On May 8, 2025, Eversource Energy (Eversource), the AWA, and Unitil submitted an amended and restated petition to the MDPU for approval of a change of control of Aquarion Water Company of Massachusetts, Inc. (AWC-MA). On December 12, 2025, the MDPU issued an Order approving the stock sale of Aquarion by Eversource to AWA, and, in turn, AWA’s simultaneous sale of AWC-MA to Unitil. The approval is subject to certain conditions, including quarterly service quality reporting and a two-year rate case filing moratorium. The approval is also contingent upon, inter alia, approval of the Initial Transaction. The MDPU also declined to rule on the issue, raised by the MA AGO, of ratemaking treatment of the gain on sale of certain assets that occurred under Eversource ownership. On January 2, 2026, Unitil, Eversource, and AWA filed a motion for reconsideration and clarification of the MDPU’s Order with respect to the rate case moratorium and ratemaking treatment of the gain on sale. This matter remains pending.

On May 8, 2025, Unitil, Eversource, Aquarion Water Company of New Hampshire, Inc., (AWC-NH), Abenaki Water Company (Abenaki) and AWA filed a motion to amend the petition originally filed on April 10, 2025 by Eversource. AWC-NH, Abenaki and AWA, requesting that the NHPUC approve the acquisition of AWC-NH and Abenaki by Unitil. On August 28, 2025, the Joint Petitioners and the DOE submitted a settlement agreement to the NHPUC recommending approval of the proposed acquisition subject to certain conditions, including a rate case stay-out through June 1, 2026. The Office of the Consumer Advocate did not join the settlement. The NHPUC conducted a hearing on the matter on September 25, 2025. On October 7, 2025, the NHPUC issued an Order approving the settlement agreement.

On May 23, 2025, pursuant to 35-A M.R.S. § 708, Northern Utilities filed a request that the MPUC grant an exemption from approval of the reorganization that will be triggered by the anticipated acquisition by Unitil of the three water utilities in Massachusetts and New Hampshire. The MPUC has previously granted Maine public utilities exemptions from regulatory approval of reorganizations under circumstances similar to those presented in this case involving the acquisition of companies outside of Maine by a utility’s holding company parent that will have no direct financial or operational impact on the Maine utility. Based on MPUC precedent in similar reorganizations, Northern Utilities requested an exemption from Section 708 approval of Unitil’s acquisition of the Aquarion MA-NH Companies. In the alternative, if the MPUC declines to grant the requested exemption, then Northern Utilities requested that the MPUC approve the reorganization pursuant to Section 708. The MPUC approved the reorganization, subject to certain conditions agreed upon by Unitil, on January 6, 2025.

Northern Utilities / Granite State - Firm Capacity Contract - Northern Utilities relies on the transportation of gas supply over its affiliate Granite State pipeline to serve its customers in the Maine and New Hampshire service areas. Granite State facilitates critical upstream interconnections with interstate pipelines and third-party suppliers essential to Northern Utilities’ service to its customers. Northern Utilities reserves firm capacity through a contract with Granite State, which is renewed annually. Pursuant to statutory requirements in Maine and orders of the MPUC, Northern Utilities submits an annual informational report requesting approval of a one-year extension of its 12-month contract for firm pipeline capacity reservation, with an evergreen provision and three-month termination notification requirement. On March 31, 2025, Northern Utilities submitted an annual informational report requesting approval on a one-year extension for the period of November 1, 2025 through October 31, 2026. The Company received an order approving the one-year extension of its request on June 3, 2025.

Northern Utilities / Portland Natural Gas Transmission System (PNGTS) and TransCanada Pipelines Limited (TCPL) transportation from Empress, Alberta to Granite State Gas Transmission, Inc. (GSGT) - On October 5, 2023, Northern Utilities filed with the NHPUC and the MPUC a request to approve agreements for the ability for Northern Utilities to increase supply portfolio capacity by 12,500 Dth per day in New Hampshire and Maine. This incremental capacity to Northern Utilities’ supply portfolio took effect April 1, 2024 for a thirty-year term. Northern Utilities was able to acquire this incremental supply of TCPL capacity through an open season process. On January 26, 2024 and January 30, 2024, the Company received orders from the NHPUC and MPUC, respectively, approving Northern Utilities’ proposal for Empress Agreements with PNGTS and TransCanada Pipelines. Conservation Law Foundation filed a motion for reconsideration of the MPUC’s decision on February 15, 2024. The Company objected to the motion, and on March 26, 2025, the Hearing Examiners issued a Recommended Order on Reconsideration from the MPUC on this CLF motion. The Recommended Order, if adopted, would affirm the MPUC’s previous decision to approve the Company’s entry into these Agreements. The MPUC issued an Order reaffirming and clarifying its initial Order approving the Empress Agreements, and specifically affirmed its conclusion that entering into the Empress Capacity Agreements is prudent, in the public interest, and not inconsistent with the state’s climate policy.

Maine Inquiry Into the Future of Gas - On May 13, 2025, the MPUC initiated an inquiry to explore the implications of Maine’s decarbonization goals for natural gas utilities and their customers and solicit information from stakeholders. Specifically, the MPUC opened the inquiry with the goal of 1) developing a consistent methodology or framework to incorporate and evaluate the GHG emissions impact in the MPUC’s decision-making around gas infrastructure investments and contractual commitments for supply or capacity needed to serve customers; 2) evaluating the consistency of these investments with state goals and 3) assisting in evaluation of a broader path for the future of natural gas in Maine. Initial comments on the scope of the inquiry were submitted on June 17, 2025. On December 18, 2025, the MPUC issued a Procedural Order scheduling a workshop on January 21, 2026 to explore issues raised in comments.

Reconciliation Filings - Fitchburg, Unitil Energy, Northern Utilities, Bangor and Maine Natural each have a number of regulatory reconciling accounts that require annual or semi-annual filings with the MDPU, NHPUC and MPUC, respectively, to reconcile revenues and costs, and to seek approval of any rate changes. These filings include: 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 Fitchburg; and the actual wholesale energy costs for electric power and gas incurred by each of the five companies. Fitchburg, Unitil Energy, Northern Utilities, Bangor and Maine Natural 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 83 of “An Act Relative to Green Communities,” St. 2008, c. 169, as amended, the Massachusetts EDCs, including Fitchburg, have conducted numerous procurements of long-term renewable energy and environmental attributes. “An Act to Promote Energy Diversity” (2016) (the Act) added Section 83C, which required the joint procurement of 1,600 MW of offshore wind by June 30, 2027 (this target has since been increased as explained below) and Section 83D, which required the joint procurement of cost-effective long-term contracts for an annual total of 9,450,000 megawatt-hours (MWh) of clean energy (hydroelectric, solar and land-based wind) by December 31, 2022. Fitchburg’s pro rata share of the contracts resulting from these procurements is approximately 1%.

The EDCs issued the RFP for Section 83D Long-Term Contracts in March 2017, and transmission service agreements with NECEC Transmission LLC and power purchase agreements (PPAs) for 9,554,940 MWh annually of hydroelectric generation and associated environmental attributes with Hydro-Quebec Energy Services (U.S.), Inc. (together, the NECEC project) over a 20-year period, were filed for approval by the MDPU in July 2018. The MDPU approved the agreements in June 2019, including the EDCs’ proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market revenue to customers. The MDPU also approved the EDCs’ request for remuneration equal to 2.75% of the contract payments, as well as the EDCs’ proposal to recover costs associated with the contracts. The NECEC project achieved commercial operation in January 2026.

The EDCs issued the first RFP for offshore wind energy generation pursuant to Section 83C in June 2017. In July 2018, the EDCs filed two long-term PPA’s with Vineyard Wind, each for 400 MW for approval by the MDPU. In April 2019, the MDPU approved the offshore wind PPAs, including similar requirements for the EDCs’ to sell the energy procured and credit or charge net costs to customers including EDC remuneration of 2.75%. The expected commercial operation dates for Vineyard Wind are January 15, 2027 for Facility 1 and May 31, 2026 for Facility 2.

The EDCs issued additional RFPs pursuant to Section 83C to procure additional offshore wind energy generation in May 2019 and in May 2021. These two procurements led to four additional PPAs for a total of 2400 MW that were approved by MDPU but were later terminated in September 2023.

The EDCs issued a fourth offshore wind RFP in August 2023 seeking to procure at least 400 MW and up to the maximum amount remaining of the statutory requirement under Section 83C of 5,600 MW of Offshore Wind Energy Generation, pursuant to “An Act Driving Clean Energy and Offshore Wind” (2022), which increased the total solicitation target (including future solicitations) for offshore wind energy generation to 5,600 MW by June 30, 2027. The EDCs received bids for offshore wind energy generation from three developers as part of a multi-state solicitation with Rhode Island and Connecticut. In September 2024, the Massachusetts DOER selected a portfolio of projects totaling 2,678 MW from the three projects, one of which was dependent on commitments from Connecticut. In December 2024, Connecticut withdrew from contract negotiations resulting in the termination of the conditional project. Contract negotiations with the remaining two developers have been extended and are targeted to be completed by June 30, 2026.

In December 2024, the Massachusetts Legislature approved “An Act promoting a clean energy grid, advancing equity, and protecting ratepayers” which among other provisions, extends the period for long-term renewable contracts up to 30 years and directs the EDCs, under a new Section 83E, to “jointly and competitively solicit proposals for energy storage systems and enter into cost-effective long-term contracts equal to, in the aggregate, approximately 5,000 megawatts of energy storage systems not later than July 31, 2030.” Pursuant to Section 83E, the EDCs jointly issued the first RFP for energy storage systems (ESS) in July 2025 seeking environmental attributes associated with approximately 1,500 megawatts of mid-duration energy storage systems. In December 2025, the DOER selected a portfolio of battery energy storage projects that total 1,268 MW and contract negotiations are underway. A second solicitation under Section 83E is currently being developed for release in July 2026. Fitchburg’s pro rata share of the contracts resulting from these procurements is approximately 1%.

Pursuant to Section 82 of Chapter 179 of the Acts of 2022 (An Act driving clean energy and offshore wind), the Massachusetts DOER is authorized to coordinate with other New England states issuing competitive solicitations for long-term clean energy generation, including nuclear power generation, associated environmental attributes, transmission or capacity for

the benefit of residents of the Commonwealth and the region. If the DOER, in consultation with the EDCs and the office of the Attorney General, determines not later than December 31, 2027, that a project would satisfy the benefits listed in Section 82, DOER may direct the EDCs to enter into cost-effective long-term contracts. DOER is currently exploring procurements issued by Maine and Connecticut. In September 2025, Connecticut issued an Expedited Zero Carbon RFP and following selections made by Connecticut, DOER selected two projects for Massachusetts.

Unitil Energy/Northern Utilities - 2024-2026 Triennial Energy Efficiency Plan - New Hampshire - On November 30, 2023, the NHPUC approved the changes to New Hampshire’s ratepayer-funded energy efficiency program offerings for the 2024–2026 period requested by New Hampshire’s electric and gas utilities. On July 1, 2024, the New Hampshire electric and gas utilities filed an interim update with the NHPUC, seeking approval to update the energy efficiency program models with benefit assumptions from the recently issued report of Avoided Energy Supply Components in New England: 2024 Report.

Fitchburg Energy Efficiency Programs - Both the electric and gas divisions of Fitchburg actively participate in the energy efficiency programs in Massachusetts, as directed by the MDPU. These programs require periodic filings and are subject to investigation and review. The Company considers these to be routine regulatory proceedings. The MDPU recently approved the Massachusetts utilities’ 2025-2027 three-year energy efficiency plan subject to certain modifications, including a $500 million reduction to the total residential sector budget.

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 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. (RENEW), 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. FERC issued an Order December 19, 2024 and a compliance filing was made on February 18, 2025 revising the ISO-NE OATT accordingly. While most of the intervening parties supported the compliance filing a new issue was raised by one participant. RENEW and the NETO’s have resolved their issues and filed briefs in support of the compliance filing. This matter remains pending in Docket No. EL23-16. The Company does not believe these proceedings will have a material adverse effect on its financial condition or results of operations.

Contractual Obligations

The following table lists the Company’s known specified gas and electric supply contractual obligations as of December 31, 2025.


			Payments Due by Period
Gas and Electric Supply Contractual Obligations (millions) as of December 31, 2025	Total		2026		2027		2028		2029		2030		2031 & Beyond
Gas Supply Contracts	$	779.4	$	113.6	$	81.1	$	74.1	$	67.9	$	53.2	$	389.5
Electric Supply Contracts		198.3		9.0		9.2		9.2		9.1		9.3		152.5
Total	$	977.7	$	122.6	$	90.3	$	83.3	$	77.0	$	62.5	$	542.0

The Company and its subsidiaries have material energy supply commitments (see Note 6 Energy Supply). Cash outlays for the purchase of electricity and natural gas to serve customers are subject to reconciling recovery through periodic changes in rates, with carrying charges on deferred balances. From year to year, there are likely to be timing differences associated with the cash recovery of such costs, creating under- or over-recovery situations at any point in time. Rate recovery mechanisms are

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

Legal Proceedings

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

Environmental Matters

The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company is in material compliance with applicable environmental and safety laws and regulations and, as of December 31, 2025, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, the Company cannot assure that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs. Based on its current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, the Company does not believe that these environmental costs will have a material adverse effect on the Company’s consolidated financial position or results of operations.

Northern Utilities Manufactured Gas Plant Sites - Northern Utilities has an extensive program to identify, investigate and remediate former manufactured gas plant (MGP) sites, which were operated from the mid-1800s through the mid-1900s. In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. In Maine, Northern Utilities has documented the presence of MGP sites in Lewiston and Portland, and a former MGP disposal site in Scarborough.

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

In May 2024, NH DES requested additional information in connection with the Company’s December 2022 remedial action plan (RAP), regarding groundwater contaminants at the Rochester site. In anticipation of the NH DES approval of one of the RAP alternatives and subsequent request for project design, the Company has accrued $5.8 million for estimated costs to complete the remediation at the Rochester site, which is included in Environmental Obligations on the Company’s Consolidated Balance Sheets. Due to extended regulatory review time periods, Northern Utilities anticipates the commencement of remediation activities in 2026.

The NHPUC and MPUC have approved regulatory mechanisms for the recovery of MGP environmental costs. For Northern Utilities’ New Hampshire division, the NHPUC has approved the recovery of MGP environmental costs over succeeding seven-year periods. For Northern Utilities’ Maine division, the MPUC has authorized the recovery of environmental remediation costs over succeeding five-year periods.

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

Fitchburg’s Manufactured Gas Plant Site - Fitchburg has worked with the Massachusetts Department of Environmental Protection (Mass DEP) to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring continues. Following submittal of the Immediate Response Action (IRA) plan in October 2023 and an update in November 2024, the Mass DEP, in May 2025 concurred with the proposed limited excavation and armoring of the riverbank at the identified seep area. Fitchburg has accrued $280,000 for estimated costs to complete the remediation at the Sawyer Passway site, which is included in Environmental Obligations on the Company’s Consolidated Balance Sheets. The Company has determined that the high end of the range of reasonably possible

remediation costs for the Sawyer Passway site could be $3.7 million based on remediation alternatives. Fitchburg anticipates the commencement of the remediation activity in 2026.

Fitchburg recovers the environmental response costs incurred at this former MGP site in gas rates pursuant to the terms of a cost recovery agreement approved by the MDPU. Pursuant to this agreement, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods.

Unitil Energy - Kensington Distribution Operations Center - Unitil Energy conducted a Phase I and II supplement environmental site assessment (ESA) in the second quarter of 2021 at its former distribution operations center in Kensington, NH. In November 2025, the NH DES requested additional investigation to further refine the Supplemental Site Investigation (SSI) submitted in June 2023, as well as develop a remedial action plan (RAP) based upon reported observations. Unitil Energy anticipates the commencement of remediation activities in late 2026 or early 2027, following RAP approval by the NH DES. The Company does not believe this investigation will have a material adverse effect on its financial condition, results of operations or cash flows.

The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the years-ended December 31, 2025 and 2024.


	December 31,
Environmental Obligations (millions)	2025		2024
Total Balance at Beginning of Period	$	7.8	$	4.6
Additions		1.0		3.6
Less: Payments / Reductions		0.7		0.4
Total Balance at End of Period		8.1		7.8
Less: Current Portion		0.8		0.7
Noncurrent Balance at End of Period	$	7.3	$	7.1

Debt and Financing Arrangements- Details on Long Term Debt (Parenthetical) (Detail)		12 Months Ended
	Oct. 31, 2025	Dec. 31, 2025
Debt Instrument [Line Items]
Debt instrument due date	Oct. 31, 2026
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
5.99% Senior Notes, Due August 21, 2034
Debt Instrument [Line Items]
Stated interest rate		5.99%
Debt instrument due date		Aug. 21, 2034
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		8.00%
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
First Mortgage Bonds 5.69% Senior Secured Notes Due August 21, 2054 \| Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate		5.69%
Debt instrument due date		Aug. 21, 2054
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
5.70 % Senior Note Due to July 2, 2033 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate		5.70%
Debt instrument due date		Jul. 02, 2033
5.54% Senior Notes Due to August 21, 2034 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate		5.54%
Debt instrument due date		Aug. 21, 2034
5.54% Senior Notes Due to August 21, 2034 \| Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate		5.54%
Debt instrument due date		Aug. 21, 2034
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
Senior Notes Five Point Nine Nine percent Due August Twenty One Twenty Forty Four [Member] \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate		5.99%
Debt instrument due date		Aug. 21, 2044
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
5.96% Senior Note Due to July 2, 2053 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate		5.96%
Debt instrument due date		Jul. 02, 2053
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
5.74% Senior Notes, Due August 21, 2039 \| Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate		5.74%
Debt instrument due date		Aug. 21, 2039
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
5.70% Senior Notes, Due July 8, 2030 \| Bangor Natural Gas
Debt Instrument [Line Items]
Stated interest rate		5.70%
Debt instrument due date		Jul. 08, 2030
6.31% Senior Notes, Due July 8, 2035 \| Bangor Natural Gas
Debt Instrument [Line Items]
Stated interest rate		6.31%
Debt instrument due date		Jul. 08, 2035
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
5.74% Senior Notes, Due August 21, 2034 \| Granite State Gas Transmission Inc
Debt Instrument [Line Items]
Stated interest rate		5.74%
Debt instrument due date		Aug. 21, 2034
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

Retirement Benefit Plans - Assets Measured at Fair Value on Recurring Basis for PBOP Plan (Detail) - Retirement Benefits - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 65,481	$ 58,402	$ 51,892
Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	28,765	25,908
Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	36,716	32,494
Fair Value Inputs Level 1
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	65,481	58,402
Fair Value Inputs Level 1 \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	28,765	25,908
Fair Value Inputs Level 1 \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	36,716	32,494
Fair Value Inputs Level 2
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	0	0
Fair Value Inputs Level 2 \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	0	0
Fair Value Inputs Level 2 \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	0	0
Fair Value Inputs Level 3
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	0	0
Fair Value Inputs Level 3 \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	0	0
Fair Value Inputs Level 3 \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 0	$ 0

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

+ Details

- Definition

Amount of asset segregated and restricted to provide benefit under defined benefit plan. Asset includes, but is not limited to, stock, bond, other investment, earning from investment, and contribution by employer and employee.

+ References

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+ Details

Retirement Benefit Plans - Estimated Future Benefit Payments (Detail) $ in Thousands	Dec. 31, 2025 USD ($)
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
2026	$ 9,244
2027	10,322
2028	10,396
2029	10,732
2030	11,313
2031-2035	57,726
Retirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2026	4,142
2027	4,369
2028	4,587
2029	5,046
2030	5,159
2031-2035	26,363
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
2026	678
2027	677
2028	1,190
2029	1,181
2030	1,172
2031-2035	$ 5,658

Summary of Significant Accounting Policies - Components of Accrued Revenue (Detail) - USD ($)
$ in Millions

Dec. 31, 2025

Dec. 31, 2024

Deferred Revenue Arrangement [Line Items]

Regulatory Assets – Current

^[1]

$ 78.1

$ 70.1

Total Accrued Revenue

87.0

77.4

Unbilled Revenues

Deferred Revenue Arrangement [Line Items]

Regulatory Assets – Current

8.9

7.3

Regulatory Assets

Deferred Revenue Arrangement [Line Items]

Regulatory Assets – Current

$ 78.1

$ 70.1

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

Segment Information (Additional Information) (Details)	12 Months Ended
Segment Information (Additional Information) (Details)	Dec. 31, 2025 Segment
Segment Reporting [Abstract]
Number of operating segments	2
Number of reportable segments	2

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Dividends per Common Share	$ 1.8	$ 1.7	$ 1.62
Common stock, shares issued	1,651,497	19,510	21,321

Pay vs Performance Disclosure - USD ($) $ in Millions	12 Months Ended
Pay vs Performance Disclosure - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Pay vs Performance Disclosure
Net Income (Loss)	$ 50.2	$ 47.1	$ 45.2

- Definition

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

+ References

+ Details

CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Millions

Dec. 31, 2025

Dec. 31, 2024

Current Assets:

Cash and Cash Equivalents

$ 15.6

$ 6.3

Accounts Receivable, Net

98.6

75.0

Accrued Revenue

87.0

77.4

Exchange Gas Receivable

9.8

6.4

Gas Inventory

1.3

1.1

Materials and Supplies

15.4

14.2

Prepayments and Other

12.4

8.4

Total Current Assets

240.1

188.8

Utility Plant:

Electric

752.2

699.4

Gas

1,413.0

1,189.9

Common

75.3

69.0

Construction Work in Progress

101.7

92.9

Utility Plant

2,342.2

2,051.2

Less: Accumulated Depreciation

543.7

511.6

Net Utility Plant

1,798.5

1,539.6

Other Noncurrent Assets:

Regulatory Assets

38.8

41.9

Operating Lease Right of Use Assets

7.0

6.7

Goodwill

4.3

0.0

Other Assets

45.5

17.5

Total Other Noncurrent Assets

95.6

66.1

TOTAL ASSETS

2,134.2

1,794.5

Current Liabilities:

Accounts Payable

62.9

49.7

Short-Term Debt

255.7

105.8

Long-Term Debt, Current Portion

^[1]

37.9

4.9

Regulatory Liabilities

16.7

17.2

Energy Supply Obligations

11.6

10.0

Environmental Obligations

0.8

0.7

Operating Lease Obligations

2.1

1.8

Interest Payable

9.4

8.4

Other Current Liabilities

28.7

30.2

Total Current Liabilities

425.8

228.7

Noncurrent Liabilities:

Retirement Benefit Obligations

32.9

25.5

Deferred Income Taxes, Net

196.7

186.1

Cost of Removal Obligations

153.0

139.2

Regulatory Liabilities

64.1

46.8

Environmental Obligations

7.3

7.1

Operating Lease Obligations

4.9

Other Noncurrent Liabilities

7.3

5.3

Total Noncurrent Liabilities

466.2

414.9

Capitalization:

Long-Term Debt, Less Current Portion

632.6

638.4

Stockholders' Equity:

Common Equity (No par value, Authorized 25,000,000 Shares; Outstanding 16,192,345 and 16,192,345 Shares as of respective dates)

418.2

341.2

Retained Earnings

191.2

171.1

Total Common Stock Equity

609.4

512.3

Preferred Stock

0.2

Total Stockholders' Equity

609.6

512.5

Total Capitalization

1,242.2

1,150.9

Commitments and Contingencies (Note 7)

TOTAL LIABILITIES AND CAPITALIZATION

$ 2,134.2

$ 1,794.5

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

Commitments and Contingencies - Additional Information (Detail)																						12 Months Ended
	Jan. 09, 2026 USD ($)	Nov. 21, 2025	Jul. 01, 2025 USD ($)	May 01, 2025 USD ($)	Apr. 15, 2025 USD ($)	Feb. 28, 2025 USD ($)	Dec. 09, 2024 USD ($)	Nov. 26, 2024 USD ($)	Nov. 01, 2024 USD ($)	Oct. 04, 2024 USD ($)	Sep. 11, 2024 USD ($)	Jul. 18, 2024 USD ($)	Jun. 28, 2024 USD ($)	Sep. 20, 2023 USD ($)	Aug. 17, 2023 USD ($)	Jul. 26, 2023 USD ($)	Dec. 30, 2022 USD ($)	Jul. 20, 2022 USD ($)	Jun. 08, 2022 USD ($)	Jun. 25, 2019	Feb. 28, 2018 USD ($)	Dec. 31, 2025 USD ($) Megawatts	Dec. 31, 2024 Megawatts	Oct. 31, 2025 USD ($)	Apr. 30, 2025 USD ($)	Nov. 25, 2024 USD ($)	Oct. 31, 2024 USD ($)	Sep. 06, 2024 MW	May 31, 2024 USD ($)	Aug. 30, 2023 MW	May 31, 2023 USD ($)	Nov. 30, 2022 USD ($)	Oct. 07, 2022 USD ($)	May 31, 2021 MW	Jul. 31, 2018 MWh MW	Jun. 30, 2017 MWh MW
Commitments And Contingencies [Line Items]
Spending cap																						$ 977,700,000
Remuneration Percentage																				2.75%
Approved annual increase in rates														$ 7,600,000
Requested annual increase in rates																					$ 2,100,000
Approved commitments for purchasing assets																	$ 1,000,000
Percentage of Weighted Average Cost Inventory														7.22%
Stock Split Conversion Ratio														0.5201
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
Major Storm Cost Reserve Recovery [Member]
Commitments And Contingencies [Line Items]
Recover costs of repairing damage						$ 1,800,000
Marketing And Outreach [Member]
Commitments And Contingencies [Line Items]
Approved commitments for purchasing assets																	$ 200,000
Gas Division [Member]
Commitments And Contingencies [Line Items]
Accumulated deferred income taxes							$ 600,000
Electric Division [Member]
Commitments And Contingencies [Line Items]
Accumulated deferred income taxes							800,000
Environmental Restoration Costs [Member]
Commitments And Contingencies [Line Items]
Estimated Costs Accrued For Remediation																						$ 5,800,000
Massachusetts Solar Massachusetts Renewable Target Program (SMART) 3.0
Commitments And Contingencies [Line Items]
Program duration		20 years
Subsequent Event [Member] \| Massachusetts Solar Massachusetts Renewable Target Program (SMART) 3.0
Commitments And Contingencies [Line Items]
Program duration	20 years
Subsequent Event [Member] \| Maximum [Member] \| Massachusetts Solar Massachusetts Renewable Target Program (SMART) 3.0
Commitments And Contingencies [Line Items]
Program costs	$ 6,700,000,000
Estimate program cost	191,000,000
Subsequent Event [Member] \| Minimum [Member] \| Massachusetts Solar Massachusetts Renewable Target Program (SMART) 3.0
Commitments And Contingencies [Line Items]
Program costs	$ 4,500,000,000
Northern Utilities Inc
Commitments And Contingencies [Line Items]
Approved annual increase in rates																		$ 6,100,000
Northern Utilities Inc \| Maximum [Member]
Commitments And Contingencies [Line Items]
Program duration																						1 year
Northern Utilities Inc \| New Hampshire
Commitments And Contingencies [Line Items]
Percentage of approved return on equity, reflecting on equity																		52.00%
Percentage of approved return on equity, reflecting on debt																		48.00%
Percentage of approved return on equity																		9.30%
Requested annual increase in rates																			$ 1,600,000
Northern Utilities Inc \| Maine
Commitments And Contingencies [Line Items]
Percentage of approved return on equity														9.35%
Fitchburg Gas and Electric Light Company
Commitments And Contingencies [Line Items]
Increase (decrease) in annual revenue									$ 500,000		$ 3,500,000					$ 3,100,000
Power generation capacity \| MWh																																				9,450,000
Percentage of approved return on equity, reflecting on equity													52.00%
Percentage of approved return on equity, reflecting on debt													48.00%
Percentage of approved return on equity													9.40%
Regulatory assets approved increase in revenue due to be recovered																								$ 200,000
Accumulated deferred income taxes							1,400,000	$ 100,000				$ 1,400,000
Transfer revenue amount													$ 2,200,000
Facility power capacity to be procured in the future \| MW																														400
Reduction in total residential sector budget																						$ 500,000,000
Energy storage systems \| Megawatts																						1,268	5,000
Mid-Duration Storage \| Megawatts																							1,500
Fitchburg Gas and Electric Light Company \| Gas Division [Member]
Commitments And Contingencies [Line Items]
Accumulated deferred income taxes							(600,000)
Fitchburg Gas and Electric Light Company \| Electric Division [Member]
Commitments And Contingencies [Line Items]
Accumulated deferred income taxes							(800,000)
Fitchburg Gas and Electric Light Company \| Maximum [Member]
Commitments And Contingencies [Line Items]
Extended long-term renewable contracts																							30 years
Fitchburg Gas and Electric Light Company \| July 1, 2024 [Member]
Commitments And Contingencies [Line Items]
Approved annual increase in rates															$ 6,800,000
Approved annual increase in rates													4,700,000
Fitchburg Gas and Electric Light Company \| Offshore Wind Energy
Commitments And Contingencies [Line Items]
Power generation facility \| MW																																		2,400	400	1,600
Facility power capacity to be procured in the future \| MW																												2,678		5,600
Fitchburg Gas and Electric Light Company \| Qualified Clean Energy
Commitments And Contingencies [Line Items]
Power generation capacity \| MWh																																			9,554,940
Fitchburg Gas Company
Commitments And Contingencies [Line Items]
Percentage of approved return on equity, reflecting on equity															52.00%
Percentage of approved return on equity, reflecting on debt															48.00%
Percentage of approved return on equity															9.40%
Regulatory assets approved increase in revenue due to be recovered																											$ 3,500,000
Approved annual increase in rates															$ 6,700,000
Accumulated deferred income taxes							$ 1,400,000					$ 1,400,000
Transfer revenue amount															4,200,000
Increase in cost															4,900,000
Fitchburg Gas Company \| July 1, 2024 [Member]
Commitments And Contingencies [Line Items]
Public utilities interim increase decrease amount													10,100,000		$ 10,900,000
Granite State
Commitments And Contingencies [Line Items]
Increase (decrease) in annual revenue										$ 3,000,000
Spending cap										$ 29,900,000
Revenue increase approved by regulator																										$ 1,200,000
Fitchburg Grid Modernization
Commitments And Contingencies [Line Items]
Order providing cost					$ 1,500,000								$ 1,600,000
Regulatory assets approved increase in revenue due to be recovered					$ 1,400,000																								$ 1,300,000		$ 1,000,000
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
Fitchburg Manufactured Gas Plant Site
Commitments And Contingencies [Line Items]
Remediation costs																						$ 3,700,000
Fitchburg Manufactured Gas Plant Site \| Environmental Restoration Costs [Member]
Commitments And Contingencies [Line Items]
Estimated Costs Accrued For Remediation																						$ 280,000
Environmental Remediation Expense, before Recovery, Statement of Income or Comprehensive Income [Extensible Enumeration]																						Utilities Operating Expense
Unitil Energy Systems Inc
Commitments And Contingencies [Line Items]
Approved annual increase in rates				$ 18,500,000
Public Utility Rate Change Percentage			3.70%	7.30%
Public utilities approved increase amount of annual revenue to recover eligible capital investments			$ 7,800,000
Fitchburg Performance Base Rate Adjustment Electric
Commitments And Contingencies [Line Items]
Increase (decrease) in annual revenue						1,600,000
Fitchburg Performance Base Rate Adjustment Gas
Commitments And Contingencies [Line Items]
Increase (decrease) in annual revenue						$ 700,000
Fitchburg Gas System Enhancement Program
Commitments And Contingencies [Line Items]
Regulatory assets approved increase in revenue due to be recovered																								5,400,000
Regulatory assets approved recovery amount																									$ 3,500,000
Regulatory assets deferred cost																								1,000,000	1,600,000
Regulatory recovery amount																								$ 6,400,000	$ 5,100,000
Fitchburg Gas System Enhancement Program \| GSEP Two Thousand Twenty Six
Commitments And Contingencies [Line Items]
Recovery cap rate																									2.00%
Fitchburg Gas System Enhancement Program \| GSEP Two Thousand Twenty Seven
Commitments And Contingencies [Line Items]
Recovery cap rate																									1.50%
Fitchburg Gas System Enhancement Program \| Maximum [Member] \| GSEP Two Thousand Twenty Five
Commitments And Contingencies [Line Items]
Revenue Cap																									3.00%
Fitchburg Gas System Enhancement Program \| Minimum [Member] \| GSEP Two Thousand Twenty Five
Commitments And Contingencies [Line Items]
Revenue Cap																									2.50%

Summary Of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2025

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), Bangor Natural Gas Company (Bangor), Maine Natural Gas Corporation (Maine Natural), Granite State Gas Transmission, Inc. (Granite State), Unitil Power Corp. (Unitil Power), Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service), Unitil Resources, Inc. (Unitil Resources) and Unitil Water Corp. (Unitil Water).

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, portions of central Maine including Augusta and the Bangor area, and in the greater Fitchburg area of north central Massachusetts. Unitil has five distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire; Fitchburg, which operates in Massachusetts; Northern Utilities, which operates in New Hampshire and Maine; and Bangor and Maine Natural, which operate in Maine (collectively, the distribution utilities).

Granite State is an interstate natural gas transmission pipeline company, operating 85 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. 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 seventh utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy, but ceased being the wholesale supplier of Unitil Energy with the implementation of industry restructuring and divested its long-term power supply contracts.

Unitil also has four other wholly-owned subsidiaries: Unitil Service, Unitil Resources, Unitil Realty and Unitil Water. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary, which currently does not have any activity. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Realty also owns land in Kingston, New Hampshire on which Unitil Energy’s solar facility is located, which became operational in May 2025. Unitil Water currently has no activity.

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

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, 2025
Electric and Gas Operating Revenues (millions):	Electric		Gas			Total
Billed and Unbilled Revenue:
Residential	$	121.1	$	121.2		$	242.3
Commercial & Industrial		94.9		171.0			265.9
Other		13.1		13.8			26.9
Total Billed and Unbilled Revenue		229.1		306.0			535.1
Rate Adjustment Mechanism Revenue		7.3		(6.4	)		0.9
Total Electric and Gas Operating Revenues	$	236.4	$	299.6		$	536.0


	Twelve Months Ended
	December 31, 2024
Electric and Gas Operating Revenues (millions):	Electric			Gas		Total
Billed and Unbilled Revenue:
Residential	$	135.0		$	92.6	$	227.6
Commercial & Industrial		103.4			133.5		236.9
Other		10.4			9.7		20.1
Total Billed and Unbilled Revenue		248.8			235.8		484.6
Rate Adjustment Mechanism Revenue		(0.5	)		10.7		10.2
Total Electric and Gas Operating Revenues	$	248.3		$	246.5	$	494.8


	Twelve Months Ended
	December 31, 2023
Electric and Gas Operating Revenues (millions):	Electric			Gas			Total
Billed and Unbilled Revenue:
Residential	$	181.6		$	98.8		$	280.4
Commercial & Industrial		120.1			146.9			267.0
Other		10.0			8.1			18.1
Total Billed and Unbilled Revenue		311.7			253.8			565.5
Rate Adjustment Mechanism Revenue		(5.2	)		(3.2	)		(8.4	)
Total Electric and Gas Operating Revenues	$	306.5		$	250.6		$	557.1

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

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: 2025 - 3.45%, 2024 - 3.49% and 2023 - 3.33%.

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.

In December 2023, the FASB issued ASU 2023-09, Income Taxes - Improvements to Income Tax Disclosures (ASU 2023-09). ASU 2023-09 establishes new income tax disclosure requirements in addition to modifying and eliminating certain existing requirements. The amendments in ASU 2023-09 are effective for annual periods beginning after December 15, 2024, with early adoption permitted. The Company adopted this new guidance for the year ended December 31, 2025 and it did not have a material effect on the Company’s Consolidated Financial Statements (See Note 9 Income Taxes).

Dividends

Dividends - The Company’s dividend policy is reviewed periodically by the Board. The amount and timing of all dividend payments is subject to the discretion of the Board and will depend upon business conditions, results of operations, financial conditions and other factors. For the year ended December 31, 2025, the Company paid quarterly dividends of $0.45 per share, resulting in an annualized dividend rate of $1.80 per common share. For the years ended December 31, 2024 and 2023, the Company paid quarterly dividends of $0.425 and $0.405 per common share, respectively, resulting in annualized dividend rates of $1.70 and $1.62 per common share, respectively. At a January 2026 meeting of the Board, the Board declared a quarterly dividend on the Company’s common stock of $0.475 per share, an increase of $0.025 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $1.90 per share from $1.80 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, 2025 and 2024, the Unitil subsidiaries had deposited $8.5 million and $5.0 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 which are under traditional cost of service regulation 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).

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, 2025 and 2024.


	December 31,
Accrued Revenue (millions)	2025		2024
Regulatory Assets—Current	$	78.1	$	70.1
Unbilled Revenues		8.9		7.3
Total Accrued Revenue	$	87.0	$	77.4

Exchange Gas Receivable

Exchange Gas Receivable - Northern Utilities, Fitchburg and Bangor 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, 2025 and 2024.


	December 31,
Exchange Gas Receivable (millions)	2025		2024
Northern Utilities	$	8.0	$	6.0
Fitchburg		0.5		0.4
Bangor		1.3		—
Total Exchange Gas Receivable	$	9.8	$	6.4

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, 2025 and 2024.


	December 31,
Gas Inventory (millions)	2025		2024
Natural Gas	$	0.4	$	0.2
Propane		0.4		0.4
Liquefied Natural Gas & Other		0.5		0.5
Total Gas Inventory	$	1.3	$	1.1

The Company also has an inventory of Materials and Supplies in the amounts of $15.4 million and $14.2 million as of December 31, 2025 and December 31, 2024, 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 5.39%, 6.22% and 5.48% in 2025, 2024 and 2023, 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, 2025 and 2024, the Company has recorded cost of removal amounts of $153.0 million and $139.2 million, respectively, that have been collected in depreciation rates but have not yet been expended, and which represent regulatory liabilities. These amounts are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations.

Regulatory Accounting

Regulatory Accounting - The Company’s principal business is the distribution of electricity and natural gas by the five distribution utilities: Unitil Energy, Fitchburg, Northern Utilities, Bangor and Maine Natural. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the Massachusetts Department of Public Utilities (MDPU), Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC), Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC, Bangor is regulated by the MPUC and Maine Natural is regulated by the MPUC. 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, 2025 and December 31, 2024, the Company has recorded $8.9 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)	2025		2024
Retirement Benefits	$	14.6	$	14.4
Energy Supply & Other Rate Adjustment Mechanisms		73.1		65.4
Deferred Storm Charges		6.0		8.3
Environmental		10.0		9.4
Income Taxes		0.4		0.4
Other Deferred Charges		12.8		14.1
Total Regulatory Assets		116.9		112.0
Less: Current Portion of Regulatory Assets(1)		78.1		70.1
Regulatory Assets—noncurrent	$	38.8	$	41.9

(1)

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


	December 31,
Regulatory Liabilities consist of the following (millions)	2025		2024
Rate Adjustment Mechanisms and Other	$	11.1	$	13.6
Income Taxes		51.1		50.4
Derivative Assets		17.7		—
Retirement Benefits		0.9		—
Total Regulatory Liabilities		80.8		64.0
Less: Current Portion of Regulatory Liabilities		16.7		17.2
Regulatory Liabilities—noncurrent	$	64.1	$	46.8

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, 2025 are $6.5 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods. 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.

The Company has contracts that meet the definition of derivatives (see Note 7 Derivatives). Derivatives are recognized on the balance sheet at fair value as either assets or liabilities. The Company considers the amount of the derivative expected to be settled within the next twelve months as current and the remainder as long-term. Derivative instruments are presented on a gross basis in the consolidated balance sheets. Cash flows related to derivative settlements are classified as operating activities in the consolidated statements of cash flows. Regulatory assets or liabilities are recorded to offset the fair value of derivatives, as contract settlement amounts are tracked and reconciled as a pass-through to customers. Costs associated with the Purchase Power Agreement (PPA) are approved by the MDPU to be passed through to customers through the Company’s Long-Term Renewable Contract Adjustment Clause tariff and accounted for per FASB Accounting Standard Codification 980, Regulated Operations. Unrealized gains or losses resulting from the change in fair value are not recognized in the income statement. Instead, they are deferred and recorded as a regulatory asset for losses or a regulatory liability for gains.

The Company recognizes an environmental attribute asset at the allocated contract cost upon receipt of the associated certificates in the applicable registry and derecognizes the asset upon retirement, at which time the related cost is recognized in Cost of Electric Sales, which are tracked and reconciled costs as pass-through to customers. Please see Note 7 (Derivatives) for additional information.

Investments in Marketable Securities

Investments in Marketable Securities - The Company maintains a trust through which it invests in a money market fund and a fixed income fund. These funds are intended to satisfy obligations under the Company’s Supplemental Executive Retirement Plan (SERP). See additional discussion of the SERP in Note 10 Retirement Benefit Plans.

At December 31, 2025 and 2024, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $6.7 million and $6.3 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)	2025		2024
Money Market Funds	$	3.2	$	2.5
Fixed Income Funds		3.5		3.8
Total Marketable Securities	$	6.7	$	6.3

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, 2025 and 2024, 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 $3.5 million and $2.2 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)	2025		2024
Equity Funds	$	3.1	$	2.0
Fixed Income Funds		0.3		0.1
Money Market Funds		0.1		0.1
Total Marketable Securities	$	3.5	$	2.2

Goodwill

Goodwill - In January, the Company completed the acquisition of Bangor Natural Gas Company resulting in the recognition of $1.6 million of goodwill. In October, the Company completed the acquisition of Maine Natural Gas Corporation resulting in the recognition of $2.7 million of goodwill. Goodwill is not amortized but is tested for impairment at least annually, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. The Company performed the annual impairment assessment of goodwill at November 1, 2025 for the gas reporting unit. The Company generally uses a qualitative analysis assessment to determine if it was more likely than not that the fair value of the reporting unit exceeded its carrying value, including goodwill. The qualitative assessment did not identify any triggering events that would indicate potential impairment of the reporting unit. Therefore, it was determined that the fair value of the reporting unit exceeded its carrying value and no goodwill impairments were recognized during the year ended December 31, 2025.

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)	2025		2024
Renewable Energy Portfolio Standards	$	2.3	$	4.0
Exchange Gas Obligation		9.3		6.0
Total Energy Supply Obligations	$	11.6	$	10.0

Renewable Energy Portfolio Standards

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 its pro rata share of clean energy and/or RECs under statewide procurement processes pursuant to Massachusetts legislation. The generating facilities associated with some of these contracts have been constructed and are now operating. Please see Note 8 (Commitments and Contingencies) discussion in Regulatory Matters for additional detail.

Exchange Gas Obligation

Exchange Gas Obligation - Northern Utilities and Bangor enter into gas exchange agreements under which Northern Utilities and Bangor release certain natural gas pipeline and storage assets, resell the natural gas storage inventory to an asset manager and subsequently repurchase 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.

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 for 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 or Regulatory Liability, reflecting ultimate recovery from or refunded to 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 10 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, 2025, the Company is not aware of any material commitments or contingencies other than those disclosed in Note 8 (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 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, 2025, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 8 (Commitments and Contingencies). Changes in future environmental compliance regulations or in future cost estimates of environmental remediation costs could have a material effect on the Company’s financial position if those amounts are not recoverable in regulatory rate mechanisms.

Recently Issued Pronouncements

Recently Issued Pronouncements - In 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (DISE), requiring public business entities to provide enhanced disclosures about the nature of expenses. The standard mandates a tabular footnote disclosure detailing relevant expense captions into natural expense categories such as purchases of inventory, employee compensation, and depreciation. It also requires disclosure of total selling expenses and, annually, the definition of selling expenses. ASU 2024-03 is effective for annual periods beginning after December 15, 2026, and interim periods within those periods starting after December 15, 2027; early adoption is permitted. The Company is evaluating the standard's impact on its Consolidated Financial Statements.

In December 2023, the FASB issued ASU 2023-09, Income Taxes - Improvements to Income Tax Disclosures (ASU 2023-09). ASU 2023-09 establishes new income tax disclosure requirements in addition to modifying and eliminating certain existing requirements. The amendments in ASU 2023-09 are effective for annual periods beginning after December 15, 2024, with early adoption permitted. The Company adopted this new guidance for the year ended December 31, 2025, and it did not have a material effect on the Company’s Consolidated Financial Statements (See Note 9 Income Taxes.)

Acquisition of Bangor Natural Gas Company

Acquisition of Bangor Natural Gas Company - On January 31, 2025, the Company acquired all issued and outstanding shares of Bangor Natural Gas Company for $71.4 million, which includes an estimated working capital adjustment. Through this acquisition, the Company expanded its service territory to include approximately 8,500 customers in the greater Bangor area of central Maine.

In connection with this acquisition, the Company recorded $66.7 million of net utility plant, $3.8 million working capital, $1.6 million goodwill, $0.2 million noncurrent assets and $0.9 million noncurrent regulatory liabilities. The financial results associated with this acquisition are included within the gas segment. Bangor’s operating revenues of $27.9 million and net income of $2.2 million were included in the consolidated results for the year ended December 31, 2025.

Goodwill represents the amount by which the purchase price exceeds the estimated fair value of the net assets acquired. The goodwill related to Bangor is partially tax deductible. The tax deductible portion of goodwill is $0.4 million and will be amortized over 15 years.

In connection with Unitil’s acquisition of Bangor, the Company entered into a Transition Services Agreement (TSA) dated January 31, 2025 between Bangor and Hope Utilities, Inc. (Hope Utilities). Pursuant to the TSA, Hope Utilities provided Bangor with certain services at cost, for up to 12 months, in order to continue the operation and maintenance of Bangor substantially consistent with past practices until Unitil has completed the successful transition. The TSA was completed in November 2025.

Acquisition of Maine Natural Gas Corporation

Acquisition of Maine Natural Gas Corporation - On October 31, 2025, the Company acquired all issued and outstanding shares of Maine Natural for $86.0 million in cash, plus $7.1 million in working capital, subject to certain adjustments as provided in the Purchase Agreement. Through this acquisition, the Company expanded its service territory to include approximately 6,300 customers in the Portland area of central Maine, as well as the capital city of Augusta.

In connection with this acquisition, the Company recorded $82.0 million of net utility plant, $10.4 million working capital, $2.7 million goodwill, $1.4 million noncurrent assets and $3.4 million noncurrent regulatory liabilities. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions and purchase accounting adjustments. The financial results associated with this acquisition are included within the gas segment. Maine Natural’s operating revenues of $8.3 million and net income of $2.8 million were included in the consolidated results for the year ended December 31, 2025.

Goodwill represents the amount by which the purchase price exceeds the estimated fair value of the net assets acquired.

In connection with Unitil’s acquisition of Maine Natural, the Company entered into a TSA dated October 31, 2025 between Maine Natural and Avangrid Service Company (Avangrid). Pursuant to the TSA, Avangrid will provide Maine Natural with certain services at cost, for up to 12 months, in order to continue the operation and maintenance of Maine Natural substantially consistent with past practices until Unitil has completed the successful transition. The Company has recorded $0.2 million of TSA costs as of December 31, 2025.

Acquisition of Aquarion Water Companies

Acquisition of Aquarion Water Companies - On May 6, 2025, Unitil entered into a definitive agreement to acquire Aquarion Water Company of Massachusetts, Inc., Aquarion Water Company of New Hampshire, Inc., and Abenaki Water Co., Inc. (the Aquarion Companies) from the Aquarion Water Authority, a quasi-public corporation and political subdivision of the State of Connecticut and a standalone, newly created water authority alongside the South Central Connecticut Regional Water Authority subject to certain closing adjustments. The aggregate enterprise value of the sale is approximately $100.0 million, which includes approximately $70.0 million in cash and the assumption of approximately $30.0 million of debt. The transaction is subject to approval by the MDPU, the NHPUC and the MPUC.

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.

Debt and Financing Arrangements - Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility (Detail) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Debt Instrument [Line Items]
Short-Term Borrowings Outstanding	$ 255.7	$ 105.8
Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility, limit	275.0	200.0
Short-Term Borrowings Outstanding	169.7	105.8
Available revolving credit facility	$ 105.3	$ 94.2

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 8A
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
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Reference 4: http://www.xbrl.org/2009/role/commonPracticeRef
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Reference 5: http://www.xbrl.org/2009/role/commonPracticeRef
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-Subparagraph (SX 210.12-04(a))
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Reference 6: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(f))
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Reference 7: http://www.xbrl.org/2003/role/exampleRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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-Name Accounting Standards Codification
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Reference 9: http://www.xbrl.org/2003/role/exampleRef
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Reference 10: http://www.xbrl.org/2003/role/exampleRef
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Reference 11: http://www.xbrl.org/2003/role/exampleRef
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Reference 12: http://www.xbrl.org/2003/role/exampleRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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Reference 15: http://www.xbrl.org/2003/role/exampleRef
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Reference 16: http://www.xbrl.org/2003/role/disclosureRef
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Reference 18: http://www.xbrl.org/2003/role/disclosureRef
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Reference 19: http://www.xbrl.org/2003/role/disclosureRef
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Reference 25: http://www.xbrl.org/2003/role/disclosureRef
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Reference 26: http://www.xbrl.org/2003/role/disclosureRef
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Reference 27: http://www.xbrl.org/2003/role/disclosureRef
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Reference 29: http://www.xbrl.org/2003/role/disclosureRef
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Reference 30: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 835
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Reference 31: http://www.xbrl.org/2009/role/commonPracticeRef
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+ Details

Income Taxes - Deferred Tax Assets and Liabilities (Detail) - USD ($)
$ in Millions

Dec. 31, 2025

Dec. 31, 2024

Deferred Tax Assets

Retirement Benefit Obligations

$ 5.6

$ 6.1

Regulatory Assets and Liabilities

^[1]

0.0

5.6

Net Operating Loss Carryforwards

0.2

2.3

Tax Credit Carryforwards

1.8

2.0

Other, net

6.3

2.5

Total Deferred Tax Assets

13.9

18.5

Deferred Tax Liabilities

Utility Plant Differences

208.9

203.6

Regulatory Assets and Liabilities

^[1]

0.3

0.0

Other, net

1.4

1.0

Total Deferred Tax Liabilities

210.6

204.6

Net Deferred Tax Liabilities

$ 196.7

$ 186.1

[1]

The Company’s Net Deferred Tax Liabilities for Regulatory Assets and Liabilities are shown net. Gross Regulatory Assets were $16.8 million and $16.6 million for the years ended December 31, 2025 and 2024, respectively. Gross Regulatory Liabilities were $17.1 million and $11.0 million for the years ended December 31, 2025 and 2024, respectively.

Allowance for Doubtful Accounts (Tables)

12 Months Ended

Dec. 31, 2025

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 2025, 2024 and 2023 (millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS


	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Balance at End of Period
Year Ended December 31, 2025
Electric	$	1.4	$	3.4	$	0.2	$	4.2	$	0.8
Gas		1.0		3.6		0.4		3.6		1.4
	$	2.4	$	7.0	$	0.6	$	7.8	$	2.2
Year Ended December 31, 2024
Electric	$	1.5	$	2.0	$	0.2	$	2.3	$	1.4
Gas		0.9		2.3		0.3		2.5		1.0
	$	2.4	$	4.3	$	0.5	$	4.8	$	2.4
Year Ended December 31, 2023
Electric	$	1.6	$	3.6	$	0.2	$	3.9	$	1.5
Gas		1.0		2.8		0.4		3.3		0.9
	$	2.6	$	6.4	$	0.6	$	7.2	$	2.4

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2025

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, 2025.


			Payments Due by Period
Gas and Electric Supply Contractual Obligations (millions) as of December 31, 2025	Total		2026		2027		2028		2029		2030		2031 & Beyond
Gas Supply Contracts	$	779.4	$	113.6	$	81.1	$	74.1	$	67.9	$	53.2	$	389.5
Electric Supply Contracts		198.3		9.0		9.2		9.2		9.1		9.3		152.5
Total	$	977.7	$	122.6	$	90.3	$	83.3	$	77.0	$	62.5	$	542.0

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, 2025 and 2024.


	December 31,
Environmental Obligations (millions)	2025		2024
Total Balance at Beginning of Period	$	7.8	$	4.6
Additions		1.0		3.6
Less: Payments / Reductions		0.7		0.4
Total Balance at End of Period		8.1		7.8
Less: Current Portion		0.8		0.7
Noncurrent Balance at End of Period	$	7.3	$	7.1

Equity - Weighted Average Non Vested Restricted Shares Excluded from Computation of Earnings Per Share (Detail) - shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
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	100,561	6,675	12,204

Income Taxes - Income taxes paid, net of refunds (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2025 USD ($)
Income Taxes Paid Net Of Refunds [Line Items]
Federal Income Taxes	$ 4,218
State Income Taxes	709
Total Cash Paid for Income Taxes, net of Refunds	4,927
MAINE
Income Taxes Paid Net Of Refunds [Line Items]
State Income Taxes	0
MASSACHUSETTS
Income Taxes Paid Net Of Refunds [Line Items]
State Income Taxes	154
NEW HAMPSHIRE
Income Taxes Paid Net Of Refunds [Line Items]
State Income Taxes	$ 555

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions		12 Months Ended
	Apr. 14, 2023	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2017
Income Taxes [Line Items]
Statutory Federal Income Tax Rate		21.00%	21.00%	21.00%
Regulatory Liability		$ 80.8	$ 64.0
Regulatory liability, expected flow back to customers					$ 47.1
State Taxes Credit to Offset Future Taxes		1.8
Net Operating Loss Carryforwards Utilized For Income Taxes			5.6
Income Tax Expense (Benefit)	$ 9.4	15.3	14.0	$ 13.2
Federal Tax Credit Carryforward			1.0
Income Tax Related Liabilities
Income Taxes [Line Items]
Regulatory Liability		51.1	$ 50.4		$ 48.9
Gas Ratepayers \| Massachusetts And Maine [Member]
Income Taxes [Line Items]
Regulatory liability, expected flow back to customers		$ 13.9

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

Dec. 31, 2025

Dec. 31, 2024

Debt Instrument [Line Items]

Total Long-Term Debt

$ 674.3

$ 647.3

Less: Unamortized Debt Issuance Costs

3.8

4.0

Long-Term Debt

670.5

643.3

Less: Current Portion

^[1]

37.9

4.9

Total Long-Term Debt, Less Current Portion

632.6

638.4

3.70% Senior Notes, Due August 1, 2026

Debt Instrument [Line Items]

Total Long-Term Debt

30.0

3.43% Senior Notes, Due December 18, 2029

Debt Instrument [Line Items]

Total Long-Term Debt

30.0

5.99% Senior Notes, Due August 21, 2034

Debt Instrument [Line Items]

Total Long-Term Debt

20.0

First Mortgage Bonds 6.96% Senior Secured Notes, Due September 1, 2028 | Unitil Energy Systems Inc

Debt Instrument [Line Items]

Total Long-Term Debt

6.0

8.0

First Mortgage Bonds 8.00% Senior Secured Notes, Due May 1, 2031 | Unitil Energy Systems Inc

Debt Instrument [Line Items]

Total Long-Term Debt

9.0

10.5

First Mortgage Bonds 6.32% Senior Secured Notes, Due September 15, 2036 | Unitil Energy Systems Inc

Debt Instrument [Line Items]

Total Long-Term Debt

15.0

First Mortgage Bonds 3.58% Senior Secured Notes Due September 15, 2040 | Unitil Energy Systems Inc

Debt Instrument [Line Items]

Total Long-Term Debt

27.5

First Mortgage Bonds 4.18% Senior Secured Notes Due November 30, 2048 | Unitil Energy Systems Inc

Debt Instrument [Line Items]

Total Long-Term Debt

30.0

First Mortgage Bonds 5.69% Senior Secured Notes Due August 21, 2054 | Unitil Energy Systems Inc

Debt Instrument [Line Items]

Total Long-Term Debt

40.0

3.52% Senior Notes, Due November 1, 2027 | Fitchburg Gas and Electric Light Company

Debt Instrument [Line Items]

Total Long-Term Debt

10.0

3.52% Senior Notes, Due November 1, 2027 | Northern Utilities Inc

Debt Instrument [Line Items]

Total Long-Term Debt

20.0

7.37% Senior Notes, Due January 15, 2029 | Fitchburg Gas and Electric Light Company

Debt Instrument [Line Items]

Total Long-Term Debt

4.8

6.0

5.90% Notes, Due December 15, 2030 | Fitchburg Gas and Electric Light Company

Debt Instrument [Line Items]

Total Long-Term Debt

15.0

7.98% Notes, Due June 1, 2031 | Fitchburg Gas and Electric Light Company

Debt Instrument [Line Items]

Total Long-Term Debt

14.0

5.70 % Senior Note Due to July 2, 2033 | Fitchburg Gas and Electric Light Company

Debt Instrument [Line Items]

Total Long-Term Debt

12.0

5.54% Senior Notes Due to August 21, 2034 | Fitchburg Gas and Electric Light Company

Debt Instrument [Line Items]

Total Long-Term Debt

12.5

5.54% Senior Notes Due to August 21, 2034 | Northern Utilities Inc

Debt Instrument [Line Items]

Total Long-Term Debt

25.0

3.78% Senior Notes, Due September 15, 2040 | Fitchburg Gas and Electric Light Company

Debt Instrument [Line Items]

Total Long-Term Debt

27.5

3.78% Senior Notes, Due September 15, 2040 | Northern Utilities Inc

Debt Instrument [Line Items]

Total Long-Term Debt

40.0

5.99% Senior Notes, Due August 21, 2044 | Fitchburg Gas and Electric Light Company

Debt Instrument [Line Items]

Total Long-Term Debt

12.5

4.32% Senior Notes, Due November 1, 2047 | Fitchburg Gas and Electric Light Company

Debt Instrument [Line Items]

Total Long-Term Debt

15.0

4.32% Senior Notes, Due November 1, 2047 | Northern Utilities Inc

Debt Instrument [Line Items]

Total Long-Term Debt

30.0

5.96% Senior Note Due to July 2, 2053 | Fitchburg Gas and Electric Light Company

Debt Instrument [Line Items]

Total Long-Term Debt

13.0

3.72% Senior Notes, Due November 1, 2027 | Granite State Gas Transmission Inc

Debt Instrument [Line Items]

Total Long-Term Debt

15.0

7.72% Senior Notes, Due December 3, 2038 | Northern Utilities Inc

Debt Instrument [Line Items]

Total Long-Term Debt

50.0

5.74% Senior Notes, Due August 21, 2039 | Northern Utilities Inc

Debt Instrument [Line Items]

Total Long-Term Debt

15.0

4.42% Senior Notes, Due October 15, 2044 | Northern Utilities Inc

Debt Instrument [Line Items]

Total Long-Term Debt

50.0

4.04% Senior Notes, Due September 12, 2049 | Northern Utilities Inc

Debt Instrument [Line Items]

Total Long-Term Debt

40.0

5.70% Senior Notes, Due July 8, 2030 | Bangor Natural Gas

Debt Instrument [Line Items]

Total Long-Term Debt

14.0

0.0

6.31% Senior Notes, Due July 8, 2035 | Bangor Natural Gas

Debt Instrument [Line Items]

Total Long-Term Debt

18.0

0.0

5.74% Senior Notes, Due August 21, 2034 | Granite State Gas Transmission Inc

Debt Instrument [Line Items]

Total Long-Term Debt

10.0

2.64% Senior Notes, Due December 18, 2030 | Unitil Realty Corp Member

Debt Instrument [Line Items]

Total Long-Term Debt

$ 3.5

$ 3.8

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

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Provisions for Federal and State Income Taxes


	(in millions)
	2025		2024		2023
Current Income Tax Provision
Federal	$	4.5	$	0.4	$	4.3
State		1.2		0.4		1.5
Total Current Income Taxes		5.7		0.8		5.8
Deferred Income Tax Provision
Federal		5.3		8.6		4.8
State		4.3		4.6		2.6
Total Deferred Income Taxes		9.6		13.2		7.4
Total Income Tax Expense	$	15.3	$	14.0	$	13.2

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

The following table presents the Company’s provisions for Income Taxes and the provisions calculated at the statutory federal tax rate for the year ended December 31, 2025:


	2025
(Dollars in thousands)	Amount			Rate
U.S. Federal Statutory Tax Rate	$	13,754			21.0	%
State Income Taxes, net of Federal Income Tax		4,251			6.5	%
Production Tax Credit		(212	)		(0.3	)%
Nontaxable and Nondeductible Items
Regulatory Amortization of Excess ADIT		(2,668	)		(4.1	)%
Other		187			0.3	%
Income Tax Expense and Effective Income Tax Rate	$	15,312			23.4	%


	2024			2023
Statutory Federal Income Tax Rate		21	%		21	%
Income Tax Effects of:
State Income Taxes, net		6	%		6	%
Utility Plant Differences		(5	)%		(5	)%
Other, net		1	%		1	%
Effective Income Tax Rate		23	%		23	%

Income Taxes Paid Net of Refunds

Income taxes paid, net of refunds are shown in the following table:



(in thousands)	2025
Cash Paid for Income Taxes, net of Refunds
Federal Income Taxes	$	4,218
State Income Taxes
Florida	*
Maine		—
Massachusetts		154
New Hampshire		555
Total State Income Taxes		709
Total Cash Paid for Income Taxes, net of Refunds	$	4,927
* Did not meet the 5% threshold required for separate disclosure

Deferred Tax Assets and Liabilities

Temporary differences which gave rise to deferred tax assets and liabilities in 2025 and 2024 are shown in the following table:


Temporary Differences (in millions)	2025		2024
Deferred Tax Assets
Retirement Benefit Obligations	$	5.6	$	6.1
Regulatory Assets and Liabilities **		—		5.6
Net Operating Loss Carryforwards		0.2		2.3
Tax Credit Carryforwards		1.8		2.0
Other, net		6.3		2.5
Total Deferred Tax Assets		13.9		18.5
Deferred Tax Liabilities
Utility Plant Differences		208.9		203.6
Regulatory Assets and Liabilities **		0.3		—
Other, net		1.4		1.0
Total Deferred Tax Liabilities		210.6		204.6
Net Deferred Tax Liabilities	$	196.7	$	186.1

Equity - Time Restricted Shares and Performance Restricted Shares activity (Details)	12 Months Ended
	Dec. 31, 2025 $ / shares shares
Time Restricted Shares
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Restricted Shares as of December 31, 2024 \| shares	19,933
Granted \| shares	26,430
Shares Issued \| shares	(28,084)
Forfeited \| shares	(396)
Restricted Shares as of December 31, 2025 \| shares	17,883
Weighted-Average Stock Price
Weighted Average Stock Price as of December 31, 2024 \| $ / shares	$ 48.09
Weighted Average Stock Price Granted \| $ / shares	52.65
Weighted Average Stock Price Shares Issued \| $ / shares	50.58
Weighted Average Stock Price Forfeited \| $ / shares	47.42
Weighted Average Stock Price as of December 31, 2025 \| $ / shares	$ 50.94
Performance Restricted Shares
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Restricted Shares as of December 31, 2024 \| shares	41,200
Granted \| shares	26,430
Shares Issued \| shares	0
Forfeited \| shares	(250)
Restricted Shares as of December 31, 2025 \| shares	67,380
Weighted-Average Stock Price
Weighted Average Stock Price as of December 31, 2024 \| $ / shares	$ 50.28
Weighted Average Stock Price Granted \| $ / shares	52.65
Weighted Average Stock Price Shares Issued \| $ / shares	0
Weighted Average Stock Price Forfeited \| $ / shares	50.35
Weighted Average Stock Price as of December 31, 2025 \| $ / shares	$ 51.21

Equity - Reconciles Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Schedule Of Computation Of Basic And Diluted Earnings Per Common Share [Line Items]
Net Income	$ 50.2	$ 47.1	$ 45.2
Less allocation of earnings and dividends to participating securities	0.3	0.0	0.0
Net Income Attributable to Commons Shares	$ 49.9	$ 47.1	$ 45.2
Weighted average common shares outstanding, gross	16,886,642	16,098,267	16,045,300
Less average participating securities	100,561	0	0
Weighted average number of shares outstanding used in the calculation of basic earnings per share	16,786,081	16,098,267	16,045,300
Add dilutive effect of:
Restricted stock and restricted stock units	1,672	10,803	7,447
Adjusted weighted average number of shares outstanding used in the calculation of diluted earnings per common share	16,787,753	16,109,070	16,052,747
Earnings per Common Share - Basic	$ 2.97	$ 2.93	$ 2.82
Earnings per Common Share - Diluted	$ 2.97	$ 2.93	$ 2.82

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2025

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Note 1: Summary of Significant Accounting Policies

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

Basis of Presentation



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

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

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

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

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


	Twelve Months Ended
	December 31, 2025
Electric and Gas Operating Revenues (millions):	Electric		Gas			Total
Billed and Unbilled Revenue:
Residential	$	121.1	$	121.2		$	242.3
Commercial & Industrial		94.9		171.0			265.9
Other		13.1		13.8			26.9
Total Billed and Unbilled Revenue		229.1		306.0			535.1
Rate Adjustment Mechanism Revenue		7.3		(6.4	)		0.9
Total Electric and Gas Operating Revenues	$	236.4	$	299.6		$	536.0


	Twelve Months Ended
	December 31, 2024
Electric and Gas Operating Revenues (millions):	Electric			Gas		Total
Billed and Unbilled Revenue:
Residential	$	135.0		$	92.6	$	227.6
Commercial & Industrial		103.4			133.5		236.9
Other		10.4			9.7		20.1
Total Billed and Unbilled Revenue		248.8			235.8		484.6
Rate Adjustment Mechanism Revenue		(0.5	)		10.7		10.2
Total Electric and Gas Operating Revenues	$	248.3		$	246.5	$	494.8


	Twelve Months Ended
	December 31, 2023
Electric and Gas Operating Revenues (millions):	Electric			Gas			Total
Billed and Unbilled Revenue:
Residential	$	181.6		$	98.8		$	280.4
Commercial & Industrial		120.1			146.9			267.0
Other		10.0			8.1			18.1
Total Billed and Unbilled Revenue		311.7			253.8			565.5
Rate Adjustment Mechanism Revenue		(5.2	)		(3.2	)		(8.4	)
Total Electric and Gas Operating Revenues	$	306.5		$	250.6		$	557.1

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


	December 31,
Accrued Revenue (millions)	2025		2024
Regulatory Assets—Current	$	78.1	$	70.1
Unbilled Revenues		8.9		7.3
Total Accrued Revenue	$	87.0	$	77.4


	December 31,
Exchange Gas Receivable (millions)	2025		2024
Northern Utilities	$	8.0	$	6.0
Fitchburg		0.5		0.4
Bangor		1.3		—
Total Exchange Gas Receivable	$	9.8	$	6.4

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, 2025 and 2024.


	December 31,
Gas Inventory (millions)	2025		2024
Natural Gas	$	0.4	$	0.2
Propane		0.4		0.4
Liquefied Natural Gas & Other		0.5		0.5
Total Gas Inventory	$	1.3	$	1.1


	December 31,
Regulatory Assets consist of the following (millions)	2025		2024
Retirement Benefits	$	14.6	$	14.4
Energy Supply & Other Rate Adjustment Mechanisms		73.1		65.4
Deferred Storm Charges		6.0		8.3
Environmental		10.0		9.4
Income Taxes		0.4		0.4
Other Deferred Charges		12.8		14.1
Total Regulatory Assets		116.9		112.0
Less: Current Portion of Regulatory Assets(1)		78.1		70.1
Regulatory Assets—noncurrent	$	38.8	$	41.9

(1)

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


	December 31,
Regulatory Liabilities consist of the following (millions)	2025		2024
Rate Adjustment Mechanisms and Other	$	11.1	$	13.6
Income Taxes		51.1		50.4
Derivative Assets		17.7		—
Retirement Benefits		0.9		—
Total Regulatory Liabilities		80.8		64.0
Less: Current Portion of Regulatory Liabilities		16.7		17.2
Regulatory Liabilities—noncurrent	$	64.1	$	46.8


	December 31,
Fair Value of Marketable Securities (millions)	2025		2024
Money Market Funds	$	3.2	$	2.5
Fixed Income Funds		3.5		3.8
Total Marketable Securities	$	6.7	$	6.3


	December 31,
Fair Value of Marketable Securities (millions)	2025		2024
Equity Funds	$	3.1	$	2.0
Fixed Income Funds		0.3		0.1
Money Market Funds		0.1		0.1
Total Marketable Securities	$	3.5	$	2.2

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)	2025		2024
Renewable Energy Portfolio Standards	$	2.3	$	4.0
Exchange Gas Obligation		9.3		6.0
Total Energy Supply Obligations	$	11.6	$	10.0

In December 2023, the FASB issued ASU 2023-09, Income Taxes - Improvements to Income Tax Disclosures (ASU 2023-09). ASU 2023-09 establishes new income tax disclosure requirements in addition to modifying and eliminating certain existing requirements. The amendments in ASU 2023-09 are effective for annual periods beginning after December 15, 2024, with early adoption permitted. The Company adopted this new guidance for the year ended December 31, 2025, and it did not have a material effect on the Company’s Consolidated Financial Statements (See Note 9 Income Taxes.)

Goodwill represents the amount by which the purchase price exceeds the estimated fair value of the net assets acquired.

Commitments and Contingencies - Gas And Electric Supply Contractual Obligations (Detail) $ in Millions	Dec. 31, 2025 USD ($)
Total	$ 977.7
2026	122.6
2027	90.3
2028	83.3
2029	77.0
2030	62.5
2030 & Beyond	542.0
Gas Segment [Member]
Total	779.4
2026	113.6
2027	81.1
2028	74.1
2029	67.9
2030	53.2
2030 & Beyond	389.5
Electric [Member]
Total	198.3
2026	9.0
2027	9.2
2028	9.2
2029	9.1
2030	9.3
2030 & Beyond	$ 152.5

Energy Supply

12 Months Ended

Dec. 31, 2025

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 2025, 85% of Unitil’s largest New Hampshire customers, representing 24% of Unitil’s New Hampshire electric kilowatt-hour (kWh) sales, and 96% of Unitil’s largest Massachusetts customers, representing 25% 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. In New Hampshire, a majority of residential and small commercial customers purchase their electric supply through Community Choice Aggregations (CCA) and retail electric suppliers. In New Hampshire, as of December 2025, the percentage of residential customers purchasing electricity from a third-party supplier or CCA decreased to 66% from 68% in 2024. In Massachusetts, as of December 2025, the percentage of residential customers purchasing electricity from a third-party supplier or municipal aggregation increased to 84% from 75% in 2024.

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 50% of the supply requirements and the remaining 50% of supply requirements are procured via direct market purchases from ISO-New England.

Fitchburg typically maintains power supply contracts with various wholesale suppliers for the provision of Basic Service electric supply. Pursuant to MDPU policy, Basic Service power supply contracts for residential and for small and medium general service customers are acquired every six months, are 12 months in duration and provide 50% 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. The Company was successful in procuring 100% of supply requirements for the small customer group from the traditional procurement process. The Company experienced a failed solicitation in its November 2025 solicitation for the medium customer group, which results in Fitchburg self-supplying 100% of its load requirements for the February through July 2026 period. The failed solicitation was due to no bidders for the medium customer group. The implications of the failed solicitation result in 100% of wholesale supply charges settling at the real-time energy price. The failed solicitation has no impact on the ability to provide default energy service to Fitchburg’s customers. The Company reconciles and recovers these supply expenses in its rates at cost on a pass through basis and therefore changes in approved expenses do not affect earnings.

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, by Fitchburg in Massachusetts, and by Bangor and Maine Natural in Maine. Unitil began purchasing and managing gas supply for customers served by Bangor on January 31, 2025 and Maine Natural on October 31, 2025.

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, 2025, 71% of Northern Utilities’s largest New Hampshire gas customers, representing 38% of Northern Utilities’s New Hampshire gas therm sales, and 59% of Northern Utilities’s largest Maine customers, representing 21% of Northern Utilities’s Maine gas therm sales, purchased their gas supply from a third-party supplier.

Bangor’s C&I customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many of Bangor’s 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 Bangor under regulated rates and tariffs. As of December 2025, 49% of Bangor’s largest customers, representing 46% of Bangor’s gas therm sales, purchased their gas supply from a third-party supplier.

Maine Natural’s C&I customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many of Maine Natural’s 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 Maine Natural under regulated rates and tariffs. As of December 2025, 11% of Maine Natural’s largest customers, representing 25% of Maine Natural 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, 2025, 70% of Unitil’s largest Massachusetts gas customers, representing 15% 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 6.3 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.

Bangor 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. Bangor arranges for gas transportation and delivery to its system through its own long-term contracts with various interstate pipeline and storage facilities.

Bangor has firm contracts for up to 35,000 MMBtu per day of year-round transportation and 0.69 BCF of underground storage capacity to its distribution facilities. Bangor Natural Gas has contracted for year-round and supplemental winter supplies to meet Bangor system demands.

Maine Natural purchases its natural gas from suppliers largely under contracts of one year or less. Maine Natural Gas arranges for gas transportation and delivery to its system through firm pipeline capacity.

Maine Natural has available under firm contract 6,500 MMBtu per day of year-round transportation. As a supplement to year-round pipeline natural gas, Maine Natural has contracted for additional supplies to meet winter demands.