0000950170-24-014186 | 10-K | XBRL Viewer

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Components of Retirement Plan Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 2,091	$ 3,165	$ 3,472
Interest Cost	7,480	5,486	5,003
Expected Return on Plan Assets	(10,689)	(10,883)	(9,693)
Prior Service Cost Amortization	356	356	301
Actuarial Loss Amortization	$ 0	5,507	8,089
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	$ (762)	3,631	7,172
Amounts Capitalized or Deferred	1,598	(1,085)	(3,384)
NPBC Recognized	836	2,546	3,788
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	1,493	2,890	3,034
Interest Cost	2,899	3,194	2,740
Expected Return on Plan Assets	(3,408)	(3,415)	(2,508)
Prior Service Cost Amortization	794	1,092	1,208
Actuarial Loss Amortization	$ (1,464)	1,020	1,045
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	$ 314	4,781	5,519
Amounts Capitalized or Deferred	555	(2,388)	(3,136)
NPBC Recognized	869	2,393	2,383
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	250	273	354
Interest Cost	754	472	458
Prior Service Cost Amortization	55	55	56
Actuarial Loss Amortization	$ 0	794	1,489
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	$ 1,059	1,594	2,357
Amounts Capitalized or Deferred	(327)	(472)	(712)
NPBC Recognized	$ 732	$ 1,122	$ 1,645

Summary of Significant Accounting Policies - Additional Information (Detail) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2024 $ / shares	Dec. 31, 2023 USD ($) Subsidiary mi $ / shares	Dec. 31, 2022 USD ($) $ / shares	Dec. 31, 2021 USD ($) $ / shares	Dec. 31, 2020 USD ($)
Significant Accounting Policies [Line Items]
Length Of Pipeline \| mi		85
Cost of removal obligation		$ 126.3	$ 116.1
Regulatory assets		109.6	114.3
Investments in trading securities		$ 6.0	5.8
Number of Subsidiaries \| Subsidiary		3
Allowance for doubtful accounts		$ 2.4	$ 2.6	$ 3.3	$ 3.3
Depreciation rate based on average depreciable property balance		3.33%	3.26%	3.29%
Dividends per Common Share \| $ / shares		$ 1.62	$ 1.56	$ 1.52
Increase in dividend declared amount per share \| $ / shares		$ 1.62
Weighted average cost inventory amount		$ 1.0	$ 1.8
Average Interest Rate On Debt		5.48%	2.50%	1.71%
Other Deferred Charges
Significant Accounting Policies [Line Items]
Regulatory assets		$ 11.0	$ 11.1
Materials And Supplies
Significant Accounting Policies [Line Items]
Weighted average cost inventory amount		13.5	11.4
Subsequent Event
Significant Accounting Policies [Line Items]
Increase in dividend declared amount per share \| $ / shares	$ 1.7
Unbilled Revenues
Significant Accounting Policies [Line Items]
Allowance for doubtful accounts		0.1	0.1	$ 0.1
Accounts Receivable
Significant Accounting Policies [Line Items]
Allowance for doubtful accounts		$ 2.3	2.5
Utilities
Significant Accounting Policies [Line Items]
Number of Subsidiaries \| Subsidiary		3
Unitil Service; Unitil Realty; and Unitil Resources
Significant Accounting Policies [Line Items]
Number of Subsidiaries \| Subsidiary		3
Fitchburg Gas and Electric Light Company \| Electric and Gas Division \| Other Deferred Charges
Significant Accounting Policies [Line Items]
Hardship accounts in regulatory assets		$ 6.0	$ 5.8
Quarterly Payment
Significant Accounting Policies [Line Items]
Dividends per Common Share \| $ / shares		$ 0.405	$ 0.39	$ 0.38
Quarterly Payment \| Subsequent Event
Significant Accounting Policies [Line Items]
Common stock dividend paid per share \| $ / shares	0.425
Increase in dividend declared amount per share \| $ / shares	$ 0.02
Environmental and Rate Case Costs and Other Expenditures \| Recovered over the next seven years
Significant Accounting Policies [Line Items]
Regulatory assets		$ 7.2
ISO-NE Obligations
Significant Accounting Policies [Line Items]
Cash Deposits		$ 3.3	$ 6.0
Maximum
Significant Accounting Policies [Line Items]
Lease term		12 months
Deferred Compensation Plan [Member]
Significant Accounting Policies [Line Items]
Investments in trading securities		$ 1.3	$ 0.6

Segment Information

12 Months Ended

Dec. 31, 2023

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 business segments, based on meeting with the managers of each segment and through their review of reports and analyses that are regularly provided to the CODM. Unitil reports two segments: utility electric operations and utility gas operations. Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capital regions of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire, Fitchburg, which operates in Massachusetts and Northern Utilities, which operates in New Hampshire and Maine.

Granite State is an interstate natural gas transmission pipeline company, operating 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 Service, Unitil Resources, Unitil Realty and the holding company are included in Other. Unitil Service provides centralized management and administrative services, including information systems management and financial record keeping.

Unitil Resources is the Company’s wholly-owned non-regulated subsidiary, which currently does not have any activity. Unitil Realty owns certain real estate, principally the Company’s corporate headquarters. The earnings of the holding company are principally derived from income earned on short-term investments and real property owned for Unitil and its subsidiaries’ use.

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

In November 2023, the FASB issued ASU 2023-07, Segment Reporting – Improvements to Reportable Segment Disclosures (ASU 2023-07). The amendments in ASU 2023-07 are intended to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The amendments in ASU 2023-07 are effective for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The Company does not expect this new guidance to have a material effect on the Company’s Consolidated Financial Statements.

The following tables provide significant segment financial data for the years ended December 31, 2023, 2022 and 2021 (millions):


Year Ended December 31, 2023	Electric			Gas			Other			Total
Revenues:
Billed and Unbilled Revenue	$	311.7		$	253.8		$	—		$	565.5
Rate Adjustment Mechanism Revenue		(5.2	)		(3.2	)		—			(8.4	)
Total Operating Revenues		306.5			250.6			—			557.1
Interest Income		2.6			2.4			1.2			6.2
Interest Expense		11.2			20.7			3.0			34.9
Depreciation & Amortization Expense		26.0			40.4			1.0			67.4
Income Tax Expense (Benefit)		4.0			9.4			(0.2	)		13.2
Segment Profit (Loss)		17.9			28.8			(1.5	)		45.2
Segment Assets		612.6			1,031.8			26.0			1,670.4
Capital Expenditures		44.2			92.7			4.1			141.0

Year Ended December 31, 2022
Revenues:
Billed and Unbilled Revenue	$	290.2		$	263.3		$	—		$	553.5
Rate Adjustment Mechanism Revenue		7.7			2.0			—			9.7
Total Operating Revenues		297.9			265.3			—			563.2
Interest Income		0.9			1.0			0.9			2.8
Interest Expense		9.1			16.8			2.4			28.3
Depreciation & Amortization Expense		25.4			36.3			0.9			62.6
Income Tax Expense (Benefit)		3.1			8.2			(0.1	)		11.2
Segment Profit (Loss)		15.7			26.5			(0.8	)		41.4
Segment Assets		580.9			988.8			20.7			1,590.4
Capital Expenditures		33.8			87.6			0.7			122.1

Year Ended December 31, 2021
Revenues:
Billed and Unbilled Revenue	$	248.5		$	217.6		$	—		$	466.1
Rate Adjustment Mechanism Revenue		—			7.2			—			7.2
Total Operating Revenues		248.5			224.8			—			473.3
Interest Income		0.8			0.5			0.3			1.6
Interest Expense		9.0			15.3			2.9			27.2
Depreciation & Amortization Expense		25.9			32.6			1.0			59.5
Income Tax Expense (Benefit)		4.5			7.7			(0.7	)		11.5
Segment Profit		14.0			23.2			(1.1	)		36.1
Segment Assets		584.0			935.9			20.4			1,540.3
Capital Expenditures		38.1			75.8			1.1			115.0

- 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

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-22

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-15

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 31
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-31

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 42
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-42

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 40
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-40

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org//280/tableOfContent

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 26
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-26

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 34
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-34

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 41
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-41

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-21

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-21

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

+ Details

Differences Between Provisions for Income Taxes and Provisions Calculated at Statutory Federal Tax Rate (Detail)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Examination [Line Items]
Statutory Federal Income Tax Rate	21.00%	21.00%	21.00%
State Income Taxes, net	6.00%	6.00%	6.00%
Utility Plant Differences	(5.00%)	(6.00%)	(3.00%)
Other, net	1.00%	0.00%	0.00%
Effective Income Tax Rate	23.00%	21.00%	24.00%

Cover Page - USD ($) $ in Millions	12 Months Ended
Cover Page - USD ($) $ in Millions	Dec. 31, 2023	Feb. 09, 2024	Jun. 30, 2023
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, 2023
Document Fiscal Year Focus	2023
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		16,163,365
Title of 12(b) Security	Common Stock
Entity Public Float			$ 802,806,380
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
ICFR Auditor Attestation Flag	true
Documents Incorporated by Reference [Text Block]	Portions of the Proxy Statement relating to the Annual Meeting of Shareholders to be held on May 1, 2024 are incorporated by reference into Part III of this Report.
Auditor Name	Deloitte & Touche LLP
Auditor Firm ID	34
Auditor Location	Boston, MA

Debt and Financing Arrangements - Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Debt Disclosure [Abstract]
Estimated Fair Value of Long-Term Debt	$ 470.5	$ 455.3

Provisions for Federal and State Income Taxes (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current Income Tax Provision
Federal	$ 4.3	$ 0.2	$ 0.0
State	1.5	0.2	0.7
Total Current Income Taxes	5.8	0.2	0.7
Deferred Income Tax Provision
Federal	4.8	6.6	7.3
State	2.6	4.4	3.5
Total Deferred Income Taxes	7.4	11.0	10.8
Total Income Tax Expense	$ 13.2	$ 11.2	$ 11.5

- Definition

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

+ References + Details

Summary of Information on Plans' Assets, Projected Benefit Obligations (PBO), and Funded Status (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	$ 126,098	$ 152,006
Actual Return on Plan Assets	16,822	(19,984)
Employer Contributions	3,850	3,800	$ 4,100
Benefits Paid	(8,877)	(9,724)
Plan Assets at End of Year	137,893	126,098	152,006
PBO at Beginning of Year	146,953	199,418
Service Cost	2,091	3,165	3,472
Interest Cost	7,480	5,486	5,003
Benefits Paid	(8,877)	(9,724)	(6,489)
Actuarial (Gain) or Loss	6,920	(51,392)
PBO at End of Year	154,567	146,953	199,418
Funded Status: Assets vs PBO	(16,674)	(20,855)
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	44,770	42,651
Actual Return on Plan Assets	6,865	(6,810)
Employer Contributions	2,790	12,153	8,903
Participant Contributions	234	279
Benefits Paid	(2,767)	(3,503)
Plan Assets at End of Year	51,892	44,770	42,651
PBO at Beginning of Year	56,510	112,087
Service Cost	1,493	2,890	3,034
Interest Cost	2,899	3,194	2,740
Benefits Paid	(2,767)	(3,503)	(2,905)
Actuarial (Gain) or Loss	8,322	(58,437)
PBO at End of Year	66,691	56,510	112,087
Funded Status: Assets vs PBO	(14,799)	(11,740)
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions	665	637	637
Benefits Paid	(665)	(637)
PBO at Beginning of Year	14,810	17,714
Service Cost	250	273	354
Interest Cost	754	472	458
Benefits Paid	(665)	(637)	(637)
Actuarial (Gain) or Loss	(295)	(3,012)
PBO at End of Year	14,854	14,810	$ 17,714
Funded Status: Assets vs PBO	$ (14,854)	$ (14,810)

Debt and Financing Arrangements - Additional Information (Detail) - USD ($) $ in Millions		12 Months Ended
	Sep. 29, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Jul. 06, 2023
Line of Credit Facility [Line Items]
Issuance of long-term debt					$ 0.2
Weighted average interest rate on short term borrowings		6.40%	3.30%	1.20%
Total rental expense under operating leases		$ 2.1	$ 1.8	$ 1.9
Accounts Payable		47.7	68.6
Operating lease obligations		2.1	1.8
Net Utility Plant		1,420.9	1,331.7
Operating Lease Obligations (current portion)		1.9	1.5
Operating Lease Obligations (long-term portion)		$ 3.7	$ 2.8
Operating lease, weighted average remaining lease term		3 years 8 months 12 days	3 years 4 months 24 days
Operating lease, weighted average discount rate percentage		4.40%	3.90%
Restriction on retained earnings for dividend payments		Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2023 for the payment of dividends.
Amount available for the payment of dividends		$ 204.3
Retained Earnings		151.5	$ 132.5
Long term debt repayments		6.9	10.4	25.8
Other Current Liabilities (current portion)		0.1	0.1
Finance Lease Liability Noncurrent		0.4	0.1
Subsidiaries [Member]
Line of Credit Facility [Line Items]
Amount available for the payment of dividends		409.9
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
Sublimit for the issuance of standby letters of credit	$ 25.0
Bonds [Member]
Line of Credit Facility [Line Items]
Long term debt repayments		6.9	10.4	$ 25.8
Debt repayment, 2024		4.9
Debt repayment, 2025		4.9
Debt repayment, 2026		37.9
Debt repayment, 2027		55.7
Debt repayment, 2028		10.7
Debt repayment, Thereafter		403.1
Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility		200.0	200.0
Proceeds from lines of credit		327.2	295.9
Repayments of lines of credit		$ 281.2	244.0
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		$ 10.9
Northern Utilities Inc
Line of Credit Facility [Line Items]
Accounts Payable		$ 2.2
Total funded indebtedness as percentage of capitalization		65.00%
Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization		65.00%
Fitchburg Gas and Electric Light Company \| 5.70 % Senior Note Due to July 2, 2033
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount					$ 12.0
Long-term debt, stated interest rate		5.70%			5.70%
Fitchburg Gas and Electric Light Company \| 5.96% Senior Note Due to July 2, 2053
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount					$ 13.0
Long-term debt, stated interest rate		5.96%			5.96%
Unitil Corporation \| Maximum [Member]
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization		70.00%
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	0.10%
Secured Overnight Financing Rate [Member] \| Revolving Credit Facility \| Credit Facility [Member] \| Third Amendment Credit Facility Member [Member] \| Maximum [Member]
Line of Credit Facility [Line Items]
Debt instrument variable interest rate additional spread	1.375%
Secured Overnight Financing Rate [Member] \| Revolving Credit Facility \| 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		$ 0.7	0.6
Net Utility Plant, accumulated amortization		$ 0.2	$ 0.4

Estimated Future Benefit Payments (Detail) $ in Thousands	Dec. 31, 2023 USD ($)
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
2024	$ 8,006
2025	8,678
2026	9,162
2027	10,210
2028	10,309
2029-2033	57,049
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
2024	3,197
2025	3,466
2026	3,698
2027	3,789
2028	3,803
2029-2033	20,913
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
2024	679
2025	1,173
2026	1,167
2027	1,160
2028	1,153
2029-2033	$ 5,607

Debt and Financing Arrangements

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Debt and Financing Arrangements

Note 4: Debt and Financing Arrangements

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

Long-Term Debt and Interest Expense

Long-Term Debt Structure and Covenants - The debt agreements for Unitil and its utility subsidiaries, Unitil Energy, Fitchburg, Northern Utilities, and Granite State, contain various covenants and restrictions. These agreements do not contain any covenants or restrictions pertaining to the maintenance of financial ratios or the issuance of short-term debt. These agreements do contain covenants relating to, among other things, the issuance of additional long-term debt, cross-default provisions and business combinations.

The long-term debt of Unitil is issued under Unsecured Promissory Notes with negative pledge provisions. The long-term debt’s negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt. Accordingly, in order for Unitil to issue new long-term debt, the covenants of the existing long-term agreement(s) must be satisfied, including that Unitil has total funded indebtedness less than 70% of total capitalization, and earnings available for interest equal to at least two times the interest charges for funded indebtedness. Each future senior long-term debt issuance of Unitil will rank pari passu with all other senior unsecured long-term debt issuances. The Unitil long-term debt agreement requires that if Unitil defaults on any other future long-term debt agreement(s), it would constitute a default under Unitil’s present long-term debt agreement. Furthermore, the default provisions are triggered by the defaults of certain Unitil subsidiaries or certain other actions against Unitil subsidiaries.

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

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

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

Unitil Energy, Fitchburg, Northern Utilities and Granite State pay common dividends to their sole common shareholder, Unitil Corporation and these common dividends are the primary source of cash for the payment of dividends to Unitil’s common shareholders. The long-term debt issued by the Company and its subsidiaries contains certain covenants that determine the amount that the Company and each of these subsidiary companies has available to pay for dividends. As of December 31, 2023, in accordance with the covenants, these subsidiary companies had a combined amount of $ 409.9 million available for the payment of dividends and Unitil Corporation had $ 204.3 million available for the payment of dividends. As of December 31, 2023, the Company’s balance in Retained Earnings was $151.5 million. Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2023 for the payment of dividends.

Issuance of Long-Term Debt - On July 6, 2023, Fitchburg issued $12.0 million of Notes due July 2, 2033 at 5.70% and $13.0 million of Notes due July 2, 2053 at 5.96%. Fitchburg used the net proceeds from these offerings to refinance existing debt and for general corporate purposes. Approximately $0.2 million of costs associated with this issuance were recorded as a reduction of Long-Term Debt for presentation purposes on the Consolidated Balance Sheet in the third quarter of 2023.

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

The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2023 is: 2024 – $4.9 million; 2025 – $4.9 million; 2026 – $37.9 million; 2027 – $55.7 million; 2028 – $10.7 million and thereafter $403.1 million.

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


	December 31,
Estimated Fair Value of Long-Term Debt (millions)	2023		2022
Estimated Fair Value of Long-Term Debt	$	470.5	$	455.3

Details on long-term debt at December 31, 2023 and 2022 are shown below:


	December 31,
Long-Term Debt (millions)	2023		2022
Unitil Corporation:
3.70% Senior Notes, Due August 1, 2026	$	30.0	$	30.0
3.43% Senior Notes, Due December 18, 2029		30.0		30.0
Unitil Energy First Mortgage Bonds:
6.96% Senior Secured Notes, Due September 1, 2028		10.0		12.0
8.00% Senior Secured Notes, Due May 1, 2031		12.0		13.5
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
Fitchburg:
6.79% Senior Notes, Due October 15, 2025		—		2.0
3.52% Senior Notes, Due November 1, 2027		10.0		10.0
7.37% Senior Notes, Due January 15, 2029		7.2		8.4
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		—
3.78% Senior Notes, Due September 15, 2040		27.5		27.5
4.32% Senior Notes, Due November 1, 2047		15.0		15.0
5.96% Senior Notes, Due July 2, 2053		13.0		—
Northern Utilities:
3.52% Senior Notes, Due November 1, 2027		20.0		20.0
7.72% Senior Notes, Due December 3, 2038		50.0		50.0
3.78% Senior Notes, Due September 15, 2040		40.0		40.0
4.42% Senior Notes, Due October 15, 2044		50.0		50.0
4.32% Senior Notes, Due November 1, 2047		30.0		30.0
4.04% Senior Notes, Due September 12, 2049		40.0		40.0
Granite State:
3.72% Senior Notes, Due November 1, 2027		15.0		15.0
Unitil Realty Corp.:
2.64% Senior Secured Notes, Due December 18, 2030		4.0		4.2
Total Long-Term Debt		517.2		499.1
Less: Unamortized Debt Issuance Costs		3.2		3.3
Total Long-Term Debt, net of Unamortized Debt Issuance Costs		514.0		495.8
Less: Current Portion(1)		4.9		6.7
Total Long-Term Debt, Less Current Portion	$	509.1	$	489.1

(1)

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

Interest Expense, Net—Interest expense is presented in the financial statements net of interest income. Interest expense is mainly comprised of interest on long-term debt and short-term borrowings. In addition, certain reconciling rate mechanisms

used by the Company’s distribution operating utilities give rise to regulatory assets and regulatory liabilities on which interest is 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)	2023			2022			2021
Interest Expense
Long-Term Debt	$	24.7		$	24.7		$	26.0
Short-Term Debt		9.2			3.0			0.8
Regulatory Liabilities & Other		1.0			0.6			0.4
Subtotal Interest Expense		34.9			28.3			27.2
Interest Income
Regulatory Assets		(3.3	)		(1.0	)		(0.5	)
AFUDC(1) and Other		(2.9	)		(1.8	)		(1.1	)
Subtotal Interest Income		(6.2	)		(2.8	)		(1.6	)
Total Interest Expense, Net	$	28.7		$	25.5		$	25.6

(1)

AFUDC—Allowance for Funds Used During Construction

Credit Arrangements

On September 29, 2022, the Company entered into a Third Amended and Restated Credit Agreement with a syndicate of lenders (collectively, the “Credit Facility”), which amended and restated in its entirety the prior credit facility. Unitil may borrow under the Credit Facility until September 29, 2027, subject to two one-year extensions under certain circumstances. The Credit Facility terminates and all amounts outstanding thereunder are due and payable on September 29, 2027, subject to the potential extension discussed in the prior sentence.

The Credit Facility has a borrowing limit of $200 million, which includes a $25 million sublimit for the issuance of standby letters of credit. Unitil may increase the borrowing limit under the Credit Facility by up to $75 million under certain circumstances. The Credit Facility generally provides Unitil with the ability to elect that borrowings under the Credit Facility bear interest under several options, including a daily fluctuating rate equal to (a) the forward-looking secured overnight financing rate (as administered by the Federal Reserve Bank of New York) term rate with a term equivalent to one month beginning on that date, plus (b) 0.1000%, plus (c) a margin of 1.125% to 1.375% (based on Unitil’s credit rating).

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $ 327.2 million and $295.9 million for the years ended December 31, 2023 and December 31, 2022, respectively. Total gross repayments were $281.2 million and $ 244.0 million for the years ended December 31, 2023 and December 31, 2022, respectively. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2023 and December 31, 2022:


	December 31,
Revolving Credit Facility (millions)	2023		2022
Limit	$	200.0	$	200.0
Short-Term Borrowings Outstanding	$	162.0	$	116.0
Available	$	38.0	$	84.0

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, 2023 and December 31, 2022, 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 6.4%, 3.3%, and 1.2 % during 2023, 2022, and 2021, respectively.

Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State are currently rated “BBB+” by Standard & Poor’s Ratings Services. Unitil Corporation and Granite State are currently rated “Baa2”, and Fitchburg, Unitil Energy and Northern Utilities are currently rated “Baa1” by Moody’s Investors Services.

Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There was $10.9 million of natural gas storage inventory and corresponding obligations at December 31, 2023 related to these asset management agreements. The amount of natural gas inventory released in December 2023, which was payable in January 2024, was $2.2 million and was recorded in Accounts Payable at December 31, 2023.

Contractual Obligations

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


			Payments Due by Period
Long-Term Debt Contractual Obligations (millions) as of December 31, 2022	Total		2024		2025		2026		2027		2028		2029 & Beyond
Long-Term Debt	$	517.2	$	4.9	$	4.9	$	37.9	$	55.7	$	10.7	$	403.1
Interest on Long-Term Debt		342.1		24.7		24.4		24.0		22.3		19.9		226.8
Total	$	859.3	$	29.6	$	29.3	$	61.9	$	78.0	$	30.6	$	629.9

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, 2023, 2022 and 2021 amounted to $2.1 million, $1.8 million and $1.9 million respectively. The balance sheet classification of the Company’s lease obligations was as follows:


	December 31,
Lease Obligations (millions)	2023		2022
Operating Lease Obligations:
Operating Lease Obligations (current portion)	$	1.9	$	1.5
Operating Lease Obligations (long-term portion)		3.7		2.8
Total Operating Lease Obligations		5.6		4.3
Capital Lease Obligations:
Other Current Liabilities (current portion)		0.1		0.1
Other Noncurrent Liabilities (long-term portion)		0.4		0.1
Total Capital Lease Obligations		0.5		0.2
Total Lease Obligations	$	6.1	$	4.5

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

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

The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2023. The payments for operating leases consist of $1.9 million of current operating lease obligations and $3.7 million of noncurrent operating lease obligations on the Company’s Consolidated Balance Sheets as of December 31, 2023. The payments for capital leases consist of $0.1 million of current Capital Lease Obligations, which are included in Other Current Liabilities, and $0.4 million of noncurrent Capital Lease Obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2023.


Lease Payments ($000’s) Year Ending December 31,	Operating Leases		Capital Leases
2024	$	2,063	$	152
2025		1,502		120
2026		1,171		107
2027		898		104
2028		336		19
2029-2033		84		—
Total Payments		6,054		502
Less: Interest		493		26
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$	5,561	$	476

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, 2023, the weighted average remaining lease term is 3.7 years and the weighted average operating discount rate used to determine the operating lease obligations was 4.4%. As of December 31, 2022, the weighted average remaining lease term was 3.4 years and the weighted average operating discount rate used to determine the operating lease obligations was 3.9%.

Guarantees

The Company provides limited guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of December 31, 2023 there were no 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 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 2: 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 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 470
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org//470/tableOfContent

Reference 4: 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 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (g)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1B

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (i)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1B

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1C

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1C

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1C

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1E
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1E

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

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1I
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1I

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1I
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1I

+ Details

Commitments and Contingencies

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 7: Commitments and Contingencies

Regulatory Matters

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

Energy, Northern Utilities' New Hampshire division, and Fitchburg’s electric and gas divisions operate under revenue decoupling mechanisms.

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

Rate Case Activity

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

Northern Utilities - Targeted Infrastructure Replacement Adjustment (TIRA) - Maine - The settlement in Northern Utilities’ Maine division’s 2013 rate case authorized the Company to implement a TIRA rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects, including the Company’s Cast Iron Replacement Program (CIRP). In its Final Order issued on February 28, 2018 for Northern Utilities’ 2017 base rate case, the MPUC approved an extension of the TIRA mechanism for an additional eight-year period, which will allow for annual rate adjustments through the end of the CIRP program. The Company’s most recent request under the TIRA mechanism, to increase annual base rates by $2.1 million for 2022 eligible facilities, was filed with the MPUC on February 28, 2023. On April 26, 2023, the MPUC issued an order approving the filing, for rates effective May 1, 2023.

Northern Utilities - Base Rates - New Hampshire - On July 20, 2022, the NHPUC issued an Order in the distribution base rate case filed with the NHPUC on August 2, 2021 by Northern Utilities. The Order approved a comprehensive Settlement Agreement between the Company, the New Hampshire Department of Energy (DOE), and the Office of the Consumer Advocate (OCA). As provided in the Settlement Agreement, in addition to authorizing an increase to permanent distribution rates of $6.1 million, effective August 1, 2022, the Order (1) approved a revenue decoupling mechanism and (2) allowed for a step adjustment effective September 1, 2022 covering the additional revenue requirement resulting from changes in Net Plant in Service associated with non-growth investments for the period January 1, 2021, through December 31, 2021. This distribution base rate case reflected the Company’s operating costs and investments in utility plant for a test year ended December 31, 2020 as adjusted for known and measurable changes. The Order provided for a return on equity of 9.3% and a capital structure reflecting 52% equity and 48% long-term debt. In light of the Step Adjustment, the Company shall not file a distribution rate case with the Commission before January 1, 2024 (the Stay-Out Period). However, during the term of the Stay-Out Period, the Company will be allowed to adjust distribution rates upward or downward resulting from a singular (not collective) exogenous event that exceeds $200,000. The increase in permanent rates was reconciled back to October 1, 2021, the effective date of temporary rates previously approved in this docket. On June 8, 2022, the Company filed for its step increase of approximately $1.6 million of annual revenue, for rates effective as of September 1, 2022, to recover eligible 2021 capital investments. On August 31, 2022, the NHPUC approved the Company’s filing. Under the terms of the Settlement Agreement, parties agreed that the Company shall recover revenues associated with the full rate year (August 1, 2022 – July 31, 2023) over an eleven-month period beginning September 1, 2022 and ending July 31, 2023. On May 5, 2023, the Company made a compliance filing to adjust base distribution rates downward to reflect a 12-month recovery period effective August 1, 2023. On July 13, 2023, the NHPUC approved the Company’s compliance filing.

Unitil Energy - Base Rates - On May 3, 2022, the NHPUC issued an Order in the distribution base rate case filed with the NHPUC on April 2, 2021 by Unitil Energy. The Order approved, in part, a comprehensive Settlement Agreement between the Company, the New Hampshire DOE, the OCA, the New Hampshire Department of Environmental Services, Clean Energy New Hampshire, and ChargePoint, Inc. In addition to authorizing an increase to permanent distribution rates of $6.3 million, effective June 1, 2022, the Order approved the following components of the Settlement Agreement: (1) a multi-year rate plan, (2) a revenue decoupling mechanism, (3) time-of-use rates, (4) resiliency programs to support the Company’s commitment to

reliability, and (5) other rate design and tariff changes. On May 10, 2022, the Company filed a request for clarification with the NHPUC to clarify that the authorized revenue requirement should exclude expenses related to the Company’s proposed Arrearage Management Program (AMP), which was not approved in the Order. On May 12, 2022, the Commission issued an Order, which clarified that because the Company will not incur the expenses associated with the AMP, those costs should be removed from the revenue requirement, and that the adjusted increase of $5.9 million will result in reasonable rates. The increase in permanent rates was reconciled back to June 1, 2021, the effective date of temporary rates previously approved in this docket. This distribution base rate case reflected the Company’s operating costs and investments in utility plant for a test year ended December 31, 2020 as adjusted for known and measurable changes. The Order provided for a return on equity of 9.2% and a capital structure reflecting 52% equity and 48% long-term debt. On July 28, 2022, the NHPUC approved the Company’s first step increase of approximately $1.3 million of annual revenue to recover eligible 2021 capital investments, effective August 1, 2022. On May 31, 2023, the NHPUC approved the Company’s second and final step adjustment increase of approximately $1.2 million to recover eligible 2022 capital investments, effective June 1, 2023.

Fitchburg - Base Rates - Electric - Fitchburg’s base rates are decoupled and subject to an annual revenue decoupling adjustment mechanism, which includes a cap on the amount that rates may be increased in any year. In addition, Fitchburg has an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions. On November 2, 2022, Fitchburg filed its cumulative revenue requirement of $3.1 million associated with its 2019-2021 capital expenditures. The MDPU allowed the associated rate increase to become effective on January 1, 2023, subject to further investigation and reconciliation. On July 26, 2023, the MDPU issued an Order approving the Company's filing. On November 1, 2023, Fitchburg filed its cumulative revenue requirement of $3.6 million associated with its 2019-2022 capital expenditures. On November 27, 2023, Fitchburg revised its cumulative revenue requirement to $3.5 million. On December 22, 2023, the MDPU allowed the associated rate increase to become effective on January 1, 2024, subject to further investigation and reconciliation.

On August 17, 2023, Fitchburg filed a petition with the MDPU seeking approval for a $6.8 million increase to base distribution rates, with new rates anticipated to be effective July 1, 2024. Fitchburg proposes to transfer $2.7 million in revenue requirements recovered through certain reconciling mechanisms to base distribution rates. Net of these transfers, the proposed overall increase to distribution revenues is $4.1 million. As part of this filing, Fitchburg is requesting approval for a performance-based ratemaking (PBR) plan for up to a five-year term and continuation of its revenue decoupling mechanism. A decision from the MDPU is expected in June 2024.

Fitchburg - Base Rates - Gas - On August 17, 2023, Fitchburg filed a petition with the MDPU seeking approval for a $10.9 million increase to base distribution rates, with new rates anticipated to be effective July 1, 2024. Fitchburg proposes to transfer $4.2 million in revenue requirements recovered through its Gas System Enhancement Program to base distribution rates. Net of these transfers, the proposed overall increase to distribution revenues is $6.7 million. As part of this filing, Fitchburg is requesting approval for a PBR plan for up to a five-year term and continuation of its revenue decoupling mechanism. A decision from the MDPU is expected in June 2024.

Fitchburg - Gas System Enhancement Program- Pursuant to statute and MDPU order, Fitchburg has an approved Gas System Enhancement Plan tariff through which it may recover certain gas infrastructure replacement and safety related investment costs, subject to an annual cap. Under the plan, the Company is required to make two annual filings with the MDPU: a forward-looking filing for the subsequent construction year, to be filed on or before October 31; and a filing, submitted on or before May 1, of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably and prudently incurred. Fitchburg’s forward-looking cumulative revenue requirement filing submitted on October 31, 2022 requested recovery of approximately $4.5 million, and received final approval on April 28, 2023, effective May 1, 2023. The Company’s most recent forward-looking cumulative revenue requirement filing, filed on October 31, 2023, requested recovery of approximately $6.4 million. The Company considers these to be routine regulatory proceedings, and there are no material issues outstanding.

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

On August 24, 2021, the FERC accepted Granite State’s first limited Section 4 rate adjustment pursuant to the Settlement Agreement, for an annual revenue increase of $0.1 million, effective September 1, 2021. On August 19, 2022, the FERC accepted Granite State’s second limited Section 4 rate adjustment pursuant to the Settlement Agreement, for an annual revenue increase of $0.3 million, effective September 1, 2022. On July 27, 2023, Granite State filed its third and final limited Section 4 rate adjustment pursuant to the Settlement Agreement, for an annual revenue increase of $1.0 million, effective September 1, 2023. On August 22, 2023, the FERC approved this filing.

Other Matters

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

Fitchburg - Grid Modernization - On July 1, 2021, Fitchburg submitted its Grid Modernization Plan (GMP) to the MDPU. The GMP includes a five-year strategic plan, including a plan for the full deployment of advanced metering functionality, and a four-year short-term investment plan, which focuses on foundational investments to facilitate the interconnection and integration of distributed energy resources, optimizing system performance through command and control and self-healing measures, and optimizing system demand by facilitating consumer price-responsiveness. On October 7, 2022, the MDPU issued a “Track 1” Order approving a budget cap of $9.3 million through 2025 for previously deployed or preauthorized grid modernization investments. On November 30, 2022, the MDPU issued its “Track 2” Order addressing new technologies and Advanced Metering Infrastructure (AMI) proposals. The MDPU preauthorizes a four-year $1.5 million budget for Fitchburg’s additional grid-facing investments. 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. On March 31, 2023, the Company submitted an AMI opt-out tariff with full support of proposed opt-out fees in compliance with the Track 2 Order. The MDPU approved the tariff on April 7, 2023.

On April 24, 2023, Fitchburg submitted its 2022 Grid Modernization Plan Annual Report to the MDPU. Among other things, the Company explained a modification to its implementation of the AMI plan that the Department preauthorized in D.P.U. 21-82. Due to a discontinuation of the meter technology upon which the Company’s initial AMI plan relied, the Company reported that it will need to replace its meters with a new meter technology and to implement a new communications system. On May 31, 2023, the MDPU issued an Order indicating its intent to explore the impact of the discontinuation and determine the appropriate next steps outside the GMF proceeding.

Fitchburg - Grid Modernization Cost Recovery Factor - On April 15, 2022, Fitchburg filed its GMF rate adjustment and reconciliation filing pursuant to the Company’s GMF Tariff, for recovery of the costs incurred as a result of implementing the Company’s 2018-2021 GMP, previously approved by the MDPU on February 7, 2019. The proposed GMF of $0.4 million was approved on May 27, 2022, effective June 1, 2022, subject to further investigation and reconciliation. On April 15, 2023, Fitchburg filed its GMF rate adjustment and reconciliation filing for recovery of the costs incurred as a result of implementing the Company’s 2022-2025 GMP, approved by the MDPU in Orders dated October 7, 2022 and November 30, 2022. On May 31, 2023, the MDPU approved, subject to further investigation and reconciliation, the cumulative recovery of $1.0 million associated with the Company’s 2022 GMP revenue requirement, effective June 1, 2023. The MDPU conducted a hearing on September 26, 2023 regarding the Company’s pending GMF filings and Grid Modernization Term Report. The matter remains pending.

Fitchburg - Investigation into the role of gas LDCs to achieve Commonwealth 2050 climate goals - The MDPU has opened an investigation to examine the role of Massachusetts gas local distribution companies (LDCs) in helping the Commonwealth achieve its 2050 climate goal of net-zero greenhouse gas (GHG) emissions. In its Order opening the inquiry, the MDPU stated it is required to consider new policies and structures as the Commonwealth reduces reliance on fossil fuels,

including natural gas, which may require LDCs to make significant changes to their planning processes and business models. The LDCs, including Fitchburg, engaged an independent consultant to conduct a study and prepare a report (Consultant Report), including a detailed study of each LDC, that analyzes the feasibility of all identified pathways to help the Commonwealth achieve its net-zero GHG goal. The study includes an examination of the potential pathways identified in the 2050 Decarbonization Roadmap developed by the MA Executive Office of Energy and Environmental Affairs, in consultation with the Massachusetts Department of Environmental Protection and the Massachusetts Department of Energy Resources (DOER). Following an active stakeholder process, on March 18, 2022, Consultant Reports on decarbonization pathways, regulatory designs and stakeholder engagement were submitted to the MDPU. Also on March 18, 2022, the LDCs, including Fitchburg, submitted proposals to the MDPU that include the LDCs’ recommendations and plans for helping the Commonwealth achieve its 2050 climate goals, supported by the Consultant Reports. The MDPU held a technical session on the Consultant Report on March 30, 2022 and a technical session on the LDC proposals on April 15, 2022. Discovery by the MDPU is complete, and the LDCs responded to stakeholder comments on July 29, 2022. Final comments from stakeholders replying to the LDCs’ comments and making any other final remarks for the MDPU’s consideration were filed on October 14, 2022.

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

Fitchburg - Electric Sector Modernization Plan - Pursuant to M.G.L. 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 and electrification technologies, improve grid reliability and resiliency, and assist the Commonwealth in achieving climate goals, among other objectives. The Council provided recommendations on the ESMP in November 2023. The Company submitted its final ESMP to the MDPU on January 29, 2024. The Company concurrently submitted a proposal to recover, among other things, incremental costs associated with ESMP investments through an annual reconciling rate adjustment mechanism. This matter remains pending before the MDPU.

Fitchburg - Electric Vehicle (EV) Proceeding - On December 30, 2022, the MDPU issued an order approving Fitchburg’s five-year EV program with a $1.0 million budget consisting of: (1) public infrastructure offering ($0.5 million); (2) Electric Vehicle Supply Equipment (EVSE) incentives for residential segment ($0.3 million); and (3) marketing and outreach ($0.2 million). The Company may shift spending between program segments and between years over the five-year term of its program, subject to a 15% cap. Any spending above the approved EV program budget or above the 15% cap for each program segment is not eligible for targeted cost recovery through the GMF and, instead, may be recovered in a base distribution rate proceeding subsequent to a prudency finding by the MDPU. Further, the MDPU has convened an EV stakeholder process to finalize EV program performance metrics. On April 3, 2023, the electric companies filed comments on the MDPU’s proposed metrics. Once performance metrics are finalized, the MDPU will require the electric companies to develop a joint state-wide program evaluation plan for MDPU approval and stakeholder input and will determine next steps at that time. The MDPU directs the Companies to submit annual reports that document their performance and these reports will be due on or before May 15th of each year. The first EV annual report is due May 15, 2024. The Company shall file annual rate adjustment and reconciliation filings on or before April 15, with rates effective June 1. The MDPU accepted the Company’s Demand Charge Alternative proposal and directed implementation within six months. The Demand Charge Alternative is offered for a ten-year period beginning July 1, 2023 with tiered rates to separately-metered EV general delivery service customers. The MDPU accepted the Company’s proposed residential EV TOU rate, effective April 1, 2023.

Fitchburg - Storm Cost Deferral Petition -On November 2, 2023, Fitchburg filed a request with the MDPU to increase its Storm Reserve Adjustment Factor effective January 1, 2024. The increase would allow the Company to recover approximately $4.8 million of costs of repairing damage to its electrical system plus $1.4 million of projected carrying costs resulting from the January and March 2023 winter storms over a five-year period. On December 19, 2023, the MDPU allowed the associated rate increase to become effective on January 1, 2024, subject to further investigation and reconciliation.

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 April 3, 2023, Northern Utilities submitted an annual informational report requesting approval on a one-year extension for the period of November 1, 2023 through October 31, 2024. The MPUC issued an Order on June 13, 2023 approving the one-year extension.

Northern Utilities / Portland Natural Gas Transmission System (PNGTS) and TransCanada Pipelines Limited (TCPL) transportation from Empress, Alberta to Granite State Gas Transmission, Inc. (GSGT) - On October 5, 2023, Northern Utilities filed with the NHPUC and the MPUC a request to approve agreements for the ability for Northern Utilities to increase supply portfolio capacity by 12,500 Dth per day in New Hampshire and Maine. This incremental capacity to Northern Utilities’ supply portfolio is proposed for effect April 1, 2024 for a thirty-year term. Northern Utilities was able to acquire this incremental supply of TCPL capacity through an open season process. On January 26, 2024 and January 30, 2024, the Company received orders from the NHPUC and MPUC, respectively, approving Northern Utilities’ proposal for Empress Agreements with PNGTS and TransCanada Pipelines.

Reconciliation Filings - Fitchburg, Unitil Energy and Northern Utilities each have a number of regulatory reconciling accounts that require annual or semi-annual filings with the MDPU, NHPUC and MPUC, respectively, to reconcile revenues and costs, and to seek approval of any rate changes. These filings include: 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 three companies. Fitchburg, Unitil Energy and Northern Utilities have been, and remain in full compliance with all directives and orders regarding these filings. The Company considers these to be routine regulatory proceedings, and there are no material issues outstanding.

Fitchburg - Massachusetts Request for Proposals (RFPs) - Pursuant to Section 83C of “An Act to Promote Energy Diversity” (2016) (the Act), the Massachusetts electric distribution companies (EDCs), including Fitchburg, are required to jointly procure a total of 1,600 MW of offshore wind by June 30, 2027. Under Section 83D of the Act, the EDCs are required to jointly seek proposals for cost-effective clean energy (hydroelectric, solar and land-based wind) long-term contracts via one or more staggered solicitations for a total of 9,450,000 megawatt-hours (MWh) by December 31, 2022. Fitchburg’s pro rata share of these contracts is approximately 1%.

The EDCs issued the RFP for Section 83D Long-Term Contracts in March 2017, and power purchase agreements (PPAs) for 9,554,940 MWh of hydroelectric generation and associated environmental attributes from Hydro-Quebec Energy Services (U.S.), Inc. were filed in July 2018 for approval by the MDPU. On June 25, 2019, the MDPU approved the PPAs, including the EDCs’ proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market revenue to customers. The MDPU also approved the EDCs’ request for remuneration equal to 2.75% of the contract payments, as well as the EDCs’ proposal to recover costs associated with the contracts. On January 13, 2023, NECEC Transmission LLC (NECEC), the company with which Fitchburg and the other EDCs entered into transmission service agreements (TSAs) for the delivery of the Hydro-Quebec energy, provided a letter to the EDCs purporting to give notice of a “change in applicable law” related to a Maine ballot initiative and requesting a negotiated amendment to the TSAs including a price adjustment. On June 27, 2023, NECEC sent a letter to the EDCs seeking schedule relief also in accordance with their “change in law” determination. The EDCs are evaluating NECEC’s requests.

The EDCs issued an initial RFP pursuant to Section 83C in June 2017. On July 23, 2018, the EDCs, filed two long-term contracts with Vineyard Wind, each for 400 MW of offshore wind energy generation, for approval by the MDPU. On

April 12, 2019, the MDPU approved the offshore wind energy generation PPAs, including the EDCs’ proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market revenue to customers. The EDCs issued a second RFP pursuant to Section 83C to procure an additional 800 MW of offshore wind energy generation in May 2019. The EDCs filed for approval of two PPAs with Mayflower Wind Energy LLC (now known as SouthCoast Wind), each for 400 MW of offshore wind energy generation, in February 10, 2020. On November 5, 2020, the MDPU approved the PPAs. In both cases, the MDPU approved the EDCs’ request for remuneration equal to 2.75% of the contract payments, as well as the EDCs’ proposal to recover costs associated with the contracts. In April 2023, SouthCoast Wind engaged with the EDCs to explore options to mitigate impacts of global resource constraints and pricing challenges associated with the PPAs from this procurement. They cited an inability to finance the project within the terms set out in the PPA. The EDCs negotiated a termination agreement with SouthCoast Wind which was filed with the MDPU for approval on August 28, 2023 and which received approval on September 30, 2023.

In accordance with “An Act to Advance Clean Energy” (2018) the Massachusetts Department of Energy Resources (DOER) recommended that the EDCs solicit up to 1,600 MW in additional offshore wind in 2022 and 2024. On May 7, 2021, the EDCs issued a third RFP for up to an additional 1,600 MW of off shore wind generation. On May 25, 2022, the EDCs sought approval of PPAs with Commonwealth Wind for 1,200 MW and with SouthCoast Wind for 400 MW. On December 16, 2022, Commonwealth Wind filed a motion requesting that the MDPU dismiss proceedings related to the approval of its contract, arguing that, due to various economic conditions, its contracts with the EDCs would no longer facilitate the financing of offshore wind energy generation. On December 30, 2022, the MDPU denied Commonwealth’s motion and approved the PPAs. The MDPU also approved the EDCs’ request for remuneration equal to 2.25% as reasonable and in the public interest. On January 19, 2023, Commonwealth Wind filed a Petition for Appeal with the Massachusetts Supreme Judicial Court seeking to set aside and vacate the MDPU’s Order approving the PPAs. In April 2023, SouthCoast Wind engaged with the EDCs to explore options to mitigate global resource constraints and pricing challenges associated with their PPAs from this procurement. SouthCoast Wind noted challenges around an inability to finance the projects under the current terms. The EDCs have negotiated termination agreements with Commonwealth Wind and SouthCoast Wind and submitted the agreements to the MDPU for approval on July 13, 2023 and August 28, 2023, respectively. The MDPU approved both termination agreements on September 30, 2023. In connection with the termination agreements the Company received $1.1 million from Commonwealth Wind and SouthCoast Wind which is recorded as a regulatory liability on the Company’s Consolidated Balance Sheets to be flowed back to customers. On October 12, 2023, Commonwealth Wind requested that the case with the Supreme Court be entered as dismissed. Concurrently, Commonwealth Wind announced publicly they could not finance the project under the terms of the PPA.

In 2021, the MA legislature increased the total solicitation target (including future solicitations) for offshore wind energy generation to 5,600 MW by June 30, 2027. On August 30, 2023, the EDCs issued a fourth offshore wind RFP seeking to procure at least 400 MW and up to the maximum amount remaining of the statutory requirement under Section 83C of 5,600 MW of Offshore Wind Energy Generation, and taking into account offshore wind generation under contract at the time when proposals are due. On January 18, 2024, the EDCs notified the MDPU that they are extending the bid submission date and subsequent solicitation schedule dates by an additional 56 days each to allow bidders the opportunity to gain more certainty around their eligibility for the investment tax credit and factor it into their proposals. The new submission date is March 27, 2024.

Section 82 of the Acts of 2022 authorizes DOER to coordinate with other New England states to consider projects for long-term clean energy generation, transmission or capacity for the benefit of residents of the Commonwealth and the region. If DOER, in consultation with the Attorney General, determines that a project would satisfy all of the benefits listed in Section 82, then pursuant to Section 82 the EDCs shall enter into cost-effective long-term contracts with a maximum term of twenty years upon such a finding. On October 26, 2022, the MPUC announced its selection of a Transmission Project and a Generation Project to promote renewable energy development in northern Maine. On December 30, 2022, the DOER made a positive determination that the selected projects would have benefits to Massachusetts and the region and Massachusetts would procure up to 40% of the projects. On December 22, 2023, the MPUC terminated the procurement after the transmission project developer indicated that it could no longer hold to the fixed price contained in its term sheet and required a price adjustment.

Fitchburg/Northern Utilities - 2024-2026 Triennial Energy Efficiency Plan - New Hampshire - On November 30, 2023, the NHPUC approved the changes to New Hampshire’s ratepayer-funded energy efficiency program offerings for the 2024–2026 period requested by New Hampshire’s electric and gas utilities.

FERC Transmission Formula Rate Proceedings- Pursuant to Section 206 of the Federal Power Act, there are several pending proceedings before the FERC concerning the justness and reasonableness of the Return on Equity (ROE) component of the ISO-New England, Inc. Participating Transmission Owners’ (PTOs) Regional Network Service and Local Network Service formula rates. In August 2013, FERC had found that the Transmission Owners existing ROE was unlawful, and set a new ROE. On April 14, 2017, the U.S. Court of Appeals for the D.C. Circuit (the Court) issued an opinion vacating and remanding FERC’s decision, finding that FERC had failed to articulate a satisfactory explanation for its orders. At this time, the ROE set in the vacated order will remain in place until further FERC action is taken. On November 21, 2019 the FERC issued an order in EL14-12, Midcontinent Independent System Operator ROE, in which FERC outlined a new methodology for calculating the ROE. The New England Transmission Owners (NETOs) thereafter filed a motion to reopen the record in their pending ROE dockets, which has been granted. This matter remains pending. The Company does not believe these proceedings will have a material adverse effect on its financial condition or results of operations.

On December 13, 2022, RENEW Northeast, Inc., a non-profit entity that advocates for the business interests of renewable power generators in New England filed a complaint with FERC against ISO-NE and the PTOs requesting a determination that certain open-access transmission tariff schedules are unjust and unreasonable to the extent they permit PTOs to directly assign to interconnection customers O&M costs associated with network upgrades. Fitchburg and Unitil Energy are PTOs, although Unitil Energy does not own transmission plant. The PTOs answered the complaint on January 23, 2023. This matter remains pending. 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, 2023.


			Payments Due by Period
Gas and Electric Supply Contractual Obligations (millions) as of December 31, 2023	Total		2024		2025		2026		2027		2028		2029 & Beyond
Gas Supply Contracts	$	479.2	$	79.9	$	45.7	$	44.3	$	43.8	$	39.1	$	226.4
Electric Supply Contracts		12.1		1.3		1.3		1.3		1.3		1.1		5.8
Total	$	491.3	$	81.2	$	47.0	$	45.6	$	45.1	$	40.2	$	232.2

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, 2023, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, the Company cannot assure that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs. Based on its current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, the Company does not believe that these environmental costs will have a material adverse effect on the Company’s consolidated financial position or results of operations.

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

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

In July 2019, the NH DES requested that Northern Utilities review modeled expectations for groundwater contaminants against observed data at the Rochester site. In June 2020, the NH DES coupled the submittal of the review to a proposed extension of the gas distribution system by Northern Utilities. Northern Utilities submitted the review in January 2022, and the NH DES directed that soil treatability studies as part of a Remedial Action Plan (RAP) be developed in June 2022. The Company submitted the studies and RAP to the NH DES in December 2022 and continues to await a decision from the agency; the RAP included three remediation alternatives for consideration by NH DES. In anticipation of the probable NH DES approval of one of the remediation alternatives and subsequent request for project design, the Company has accrued $2.5 million for estimated costs to complete the remediation at the Rochester site, which is included in Environmental Obligations on the Company’s Consolidated Balance Sheets. The Company has determined that the high end of the range of reasonably possible remediation costs for the Rochester site could be $5.6 million based on remediation alternatives. Due to extended regulatory review time periods, Northern Utilities anticipates the commencement of remediation activities in 2025.

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

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

Fitchburg’s Manufactured Gas Plant Site - Fitchburg has worked with the Massachusetts Department of Environmental Protection (Mass DEP) to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring continues. In April 2020, Fitchburg received notification from the Massachusetts Department of Transportation (Mass DOT) that a portion of the site may be incorporated into the proposed Twin City Rail Trail with an anticipated commencement date in 2025. Depending upon the final agreement between Fitchburg and Mass DOT, additional minor costs are expected prior to completion.

In August 2021, the Mass DEP issued a Notice of Non-compliance to Fitchburg following a November 2020 audit of the September 2015 Response Action Outcome on the MGP site. Mass DEP directed Fitchburg to further define the extent of MGP site contaminants in the sediment and riverbank of an abutting watercourse. Fitchburg began the investigation in November 2021 with the Mass DEP expanding the scope in June 2022 to include an observed river seep. Fitchburg submitted the results of its investigation and an Immediate Response Action (IRA) plan associated with the river seep to the Mass DEP in December 2022. The Mass DEP has review and approval authority over the IRA plan’s recommendations.

Fitchburg submitted an updated IRA plan to the Mass DEP in October 2023. The Company obtained cost-estimates for several remediation alternatives. In anticipation of the DEP accepting one of the remediation alternatives, Fitchburg has accrued $40,000 for estimated costs to complete the remediation at the Sawyer Passway site, which is included in Environmental Obligations on the Company’s Consolidated Balance Sheets. The Company has determined that the high end of the range of reasonably possible remediation costs for the Sawyer Passway site could be $3.5 million based on remediation alternatives. Fitchburg anticipates the commencement of remediation activities by the end of 2024.

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

Unitil Energy - Kensington Distribution Operations Center - Unitil Energy conducted a Phase I and II environmental site assessment (ESA) in the second quarter of 2021. The ESA results identified soil and groundwater contaminants in excess of state regulatory standards. In September 2021, the NH DES directed Unitil Energy to conduct a supplemental site investigation (SSI) and identify whether there is a need to conduct further investigation or remedial actions. Unitil Energy began the SSI in December 2021 with the NH DES extending the SSI scope in June 2022 to further delineate potential impacts. Unitil Energy completed the field portion of the SSI in September 2022 and submitted the report to the NH DES in June 2023 and is awaiting a decision by the agency. Unitil Energy anticipates the commencement of remediation activities in 2025. The Company does not believe this investigation will have a material adverse effect on its financial condition, results of operations or cash flows.

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


	December 31,
Environmental Obligations (millions)	2023		2022
Total Balance at Beginning of Period	$	4.4	$	2.7
Additions		0.7		2.0
Less: Payments / Reductions		0.5		0.3
Total Balance at End of Period		4.6		4.4
Less: Current Portion		0.6		0.6
Noncurrent Balance at End of Period	$	4.0	$	3.8

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Note 1: Summary of Significant Accounting Policies

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

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

Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and capital city areas of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire; Fitchburg, which operates in Massachusetts; and Northern Utilities, which operates in New Hampshire and Maine (collectively, the distribution utilities).

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

Unitil also has three other wholly-owned subsidiaries: Unitil Service, Unitil Resources and Unitil Realty. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary, which currently does not have any activity. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Realty also owns land for future use in Kingston, New Hampshire.

Basis of Presentation

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

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

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



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


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

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

To the extent valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. Accordingly, the degree of judgment exercised by the Company in determining fair value is greatest for instruments categorized in Level 3. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.

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

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

Utility Revenue Recognition - Electric Operating Revenues and Gas Operating Revenues consist of billed and unbilled revenue and revenue from rate adjustment mechanisms. Billed and unbilled revenue includes delivery revenue and pass-through revenue, recognized according to tariffs approved by federal and state regulatory commissions which determine the amount of revenue the Company will record for these items. Revenue from rate adjustment mechanisms is accrued revenue, recognized in connection with rate adjustment mechanisms, and authorized by regulators for recognition in the current period for future cash recoveries from, or credits to, customers.

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

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

The Company’s billed and unbilled revenue meets the definition of “revenues from contracts with customers” as defined in Accounting Standards Codification (ASC) 606. Revenue recognized in connection with rate adjustment mechanisms is consistent with the definition of alternative revenue programs in ASC 980, as the Company has the ability to adjust rates in the future as a result of past activities or completed events. The rate adjustment mechanisms meet the criteria within ASC 980. In cases where allowable costs are greater than operating revenues billed in the current period for the individual rate adjustment mechanism additional operating revenue is recognized. In cases where allowable costs are less than operating revenues billed in the current period for the individual rate adjustment mechanism, operating revenue is reduced. ASC 606 requires the Company to disclose separately the amount of revenues from contracts with customers and alternative revenue program revenues.

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


	Twelve Months Ended
	December 31, 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


	Twelve Months Ended
	December 31, 2022
Electric and Gas Operating Revenues (millions):	Electric		Gas		Total
Billed and Unbilled Revenue:
Residential	$	159.9	$	98.2	$	258.1
Commercial & Industrial		112.6		153.8		266.4
Other		17.7		11.3		29.0
Total Billed and Unbilled Revenue		290.2		263.3		553.5
Rate Adjustment Mechanism Revenue		7.7		2.0		9.7
Total Electric and Gas Operating Revenues	$	297.9	$	265.3	$	563.2


	Twelve Months Ended
	December 31, 2021
Electric and Gas Operating Revenues (millions):	Electric		Gas		Total
Billed and Unbilled Revenue:
Residential	$	135.1	$	83.9	$	219.0
Commercial & Industrial		103.3		124.1		227.4
Other		10.1		9.6		19.7
Total Billed and Unbilled Revenue		248.5		217.6		466.1
Rate Adjustment Mechanism Revenue		—		7.2		7.2
Total Electric and Gas Operating Revenues	$	248.5	$	224.8	$	473.3

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 Massachusetts Department of Public Utilities (MDPU) and New Hampshire Public Utilities Commission (NHPUC). Fitchburg has been subject to revenue decoupling since 2011. Unitil Energy has been subject to revenue decoupling since June 1, 2022. As a result of Unitil Energy now being subject to revenue decoupling, as of June 1, 2022, revenue decoupling now applies to substantially all of Unitil’s total annual electric sales volumes. Substantially all of Northern Utilities’ gas sales volumes in New Hampshire have been subject to decoupling since August 1, 2022. The Company's electric and gas sales in New Hampshire and Massachusetts are now largely decoupled. The following table shows the estimated percentages of electric and gas sales, as of December 31, 2023, that are subject to revenue decoupling for the periods presented.

Revenue Decoupling

Estimated Percentage of Decoupled Sales

For Periods Presented


Electric
Before June 1, 2022		27%
After June 1, 2022		Substantially All
Gas
Before August 1, 2022		11%
After August 1, 2022		42%

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

Depreciation and Amortization - Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets, and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company’s fixed assets. A change in the estimated useful lives of these assets could have a material effect on the Company’s consolidated financial statements. Provisions for depreciation were equivalent to the following composite rates, based on the average depreciable property balances at the beginning and end of each year: 2023 - 3.33%, 2022 - 3.26% and 2021 - 3.29%.

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

Income Taxes - The Company is subject to Federal and State income taxes as well as various other business taxes. The Company’s process for determining income tax amounts involves estimating the Company’s current tax liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included in the Company’s Consolidated Balance Sheets. The Company accounts for income tax assets, liabilities and expenses in accordance with the FASB Codification guidance on Income Taxes. The Company classifies penalties and interest expense related to income tax liabilities as income tax expense and interest expense, respectively, in the Consolidated Statements of Earnings.

Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known.

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

Dividends - The Company’s dividend policy is reviewed periodically by the Board of Directors. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. For the year ended December 31, 2023 the Company paid quarterly dividends of $0.405 per share, resulting in an annualized dividend rate of $1.62 per common share. For the years ended December 31, 2022 and 2021, the Company paid quarterly dividends of $0.39 and $0.38 per common share, respectively, resulting in annualized dividend rates of $1.56 and $1.52 per common share, respectively. At its January 2024 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.425 per share, an increase of $0.02 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $1.70 per share from $1.62 per share.

Cash and Cash Equivalents - Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the

Company’s credit rating. On December 31, 2023 and 2022, the Unitil subsidiaries had deposited $3.3 million and $6.0 million, respectively, to satisfy their ISO-NE obligations.

Allowance for Doubtful Accounts - The Company recognizes a provision for doubtful accounts that reflects the Company’s estimate of expected credit losses for electric and gas utility service accounts receivable. The allowance for doubtful accounts is calculated by applying a historical loss rate to customer account balances and management’s assessment of current and expected economic conditions, customer trends, or other factors. The Company also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of the energy commodity portion of bad debts through rate mechanisms. Also, the electric and gas divisions of Fitchburg are authorized to recover through rates past due amounts associated with protected hardship accounts. Evaluating the adequacy of the allowance for doubtful accounts requires judgment about the assumptions used in the analysis. The Company’s experience has been that the assumptions used in evaluating the adequacy of the allowance for doubtful accounts have proven to be reasonably accurate. (See Note 3 Allowance for Doubtful Accounts).

Accounts Receivable, Net includes $2.3 million and $2.5 million of the Allowance for Doubtful Accounts at December 31, 2023 and December 31, 2022, respectively. Unbilled Revenues, net (a component of Accrued Revenue) includes $0.1 million and $0.1 million of the Allowance for Doubtful Accounts at December 31, 2023 and December 31, 2022, respectively.

Accrued Revenue - Accrued Revenue includes the current portion of Regulatory Assets (see “Regulatory Accounting”) and unbilled revenues (see “Utility Revenue Recognition”). The following table shows the components of Accrued Revenue as of December 31, 2023 and 2022.


	December 31,
Accrued Revenue (millions)	2023		2022
Regulatory Assets—Current	$	56.5	$	66.5
Unbilled Revenues		6.9		6.3
Total Accrued Revenue	$	63.4	$	72.8

Exchange Gas Receivable - Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers natural gas back to the Company during the months of November through March. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of December 31, 2023 and 2022.


	December 31,
Exchange Gas Receivable (millions)	2023		2022
Northern Utilities	$	8.6	$	16.3
Fitchburg		0.8		1.7
Total Exchange Gas Receivable	$	9.4	$	18.0

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, 2023 and 2022.


	December 31,
Gas Inventory (millions)	2023		2022
Natural Gas	$	0.3	$	1.0
Propane		0.3		0.4
Liquefied Natural Gas & Other		0.4		0.4
Total Gas Inventory	$	1.0	$	1.8

The Company also has an inventory of Materials and Supplies in the amounts of $13.5 million and $11.4 million as of December 31, 2023 and December 31, 2022, respectively. These amounts are recorded at weighted average cost.

Utility Plant - The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost of additions consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The average interest rates applied to AFUDC were 5.48%, 2.50% and 1.71% in 2023, 2022 and 2021, 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, 2023 and 2022, the Company has recorded cost of removal amounts of $126.3 million and $116.1 million, respectively, that have been collected in depreciation rates but have not yet been expended, and which represent regulatory liabilities. These amounts are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations.

Regulatory Accounting - The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the MDPU, Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC) and Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the FASB Codification. The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission. The electric and gas divisions of Fitchburg are authorized to recover through rates past due amounts associated with hardship accounts that are protected from shut-off. As of December 31, 2023 and December 31, 2022, the Company has recorded $6.0 million and $5.8 million, respectively, of hardship accounts in Regulatory Assets. These amounts are included in “Other Deferred Charges” in the following table. 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)	2023		2022
Retirement Benefits	$	29.8	$	29.1
Energy Supply & Other Rate Adjustment Mechanisms		52.4		63.0
Deferred Storm Charges		9.2		3.4
Environmental		6.1		5.9
Income Taxes		1.1		1.8
Other Deferred Charges		11.0		11.1
Total Regulatory Assets		109.6		114.3
Less: Current Portion of Regulatory Assets(1)		56.5		66.5
Regulatory Assets—noncurrent	$	53.1	$	47.8

(1)

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


	December 31,
Regulatory Liabilities consist of the following (millions)	2023		2022
Rate Adjustment Mechanisms	$	9.3	$	10.9
Income Taxes		38.6		41.0
Total Regulatory Liabilities		47.9		51.9
Less: Current Portion of Regulatory Liabilities		13.5		15.0
Regulatory Liabilities—noncurrent	$	34.4	$	36.9

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, 2023 are $7.2 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years. Regulators have authorized recovery of these expenditures, but without a return. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material effect on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

Leases - The Company records assets and liabilities on the balance sheet for all leases with terms longer than 12 months. Leases are classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The Company has elected the practical expedient to not separate non-lease components from lease components and instead to account for both as a single lease component. The Company’s accounting policy election for leases with a lease term of 12 months or less is to recognize the lease payments as lease expense in the Consolidated Statements of Earnings on a straight-line basis over the lease term. See additional discussion in the “Leases” section of Note 4 (Debt and Financing Arrangements).

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

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

Investments in Marketable Securities - The Company maintains a trust through which it invests in a money market fund and a fixed income fund. These funds are intended to satisfy obligations under the Company’s Supplemental Executive Retirement Plan (SERP) (See additional discussion of the SERP in Note 9 Retirement Benefit Plans).

At December 31, 2023 and 2022, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $6.0 million and $5.8 million, respectively, as shown in the following table. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other (Income) Expense, Net.


	December 31,
Fair Value of Marketable Securities (millions)	2023		2022
Money Market Funds	$	2.0	$	5.8
Fixed Income Funds		4.0		—
Total Marketable Securities	$	6.0	$	5.8

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, 2023 and 2022, the fair value of the Company’s investments in these trading securities related to the DC Plan, which are recorded on the Consolidated Balance Sheets in Other Assets, were $1.3 million and $0.6 million, respectively. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other (Income) Expense, Net.


	December 31,
Fair Value of Marketable Securities (millions)	2023		2022
Equity Funds	$	1.1	$	0.5
Fixed Income Funds		0.1		—
Money Market Funds		0.1		0.1
Total Marketable Securities	$	1.3	$	0.6

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


	December 31,
Energy Supply Obligations consist of the following (millions)	2023		2022
Renewable Energy Portfolio Standards	$	6.4	$	7.8
Exchange Gas Obligation		8.6		16.3
Total Energy Supply Obligations	$	15.0	$	24.1

Renewable Energy Portfolio Standards - Renewable Energy Portfolio Standards (RPS) require retail electricity suppliers, including public utilities, to demonstrate that required percentages of their sales are met with power generated from certain types of resources or technologies. Compliance is demonstrated by purchasing and retiring Renewable Energy Certificates (REC) generated by facilities approved by the state as qualifying for REC treatment. Unitil Energy and Fitchburg purchase RECs in compliance with RPS legislation in New Hampshire and Massachusetts for supply provided to default service customers. RPS compliance costs are a supply cost that is recovered in customer default service rates. Unitil Energy and Fitchburg collect RPS compliance costs from customers throughout the year and demonstrate compliance for each calendar year on the following July 1. Due to timing differences between collection of revenue from customers and payment of REC costs to suppliers, Unitil Energy and Fitchburg typically defer costs for RPS compliance which are recorded within Accrued Revenue with a corresponding liability in Energy Supply Obligations on the Company’s Consolidated Balance Sheets.

Fitchburg has entered into long-term renewable contracts for the purchase of clean energy and/or RECs pursuant to Massachusetts legislation, specifically, An Act Relative to Green Communities (Green Communities Act, 2008), An Act Relative to Competitively Priced Electricity in the Commonwealth (2012) and An Act to Promote Energy Diversity (Energy Diversity Act, 2016). The generating facilities associated with ten of these contracts have been constructed and are now operating. Three approved contracts are currently under development. These include long-term contracts filed with the MDPU in 2018, two for offshore wind generation (each 400MW) and one for imported hydroelectric power and associated transmission, all three of which were approved in 2019. Four offshore wind contracts, totaling 2,400 MW, previously solicited for pursuant to the Green Communities Act and approved by the MDPU in 2021 and 2022, were subsequently terminated in September 30, 2023. In compliance with the Green Communities Act as amended by the Energy Diversity Act and the Act Driving Clean Energy and Offshore Wind in coordination with the other electric distribution companies (EDCs) in Massachusetts, on August 30, 2023 the Company issued a fourth offshore wind Request for Proposal seeking to procure at least 400 MW and up to the maximum amount remaining of the statutory requirement under Section 83C of 5,600 MW. On January 18, 2024, the EDCs notified the MDPU that they are extending the bid submission date and subsequent solicitation schedule dates by an additional 56 days each to allow bidders the opportunity to gain more certainty around their eligibility for the investment tax credit and factor it into their proposals. The new submission date is March 27, 2024. Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism, and has received remuneration for entering into them.

Exchange Gas Obligation - Northern Utilities enters into gas exchange agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. The gas inventory related to these agreements is recorded in Exchange Gas

Receivable on the Company’s Consolidated Balance Sheets while the corresponding obligations are recorded in Energy Supply Obligations.

Retirement Benefit Obligations - The Company sponsors the Pension Plan, which is a defined benefit pension plan. Effective January 1, 2010, the Pension Plan was closed to new non-union employees. For union employees, the Pension Plan was closed on various dates between December 31, 2010 and June 1, 2013, depending on the various Collective Bargaining Agreements of each union. The Company also sponsors a non-qualified retirement plan, the SERP, covering certain executives of the Company, and an employee 401(k) savings plan. Additionally, the Company sponsors the PBOP Plan, primarily to provide health care and life insurance benefits to retired employees.

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

Commitments and Contingencies - The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of December 31, 2023, the Company is not aware of any material commitments or contingencies other than those disclosed in Note 7 (Commitments and Contingencies).

Environmental Matters - The Company’s past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. The Company has recovered or will recover substantially all of the costs of the environmental remediation work performed to date from customers or from its insurance carriers. The Company believes it is in compliance with all applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2023, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 7 (Commitments and Contingencies). Changes in future environmental compliance regulations or in future cost estimates of environmental remediation costs could have a material effect on the Company’s financial position if those amounts are not recoverable in regulatory rate mechanisms.

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

12 Months Ended

Dec. 31, 2023

Details on Long Term Debt

Details on long-term debt at December 31, 2023 and 2022 are shown below:


	December 31,
Long-Term Debt (millions)	2023		2022
Unitil Corporation:
3.70% Senior Notes, Due August 1, 2026	$	30.0	$	30.0
3.43% Senior Notes, Due December 18, 2029		30.0		30.0
Unitil Energy First Mortgage Bonds:
6.96% Senior Secured Notes, Due September 1, 2028		10.0		12.0
8.00% Senior Secured Notes, Due May 1, 2031		12.0		13.5
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
Fitchburg:
6.79% Senior Notes, Due October 15, 2025		—		2.0
3.52% Senior Notes, Due November 1, 2027		10.0		10.0
7.37% Senior Notes, Due January 15, 2029		7.2		8.4
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		—
3.78% Senior Notes, Due September 15, 2040		27.5		27.5
4.32% Senior Notes, Due November 1, 2047		15.0		15.0
5.96% Senior Notes, Due July 2, 2053		13.0		—
Northern Utilities:
3.52% Senior Notes, Due November 1, 2027		20.0		20.0
7.72% Senior Notes, Due December 3, 2038		50.0		50.0
3.78% Senior Notes, Due September 15, 2040		40.0		40.0
4.42% Senior Notes, Due October 15, 2044		50.0		50.0
4.32% Senior Notes, Due November 1, 2047		30.0		30.0
4.04% Senior Notes, Due September 12, 2049		40.0		40.0
Granite State:
3.72% Senior Notes, Due November 1, 2027		15.0		15.0
Unitil Realty Corp.:
2.64% Senior Secured Notes, Due December 18, 2030		4.0		4.2
Total Long-Term Debt		517.2		499.1
Less: Unamortized Debt Issuance Costs		3.2		3.3
Total Long-Term Debt, net of Unamortized Debt Issuance Costs		514.0		495.8
Less: Current Portion(1)		4.9		6.7
Total Long-Term Debt, Less Current Portion	$	509.1	$	489.1

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)	2023		2022
Estimated Fair Value of Long-Term Debt	$	470.5	$	455.3

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)	2023			2022			2021
Interest Expense
Long-Term Debt	$	24.7		$	24.7		$	26.0
Short-Term Debt		9.2			3.0			0.8
Regulatory Liabilities & Other		1.0			0.6			0.4
Subtotal Interest Expense		34.9			28.3			27.2
Interest Income
Regulatory Assets		(3.3	)		(1.0	)		(0.5	)
AFUDC(1) and Other		(2.9	)		(1.8	)		(1.1	)
Subtotal Interest Income		(6.2	)		(2.8	)		(1.6	)
Total Interest Expense, Net	$	28.7		$	25.5		$	25.6

(1)

AFUDC—Allowance for Funds Used During Construction

Borrowing Limits Amounts Outstanding and Amounts Available under Credit Facility

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2023 and December 31, 2022:


	December 31,
Revolving Credit Facility (millions)	2023		2022
Limit	$	200.0	$	200.0
Short-Term Borrowings Outstanding	$	162.0	$	116.0
Available	$	38.0	$	84.0

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, 2023.


			Payments Due by Period
Long-Term Debt Contractual Obligations (millions) as of December 31, 2022	Total		2024		2025		2026		2027		2028		2029 & Beyond
Long-Term Debt	$	517.2	$	4.9	$	4.9	$	37.9	$	55.7	$	10.7	$	403.1
Interest on Long-Term Debt		342.1		24.7		24.4		24.0		22.3		19.9		226.8
Total	$	859.3	$	29.6	$	29.3	$	61.9	$	78.0	$	30.6	$	629.9

Classification of the Company Lease Obligations

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


	December 31,
Lease Obligations (millions)	2023		2022
Operating Lease Obligations:
Operating Lease Obligations (current portion)	$	1.9	$	1.5
Operating Lease Obligations (long-term portion)		3.7		2.8
Total Operating Lease Obligations		5.6		4.3
Capital Lease Obligations:
Other Current Liabilities (current portion)		0.1		0.1
Other Noncurrent Liabilities (long-term portion)		0.4		0.1
Total Capital Lease Obligations		0.5		0.2
Total Lease Obligations	$	6.1	$	4.5

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


Lease Payments ($000’s) Year Ending December 31,	Operating Leases		Capital Leases
2024	$	2,063	$	152
2025		1,502		120
2026		1,171		107
2027		898		104
2028		336		19
2029-2033		84		—
Total Payments		6,054		502
Less: Interest		493		26
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$	5,561	$	476

- 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://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 2: 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 3: 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 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482925/835-30-45-2

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482925/835-30-45-1A

Reference 6: 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 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480566/210-10-S99-1

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482949/835-30-55-8

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//1943274/2147480848/942-470-50-3

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

Energy Supply - Additional Information (Detail) - 12 months ended Dec. 31, 2023 Bcfe in Billions	Total	Total	Bcfe	BTU
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			6.3	44,000
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			0.4
Percentage of power supply requirement		50.00%
Power supply contract duration	12 months
ISO New England markets
Gas and Oil Acreage [Line Items]
Percentage of power supply requirement		50.00%
Power supply contract duration	12 months
Unitil Energy Systems Inc
Gas and Oil Acreage [Line Items]
Percentage of power supply requirement		100.00%
Power supply contract duration	6 months

Allowance for Doubtful Accounts - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Financing Receivable, Impaired [Line Items]
Recoveries	$ 0.6	$ 0.9	$ 0.8
Provision for Bad Debt	6.4	6.7	5.6
Allowance for doubtful accounts	2.4	2.6	3.3	$ 3.3
Unbilled Revenues
Financing Receivable, Impaired [Line Items]
Allowance for doubtful accounts	0.1	0.1	0.1
Accounts Receivable
Financing Receivable, Impaired [Line Items]
Allowance for doubtful accounts	2.3	2.5
Regulatory Assets Harship Accounts
Financing Receivable, Impaired [Line Items]
Recoveries	6.0	5.8
Energy Commodity
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 3.8	$ 3.8	$ 2.4

Retirement Benefit Obligations - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
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	$ 113,200
Defined benefit plan, assumed health care cost trend rate, description	The health care cost trend rate used to determine benefit obligations at December 31, 2023 for pre-65 retirees is 8.00%, with an ultimate rate of 4.50% in 2033, and for post-65 retirees, the health care cost trend rate is 6.00%, with an ultimate rate of 4.50% in 2033. The health care cost trend rate used to determine benefit obligations at December 31, 2022 for pre-65 retirees is 8.00%, with an ultimate rate of 4.50% in 2030, and for post-65 retirees, the health care cost trend rate is 6.25%, with an ultimate rate of 4.50% in 2030. The health care cost trend rate used to determine benefit obligations at December 31, 2021 for both pre-65 and post-65 retirees is 6.20%, with an ultimate rate 4.50% in 2029.	The health care cost trend rate used to determine benefit obligations at December 31, 2022 for pre-65 retirees is 8.00%, with an ultimate rate of 4.50% in 2030, and for post-65 retirees, the health care cost trend rate is 6.25%, with an ultimate rate of 4.50% in 2030. The health care cost trend rate used to determine benefit obligations at December 31, 2021 for both pre-65 and post-65 retirees is 6.20%, with an ultimate rate 4.50% in 2029
Regulatory assets	$ 109,600	$ 114,300
Health Care Cost Trend Rate, Description	The health care cost trend rate used to determine plan costs for 2023 for pre-65 retirees is 8.00%, with an ultimate rate of 4.50% in 2030, and for post-65 retirees, the health care cost trend rate is 6.25%, with an ultimate rate of 4.50% in 2030. The health care cost trend rate used to determine plan costs for 2022 for both pre-65 retirees and post-65 retirees is 6.20%, with an ultimate rate of 4.50% in 2029. The health care cost trend rate used to determine plan costs for 2021 for both pre-65 retirees and post-65 retirees is 6.60%, with an ultimate rate of 4.50% in 2029.	The health care cost trend rate used to determine plan costs for 2022 for both pre-65 retirees and post-65 retirees is 6.20%, with an ultimate rate of 4.50% in 2029. The health care cost trend rate used to determine plan costs for 2021 for both pre-65 retirees and post-65 retirees is 6.60%, with an ultimate rate of 4.50% in 2029.
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation	$ 146,300	$ 138,300
Defined Benefit Plan, Plan Assets, Contributions by Employer	3,850	3,800	$ 4,100
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	2,790	12,153	8,903
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation	14,400	13,900
Defined Benefit Plan, Plan Assets, Contributions by Employer	665	637	637
Fair Value Of Plan Assets
Defined Benefit Plan Disclosure [Line Items]
Pension expense	2,800	2,400	6,100
Defined Benefit Obligations
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	29,800	29,100
Four Zero One K Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 4,000	$ 3,500	$ 3,300
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	8.00%	8.00%	6.20%
Health care cost trend rate determine plan costs	8.00%	6.20%
Health care cost trend rate, ultimate rate in year	2033	2030	2029
Reaches Ultimate Trend Rate Year	2030		2029
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	6.00%	6.25%	6.20%
Health care cost trend rate determine plan costs	6.25%
Health care cost trend rate, ultimate rate in year	2033	2030	2029
Reaches Ultimate Trend Rate Year	2030	2029
Pre-65 retirees and Post -65 retirees
Defined Benefit Plan Disclosure [Line Items]
Determine plan costs ultimate rate			4.50%
Health care cost trend rate determine plan costs			6.60%

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Activities:
Net Income	$ 45.2	$ 41.4	$ 36.1
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	67.4	62.6	59.5
Deferred Tax Provision	7.4	11.0	10.8
Changes in Working Capital Items:
Accounts Receivable	(1.2)	(6.9)	(4.9)
Accrued Revenue	9.4	(11.6)	(10.3)
Regulatory Liabilities	(1.5)	5.5	4.0
Exchange Gas Receivable	8.6	(10.6)	(2.5)
Accounts Payable	(20.9)	16.2	19.2
Other Changes in Working Capital Items	1.0	1.4	0.7
Deferred Regulatory and Other Charges	(8.5)	(6.5)	(2.7)
Other, net	0.1	(4.8)	(2.1)
Cash Provided by Operating Activities	107.0	97.7	107.8
Investing Activities:
Property, Plant and Equipment Additions	(141.0)	(122.1)	(115.0)
Cash Used In Investing Activities	(141.0)	(122.1)	(115.0)
Financing Activities:
Proceeds from (Repayment of) Short-Term Debt, net	46.0	51.9	9.4
Issuance of Long-Term Debt	25.0	0.0	0.0
Repayment of Long-Term Debt	(6.9)	(10.4)	(25.8)
Long-Term Debt Issuance Costs	(0.2)	0.0	0.0
(Decrease) Increase in Capital Lease Obligations	0.3	(0.1)	(0.1)
Net Increase (Decrease) in Exchange Gas Financing	(7.6)	9.6	2.3
Dividends Paid	(26.2)	(25.1)	(23.6)
Proceeds from Issuance of Common Stock	1.1	1.0	45.5
Cash Provided by (Used In) Financing Activities	31.5	26.9	7.7
Net Increase (Decrease) in Cash and Cash Equivalents	(2.5)	2.5	0.5
Cash and Cash Equivalents at Beginning of Year	9.0	6.5	6.0
Cash and Cash Equivalents at End of Year	6.5	9.0	6.5
Supplemental Information:
Interest Paid	30.9	26.0	26.0
Income Taxes Paid	0.0	1.2	1.4
Payments on Capital Leases	0.2	0.2	0.2
Capital Expenditures Included in Accounts Payable	7.5	7.3	4.9
Right-of-Use Assets Obtained in Exchange for Lease Obligations	$ 2.7	$ 1.1	$ 0.7

Components of Exchange Gas Receivable (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Receivables [Line Items]
Total Exchange Gas Receivable	$ 9.4	$ 18.0
Northern Utilities Inc
Receivables [Line Items]
Total Exchange Gas Receivable	8.6	16.3
Fitchburg
Receivables [Line Items]
Total Exchange Gas Receivable	$ 0.8	$ 1.7

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

12 Months Ended

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

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

Balance at Beginning of Period

$ 2.6

$ 3.3

Provision

6.4

6.7

5.6

Recoveries

0.6

0.9

0.8

Accounts Written Off

7.2

7.6

6.5

Regulatory Defferals

^[1]

0.0

(0.7)

0.1

Balance at End of Period

2.4

2.6

3.3

Electric

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

Balance at Beginning of Period

1.6

2.0

1.6

Provision

3.6

4.2

3.3

Recoveries

0.2

0.3

0.4

Accounts Written Off

3.9

4.4

3.4

Regulatory Defferals

^[1]

0.0

(0.5)

0.1

Balance at End of Period

1.5

1.6

2.0

Gas

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

Balance at Beginning of Period

1.0

1.3

1.7

Provision

2.8

2.5

2.3

Recoveries

0.4

0.6

0.4

Accounts Written Off

3.3

3.2

3.1

Regulatory Defferals

^[1]

0.0

(0.2)

0.0

Balance at End of Period

$ 0.9

$ 1.0

$ 1.3

[1]

In 2021, the Company recorded higher than normal expected bad debt expense due to the coronavirus pandemic. The incremental bad debt expense amounts were previously deferred as regulatory assets based on certain regulatory proceedings and management’s view that such amounts were probable of recovery. Based on actual billing and collections experience, the Company has not deferred any incremental bad debt expense as a regulatory asset as of December 31, 2023 and December 31, 2022.

Debt and Financing Arrangements - Classification of the Company Lease Obligations (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Operating Lease Obligations:
Operating Lease Obligations (current portion)	$ 1.9	$ 1.5
Operating Lease Obligations (current portion)	Liabilities, Current	Liabilities, Current
Operating Lease Obligations (long-term portion)	$ 3.7	$ 2.8
Operating Lease Obligations (long-term portion)	Liabilities, Noncurrent	Liabilities, Noncurrent
Total Operating Lease Obligations	$ 5.6	$ 4.3
Capital Lease Obligations:
Other Current Liabilities (current portion)	$ 0.1	$ 0.1
Other Current Liabilities (current portion)	Other Liabilities, Current	Other Liabilities, Current
Other Noncurrent Liabilities (long-term portion)	$ 0.4	$ 0.1
Other Noncurrent Liabilities (long-term portion)	Other Liabilities, Noncurrent	Other Liabilities, Noncurrent
Total Capital Lease Obligations	$ 0.5	$ 0.2
Total Lease Obligations	6.1	$ 4.5
Lease Obligations [Member]
Operating Lease Obligations:
Total Operating Lease Obligations	$ 5,561.0

Pay vs Performance Disclosure - USD ($) $ in Millions	12 Months Ended
Pay vs Performance Disclosure - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net Income (Loss)	$ 45.2	$ 41.4	$ 36.1

- Definition

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

+ References

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+ Details

Weighted Average Non Vested Restricted Shares Excluded from Computation of Earnings Per Share (Detail) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Non Vested Restricted Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation	12,204	12,086	23,636

Retirement Benefit Plans

12 Months Ended

Dec. 31, 2023

Retirement Benefits [Abstract]

Retirement Benefit Plans

Note 9: Retirement Benefit Plans

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

•

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

•

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

•

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

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


	2023			2022			2021
Used to Determine Plan costs for years ended December 31:
Discount Rate		5.25	%		2.85	%		2.50	%
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	%


Used to Determine Benefit Obligations at December 31:
Discount Rate	5.00	%	5.25	%	2.85	%
Rate of Compensation Increase	3.00	%	3.00	%	3.00	%

The health care cost trend rate used to determine plan costs for 2023 for pre-65 retirees is 8.00%, with an ultimate rate of 4.50% in 2030, and for post-65 retirees, the health care cost trend rate is 6.25%, with an ultimate rate of 4.50% in 2030. The health care cost trend rate used to determine plan costs for 2022 for both pre-65 retirees and post-65 retirees is 6.20%, with an ultimate rate of 4.50% in 2029. The health care cost trend rate used to determine plan costs for 2021 for both pre-65 retirees and post-65 retirees is 6.60%, with an ultimate rate of 4.50% in 2029.

The health care cost trend rate used to determine benefit obligations at December 31, 2023 for pre-65 retirees is 8.00%, with an ultimate rate of 4.50% in 2033, and for post-65 retirees, the health care cost trend rate is 6.00%, with an ultimate rate of 4.50% in 2033. The health care cost trend rate used to determine benefit obligations at December 31, 2022 for pre-65 retirees is 8.00%, with an ultimate rate of 4.50% in 2030, and for post-65 retirees, the health care cost trend rate is 6.25%, with an ultimate rate of 4.50% in 2030. The health care cost trend rate used to determine benefit obligations at December 31, 2021 for both pre-65 and post-65 retirees is 6.20%, with an ultimate rate 4.50% in 2029.

The 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 2023, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $113,200 in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2023 was based on the expected long-term increase in compensation costs for personnel covered by the plans.

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


	Pension Plan									PBOP Plan									SERP
	2023			2022			2021			2023			2022			2021			2023			2022			2021

Service Cost	$	2,091		$	3,165		$	3,472		$	1,493		$	2,890		$	3,034		$	250		$	273		$	354

Interest Cost		7,480			5,486			5,003			2,899			3,194			2,740			754			472			458

Expected Return on Plan Assets		(10,689	)		(10,883	)		(9,693	)		(3,408	)		(3,415	)		(2,508	)		—			—			—

Prior Service Cost Amortization		356			356			301			794			1,092			1,208			55			55			56

Actuarial Loss Amortization		—			5,507			8,089			(1,464	)		1,020			1,045			—			794			1,489

Sub-total		(762	)		3,631			7,172			314			4,781			5,519			1,059			1,594			2,357

Amounts Capitalized or Deferred		1,598			(1,085	)		(3,384	)		555			(2,388	)		(3,136	)		(327	)		(472	)		(712	)
NPBC Recognized	$	836		$	2,546		$	3,788		$	869		$	2,393		$	2,383		$	732		$	1,122		$	1,645

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 2023, 2022 and 2021 would have been $2.8 million, $2.4 million and $6.1 million respectively, prior to amounts capitalized or deferred.

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


	Pension Plan						PBOP Plan						SERP
Change in Plan Assets:	2023			2022			2023			2022			2023			2022

Plan Assets at Beginning of Year	$	126,098		$	152,006		$	44,770		$	42,651		$	—		$	—

Actual Return on Plan Assets		16,822			(19,984	)		6,865			(6,810	)		—			—

Employer Contributions		3,850			3,800			2,790			12,153			665			637

Participant Contributions		—			—			234			279			—			—

Benefits Paid		(8,877	)		(9,724	)		(2,767	)		(3,503	)		(665	)		(637	)
Plan Assets at End of Year	$	137,893		$	126,098		$	51,892		$	44,770		$	—		$	—

Change in PBO:

PBO at Beginning of Year	$	146,953		$	199,418		$	56,510		$	112,087		$	14,810		$	17,714

Service Cost		2,091			3,165			1,493			2,890			250			273

Interest Cost		7,480			5,486			2,899			3,194			754			472

Participant Contributions		—			—			234			279			—			—

Plan Amendments		—			—			—			—			—			—

Benefits Paid		(8,877	)		(9,724	)		(2,767	)		(3,503	)		(665	)		(637	)

Actuarial (Gain) or Loss		6,920			(51,392	)		8,322			(58,437	)		(295	)		(3,012	)
PBO at End of Year	$	154,567		$	146,953		$	66,691		$	56,510		$	14,854		$	14,810
Funded Status: Assets vs PBO	$	(16,674	)	$	(20,855	)	$	(14,799	)	$	(11,740	)	$	(14,854	)	$	(14,810	)

The increase in the PBO for the Pension, PBOP and SERP plans as of December 31, 2023 compared to December 31, 2022 primarily reflects a decrease in the assumed discount rate as of December 31, 2023 and normal changes in service cost, interest cost and demographic data.

The funded status of the Pension, PBOP and SERP Plans is calculated based on the difference between the benefit obligation and the fair value of plan assets and is recorded on the balance sheets as an asset or a liability. Because the Company recovers the retiree benefit costs from customers through rates, regulatory assets are recorded in lieu of an adjustment to Accumulated Other Comprehensive Income/(Loss).

The Company has recorded on its consolidated balance sheets as a liability the underfunded status of its and its subsidiaries’ retirement benefit obligations based on the projected benefit obligation. The Company has recognized Regulatory Assets, net of deferred tax benefits, of $29.8 million and $29.1 million at December 31, 2023 and 2022, respectively, to account for the future collection of these plan obligations in electric and gas rates. 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 $146.3 million and $138.3 million as of December 31, 2023 and 2022, respectively. The ABO for the SERP was $14.4 million and $13.9 million as of December 31, 2023 and 2022, 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 2024 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension Plan costs.

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


	Pension Plan						PBOP Plan							SERP
	2023		2022		2021		2023			2022		2021		2023		2022		2021
Employer Contributions	$	3,850	$	3,800	$	4,100	$	2,790		$	12,153	$	8,903	$	665	$	637	$	637
Participant Contributions	$	—	$	—	$	—	$	234		$	279	$	220	$	—	$	—	$	—
Benefit Payments	$	8,877	$	9,724	$	6,489	$	(2,767	)	$	3,503	$	2,905	$	665	$	637	$	637

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


Estimated Future Benefit Payments
	Pension		PBOP		SERP
2024	$	8,006	$	3,197	$	679
2025		8,678		3,466		1,173
2026		9,162		3,698		1,167
2027		10,210		3,789		1,160
2028		10,309		3,803		1,153
2029-2033		57,049		20,913		5,607

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 58% in common stock equities, 37% in fixed income securities and 5% in real estate securities. The Company’s Expected Long-Term Rate of Return on PBOP Plan assets is based on target investment allocation of 55% in common stock equities and 45% in fixed income securities. The actual investment allocations are shown in the following tables.


Pension Plan	Target Allocation			Actual Allocation at December 31,
	2024			2023			2022			2021
Equity Funds		58	%		57	%		53	%		57	%
Debt Funds		37	%		36	%		38	%		38	%
Real Estate Fund		5	%		6	%		7	%		4	%
Other(1)		—			1	%		2	%		1	%
Total					100	%		100	%		100	%

(1)

Represents investments being held in cash equivalents as of December 31, 2023, December 31, 2022 and December 31, 2021 pending payment of benefits.


PBOP Plan	Target Allocation			Actual Allocation at December 31,
	2024			2023			2022			2021
Equity Funds		55	%		56	%		55	%		56	%
Debt Funds		45	%		44	%		45	%		44	%
Total					100	%		100	%		100	%

The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 7.50% for 2023. 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, 2023 and 2022. Please also see Note 1 (Summary of Significant Accounting Policies) for a discussion of the Company’s fair value accounting policy.

Equity, Fixed Income, Index and Asset Allocation Funds

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, 2023 and 2022 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)
2023
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	78,522	$	78,522	$	—	$	—
Fixed Income Funds		49,359		49,359		—		—
Total Mutual Funds		127,881		127,881		—		—
Cash Equivalents		2,266		2,266
Total Assets in the Fair Value Hierarchy	$	130,147	$	130,147	$	—	$	—
Real Estate Fund–Measured at Net Asset Value		7,746
Total Assets	$	137,893
2022
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	67,332	$	67,332	$	—	$	—
Fixed Income Funds		47,646		47,646		—		—
Total Mutual Funds		114,978		114,978		—		—
Cash Equivalents		2,598		2,598
Total Assets in the Fair Value Hierarchy	$	117,576	$	117,576	$	—	$	—
Real Estate Fund–Measured at Net Asset Value		8,522
Total Assets	$	126,098

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, 2023 and 2022 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)
2023
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	23,025	$	23,025	$	—	$	—
Equity Funds		28,867		28,867		—		—
Total Assets	$	51,892	$	51,892	$	—	$	—

2022
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	20,156	$	20,156	$	—	$	—
Equity Funds		24,614		24,614		—		—
Total Assets	$	44,770	$	44,770	$	—	$	—

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 $4.0 million, $3.5 million and $3.3 million for the years ended December 31, 2023, 2022 and 2021, respectively.

- Definition

The entire disclosure for retirement benefits.

+ References

Reference 1: 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 2: 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 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-Section 50
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-Name Accounting Standards Codification
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-Paragraph 1
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-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-Paragraph 1
-Subparagraph (q)
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-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
-Section 50
-Paragraph 1
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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-Name Accounting Standards Codification
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-URI https://asc.fasb.org//715/tableOfContent

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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-Section 50
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-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-Subparagraph (o)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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-Section 50
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-Subparagraph (p)
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-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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-SubTopic 20
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-Section 50
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-Subparagraph (r)(2)
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-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 S99
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480126/715-20-S99-2

Reference 14: 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

+ Details

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Common Equity Outstanding	16,116,724	16,043,355

Regulatory Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2017
Regulatory Liability [Line Items]
Regulatory Liabilities	$ 47.9	$ 51.9
Less: Current Portion of Regulatory Liabilities	13.5	15.0
Regulatory Liabilities-noncurrent	34.4	36.9
Rate Adjustment Mechanisms
Regulatory Liability [Line Items]
Regulatory Liabilities	9.3	10.9
Income Taxes
Regulatory Liability [Line Items]
Regulatory Liabilities	$ 38.6	$ 41.0	$ 48.9

Equity

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

Equity

Note 5: Equity

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

Common Stock

The Company’s common stock trades on the New York Stock Exchange under the symbol “UTL”. The Company had 16,116,724 and 16,043,355 shares of common stock outstanding at December 31, 2023 and December 31, 2022, respectively. The Company has 25,000,000 shares of common stock authorized as of December 31, 2023 and December 31, 2022.

Unitil Corporation Common Stock Offering—On August 6, 2021, the Company issued and sold 800,000 shares of its common stock at a price of $50.80 per share in a registered public offering (Offering). The Company’s net increase to Common Equity and Cash proceeds from the Offering was approximately $38.6 million. The proceeds were used to make equity capital contributions to the Company’s regulated utility subsidiaries, to repay debt and for other general corporate purposes.

As part of the Offering, the Company granted the underwriters a 30-day option to purchase additional shares. The underwriters exercised the option and purchased an additional 120,000 shares of the Company’s common stock on September 8, 2021. The Company’s net increase to Common Equity and Cash proceeds from the exercise of the option was approximately $5.9 million. The proceeds were used to make equity capital contributions to the Company’s regulated utility subsidiaries, to repay debt and for other general corporate purposes.

Dividend Reinvestment and Stock Purchase Plan—During 2023, the Company sold 21,321 shares of its common stock, at an average price of $51.58 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $1.1 million. The DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock. During 2022 and 2021, the Company raised $1.0 million and $1.0 million, respectively, through the issuance of 18,853 and 22,316 shares, respectively, of its common stock in connection with its DRP and 401(k) plans.

Common Shares Repurchased, Cancelled and Retired—Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted by the Company on May 1, 2014, the Company may periodically repurchase shares of its common stock on the open market related to the stock portion of the Directors’ annual retainer. Until December 1, 2018, the Company also periodically repurchased shares of its common stock on the open market related to Employee Length of Service Awards. (See Part II, Item 5, for additional information). During 2023, 2022 and 2021, the Company repurchased 14,680, 9,449 and 8,012 shares of its common stock, respectively, pursuant to the Rule 10b5-1 trading plan. The expense recognized by the Company for these repurchases was $0.6 million, $0.4 million, and $0.4 million in 2023, 2022 and 2021, respectively.

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

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

Stock Plan—The Company maintains the Unitil Corporation Second Amended and Restated 2003 Stock Plan (the Stock Plan). Participants in the Stock Plan are selected by the Compensation Committee of the Board of Directors to receive awards under the Stock Plan, including: (i) awards of restricted shares that vest based on time (Time Restricted Shares); (ii) awards of restricted shares that vest based on performance (Performance Restricted Shares), effective January 24, 2023; or (iii) awards of restricted stock units (Restricted Stock Units). The Compensation Committee has the authority to determine the sizes of awards; determine the terms and conditions of awards in a manner consistent with the Stock Plan; construe and interpret the Stock Plan and any agreement or instrument entered into under the Stock Plan as they apply to participants; establish, amend, or waive rules and regulations for the Stock Plan’s administration as they apply to participants; and, subject to the provisions of the Stock Plan, amend the terms and conditions of any outstanding award to the extent such terms and conditions are within the discretion of the Compensation Committee as provided for in the Stock Plan. On April 19, 2012, the Company’s shareholders approved an amendment to the Stock Plan to, among other things, increase the maximum number of shares of common stock available for awards to plan participants.

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

Time Restricted Shares

Outstanding awards of Time Restricted Shares fully vest over a period of four years at a rate of 25% each year. During the vesting period, dividends on Time Restricted Shares underlying the award may be credited to a participant’s account. The Company may deduct or withhold, or require a participant to remit to the Company, an amount sufficient to satisfy any taxes required by federal, state, or local law or regulation to be withheld with respect to any taxable event arising in connection with an award.

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

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


Issuance Date	Shares	Aggregate Market Value (millions)
1/26/21	23,140	$0.9
1/25/22	36,770	$1.7
1/24/23	18,770	$1.0

There were 36,483 and 45,473 non-vested Time Restricted Shares under the Stock Plan as of December 31, 2023 and 2022, respectively. The weighted average grant date fair value of these shares was $46.94 per share and $46.45 per share, respectively. The compensation expense associated with the issuance of Time Restricted Shares under the Stock Plan is being recorded over the vesting period and was $1.4 million, $2.1 million and $1.4 million in 2023, 2022 and 2021, respectively. At December 31, 2023, there was approximately $0.7 million of total unrecognized compensation cost for Time Restricted Shares under the Stock Plan which is expected to be recognized over approximately 2.2 years. During 2023, there were zero Time Restricted Shares forfeited or cancelled under the Stock Plan. On January 30, 2024, there were 22,680 Time Restricted Shares issued under the Stock Plan with an aggregate market value of $1.1 million.

Performance Restricted Shares

Outstanding awards of Performance Restricted Shares vest after a performance period of three years based on the attainment of certain goals set by the Compensation Committee at the beginning of the performance period. If goals are met, awards of Performance Restricted Shares may vest fully; if goals are exceeded, awards of Performance Restricted Shares may vest fully and additional shares of common stock may be awarded; if goals are not met, a portion of the Performance Restricted Shares may vest and/or all or a portion of the Performance Restricted Shares may be forfeited. During the performance period, dividends on Performance Restricted Shares underlying the award may be credited to a participant’s account. The Company may deduct or withhold, or require a participant to remit to the Company, an amount sufficient to satisfy any taxes required by federal, state, or local law or regulation to be withheld with respect to any taxable event arising in connection with an award.

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

Initial awards of Performance Restricted Shares were granted January 24, 2023. No Performance Restricted Shares were awarded in 2022 or 2021. On January 24, 2023, there were 18,770 Performance Restricted Shares issued under the Stock Plan with an aggregate market value of $1.0 million.


Issuance Date	Shares	Aggregate Market Value (millions)
1/24/23	18,770	$1.0

There were 18,770 non-vested Performance Restricted Shares under the Stock Plan as of December 31, 2023. The weighted average grant date fair value of these shares was $51.83 per share. The compensation expense associated with the issuance of Performance Restricted Shares under the Stock Plan is being recognized over the vesting period and was $0.5 million in 2023. At December 31, 2023, there was approximately $0.9 million of total unrecognized compensation cost for Performance Restricted Shares under the Stock Plan which is expected to be recognized over approximately 2.0 years. During 2023, there were zero Performance Restricted Shares forfeited or cancelled under the Stock Plan. On January 30, 2024, there were 22,680 Performance Restricted Shares issued under the Stock Plan with an aggregate market value of $1.1 million.

Restricted Stock Units

Restricted Stock Units, which are issued to members of the Company’s Board of Directors, earn dividend equivalents and will generally be settled by payment to each Director as soon as practicable following the Director’s separation from service to the Company. The Restricted Stock Units will be paid such that the Director will receive (i) 70% of the shares of the Company’s common stock underlying the restricted stock units and (ii) cash in an amount equal to the fair market value of 30% of the shares of the Company’s common stock underlying the Restricted Stock Units.

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


Restricted Stock Units (Equity Portion)
	2023					2022
	Units			Weighted Average Stock Price		Units			Weighted Average Stock Price
Beginning Restricted Stock Units		43,799		$	40.17		49,182		$	41.67
Restricted Stock Units Granted		2,646		$	42.31		3,595		$	46.72
Dividend Equivalents Earned		1,442		$	50.53		1,258		$	53.20
Restricted Stock Units Settled		(14,512	)	$	35.69		(10,236	)	$	51.28
Ending Restricted Stock Units		33,375		$	42.73		43,799		$	40.17

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

Preferred Stock

There were $0.2 million, or 1,727 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of December 31, 2023. There were $0.2 million, or 1,861 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of December 31, 2022. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the twelve month periods ended December 31, 2023 and December 31, 2022, respectively.

Earnings Per Share

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


(Millions except shares and per share data)	2023		2022		2021
Earnings Available to Common Shareholders	$	45.2	$	41.4	$	36.1
Weighted Average Common Shares Outstanding—Basic (000’s)		16,045		15,991		15,373
Plus: Diluted Effect of Incremental Shares (000’s)		8		5		3
Weighted Average Common Shares Outstanding—Diluted (000’s)		16,053		15,996		15,376
Earnings per Share—Basic and Diluted	$	2.82	$	2.59	$	2.35

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.


	2023		2022		2021
Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation		12,204		12,086		23,636

- Definition

The entire disclosure for equity.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481112/505-10-50-13

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org//1943274/2147481112/505-10-50-14

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org//1943274/2147481062/946-235-50-2

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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-Publisher FASB
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Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
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-Publisher FASB
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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-Section 50
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-Subparagraph (i)
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-URI https://asc.fasb.org//1943274/2147481112/505-10-50-13

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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Reference 15: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Income Taxes

12 Months Ended

Dec. 31, 2023

Income Taxes

Note 8: Income Taxes

Provisions for Federal and State Income Taxes reflected as operating expenses in the accompanying consolidated statements of earnings for the years ended December 31, 2023, 2022, and 2021 are shown in the following table:


	(in millions)
	2023		2022		2021
Current Income Tax Provision
Federal	$	4.3	$	—	$	—
State		1.5		0.2		0.7
Total Current Income Taxes	$	5.8	$	0.2	$	0.7
Deferred Income Tax Provision
Federal	$	4.8	$	6.6	$	7.3
State		2.6		4.4		3.5
Total Deferred Income Taxes		7.4		11.0		10.8
Total Income Tax Expense	$	13.2	$	11.2	$	11.5

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


	2023			2022			2021
Statutory Federal Income Tax Rate		21	%		21	%		21	%
Income Tax Effects of:
State Income Taxes, net		6	%		6	%		6	%
Utility Plant Differences		(5	)%		(6	)%		(3	)%
Other, net		1	%		—	%		—	%
Effective Income Tax Rate		23	%		21	%		24	%

Temporary differences which gave rise to deferred tax assets and liabilities in 2023 and 2022 are shown in the following table:


Temporary Differences (in millions)	2023		2022
Deferred Tax Assets
Retirement Benefit Obligations	$	11.2	$	11.0
Net Operating Loss Carryforwards		0.1		3.5
Tax Credit Carryforwards		1.3		1.0
Other, net		1.3		1.4
Total Deferred Tax Assets	$	13.9	$	16.9
Deferred Tax Liabilities
Utility Plant Differences		180.3	$	168.3
Regulatory Assets & Liabilities		8.9		11.3
Other, net		0.8		0.7
Total Deferred Tax Liabilities		190.0		180.3
Net Deferred Tax Liabilities	$	176.1	$	163.4

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, 2023 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, de-recognition, settlement or foreseeable future events to any tax liabilities or assets as defined by the FASB Codification is required. The Company remains subject to examination by Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2022; December 31, 2021; and December 31, 2020.

Income tax filings for the year ended December 31, 2022 have been filed with the IRS, Massachusetts Department of Revenue, the Maine Revenue Service, and the New Hampshire Department of Revenue Administration. In the Company’s federal tax returns for the year ended December 31, 2022 which were filed with the IRS in October 2023, the Company utilized federal Net Operating Loss Carryforward (NOLC) assets of $1.4 million and $0.2 million of federal tax credit carryforward. As of December 31, 2023, the Company recognized the utilization of approximately $4.4 million of the NOLC asset and $1.7 million of federal tax credits available to offset current taxes payable. In addition, at December 31, 2023, the Company had $1.3 million of cumulative state tax credit carryforwards to offset future income taxes payable. If unused, the Company’s state tax credit carryforwards will begin to expire in 2027.

On April 14, 2023, the IRS issued Revenue Procedure 2023-15 that provides a safe harbor method of accounting that taxpayers may use to determine whether to deduct or capitalize expenditures to repair, maintain, replace, or improve natural gas transmission and distribution property. Under the revenue procedure, the method of accounting will depend on the property’s classification as linear transmission property, linear distribution property, or non-linear property. The revenue procedure may be adopted in tax years ending after May 1, 2023. The Company is evaluating the revenue procedure and the effect adopting the safe harbor would have on its property that is subject to this guidance.

In August 2022, the Inflation Reduction Act of 2022 (IRA) was signed into law. The IRA included new taxes on corporations, including the Corporate Alternative Minimum Tax (AMT) and the Excise Tax on Repurchase of Corporate Stock. The AMT is equal to 15% of a corporation’s adjusted financial statement income (AFSI). The AMT applies to companies that have a 3 year average AFSI of greater than $1 billion. The IRA also extended and modified certain renewable energy related credits. The Company has evaluated the IRA provisions and determined that they do not have a material effect on the Company’s financial statements as of December 31, 2023.

In December 2017, the Tax Cuts and Jobs Act (TCJA), which included a reduction of the corporate federal income tax rate to 21% effective January 1, 2018, was signed into law. In accordance with FASB Codification Topic 740, the Company revalued its Accumulated Deferred Income Taxes (ADIT) and recorded a net Regulatory Liability in the amount of $48.9 million at December 31, 2017. The Company expects to flow through to customers $47.1 million of excess ADIT in utility base rates. Approximately $1.8 million of excess ADIT was created through reconciling mechanisms at December 31, 2017, which had not been previously collected from customers through utility rates. The Company reconciled these excess ADIT amounts

through the specific reconciliation mechanisms in each of those individual reconciling mechanisms which were reviewed by state regulators. The benefit of protected excess ADIT amounts will be subject to flow back to customers in utility rates according to the Average Rate Assumption Method (ARAM). The Company estimates the ARAM flow back period for protected and unprotected excess ADIT to be between fifteen and twenty years over the remaining life of the related utility plant. As of December 31, 2023, the Company flowed back $9.3 million to customers in its Massachusetts, Maine, New Hampshire and federal jurisdictions.

- Definition

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

+ References

Reference 1: 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 2: 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 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org//740/tableOfContent

Reference 4: 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 5: 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 6: 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//1943274/2147482526/740-270-50-1

Reference 7: 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 8: 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 9: 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 10: 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

Estimated Percentage of Decoupled Sales (Details)	12 Months Ended
Estimated Percentage of Decoupled Sales (Details)	Dec. 31, 2023
Electric \| Before June 1, 2022
Operating Revenues [Line Items]
Percentage of total sales volumes revenue subject to RDM	27.00%
Gas \| Before August 1, 2022
Operating Revenues [Line Items]
Percentage of total sales volumes revenue subject to RDM	11.00%
Gas \| After August 1, 2022
Operating Revenues [Line Items]
Percentage of total sales volumes revenue subject to RDM	42.00%

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2023

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, 2023.


			Payments Due by Period
Gas and Electric Supply Contractual Obligations (millions) as of December 31, 2023	Total		2024		2025		2026		2027		2028		2029 & Beyond
Gas Supply Contracts	$	479.2	$	79.9	$	45.7	$	44.3	$	43.8	$	39.1	$	226.4
Electric Supply Contracts		12.1		1.3		1.3		1.3		1.3		1.1		5.8
Total	$	491.3	$	81.2	$	47.0	$	45.6	$	45.1	$	40.2	$	232.2

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, 2023 and 2022.


	December 31,
Environmental Obligations (millions)	2023		2022
Total Balance at Beginning of Period	$	4.4	$	2.7
Additions		0.7		2.0
Less: Payments / Reductions		0.5		0.3
Total Balance at End of Period		4.6		4.4
Less: Current Portion		0.6		0.6
Noncurrent Balance at End of Period	$	4.0	$	3.8

Restricted Stock Units Issued (Detail) - Restricted Stock Units (RSUs) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Restricted Stock Units
Beginning Restricted Stock Units	43,799	49,182
Restricted Stock Units Granted	2,646	3,595
Dividend Equivalents Earned	1,442	1,258
Restricted Stock Units Settled	(14,512)	(10,236)
Ending Restricted Stock Units	33,375	43,799
Weighted-Average Stock Price
Beginning Restricted Stock Units	$ 40.17	$ 41.67
Restricted Stock Units Granted	42.31	46.72
Dividend Equivalents Earned	50.53	53.2
Restricted Stock Units Settled	35.69	51.28
Ending Restricted Stock Units	$ 42.73	$ 40.17

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

Dec. 31, 2023

Dec. 31, 2022

Debt Instrument [Line Items]

Total Long-Term Debt

$ 517.2

$ 499.1

Less: Unamortized Debt Issuance Costs

3.2

3.3

Long-Term Debt

514.0

495.8

Less: Current Portion

^[1]

4.9

6.7

Total Long-Term Debt, Less Current Portion

509.1

489.1

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

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

Debt Instrument [Line Items]

Total Long-Term Debt

10.0

12.0

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

Debt Instrument [Line Items]

Total Long-Term Debt

12.0

13.5

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

Debt Instrument [Line Items]

Total Long-Term Debt

15.0

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

Debt Instrument [Line Items]

Total Long-Term Debt

27.5

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

Debt Instrument [Line Items]

Total Long-Term Debt

30.0

Fitchburg Gas and Electric Light Company | 6.79% Senior Notes, Due October 15, 2025

Debt Instrument [Line Items]

Total Long-Term Debt

0.0

2.0

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

Debt Instrument [Line Items]

Total Long-Term Debt

10.0

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

Debt Instrument [Line Items]

Total Long-Term Debt

7.2

8.4

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

Debt Instrument [Line Items]

Total Long-Term Debt

15.0

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

Debt Instrument [Line Items]

Total Long-Term Debt

14.0

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

Debt Instrument [Line Items]

Total Long-Term Debt

12.0

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

Debt Instrument [Line Items]

Total Long-Term Debt

27.5

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

Debt Instrument [Line Items]

Total Long-Term Debt

15.0

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

Debt Instrument [Line Items]

Total Long-Term Debt

13.0

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

Debt Instrument [Line Items]

Total Long-Term Debt

20.0

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

Debt Instrument [Line Items]

Total Long-Term Debt

40.0

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

Debt Instrument [Line Items]

Total Long-Term Debt

30.0

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

Debt Instrument [Line Items]

Total Long-Term Debt

50.0

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

Debt Instrument [Line Items]

Total Long-Term Debt

50.0

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

Debt Instrument [Line Items]

Total Long-Term Debt

40.0

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

Debt Instrument [Line Items]

Total Long-Term Debt

15.0

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

Debt Instrument [Line Items]

Total Long-Term Debt

$ 4.0

$ 4.2

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

Components of Energy Supply Obligations (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 15.0	$ 24.1
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	6.4	7.8
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 8.6	$ 16.3

Restricted Shares Issued in Conjunction with Stock Plan (Detail) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
	Jan. 24, 2023	Jan. 30, 2024	Dec. 31, 2023
Restricted Stock
Class of Stock [Line Items]
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Grants In Period Aggregate Intrinsic Value		$ 1.1
Restricted Stock \| Period 1
Class of Stock [Line Items]
Issuance Date			Jan. 26, 2021
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period			23,140
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Grants In Period Aggregate Intrinsic Value			$ 0.9
Restricted Stock \| Period 2
Class of Stock [Line Items]
Issuance Date			Jan. 25, 2022
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period			36,770
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Grants In Period Aggregate Intrinsic Value			$ 1.7
Restricted Stock \| Period 3
Class of Stock [Line Items]
Issuance Date			Jan. 24, 2023
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period			18,770
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Grants In Period Aggregate Intrinsic Value			$ 1.0
Performance Shares [Member]
Class of Stock [Line Items]
Issuance Date	Jan. 24, 2023
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period	18,770
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Grants In Period Aggregate Intrinsic Value	$ 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

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481112/505-10-50-13

Reference 2: http://www.xbrl.org/2003/role/recommendedDisclosureRef
-Topic 272
-SubTopic 10
-Name Accounting Standards Codification
-Section 45
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147483014/272-10-45-3

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 272
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482987/272-10-50-1

Reference 4: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(d))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480678/235-10-S99-1

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481112/505-10-50-13

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481112/505-10-50-13

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (e)
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-URI https://asc.fasb.org//1943274/2147481112/505-10-50-13

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
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-Paragraph 13
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481112/505-10-50-13

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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-Paragraph 14
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481112/505-10-50-14

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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-Name Accounting Standards Codification
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-Paragraph 18
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481112/505-10-50-18

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 210
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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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/disclosureRef
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Reference 17: http://www.xbrl.org/2003/role/disclosureRef
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Reference 18: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Provisions for Federal and State Income Taxes


	(in millions)
	2023		2022		2021
Current Income Tax Provision
Federal	$	4.3	$	—	$	—
State		1.5		0.2		0.7
Total Current Income Taxes	$	5.8	$	0.2	$	0.7
Deferred Income Tax Provision
Federal	$	4.8	$	6.6	$	7.3
State		2.6		4.4		3.5
Total Deferred Income Taxes		7.4		11.0		10.8
Total Income Tax Expense	$	13.2	$	11.2	$	11.5

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

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


	2023			2022			2021
Statutory Federal Income Tax Rate		21	%		21	%		21	%
Income Tax Effects of:
State Income Taxes, net		6	%		6	%		6	%
Utility Plant Differences		(5	)%		(6	)%		(3	)%
Other, net		1	%		—	%		—	%
Effective Income Tax Rate		23	%		21	%		24	%

Deferred Tax Assets and Liabilities

Temporary differences which gave rise to deferred tax assets and liabilities in 2023 and 2022 are shown in the following table:


Temporary Differences (in millions)	2023		2022
Deferred Tax Assets
Retirement Benefit Obligations	$	11.2	$	11.0
Net Operating Loss Carryforwards		0.1		3.5
Tax Credit Carryforwards		1.3		1.0
Other, net		1.3		1.4
Total Deferred Tax Assets	$	13.9	$	16.9
Deferred Tax Liabilities
Utility Plant Differences		180.3	$	168.3
Regulatory Assets & Liabilities		8.9		11.3
Other, net		0.8		0.7
Total Deferred Tax Liabilities		190.0		180.3
Net Deferred Tax Liabilities	$	176.1	$	163.4

Debt and Financing Arrangements - Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Operating leases
2024	$ 2,063.0
2025	1,502.0
2026	1,171.0
2027	898.0
2028	336.0
2029-2033	84.0
Lessee, Operating Lease, Liability, to be Paid, Total	6,054.0
Less: Interest	493.0
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	5.6	$ 4.3
Capital lease
2024	152.0
2025	120.0
2026	107.0
2027	104.0
2028	19.0
2029-2033
Finance Lease, Liability, to be Paid, Total	502.0
Less: Interest	26.0
Lease Obligations [Member]
Operating leases
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	5,561.0
Capital lease
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$ 476.0

Components of Gas and Electric Operating Revenue (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ 557.1	$ 563.2	$ 473.3
Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	565.5	553.5	466.1
Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	(8.4)	9.7	7.2
Gas Segment
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	250.6	265.3	224.8
Gas Segment \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	253.8	263.3	217.6
Gas Segment \| Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	(3.2)	2.0	7.2
Electric
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	306.5	297.9	248.5
Electric \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	311.7	290.2	248.5
Electric \| Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	(5.2)	7.7	0.0
Residential \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	280.4	258.1	219.0
Residential \| Gas Segment \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	98.8	98.2	83.9
Residential \| Electric \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	181.6	159.9	135.1
C&I \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	267.0	266.4	227.4
C&I \| Gas Segment \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	146.9	153.8	124.1
C&I \| Electric \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	120.1	112.6	103.3
Other \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	18.1	29.0	19.7
Other \| Gas Segment \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	8.1	11.3	9.6
Other \| Electric \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ 10.0	$ 17.7	$ 10.1

- 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.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 924
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SAB Topic 11.L)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479941/924-10-S99-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-5

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 30
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-30

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 42
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-42

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-22

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 40
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-40

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-22

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 41
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-41

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-4

+ Details

Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Benefit Plan Costs [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	5.25%	2.85%	2.50%
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	5.00%	5.25%	2.85%
Rate of Compensation Increase	3.00%	3.00%	3.00%

Components of Gas Inventory (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 1.0	$ 1.8
Liquefied Natural Gas & Other
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.4	0.4
Natural Gas
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.3	1.0
Propane
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.3	$ 0.4

Retirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2023

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:


	2023			2022			2021
Used to Determine Plan costs for years ended December 31:
Discount Rate		5.25	%		2.85	%		2.50	%
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	%


Used to Determine Benefit Obligations at December 31:
Discount Rate	5.00	%	5.25	%	2.85	%
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
	2023			2022			2021			2023			2022			2021			2023			2022			2021

Service Cost	$	2,091		$	3,165		$	3,472		$	1,493		$	2,890		$	3,034		$	250		$	273		$	354

Interest Cost		7,480			5,486			5,003			2,899			3,194			2,740			754			472			458

Expected Return on Plan Assets		(10,689	)		(10,883	)		(9,693	)		(3,408	)		(3,415	)		(2,508	)		—			—			—

Prior Service Cost Amortization		356			356			301			794			1,092			1,208			55			55			56

Actuarial Loss Amortization		—			5,507			8,089			(1,464	)		1,020			1,045			—			794			1,489

Sub-total		(762	)		3,631			7,172			314			4,781			5,519			1,059			1,594			2,357

Amounts Capitalized or Deferred		1,598			(1,085	)		(3,384	)		555			(2,388	)		(3,136	)		(327	)		(472	)		(712	)
NPBC Recognized	$	836		$	2,546		$	3,788		$	869		$	2,393		$	2,383		$	732		$	1,122		$	1,645

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:	2023			2022			2023			2022			2023			2022

Plan Assets at Beginning of Year	$	126,098		$	152,006		$	44,770		$	42,651		$	—		$	—

Actual Return on Plan Assets		16,822			(19,984	)		6,865			(6,810	)		—			—

Employer Contributions		3,850			3,800			2,790			12,153			665			637

Participant Contributions		—			—			234			279			—			—

Benefits Paid		(8,877	)		(9,724	)		(2,767	)		(3,503	)		(665	)		(637	)
Plan Assets at End of Year	$	137,893		$	126,098		$	51,892		$	44,770		$	—		$	—

Change in PBO:

PBO at Beginning of Year	$	146,953		$	199,418		$	56,510		$	112,087		$	14,810		$	17,714

Service Cost		2,091			3,165			1,493			2,890			250			273

Interest Cost		7,480			5,486			2,899			3,194			754			472

Participant Contributions		—			—			234			279			—			—

Plan Amendments		—			—			—			—			—			—

Benefits Paid		(8,877	)		(9,724	)		(2,767	)		(3,503	)		(665	)		(637	)

Actuarial (Gain) or Loss		6,920			(51,392	)		8,322			(58,437	)		(295	)		(3,012	)
PBO at End of Year	$	154,567		$	146,953		$	66,691		$	56,510		$	14,854		$	14,810
Funded Status: Assets vs PBO	$	(16,674	)	$	(20,855	)	$	(14,799	)	$	(11,740	)	$	(14,854	)	$	(14,810	)

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
	2023		2022		2021		2023			2022		2021		2023		2022		2021
Employer Contributions	$	3,850	$	3,800	$	4,100	$	2,790		$	12,153	$	8,903	$	665	$	637	$	637
Participant Contributions	$	—	$	—	$	—	$	234		$	279	$	220	$	—	$	—	$	—
Benefit Payments	$	8,877	$	9,724	$	6,489	$	(2,767	)	$	3,503	$	2,905	$	665	$	637	$	637

Estimated Future Benefit Payments

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


Estimated Future Benefit Payments
	Pension		PBOP		SERP
2024	$	8,006	$	3,197	$	679
2025		8,678		3,466		1,173
2026		9,162		3,698		1,167
2027		10,210		3,789		1,160
2028		10,309		3,803		1,153
2029-2033		57,049		20,913		5,607

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,
	2024			2023			2022			2021
Equity Funds		58	%		57	%		53	%		57	%
Debt Funds		37	%		36	%		38	%		38	%
Real Estate Fund		5	%		6	%		7	%		4	%
Other(1)		—			1	%		2	%		1	%
Total					100	%		100	%		100	%

Represents investments being held in cash equivalents as of December 31, 2023, December 31, 2022 and December 31, 2021 pending payment of benefits.

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


	Fair Value Measurements at Reporting Date Using
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)
2023
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	78,522	$	78,522	$	—	$	—
Fixed Income Funds		49,359		49,359		—		—
Total Mutual Funds		127,881		127,881		—		—
Cash Equivalents		2,266		2,266
Total Assets in the Fair Value Hierarchy	$	130,147	$	130,147	$	—	$	—
Real Estate Fund–Measured at Net Asset Value		7,746
Total Assets	$	137,893
2022
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	67,332	$	67,332	$	—	$	—
Fixed Income Funds		47,646		47,646		—		—
Total Mutual Funds		114,978		114,978		—		—
Cash Equivalents		2,598		2,598
Total Assets in the Fair Value Hierarchy	$	117,576	$	117,576	$	—	$	—
Real Estate Fund–Measured at Net Asset Value		8,522
Total Assets	$	126,098

Other Postretirement Benefit Plans, Defined Benefit

Schedule of Allocation of Plan Assets

The actual investment allocations are shown in the following tables.


PBOP Plan	Target Allocation			Actual Allocation at December 31,
	2024			2023			2022			2021
Equity Funds		55	%		56	%		55	%		56	%
Debt Funds		45	%		44	%		45	%		44	%
Total					100	%		100	%		100	%

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2023 and 2022 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)
2023
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	23,025	$	23,025	$	—	$	—
Equity Funds		28,867		28,867		—		—
Total Assets	$	51,892	$	51,892	$	—	$	—

2022
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	20,156	$	20,156	$	—	$	—
Equity Funds		24,614		24,614		—		—
Total Assets	$	44,770	$	44,770	$	—	$	—

Allowance for Doubtful Accounts (Tables)

12 Months Ended

Dec. 31, 2023

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 2023, 2022 and 2021 (millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS


	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Regulatory Deferrals*			Balance at End of Period
Year Ended December 31, 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
Year Ended December 31, 2022
Electric	$	2.0	$	4.2	$	0.3	$	4.4	$	(0.5	)	$	1.6
Gas		1.3		2.5		0.6		3.2		(0.2	)		1.0
	$	3.3	$	6.7	$	0.9	$	7.6	$	(0.7	)	$	2.6
Year Ended December 31, 2021
Electric	$	1.6	$	3.3	$	0.4	$	3.4	$	0.1		$	2.0
Gas		1.7		2.3		0.4		3.1		—			1.3
	$	3.3	$	5.6	$	0.8	$	6.5	$	0.1		$	3.3

Equity (Tables)

12 Months Ended

Dec. 31, 2023

Table Text Block Supplement [Abstract]

Restricted Shares Issued in Conjunction with Stock Plan

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


Issuance Date	Shares	Aggregate Market Value (millions)
1/26/21	23,140	$0.9
1/25/22	36,770	$1.7
1/24/23	18,770	$1.0


Issuance Date	Shares	Aggregate Market Value (millions)
1/24/23	18,770	$1.0

Restricted Stock Units Issued

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


Restricted Stock Units (Equity Portion)
	2023					2022
	Units			Weighted Average Stock Price		Units			Weighted Average Stock Price
Beginning Restricted Stock Units		43,799		$	40.17		49,182		$	41.67
Restricted Stock Units Granted		2,646		$	42.31		3,595		$	46.72
Dividend Equivalents Earned		1,442		$	50.53		1,258		$	53.20
Restricted Stock Units Settled		(14,512	)	$	35.69		(10,236	)	$	51.28
Ending Restricted Stock Units		33,375		$	42.73		43,799		$	40.17

Reconciliation of Basic and Diluted Earnings Per Share

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


(Millions except shares and per share data)	2023		2022		2021
Earnings Available to Common Shareholders	$	45.2	$	41.4	$	36.1
Weighted Average Common Shares Outstanding—Basic (000’s)		16,045		15,991		15,373
Plus: Diluted Effect of Incremental Shares (000’s)		8		5		3
Weighted Average Common Shares Outstanding—Diluted (000’s)		16,053		15,996		15,376
Earnings per Share—Basic and Diluted	$	2.82	$	2.59	$	2.35

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.


	2023		2022		2021
Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation		12,204		12,086		23,636

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY - USD ($) $ in Millions	Total	Common Equity	Retained Earnings
Beginning Balance at Dec. 31, 2020	$ 389.0	$ 285.3	$ 103.7
Net Income	36.1		36.1
Dividends	(23.6)		(23.6)
Shares Issued Under Stock Plans	1.3	1.3
Issuance of Common Shares	45.5	45.5
Ending Balance at Dec. 31, 2021	448.3	332.1	116.2
Net Income	41.4		41.4
Dividends	(25.1)		(25.1)
Shares Issued Under Stock Plans	1.8	1.8
Issuance of Common Shares	1.0	1.0
Ending Balance at Dec. 31, 2022	467.4	334.9	132.5
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	$ 489.1	$ 337.6	$ 151.5

- Definition

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

+ References

+ Details

- Definition

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.

+ References + Details

Actual Investment Allocations (Detail)

Dec. 31, 2024

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Pension Plans

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

58.00%

Actual Allocation

100.00%

Pension Plans | Equity Funds

Defined Benefit Plan Disclosure [Line Items]

Actual Allocation

57.00%

53.00%

57.00%

Pension Plans | Fixed Income Securities

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

37.00%

Actual Allocation

36.00%

38.00%

Pension Plans | Other

Defined Benefit Plan Disclosure [Line Items]

Actual Allocation

^[1]

1.00%

2.00%

1.00%

Other Postretirement Benefit Plans, Defined Benefit

Defined Benefit Plan Disclosure [Line Items]

Actual Allocation

100.00%

Other Postretirement Benefit Plans, Defined Benefit | Equity Funds

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

55.00%

Actual Allocation

56.00%

55.00%

56.00%

Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

45.00%

Actual Allocation

44.00%

45.00%

44.00%

Real Estate Funds | Pension Plans

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

5.00%

Actual Allocation

6.00%

7.00%

4.00%

Scenario Forecast | Pension Plans

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

5.00%

Scenario Forecast | Pension Plans | Equity Funds

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

58.00%

Scenario Forecast | Pension Plans | Fixed Income Securities

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

37.00%

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

Defined Benefit Plan Disclosure [Line Items]

Target Allocation

55.00%

Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | 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, 2023, December 31, 2022 and December 31, 2021 pending payment of benefits.

CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Millions

Dec. 31, 2023

Dec. 31, 2022

Current Assets:

Cash and Cash Equivalents

$ 6.5

$ 9.0

Accounts Receivable, Net

75.0

73.8

Accrued Revenue

63.4

72.8

Exchange Gas Receivable

9.4

18.0

Gas Inventory

1.0

1.8

Materials and Supplies

13.5

11.4

Prepayments and Other

8.3

8.0

Total Current Assets

177.1

194.8

Utility Plant:

Electric

654.9

627.5

Gas

1,117.6

1,043.6

Common

70.0

67.6

Construction Work in Progress

65.3

52.6

Utility Plant

1,907.8

1,791.3

Less: Accumulated Depreciation

486.9

459.6

Net Utility Plant

1,420.9

1,331.7

Other Noncurrent Assets:

Regulatory Assets

53.1

47.8

Operating Lease Right of Use Assets

5.6

4.3

Other Assets

13.7

11.8

Total Other Noncurrent Assets

72.4

63.9

TOTAL ASSETS

1,670.4

1,590.4

Current Liabilities:

Accounts Payable

47.7

68.6

Short-Term Debt

162.0

116.0

Long-Term Debt, Current Portion

^[1]

4.9

6.7

Regulatory Liabilities

13.5

15.0

Energy Supply Obligations

15.0

24.1

Environmental Obligations

0.6

Operating Lease Obligations (current portion)

1.9

1.5

Taxes Payable

1.9

0.4

Other Current Liabilities

29.8

27.2

Total Current Liabilities

277.3

260.1

Noncurrent Liabilities:

Retirement Benefit Obligations

45.6

46.8

Deferred Income Taxes, net

176.1

163.4

Cost of Removal Obligations

126.3

116.1

Regulatory Liabilities

34.4

36.9

Environmental Obligations

4.0

3.8

Operating Lease Obligations (long-term portion)

3.7

2.8

Other Noncurrent Liabilities

4.6

3.8

Total Noncurrent Liabilities

394.7

373.6

Capitalization:

Long-Term Debt, Less Current Portion

509.1

489.1

Stockholders' Equity:

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

337.6

334.9

Retained Earnings

151.5

132.5

Total Common Stock Equity

489.1

467.4

Preferred Stock

0.2

Total Stockholders' Equity

489.3

467.6

Total Capitalization

998.4

956.7

Commitments and Contingencies (Note 7)

TOTAL LIABILITIES AND CAPITALIZATION

$ 1,670.4

$ 1,590.4

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

Summary Of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Nature of Operations

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

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.

Principles of Consolidation

Use of Estimates

Fair Value



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


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

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

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

Utility Revenue Recognition

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


	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


	Twelve Months Ended
	December 31, 2022
Electric and Gas Operating Revenues (millions):	Electric		Gas		Total
Billed and Unbilled Revenue:
Residential	$	159.9	$	98.2	$	258.1
Commercial & Industrial		112.6		153.8		266.4
Other		17.7		11.3		29.0
Total Billed and Unbilled Revenue		290.2		263.3		553.5
Rate Adjustment Mechanism Revenue		7.7		2.0		9.7
Total Electric and Gas Operating Revenues	$	297.9	$	265.3	$	563.2


	Twelve Months Ended
	December 31, 2021
Electric and Gas Operating Revenues (millions):	Electric		Gas		Total
Billed and Unbilled Revenue:
Residential	$	135.1	$	83.9	$	219.0
Commercial & Industrial		103.3		124.1		227.4
Other		10.1		9.6		19.7
Total Billed and Unbilled Revenue		248.5		217.6		466.1
Rate Adjustment Mechanism Revenue		—		7.2		7.2
Total Electric and Gas Operating Revenues	$	248.5	$	224.8	$	473.3

Revenue Decoupling

Estimated Percentage of Decoupled Sales

For Periods Presented


Electric
Before June 1, 2022		27%
After June 1, 2022		Substantially All
Gas
Before August 1, 2022		11%
After August 1, 2022		42%

Depreciation and Amortization

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

Dividends

Cash and Cash Equivalents

Company’s credit rating. On December 31, 2023 and 2022, the Unitil subsidiaries had deposited $3.3 million and $6.0 million, respectively, to satisfy their ISO-NE obligations.

Allowance for Doubtful Accounts

Accrued Revenue


	December 31,
Accrued Revenue (millions)	2023		2022
Regulatory Assets—Current	$	56.5	$	66.5
Unbilled Revenues		6.9		6.3
Total Accrued Revenue	$	63.4	$	72.8

Exchange Gas Receivable


	December 31,
Exchange Gas Receivable (millions)	2023		2022
Northern Utilities	$	8.6	$	16.3
Fitchburg		0.8		1.7
Total Exchange Gas Receivable	$	9.4	$	18.0

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, 2023 and 2022.


	December 31,
Gas Inventory (millions)	2023		2022
Natural Gas	$	0.3	$	1.0
Propane		0.3		0.4
Liquefied Natural Gas & Other		0.4		0.4
Total Gas Inventory	$	1.0	$	1.8

Utility Plant

Regulatory Accounting


	December 31,
Regulatory Assets consist of the following (millions)	2023		2022
Retirement Benefits	$	29.8	$	29.1
Energy Supply & Other Rate Adjustment Mechanisms		52.4		63.0
Deferred Storm Charges		9.2		3.4
Environmental		6.1		5.9
Income Taxes		1.1		1.8
Other Deferred Charges		11.0		11.1
Total Regulatory Assets		109.6		114.3
Less: Current Portion of Regulatory Assets(1)		56.5		66.5
Regulatory Assets—noncurrent	$	53.1	$	47.8

(1)

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


	December 31,
Regulatory Liabilities consist of the following (millions)	2023		2022
Rate Adjustment Mechanisms	$	9.3	$	10.9
Income Taxes		38.6		41.0
Total Regulatory Liabilities		47.9		51.9
Less: Current Portion of Regulatory Liabilities		13.5		15.0
Regulatory Liabilities—noncurrent	$	34.4	$	36.9

Leases

Derivatives

Investments in Marketable Securities


	December 31,
Fair Value of Marketable Securities (millions)	2023		2022
Money Market Funds	$	2.0	$	5.8
Fixed Income Funds		4.0		—
Total Marketable Securities	$	6.0	$	5.8


	December 31,
Fair Value of Marketable Securities (millions)	2023		2022
Equity Funds	$	1.1	$	0.5
Fixed Income Funds		0.1		—
Money Market Funds		0.1		0.1
Total Marketable Securities	$	1.3	$	0.6

Energy Supply Obligations

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


	December 31,
Energy Supply Obligations consist of the following (millions)	2023		2022
Renewable Energy Portfolio Standards	$	6.4	$	7.8
Exchange Gas Obligation		8.6		16.3
Total Energy Supply Obligations	$	15.0	$	24.1

Receivable on the Company’s Consolidated Balance Sheets while the corresponding obligations are recorded in Energy Supply Obligations.

Retirement Benefit Obligations

Commitments and Contingencies

Environmental Matters

Subsequent Events

Energy Supply

12 Months Ended

Dec. 31, 2023

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 2023, 88% of Unitil’s largest New Hampshire customers, representing 26% of Unitil’s New Hampshire electric kilowatt-hour (kWh) sales, and 97% of Unitil’s largest Massachusetts customers, representing 35% of Unitil’s Massachusetts electric kWh sales, purchased their electric power supply in the competitive market. Additionally, cities and towns in Massachusetts may, with approval from the MDPU, implement municipal aggregations

whereby the municipality purchases electric power on behalf of all citizens and businesses that do not opt out of the aggregation. The Towns of Lunenburg and Ashby, and the City of Fitchburg have active municipal aggregations. Customers in these three town’s represent 88% of Fitchburg’s customer base.

In New Hampshire, most residential and small commercial customers continue to purchase their electric supply through Unitil’s electric distribution utilities under regulated energy rates and tariffs, although this trend is changing. As of December 2023, the percentage of residential customers purchasing electricity from a third-party supplier increased to 22% from nearly 9% in December 2022. Municipal aggregation is now offered in New Hampshire. The towns of Exeter and Canterbury currently have active aggregations. Customers in these two towns represent 12% of Unitil’s customer base in New Hampshire. In Massachusetts, as of December 2023, 75% of Unitil’s residential customers in Massachusetts purchased their electricity from a third-party supplier which is up from 28% in December 2022.

Regulated Electric Power Supply

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

Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. Currently, with approval of the NHPUC, Unitil Energy purchases Default Service power supply contracts for small, medium and large customers every six months for 100% of the supply requirements.

Fitchburg typically maintains power supply contracts with various wholesale suppliers for the provision of Basic Service electric supply. Pursuant to MDPU policy, Basic Service power supply contracts for residential and for small and medium general service customers are acquired every six months, are 12 months in duration and provide 50 percent of the supply requirements. On June 13, 2012, the MDPU approved Fitchburg’s request to discontinue the procurement process for Fitchburg’s large customers and become the load-serving entity for these customers. As such, Fitchburg procures electric power supply for large account customers directly through ISO-NE’s markets. In its August 2022 solicitation, Fitchburg received no supply offers for load-following power to meet the needs of customers taking service under its Default Service tariff beginning December 2022. As such, beginning December 1, 2022 through July 31, 2023, Fitchburg began procuring electric supply for residential and small commercial customers directly from the ISO New England markets. In 2023, the Company ran successful solicitations in May and October and has returned to its staggered approach for procuring 50% of supply requirements for 12 months.

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

Regional Electric Transmission and Power Markets

Fitchburg, Unitil Energy and Unitil Power, as well as virtually all New England electric utilities, are participants in the ISO-NE markets. ISO-NE is the Regional Transmission Organization (RTO) in New England. The purpose of ISO-NE is to assure reliable operation of the bulk power system in the most economical manner for the region. Substantially all operation and dispatching of electric generation and bulk transmission capacity in New England are performed on a regional basis. The ISO-NE tariff imposes generating capacity and reserve obligations, and provides for the use of major transmission facilities and associated support payments. The most notable benefits of the ISO-NE are coordinated, reliable power system operation and a supportive business environment for the development of competitive electric markets.

Electric Power Supply Divestiture

In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets.

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

NATURAL GAS SUPPLY

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

Northern Utilities’ Commercial and Industrial (C&I) customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many of Northern Utilities’ large, and some of its medium, C&I customers purchase their gas supply from third-party suppliers. Most small C&I customers, and all residential customers, purchase their gas supply from Northern Utilities under regulated rates and tariffs. As of December 2023, 75% of Unitil’s largest New Hampshire gas customers, representing 40% of Unitil’s New Hampshire gas therm sales, and 59% of Unitil’s largest Maine customers, representing 21% of Unitil’s Maine gas therm sales, purchased their gas supply from a third-party supplier.

Fitchburg’s residential and C&I business customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many of Fitchburg’s large, and some of its medium, C&I customers, purchase their gas supply from third-party suppliers. Most of Fitchburg’s residential and small C&I customers continue to purchase their supplies at regulated rates from Fitchburg. As of December 2023, 77% of Unitil’s largest Massachusetts gas customers, representing 29% of Unitil’s Massachusetts gas therm sales, purchased their gas supply from third-party suppliers. The approved costs associated with natural gas supplied to customers who do not contract with third-party suppliers are recovered on a pass-through basis through periodically adjusted rates, and are included in Cost of Gas Sales in the Consolidated Statements of Earnings.

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.

CONSOLIDATED STATEMENTS OF EARNINGS - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Revenues:
Total Operating Revenues	$ 557.1	$ 563.2	$ 473.3
Operating Expenses:
Operation and Maintenance	75.6	73.7	68.7
Depreciation and Amortization	67.4	62.6	59.5
Taxes Other Than Income Taxes	28.5	25.9	24.5
Total Operating Expenses	470.0	482.7	395.5
Operating Income	87.1	80.5	77.8
Interest Expense, Net	28.7	25.5	25.6
Other Expense (Income), Net	0.0	2.4	4.6
Income Before Income Taxes	58.4	52.6	47.6
Provision for Income Taxes	13.2	11.2	11.5
Net Income Applicable to Common Shares	$ 45.2	$ 41.4	$ 36.1
Earnings per Common Share - Basic	$ 2.82	$ 2.59	$ 2.35
Earnings per Common Share - Diluted	$ 2.82	$ 2.59	$ 2.35
Weighted Average Common Shares Outstanding - Basic	16,045	15,991	15,373
Weighted Average Common Shares Outstanding - Diluted	16,053	15,996	15,376
Electric
Operating Revenues:
Total Operating Revenues	$ 306.5	$ 297.9	$ 248.5
Operating Expenses:
Cost of Sales	202.4	199.1	151.1
Gas
Operating Revenues:
Total Operating Revenues	250.6	265.3	224.8
Operating Expenses:
Cost of Sales	$ 96.1	$ 121.4	$ 91.7

Assets Measured at Fair Value on Recurring Basis for PBOP Plan (Detail) - Other Postretirement Benefit Plans, Defined Benefit - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 51,892	$ 44,770	$ 42,651
Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	23,025	20,156
Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	28,867	24,614
Fair Value, Inputs, Level 1
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	51,892	44,770
Fair Value, Inputs, Level 1 \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	23,025	20,156
Fair Value, Inputs, Level 1 \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 28,867	$ 24,614

- 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 + Details

Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions			1 Months Ended		12 Months Ended
	Jan. 24, 2023	Aug. 06, 2021	Jan. 31, 2024	Jan. 30, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Class of Stock [Line Items]
Common Stock, Shares, Outstanding					16,116,724	16,043,355
Common stock, shares issued					21,321	18,853	942,316
Common stock, shares authorized					25,000,000	25,000,000
Proceeds from Issuance of Common Stock					$ 1.1	$ 1.0	$ 45.5
Restricted stock weighted average grant date fair value					$ 46.94	$ 46.45
Percentage of fully-vested restricted stock units that directors will receive in common shares when settled					70.00%
Common stock shares repurchase					14,680	9,449	8,012
Share based compensation expense					$ 1.4	$ 2.1	$ 1.4
Percentage of fully-vested restricted stock units that directors will receive in cash when settled					30.00%
Preferred Stock					$ 0.2	$ 0.2
Restricted Stock
Class of Stock [Line Items]
Restricted stock vesting period					4 years
Restricted stock non-vested					36,483	45,473
Fair value of liabilities associated with fully vested RSUs that will be settled in cash					$ 0.8	$ 1.0
Unrecognized share based compensation					$ 0.7
Share compensation recognition period					2 years 2 months 12 days
Aggregate Market Value				$ 1.1
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Grants In Period Aggregate Intrinsic Value				$ 1.1
Cancellations under the stock plan					0
Restricted Stock \| Subsequent Event
Class of Stock [Line Items]
Restricted Stock Units Granted			22,680
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period			22,680
Restricted Stock \| Vesting Annually
Class of Stock [Line Items]
Restricted stock vesting percentage annually					25.00%
Restricted Stock \| Period One [Member]
Class of Stock [Line Items]
Restricted Stock Units Granted					23,140
Aggregate Market Value					$ 0.9
Share Issued Date					Jan. 26, 2021
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period					23,140
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Grants In Period Aggregate Intrinsic Value					$ 0.9
Restricted Stock \| Period Two [Member]
Class of Stock [Line Items]
Restricted Stock Units Granted					36,770
Aggregate Market Value					$ 1.7
Share Issued Date					Jan. 25, 2022
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period					36,770
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Grants In Period Aggregate Intrinsic Value					$ 1.7
Restricted Stock \| Period Three [Member]
Class of Stock [Line Items]
Restricted Stock Units Granted					18,770
Aggregate Market Value					$ 1.0
Share Issued Date					Jan. 24, 2023
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period					18,770
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Grants In Period Aggregate Intrinsic Value					$ 1.0
Performance Restricted Shares
Class of Stock [Line Items]
Restricted stock non-vested					18,770
Restricted stock weighted average grant date fair value					$ 51.83
Share based compensation expense					$ 0.5
Unrecognized share based compensation					$ 0.9
Share compensation recognition period					2 years
Restricted Stock Units Granted	18,770
Aggregate Market Value	$ 1.0
Share Issued Date	Jan. 24, 2023
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period	18,770
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Grants In Period Aggregate Intrinsic Value	$ 1.0
Performance Restricted Shares \| Subsequent Event
Class of Stock [Line Items]
Restricted Stock Units Granted				22,680
Aggregate Market Value				$ 1.1
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period				22,680
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Grants In Period Aggregate Intrinsic Value				$ 1.1
Common Stock
Class of Stock [Line Items]
Common stock, shares issued		800,000
Common stock price per share		$ 50.8
Proceeds from Issuance Initial Public Offering		$ 38.6
Unitil Energy Systems Inc \| Series 6
Class of Stock [Line Items]
Preferred stock, outstanding					1,727	1,861
Preferred Stock					$ 0.2	$ 0.2
Dividend rate					6.00%	6.00%
Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Proceeds from Issuance of Common Stock					$ 1.1	$ 1.0	$ 1.0
Dividend and Distribution Reinvestment and Share Purchase Plan \| Common Stock
Class of Stock [Line Items]
Common stock, shares issued					21,321	18,853	22,316
Over-Allotment Option [Member]
Class of Stock [Line Items]
Number Of Shares Granted Overallotment Option To Purchase Additional Shares		30 days
Sale of Stock, Number of Shares Issued in Transaction		120,000
Proceeds from Issuance of Private Placement		$ 5.9
Maximum
Class of Stock [Line Items]
Dividend declared					$ 0.1	$ 0.1
Repurchase expense					$ 0.6	$ 0.4	$ 0.4
Maximum \| Restricted Stock
Class of Stock [Line Items]
Restricted stock available for awards					677,500
Restricted stock that may be awarded in any one calendar year to any one participant					20,000
Average \| Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Common stock price per share					$ 51.58

Gas And Electric Supply Contractual Obligations (Detail) $ in Millions	Dec. 31, 2023 USD ($)
Total	$ 491.3
2024	81.2
2025	47.0
2026	45.6
2027	45.1
2028	40.2
2029 & Beyond	232.2
Gas Segment [Member]
Total	479.2
2024	79.9
2025	45.7
2026	44.3
2027	43.8
2028	39.1
2029 & Beyond	226.4
Electric [Member]
Total	12.1
2024	1.3
2025	1.3
2026	1.3
2027	1.3
2028	1.1
2029 & Beyond	$ 5.8

Debt and Financing Arrangements - Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Short-Term Borrowings Outstanding	$ 162.0	$ 116.0
Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility, limit	200.0	200.0
Short-Term Borrowings Outstanding	162.0	116.0
Available revolving credit facility	$ 38.0	$ 84.0

- 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

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 835
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482900/835-30-50-1

Reference 2: 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))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480678/235-10-S99-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-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 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1B

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 69C
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481568/470-20-55-69C

Reference 7: 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 8: http://www.xbrl.org/2003/role/exampleRef
-Topic 470
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+ Details

Allowance for Doubtful Accounts

12 Months Ended

Dec. 31, 2023

Allowance For Doubtful Accounts [Abstract]

Allowance for Doubtful Accounts

Note 3: Allowance for Doubtful Accounts

Unitil’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. In 2023, 2022 and 2021, the Company recorded provisions for the energy commodity portion of bad debts of $3.8 million, $3.8 million and $2.4 million, respectively. 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, 2023 and 2022, the Company has recorded $6.0 million and $5.8 million, respectively, of hardship accounts in Regulatory Assets. The Company currently receives recovery in rates or expects to receive recovery of these hardship accounts in future rate cases.

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

ALLOWANCE FOR DOUBTFUL ACCOUNTS


	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Regulatory Deferrals*			Balance at End of Period
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
Year Ended December 31, 2022
Electric	$	2.0	$	4.2	$	0.3	$	4.4	$	(0.5	)	$	1.6
Gas		1.3		2.5		0.6		3.2		(0.2	)		1.0
	$	3.3	$	6.7	$	0.9	$	7.6	$	(0.7	)	$	2.6
Year Ended December 31, 2021
Electric	$	1.6	$	3.3	$	0.4	$	3.4	$	0.1		$	2.0
Gas		1.7		2.3		0.4		3.1		—			1.3
	$	3.3	$	5.6	$	0.8	$	6.5	$	0.1		$	3.3

* In 2021, the Company recorded higher than normal expected bad debt expense due to the coronavirus pandemic. The incremental bad debt expense amounts were previously deferred as regulatory assets based on certain regulatory proceedings and management’s view that such amounts were probable of recovery. Based on actual billing and collections experience, the Company has not deferred any incremental bad debt expense as a regulatory asset as of December 31, 2023 and December 31, 2022.

Insider Trading Arrangements	12 Months Ended
Insider Trading Arrangements	Dec. 31, 2023
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

Segment Information (Tables)

12 Months Ended

Dec. 31, 2023

Significant Segment Financial Data

The following tables provide significant segment financial data for the years ended December 31, 2023, 2022 and 2021 (millions):


Year Ended December 31, 2023	Electric			Gas			Other			Total
Revenues:
Billed and Unbilled Revenue	$	311.7		$	253.8		$	—		$	565.5
Rate Adjustment Mechanism Revenue		(5.2	)		(3.2	)		—			(8.4	)
Total Operating Revenues		306.5			250.6			—			557.1
Interest Income		2.6			2.4			1.2			6.2
Interest Expense		11.2			20.7			3.0			34.9
Depreciation & Amortization Expense		26.0			40.4			1.0			67.4
Income Tax Expense (Benefit)		4.0			9.4			(0.2	)		13.2
Segment Profit (Loss)		17.9			28.8			(1.5	)		45.2
Segment Assets		612.6			1,031.8			26.0			1,670.4
Capital Expenditures		44.2			92.7			4.1			141.0

Year Ended December 31, 2022
Revenues:
Billed and Unbilled Revenue	$	290.2		$	263.3		$	—		$	553.5
Rate Adjustment Mechanism Revenue		7.7			2.0			—			9.7
Total Operating Revenues		297.9			265.3			—			563.2
Interest Income		0.9			1.0			0.9			2.8
Interest Expense		9.1			16.8			2.4			28.3
Depreciation & Amortization Expense		25.4			36.3			0.9			62.6
Income Tax Expense (Benefit)		3.1			8.2			(0.1	)		11.2
Segment Profit (Loss)		15.7			26.5			(0.8	)		41.4
Segment Assets		580.9			988.8			20.7			1,590.4
Capital Expenditures		33.8			87.6			0.7			122.1

Year Ended December 31, 2021
Revenues:
Billed and Unbilled Revenue	$	248.5		$	217.6		$	—		$	466.1
Rate Adjustment Mechanism Revenue		—			7.2			—			7.2
Total Operating Revenues		248.5			224.8			—			473.3
Interest Income		0.8			0.5			0.3			1.6
Interest Expense		9.0			15.3			2.9			27.2
Depreciation & Amortization Expense		25.9			32.6			1.0			59.5
Income Tax Expense (Benefit)		4.5			7.7			(0.7	)		11.5
Segment Profit		14.0			23.2			(1.1	)		36.1
Segment Assets		584.0			935.9			20.4			1,540.3
Capital Expenditures		38.1			75.8			1.1			115.0

Debt and Financing Arrangements- Details on Long Term Debt (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2023	Jul. 06, 2023
3.70% Senior Notes, Due August 1, 2026
Debt Instrument [Line Items]
Stated interest rate	3.70%
Debt instrument due date	Aug. 01, 2026
3.43% Senior Notes, Due December 18, 2029
Debt Instrument [Line Items]
Stated interest rate	3.43%
Debt instrument due date	Dec. 18, 2029
First Mortgage Bonds 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
6.79% Senior Notes, Due October 15, 2025 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	6.79%
Debt instrument due date	Oct. 15, 2025
3.52% Senior Notes, Due November 1, 2027 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	3.52%
Debt instrument due date	Nov. 01, 2027
3.52% Senior Notes, Due November 1, 2027 \| Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	3.52%
Debt instrument due date	Nov. 01, 2027
7.37% Senior Notes, Due January 15, 2029 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	7.37%
Debt instrument due date	Jan. 15, 2029
5.90% Notes, Due December 15, 2030 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	5.90%
Debt instrument due date	Dec. 15, 2030
7.98% Notes, Due June 1, 2031 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	7.98%
Debt instrument due date	Jun. 01, 2031
5.70 % Senior Note Due to July 2, 2033 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	5.70%	5.70%
Debt instrument due date	Jul. 02, 2033
3.78% Senior Notes, Due September 15, 2040 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	3.78%
Debt instrument due date	Sep. 15, 2040
3.78% Senior Notes, Due September 15, 2040 \| Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	3.78%
Debt instrument due date	Sep. 15, 2040
4.32% Senior Notes, Due November 1, 2047 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	4.32%
Debt instrument due date	Nov. 01, 2047
4.32% Senior Notes, Due November 1, 2047 \| Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	4.32%
Debt instrument due date	Nov. 01, 2047
5.96% Senior Note Due to July 2, 2053 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	5.96%	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
4.42% Senior Notes, Due October 15, 2044 \| Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	4.42%
Debt instrument due date	Oct. 15, 2044
4.04% Senior Notes, Due September 12, 2049 \| Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	4.04%
Debt instrument due date	Sep. 12, 2049
3.72% Senior Notes, Due November 1, 2027 \| Granite State Gas Transmission Inc
Debt Instrument [Line Items]
Stated interest rate	3.72%
Debt instrument due date	Nov. 01, 2027
2.64% Senior Notes, Due December 18, 2030 \| Unitil Realty Corp Member
Debt Instrument [Line Items]
Stated interest rate	2.64%
Debt instrument due date	Dec. 18, 2030

Debt and Financing Arrangements - Summary of Contractual Obligations for Long-term Debt (Detail) $ in Millions	Dec. 31, 2023 USD ($)
Contractual Obligation Fiscal Year Maturity Schedule [Line Items]
Total	$ 491.3
2024	81.2
2025	47.0
2026	45.6
2027	45.1
2028	40.2
2029 & Beyond	232.2
Long Term Debt Comprising Principal And Interest [Member]
Contractual Obligation Fiscal Year Maturity Schedule [Line Items]
Total	859.3
2024	29.6
2025	29.3
2026	61.9
2027	78.0
2028	30.6
2029 & Beyond	629.9
Long-Term Debt [Member] \| Long Term Debt Comprising Principal And Interest [Member]
Contractual Obligation Fiscal Year Maturity Schedule [Line Items]
Total	517.2
2024	4.9
2025	4.9
2026	37.9
2027	55.7
2028	10.7
2029 & Beyond	403.1
Interest on Long-Term Debt [Member] \| Long Term Debt Comprising Principal And Interest [Member]
Contractual Obligation Fiscal Year Maturity Schedule [Line Items]
Total	342.1
2024	24.7
2025	24.4
2026	24.0
2027	22.3
2028	19.9
2029 & Beyond	$ 226.8

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Dividends per Common Share	$ 1.62	$ 1.56	$ 1.52
Common stock, shares issued	21,321	18,853	942,316

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

Dec. 31, 2023

Dec. 31, 2022

Deferred Revenue Arrangement [Line Items]

Regulatory Assets – Current

^[1]

$ 56.5

$ 66.5

Total Accrued Revenue

63.4

72.8

Unbilled Revenues

Deferred Revenue Arrangement [Line Items]

Regulatory Assets – Current

6.9

6.3

Regulatory Assets

Deferred Revenue Arrangement [Line Items]

Regulatory Assets – Current

$ 56.5

$ 66.5

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

Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Deferred Tax Assets
Retirement Benefit Obligations	$ 11.2	$ 11.0
Net Operating Loss Carryforwards	0.1	3.5
Tax Credit Carryforwards	1.3	1.0
Other, net	1.3	1.4
Total Deferred Tax Assets	13.9	16.9
Deferred Tax Liabilities
Utility Plant Differences	180.3	168.3
Regulatory Assets & Liabilities	8.9	11.3
Other, net	0.8	0.7
Total Deferred Tax Liabilities	190.0	180.3
Net Deferred Tax Liabilities	$ 176.1	$ 163.4

Company's Liability for Environmental Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	$ 4.4	$ 2.7
Additions	0.7	2.0
Less: Payments / Reductions	0.5	0.3
Total Balance at end of Period	4.6	4.4
Less: Current Portion	0.6	0.6
Noncurrent Balance at End of Period	$ 4.0	$ 3.8

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2023

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, 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


	Twelve Months Ended
	December 31, 2022
Electric and Gas Operating Revenues (millions):	Electric		Gas		Total
Billed and Unbilled Revenue:
Residential	$	159.9	$	98.2	$	258.1
Commercial & Industrial		112.6		153.8		266.4
Other		17.7		11.3		29.0
Total Billed and Unbilled Revenue		290.2		263.3		553.5
Rate Adjustment Mechanism Revenue		7.7		2.0		9.7
Total Electric and Gas Operating Revenues	$	297.9	$	265.3	$	563.2


	Twelve Months Ended
	December 31, 2021
Electric and Gas Operating Revenues (millions):	Electric		Gas		Total
Billed and Unbilled Revenue:
Residential	$	135.1	$	83.9	$	219.0
Commercial & Industrial		103.3		124.1		227.4
Other		10.1		9.6		19.7
Total Billed and Unbilled Revenue		248.5		217.6		466.1
Rate Adjustment Mechanism Revenue		—		7.2		7.2
Total Electric and Gas Operating Revenues	$	248.5	$	224.8	$	473.3

Estimated Percentage of Decoupled Sales

Revenue Decoupling

Estimated Percentage of Decoupled Sales

For Periods Presented


Electric
Before June 1, 2022		27%
After June 1, 2022		Substantially All
Gas
Before August 1, 2022		11%
After August 1, 2022		42%

Components of Accrued Revenue

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


	December 31,
Accrued Revenue (millions)	2023		2022
Regulatory Assets—Current	$	56.5	$	66.5
Unbilled Revenues		6.9		6.3
Total Accrued Revenue	$	63.4	$	72.8

Components of Exchange Gas Receivable

The following table shows the components of Exchange Gas Receivable as of December 31, 2023 and 2022.


	December 31,
Exchange Gas Receivable (millions)	2023		2022
Northern Utilities	$	8.6	$	16.3
Fitchburg		0.8		1.7
Total Exchange Gas Receivable	$	9.4	$	18.0

Components of Gas Inventory

The following table shows the components of Gas Inventory as of December 31, 2023 and 2022.


	December 31,
Gas Inventory (millions)	2023		2022
Natural Gas	$	0.3	$	1.0
Propane		0.3		0.4
Liquefied Natural Gas & Other		0.4		0.4
Total Gas Inventory	$	1.0	$	1.8

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)	2023		2022
Retirement Benefits	$	29.8	$	29.1
Energy Supply & Other Rate Adjustment Mechanisms		52.4		63.0
Deferred Storm Charges		9.2		3.4
Environmental		6.1		5.9
Income Taxes		1.1		1.8
Other Deferred Charges		11.0		11.1
Total Regulatory Assets		109.6		114.3
Less: Current Portion of Regulatory Assets(1)		56.5		66.5
Regulatory Assets—noncurrent	$	53.1	$	47.8

(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)	2023		2022
Rate Adjustment Mechanisms	$	9.3	$	10.9
Income Taxes		38.6		41.0
Total Regulatory Liabilities		47.9		51.9
Less: Current Portion of Regulatory Liabilities		13.5		15.0
Regulatory Liabilities—noncurrent	$	34.4	$	36.9

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)	2023		2022
Money Market Funds	$	2.0	$	5.8
Fixed Income Funds		4.0		—
Total Marketable Securities	$	6.0	$	5.8

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)	2023		2022
Renewable Energy Portfolio Standards	$	6.4	$	7.8
Exchange Gas Obligation		8.6		16.3
Total Energy Supply Obligations	$	15.0	$	24.1

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)	2023		2022
Equity Funds	$	1.1	$	0.5
Fixed Income Funds		0.1		—
Money Market Funds		0.1		0.1
Total Marketable Securities	$	1.3	$	0.6

Commitments and Contingencies - Additional Information (Detail)																				3 Months Ended	12 Months Ended
	Nov. 27, 2023 USD ($)	Nov. 01, 2023 USD ($)	Sep. 20, 2023 USD ($)	Aug. 17, 2023 USD ($)	Jul. 27, 2023 USD ($)	May 31, 2023 USD ($)	Jan. 19, 2023	Nov. 02, 2022 USD ($)	Aug. 19, 2022 USD ($)	Jul. 28, 2022 USD ($)	Jul. 20, 2022 USD ($)	Jun. 08, 2022 USD ($)	May 12, 2022 USD ($)	May 03, 2022 USD ($)	Aug. 24, 2021 USD ($)	Dec. 30, 2020 USD ($)	Nov. 30, 2020 USD ($)	Jun. 25, 2019	Feb. 28, 2018 USD ($)	Mar. 31, 2023 USD ($)	Dec. 31, 2023 USD ($) MW	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2017	Oct. 31, 2023 USD ($)	Aug. 30, 2023 MW	Oct. 31, 2022 USD ($)	Oct. 07, 2022 USD ($)	May 27, 2022 USD ($)	May 25, 2022 MW	May 07, 2021 MW	Feb. 10, 2020 MW	May 31, 2019 MW	Jul. 31, 2018 MW MWh	Jun. 30, 2017 MW MWh
Commitments And Contingencies [Line Items]
Statutory Federal Income Tax Rate																					21.00%	21.00%	21.00%
Spending cap																					$ 491,300,000
Remuneration Percentage							2.25%											2.75%
Termination agreements																					$ 1,100,000
Approved annual increase in rates			$ 7,600,000
Requested annual increase in rates																			$ 2,100,000
Approved commitments for purchasing assets																$ 1,000,000
Environmental Remediation Expense, before Recovery, Statement of Income or Comprehensive Income [Extensible Enumeration]																					Costs and Expenses
Remediation costs																					$ 5,600,000
Percentage of Weighted Average Cost Inventory			7.22%
Stock Split Conversion Ratio			0.5201
Environmental Restoration Costs [Member]
Commitments And Contingencies [Line Items]
Estimated Costs Accrued For Remediation																					$ 2,500,000
Public Infrastructure Offering [Member]
Commitments And Contingencies [Line Items]
Approved commitments for purchasing assets																500,000
Electric Vehicle Supply Equipment [Member]
Commitments And Contingencies [Line Items]
Approved commitments for purchasing assets																300,000
Storm Cost Deferral Petition [Member]
Commitments And Contingencies [Line Items]
Recover costs of repairing damage																				$ 4,800,000
Carrying costs																				$ 1,400,000
Marketing And Outreach [Member]
Commitments And Contingencies [Line Items]
Approved commitments for purchasing assets																$ 200,000
Tax Year 2018
Commitments And Contingencies [Line Items]
Statutory Federal Income Tax Rate																								21.00%
Northern Utilities Inc
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													9.20%
Approved annual increase in rates														$ 6,300,000
Public utilities approved increase amount of annual revenue to recover eligible capital investments						$ 1,200,000				$ 1,300,000
Northern Utilities Inc \| Arrearage Management Program
Commitments And Contingencies [Line Items]
Expenses associated with the program excluded from the revenue requirement as per order and adjusted increase amount will result in reasonable rates													$ 5,900,000
Northern Utilities Inc \| New Hampshire
Commitments And Contingencies [Line Items]
Percentage of approved return on equity, reflecting on equity											52.00%
Percentage of approved return on equity, reflecting on debt											48.00%
Percentage of approved return on equity											9.30%
Threshold amount that will be allowed to adjust distribution rates upward or downward during the term of stay out period											$ 200,000
Requested annual increase in rates												$ 1,600,000
Northern Utilities Inc \| Maine
Commitments And Contingencies [Line Items]
Percentage of approved return on equity			9.35%
Northern Utilities Inc \| Settlement Agreement [Member]
Commitments And Contingencies [Line Items]
Approved annual increase in rates											$ 6,100,000
Fitchburg Gas and Electric Light Company
Commitments And Contingencies [Line Items]
Increase (decrease) in annual revenue	$ 3,500,000	$ 3,600,000						$ 3,100,000
Power generation capacity \| MWh																																			9,450,000
Approved annual increase in rates				$ 4,100,000
Transfer revenue amount				2,700,000
Fitchburg Gas and Electric Light Company \| July 1, 2024 [Member]
Commitments And Contingencies [Line Items]
Approved annual increase in rates				6,800,000
Fitchburg Gas and Electric Light Company \| Offshore Wind Energy
Commitments And Contingencies [Line Items]
Power generation facility \| MW																																400		400	1,600
Remuneration Percentage																		2.75%
Facility power capacity to be procured in the future \| MW																					5,600					400
Fitchburg Gas and Electric Light Company \| Offshore Wind Energy \| Second Solicitation [Member]
Commitments And Contingencies [Line Items]
Power generation facility \| MW																															1,600		800
Fitchburg Gas and Electric Light Company \| Qualified Clean Energy
Commitments And Contingencies [Line Items]
Power generation capacity \| MWh																																		9,554,940
Fitchburg Gas and Electric Light Company \| Mayflower Wind energy [Member] \| Third Solicitation [Member]
Commitments And Contingencies [Line Items]
Power generation facility \| MW																														400
Fitchburg Gas and Electric Light Company \| Commonwealth Wind [Member] \| Third Solicitation [Member]
Commitments And Contingencies [Line Items]
Power generation facility \| MW																														1,200
Fitchburg Gas Company
Commitments And Contingencies [Line Items]
Regulatory assets approved increase in revenue due to be recovered																									$ 6,400,000		$ 4,500,000
Approved annual increase in rates				6,700,000
Transfer revenue amount				4,200,000
Fitchburg Gas Company \| July 1, 2024 [Member]
Commitments And Contingencies [Line Items]
Public utilities interim increase decrease amount				$ 10,900,000
Granite State
Commitments And Contingencies [Line Items]
Increase (decrease) in annual revenue					$ 1,000,000				$ 300,000						$ 100,000		$ 1,300,000
Spending cap																	14,600,000
Fitchburg Grid Modernization
Commitments And Contingencies [Line Items]
Regulatory assets approved increase in revenue due to be recovered						$ 1,000,000																							$ 400,000
Amount of replacement investments approved by regulatory authority																	11,200,000
Purchase commitments for data sharing platform investments																	2,300,000
Fitchburg Grid Modernization \| Track One [Member]
Commitments And Contingencies [Line Items]
Amount of capital expenditure approved by regulatory authority																												$ 9,300,000
Fitchburg Grid Modernization \| Track Two [Member]
Commitments And Contingencies [Line Items]
Amount of capital expenditure approved by regulatory authority																	$ 1,500,000
Fitchburg Manufactured Gas Plant Site [Member]
Commitments And Contingencies [Line Items]
Environmental Remediation Expense, before Recovery, Statement of Income or Comprehensive Income [Extensible Enumeration]																					Costs and Expenses
Remediation costs																					$ 3,500,000
Fitchburg Manufactured Gas Plant Site [Member] \| Environmental Restoration Costs [Member]
Commitments And Contingencies [Line Items]
Estimated Costs Accrued For Remediation																					$ 40,000

Segment Information - Significant Segment Financial Data (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	$ 557.1	$ 563.2	$ 473.3
Interest Income	6.2	2.8	1.6
Interest Expense	34.9	28.3	27.2
Depreciation & Amortization Expense	67.4	62.6	59.5
Income Tax Expense (Benefit)	13.2	11.2	11.5
Segment Profit (Loss)	45.2	41.4	36.1
Segment Assets	1,670.4	1,590.4	1,540.3
Capital Expenditures	141.0	122.1	115.0
Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	565.5	553.5	466.1
Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	(8.4)	9.7	7.2
Electric
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	306.5	297.9	248.5
Interest Income	2.6	0.9	0.8
Interest Expense	11.2	9.1	9.0
Depreciation & Amortization Expense	26.0	25.4	25.9
Income Tax Expense (Benefit)	4.0	3.1	4.5
Segment Profit (Loss)	17.9	15.7	14.0
Segment Assets	612.6	580.9	584.0
Capital Expenditures	44.2	33.8	38.1
Electric \| Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	311.7	290.2	248.5
Electric \| Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	(5.2)	7.7
Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	250.6	265.3	224.8
Interest Income	2.4	1.0	0.5
Interest Expense	20.7	16.8	15.3
Depreciation & Amortization Expense	40.4	36.3	32.6
Income Tax Expense (Benefit)	9.4	8.2	7.7
Segment Profit (Loss)	28.8	26.5	23.2
Segment Assets	1,031.8	988.8	935.9
Capital Expenditures	92.7	87.6	75.8
Gas Segment \| Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	253.8	263.3	217.6
Gas Segment \| Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	(3.2)	2.0	7.2
All Other Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Interest Income	1.2	0.9	0.3
Interest Expense	3.0	2.4	2.9
Depreciation & Amortization Expense	1.0	0.9	1.0
Income Tax Expense (Benefit)	(0.2)	(0.1)	(0.7)
Segment Profit (Loss)	(1.5)	(0.8)	(1.1)
Segment Assets	26.0	20.7	20.4
Capital Expenditures	$ 4.1	$ 0.7	$ 1.1

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Aug. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2017
Income Taxes [Line Items]
Statutory Federal Income Tax Rate		21.00%	21.00%	21.00%
Regulatory Liability		$ 47.9	$ 51.9
Regulatory liability, expected flow back to customers					$ 47.1
Regulatory liability, expected pass back to ratepayers		1.3				$ 1.8
Net Operating Loss Carryforwards Utilized For Income Taxes			1.4
Deferred tax assets, operating loss carryforwards, federal		4.4
Percentage of alternate minimum tax	15.00%
Number of years used for calculating adjusted financial statement income	3 years
Adjustment financial statement income	$ 1.0
FederalTaxCreditsToOffsetCurrentTaxes			1.7
Income Tax Related Liabilities
Income Taxes [Line Items]
Regulatory Liability		38.6	$ 41.0			$ 48.9
Gas Ratepayers \| Massachusetts And Maine [Member]
Income Taxes [Line Items]
Regulatory liability, expected flow back to customers		$ 9.3
Tax Year 2018
Income Taxes [Line Items]
Statutory Federal Income Tax Rate						21.00%

Employer Contributions, Participant Contributions and Benefit Payments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Plans
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	$ 3,850	$ 3,800	$ 4,100
Benefits Paid	8,877	9,724	6,489
Other Postretirement Benefit Plans, Defined Benefit
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	2,790	12,153	8,903
Participant Contributions	234	279	220
Benefits Paid	2,767	3,503	2,905
Supplemental Employee Retirement Plans, Defined Benefit
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	665	637	637
Benefits Paid	$ 665	$ 637	$ 637

Fair Value of Marketable Securities (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	$ 6.0	$ 5.8
Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	1.3	0.6
Fair Value, Inputs, Level 1
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	6.0	5.8
Fair Value, Inputs, Level 1 \| Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	1.3	0.6
Fair Value, Inputs, Level 1 \| Equity Funds \| Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	1.1	0.5
Fair Value, Inputs, Level 1 \| Money Market Funds
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	2.0	5.8
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	4.0	0.0
Fair Value, Inputs, Level 1 \| Fixed Income Funds \| Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	$ 0.1	$ 0.0

Assets Measured at Fair Value on Recurring Basis for Pension Plan (Detail) - Pension Plans - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 137,893	$ 126,098	$ 152,006
Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	127,881	114,978
Mutual Fund \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	78,522	67,332
Mutual Fund \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	49,359	47,646
Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	2,266	2,598
Mutual Fund Including Cash And Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	130,147	117,576
Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	7,746	8,522
Fair Value, Inputs, Level 1 \| Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	127,881	114,978
Fair Value, Inputs, Level 1 \| Mutual Fund \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	78,522	67,332
Fair Value, Inputs, Level 1 \| Mutual Fund \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	49,359	47,646
Fair Value, Inputs, Level 1 \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	2,266	2,598
Fair Value, Inputs, Level 1 \| Mutual Fund Including Cash And Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 130,147	$ 117,576

Reconciliation of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Schedule Of Computation Of Basic And Diluted Earnings Per Common Share [Line Items]
Net Income (Loss)	$ 45.2	$ 41.4	$ 36.1
Weighted Average Common Shares Outstanding - Basic	16,045	15,991	15,373
Plus: Diluted Effect of Incremental Shares	8	5	3
Weighted Average Common Shares Outstanding - Diluted	16,053	15,996	15,376
Earnings per Common Share - Basic	$ 2.82	$ 2.59	$ 2.35
Earnings per Common Share - Diluted	$ 2.82	$ 2.59	$ 2.35

- Definition

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
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-URI https://asc.fasb.org//1943274/2147483443/250-10-50-3

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

- Definition

The amount of net income (loss) for the period available to each share of common stock or common unit outstanding during the reporting period and to each share or unit that would have been outstanding assuming the issuance of common shares or units for all dilutive potential common shares or units outstanding during the reporting period.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147483589/942-220-S99-1

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04(23))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147483586/944-220-S99-1

Reference 15: http://www.xbrl.org/2003/role/exampleRef
-Topic 260
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 52
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482635/260-10-55-52

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 260
-SubTopic 10
-Name Accounting Standards Codification
-Section 45
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482689/260-10-45-7

+ Details

- Definition

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

+ References

+ Details

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

Dec. 31, 2023

Dec. 31, 2022

Regulatory Asset [Line Items]

Regulatory Assets

$ 109.6

$ 114.3

Less: Current Portion of Regulatory Assets

^[1]

56.5

66.5

Regulatory Assets—noncurrent

53.1

47.8

Environmental Matters

Regulatory Asset [Line Items]

Regulatory Assets

6.1

5.9

Other Deferred Charges

Regulatory Asset [Line Items]

Regulatory Assets

11.0

11.1

Other Postretirement Benefits Plan [Member]

Regulatory Asset [Line Items]

Regulatory Assets

29.8

29.1

Deferred Storm Charges

Regulatory Asset [Line Items]

Regulatory Assets

9.2

3.4

Income Taxes

Regulatory Asset [Line Items]

Regulatory Assets

1.1

1.8

Energy Supply & Other Rate Adjustment Mechanisms

Regulatory Asset [Line Items]

Regulatory Assets

$ 52.4

$ 63.0

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

Debt and Financing Arrangements - Summary of Interest Expense and Interest Income (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Interest Expense
Long-Term Debt	$ 24.7	$ 24.7	$ 26.0
Short-Term Debt	9.2	3.0	0.8
Regulatory Liabilities	1.0	0.6	0.4
Subtotal Interest Expense	34.9	28.3	27.2
Interest Income
Interest and Other Income	(6.2)	(2.8)	(1.6)
Interest Expense, Net	28.7	25.5	25.6
Regulatory Assets
Interest Income
Interest and Other Income	(3.3)	(1.0)	(0.5)
AFUDC and Other
Interest Income
Interest and Other Income	$ (2.9)	$ (1.8)	$ (1.1)