10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2023

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 1-8858

UNITIL CORPORATION

(Exact name of registrant as specified in its charter)

New Hampshire	02-0381573
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
6 Liberty Lane West, Hampton, New Hampshire	03842-1720
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (603) 772-0775

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol	Name of each exchange of which registered
Common Stock, no par value	UTL	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐

Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 762(b)) by the registered public accounting firm that prepared or issued its audit report ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

Based on the closing price of the registrant’s common stock on June 30, 2023, the aggregate market value of common stock held by non-affiliates of the registrant was $802,806,380.

The number of shares of the registrant’s common stock outstanding was 16,163,365 as of February 9, 2024.

Documents Incorporated by Reference:

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.

UNITIL CORPORATION

FORM 10-K

For the Fiscal Year Ended December 31, 2023

Table of Contents

Item	Description	Page
	PART I
1.	Business	3
	Unitil Corporation	3
	Operations	4
	Rates and Regulation	6
	Employees	6
	Available Information	7
	Investor Information	7
1A.	Risk Factors	8
1B.	Unresolved Staff Comments	14
1C.	Cybersecurity	14
2.	Properties	16
3.	Legal Proceedings	17
4.	Mine Safety Disclosures	17
	PART II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	18
6.	Reserved	20
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A)	21
7A.	Quantitative and Qualitative Disclosures about Market Risk	34
8.	Financial Statements and Supplementary Data	35
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	80
9A.	Controls and Procedures	80
9B.	Other Information	80
9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	80
	PART III
10.	Directors, Executive Officers and Corporate Governance	81
11.	Executive Compensation	81
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	81
13.	Certain Relationships and Related Transactions, and Director Independence	81
14.	Principal Accountant Fees and Services	81
	PART IV
15.	Exhibits and Financial Statement Schedules	82
	SIGNATURES
	Signatures	90

In this Annual Report on Form 10-K, the “Company”, “Unitil”, “we”, “us”, “our” and similar terms refer to Unitil Corporation and its subsidiaries, unless the context requires otherwise.

CAUTIONARY STATEMENT

This report and the documents incorporated by reference into this report contain statements that may constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact, included or incorporated by reference into this report, including, without limitation, statements regarding the financial position, business strategy and other plans and objectives for the future operations of the Company (as such term is defined in Part I, Item I (Business)), are forward-looking statements.

These statements include declarations regarding the Company’s beliefs and current expectations. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. These forward-looking statements are subject to inherent risks and uncertainties in predicting future results and conditions that could cause the actual results to differ materially from those projected in these forward-looking statements. Some, but not all, of the risks and uncertainties include those described in Part I, Item 1A (Risk Factors) and the following:

•numerous hazards and operating risks relating to the Company’s electric and natural gas distribution activities, which could result in accidents and other operating risks and costs;

•fluctuations in the supply of, demand for, and the prices of, electric and gas energy commodities and transmission and transportation capacity and the Company’s ability to recover energy supply costs in its rates;

•catastrophic events;

•cyber-attacks, acts of terrorism, acts of war, severe weather, a solar event, an electromagnetic event, a natural disaster, the age and condition of information technology assets, human error, or other factors could disrupt the Company’s operations and cause the Company to incur unanticipated losses and expense;

•outsourcing of services to third parties could expose us to substandard quality of service delivery or substandard deliverables, which may result in missed deadlines or other timeliness issues, non-compliance (including with applicable legal requirements and industry standards) or reputational harm, which could negatively affect our results of operations;

•unforeseen or changing circumstances, which could adversely affect the reduction of Company-wide direct greenhouse gas emissions;

•the Company’s regulatory and legislative environment (including laws and regulations relating to climate change, greenhouse gas emissions and other environmental matters) could affect the rates the Company is able to charge, the Company’s authorized rate of return, the Company’s ability to recover costs in its rates, the Company’s financial condition, results of operations and cash flows, and the scope of the Company’s regulated activities;

•general economic conditions, which could adversely affect (i) the Company’s customers and, consequently, the demand for the Company’s distribution services, (ii) the availability of credit and liquidity resources, and (iii) certain of the Company’s counterparty’s obligations (including those of its insurers and lenders);

•the Company’s ability to obtain debt or equity financing on acceptable terms;

•increases in interest rates, which could increase the Company’s interest expense;

•declines in capital markets valuations, which could require the Company to make substantial cash contributions to cover its pension obligations, and the Company’s ability to recover pension obligation costs in its rates;

•restrictive covenants contained in the terms of the Company’s and its subsidiaries’ indebtedness, which restrict certain aspects of the Company’s business operations;

•customers’ preferred energy sources;

•severe storms and the Company’s ability to recover storm costs in its rates;

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•variations in weather, which could decrease demand for the Company’s distribution services;

•long-term global climate change, which could adversely affect customer demand or cause extreme weather events that could disrupt the Company’s electric and natural gas distribution services;

•Employee workforce factors, including the ability to attract and retain key personnel

•the Company’s ability to retain its existing customers and attract new customers;

•increased competition; and

•other presently unknown or unforeseen factors.

Many of these risks are beyond the Company’s control. Any forward-looking statements speak only as of the date of this report, and the Company undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events, except as required by law. New factors emerge from time to time, and it is not possible for the Company to predict all such factors, nor can the Company assess the effect of any such factor on its business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements.

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PART I

Item 1. Business

UNITIL CORPORATION

In this Annual Report on Form 10-K, the “Company”, “Unitil”, “we”, and “our” refer to Unitil Corporation and its subsidiaries, unless the context requires otherwise. Unitil is a public utility holding company incorporated under the laws of the State of New Hampshire in 1984. The following companies are wholly-owned subsidiaries of Unitil:

Company Name	State and Year of Organization	Principal Business
Unitil Energy Systems, Inc. (Unitil Energy)	NH - 1901	Electric Distribution Utility
Fitchburg Gas and Electric Light Company (Fitchburg)	MA - 1852	Electric & Natural Gas Distribution Utility
Northern Utilities, Inc. (Northern Utilities)	NH - 1979	Natural Gas Distribution Utility
Granite State Gas Transmission, Inc. (Granite State)	NH - 1955	Natural Gas Transmission Pipeline
Unitil Power Corp. (Unitil Power)	NH - 1984	Wholesale Electric Power Utility
Unitil Service Corp. (Unitil Service)	NH - 1984	Utility Service Company
Unitil Realty Corp. (Unitil Realty)	NH - 1986	Real Estate Management
Unitil Resources, Inc. (Unitil Resources)	NH - 1993	Non-regulated Energy Services

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.

Unitil’s principal business is the local distribution of electricity and natural gas to approximately 196,900 customers throughout its service territories in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of three wholly-owned distribution utilities: i) Unitil Energy, which provides electric service in the southeastern seacoast and state capital regions of New Hampshire, including the capital city of Concord, ii) Fitchburg, which provides both electric and natural gas service in the greater Fitchburg area of north central Massachusetts, and iii) Northern Utilities, which provides natural gas service in southeastern New Hampshire and portions of southern and central Maine, including the city of Portland, which is the largest city in northern New England. In addition, Unitil is the parent company of Granite State, an interstate natural gas transmission pipeline company that provides interstate natural gas pipeline access and transportation services to Northern Utilities in its New Hampshire and Maine service territory. Together, Unitil’s three distribution utilities serve approximately 108,500 electric customers and 88,400 natural gas customers.

	Customers Served as of December 31, 2023
	Residential		Commercial & Industrial (C&I)		Total
Electric:
Unitil Energy		66,762		11,352		78,114
Fitchburg		26,211		4,129		30,340
Total Electric		92,973		15,481		108,454
Natural Gas:
Northern Utilities		55,040		17,011		72,051
Fitchburg		14,612		1,734		16,346
Total Natural Gas		69,652		18,745		88,397
Total Customers Served		162,625		34,226		196,851

Unitil had an investment in Net Utility Plant of $1,420.9 million at December 31, 2023. The Company’s total operating revenue was $557.1 million in 2023. Unitil’s operating revenue is substantially derived from regulated electric and natural gas distribution utility operations. 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 has three other wholly-owned non-utility subsidiaries: Unitil Service, Unitil Realty, and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology and energy supply management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire.

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Unitil Resources is the Company’s wholly-owned non-regulated subsidiary which currently does not have any activity. For segment information relating to each segment’s revenue, earnings and assets, see Note 2 (Segment Information) to the Consolidated Financial Statements included in Part II, Item 8 (Financial Statements and Supplementary Data) of this report. All of the Company’s revenues are attributable to customers in the United States of America and all its long-lived assets are located in the United States of America.

OPERATIONS

Electric Distribution Utility Operations

Unitil’s electric distribution operations are conducted through two of the Company’s utilities, Unitil Energy and Fitchburg. Revenue from Unitil’s electric utility operations was $306.5 million in 2023, which represents about 55% of Unitil’s total operating revenue. The Company’s GAAP Electric Gross Margin was $78.1 million in 2023. The Company’s Electric Adjusted Gross Margin (a non-GAAP financial measure) was $104.1 million in 2023, or 40% of Unitil’s total Adjusted Gross Margin. See “Results of Operations” in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) for a discussion of the non-GAAP financial measures presented in this Annual Report on Form 10-K, including a reconciliation of the non-GAAP financial measures to the most comparable GAAP financial measures for the periods presented.

The primary business of Unitil’s electric utility operations is the local distribution of electricity to customers in its service territory in New Hampshire and Massachusetts. All of Unitil Energy’s and Fitchburg’s electric customers are entitled to purchase their supply of electricity from third-party competitive suppliers, while Unitil Energy and Fitchburg remain their electric distribution company. Both Unitil Energy and Fitchburg supply electricity to those customers who do not obtain their supply from third-party competitive suppliers, with the approved costs associated with electricity supply being recovered on a pass-through basis under regulated reconciling rate mechanisms that are periodically adjusted.

Unitil Energy distributes electricity to approximately 78,100 customers in New Hampshire in the capital city of Concord as well as parts of 12 surrounding towns, and all or part of 18 towns in the southeastern and seacoast regions of New Hampshire, including the towns of Hampton, Exeter, Atkinson and Plaistow. Unitil Energy’s service territory consists of approximately 408 square miles. Unitil Energy’s service territory encompasses retail and recreation centers for the central and southeastern parts of the state and includes the Hampton Beach recreational area. These areas serve diversified commercial and industrial businesses, including manufacturing firms engaged in the production of electronic components, wire and plastics, as well as firms engaged in the aviation, defense, healthcare and education sectors. Unitil Energy’s 2023 electric operating revenue was $222.6 million, of which approximately 62% was derived from residential sales and 38% from commercial and industrial (C&I) sales.

Fitchburg is engaged in the distribution of both electricity and natural gas in the greater Fitchburg area of north central Massachusetts. Fitchburg’s service territory encompasses approximately 170 square miles. Electricity is distributed by Fitchburg to approximately 30,300 customers in the communities of Fitchburg, Ashby, Townsend and Lunenburg. Fitchburg’s industrial customers include paper manufacturing and paper products companies, rubber and plastics manufacturers, precision machining and molding, non-lethal ballistics manufacturing, specialty chemicals compounding, cannabis growing and processing facilities, printing, and educational institutions. Fitchburg’s 2023 electric operating revenue was $83.9 million, of which approximately 57% was derived from residential sales and 43% from C&I sales.

Natural Gas Operations

Unitil’s natural gas operations include gas distribution utility operations and interstate gas transmission pipeline operations. Revenue from Unitil’s gas operations was $250.6 million in 2023, which represents about 45% of Unitil’s total operating revenue. The Company’s GAAP Gas Gross Margin was $114.1 million in 2023. The Company’s Gas Adjusted Gross Margin (a non-GAAP financial measure) was $154.5 million in 2023, or 60% of Unitil’s total Adjusted Gross Margin. See “Results of Operations” in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) for a discussion of the non-GAAP financial measures presented in this Annual Report on Form 10-K, including a reconciliation of the non-GAAP financial measures to the most comparable GAAP financial measures for the periods presented.

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Natural Gas Distribution Utility Operations

Unitil’s natural gas distribution operations are conducted through two of the Company’s operating utilities, Northern Utilities and Fitchburg. The primary business of Unitil’s natural gas utility operations is the local distribution of natural gas to customers in its service territories in New Hampshire, Massachusetts and Maine. Northern Utilities’ C&I customers and Fitchburg’s residential and C&I customers are entitled to purchase their natural gas supply from third-party competitive suppliers, while Northern Utilities or Fitchburg remains their gas distribution company. Both Northern Utilities and Fitchburg supply gas to those customers who do not obtain their supply from third-party competitive suppliers, with the approved costs associated with this gas supply recovered on a pass-through basis under regulated reconciling rate mechanisms that are periodically adjusted.

Northern Utilities distributes natural gas to approximately 72,100 customers in 47 New Hampshire and southern Maine communities, from Plaistow, New Hampshire in the south to the city of Portland, Maine and then extending to Lewiston-Auburn, Maine to the north. Northern Utilities has a diversified customer base both in Maine and New Hampshire. Commercial businesses include healthcare, education, government and retail. Northern Utilities’ industrial base includes manufacturers in the auto, housing, paper, printing, textile, pharmaceutical, electronics, wire and food production industries as well as a military installation. Northern Utilities’ 2023 gas operating revenue was $195.5 million, of which approximately 37% was derived from residential firm sales and 63% from C&I firm sales.

Fitchburg distributes natural gas to approximately 16,300 customers in the communities of Fitchburg, Lunenburg, Townsend, Ashby, Gardner and Westminster, all located in Massachusetts. Fitchburg’s industrial customers include paper manufacturing and paper products companies, rubber and plastics manufacturers, cannabis growing and processing facilities, printing, educational institutions. Fitchburg’s 2023 gas operating revenue was $46.4 million, of which approximately 59% was derived from residential firm sales and 41% from C&I firm sales.

Gas Transmission Pipeline Operations

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 major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State had operating revenue of $8.7 million in 2023. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and to third-party suppliers under FERC-approved rates.

Seasonality

The Company’s results of operations are expected to reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the colder weather seasons of the year as a result of higher sales of natural gas used for heating-related purposes. Accordingly, the results of operations are historically most favorable in the first and fourth quarters. Fluctuations in seasonal weather conditions may have a significant effect on the result of operations. Sales of electricity are generally less sensitive to weather than natural gas sales, but may also be affected by weather conditions and the temperature in the winter and summer seasons.

Unitil Energy, Fitchburg and Northern Utilities have a well-diversified customer mix and are not dependent on a single customer, or a few customers, for their electric and natural gas sales.

Revenue Decoupling

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

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The following table shows the estimated percentages, as of December 31, 2023, of electric and gas sales that are subject to revenue decoupling for the periods presented.

Revenue Decoupling

Estimated Percentage of Decoupled Sales

For Periods Presented

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

Non-Regulated and Other Non-Utility Operations

The results of Unitil’s other non-utility subsidiaries, Unitil Service, Unitil Resources, Unitil Realty, and the holding company, are included in the Company’s consolidated results of operations. The results of these non-utility operations are principally derived from income earned on short-term investments and real property owned for Unitil’s and its subsidiaries’ use and are reported, after intercompany eliminations, in Other segment income. For segment information, see Note 2 (Segment Information) to the Consolidated Financial Statements included in Part II, Item 8 (Financial Statements and Supplementary Data) of this report.

RATES AND REGULATION

Regulation

Unitil is subject to comprehensive regulation by federal and state regulatory authorities. Unitil and its subsidiaries are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005 with regard to certain bookkeeping, accounting and reporting requirements. Unitil’s utility operations related to wholesale and interstate energy business activities also are regulated by the FERC. Unitil’s distribution utilities are subject to regulation by the applicable state public utility commissions, with regard to their rates, issuance of securities and other accounting and operational matters: Unitil Energy is subject to regulation by the NHPUC; Fitchburg is subject to regulation by the MDPU; and Northern Utilities is regulated by the NHPUC and Maine Public Utilities Commission (MPUC). Granite State, Unitil’s interstate natural gas transmission pipeline, is subject to regulation by the FERC with regard to its rates and operations. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations and financial position.

Unitil’s distribution utilities deliver electricity and/or natural gas to all customers in their service territory, at rates established under cost of service regulation. Under this regulatory structure, Unitil’s distribution utilities are provided the opportunity to recover the cost of providing distribution service to their customers based on a test year, and to earn a reasonable return on their capital investment in utility assets. In addition, the Company’s distribution utilities and its natural gas transmission pipeline company may recover certain base rate costs, including capital project spending and enhanced reliability and vegetation management programs, through annual step adjustments and cost tracking rate mechanisms. The Company's electric and gas sales in New Hampshire and Massachusetts are now largely decoupled.

Also see Note 6 (Energy Supply) and Note 7 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information regarding rates and regulation.

EMPLOYEES

As of December 31, 2023, the Company and its subsidiaries had 531 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

The Company strives to be the employer of choice in the communities it serves—regardless of race, religion, color, gender, or sexual orientation. The Company works diligently to attract the best talent from a diverse range of sources to meet the current and future demands of our business.

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To attract and retain a talented workforce, Unitil provides employee wages that are competitive and consistent with employee positions, skill levels, experience, knowledge and geographic location. All employees are eligible for health insurance, paid and unpaid leave, educational assistance, retirement plan and life and disability/accident coverage. Feedback from employees is collected annually in the Company’s employee opinion survey. This feedback helps create action plans to improve the engagement of employees consistent with the Company’s culture of continuous improvement.

As of December 31, 2023, a total of 182 employees of certain of the Company’s subsidiaries were represented by labor unions. The following table details by subsidiary the employees covered by a collective bargaining agreement (CBA) as of December 31, 2023:

	Employees Covered	CBA Expiration
Fitchburg	47	5/31/2027
Northern Utilities NH Division	37	06/07/2025
Northern Utilities ME Division	39	03/31/2026
Granite State	5	03/31/2026
Unitil Energy	43	5/31/2028
Unitil Service - Gas Control	6	3/31/2024
Unitil Service	5	5/31/2028

The CBAs provide discrete salary adjustments, established work practices and uniform benefit packages. The Company expects to negotiate new agreements prior to their expiration dates.

AVAILABLE INFORMATION

The Internet address for the Company’s website is unitil.com. On the Investors section of the Company’s website, the Company makes available, free of charge, its Securities and Exchange Commission (SEC) reports, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other reports, as well as amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practical after the Company electronically files such material with, or furnishes such material to, the SEC.

The Company’s current Code of Ethics was approved by Unitil’s Board of Directors on January 15, 2004. This Code of Ethics, along with any amendments or waivers, is also available on Unitil’s website.

Unitil’s common stock is listed on the New York Stock Exchange under the ticker symbol “UTL”.

INVESTOR INFORMATION

Annual Meeting

The Company’s annual meeting of shareholders is scheduled to be held at the offices of the Company, 6 Liberty Lane West, Hampton, New Hampshire, on Wednesday, May 1, 2024, at 11:30 a.m.

Transfer Agent

The Company’s transfer agent, Computershare Investor Services, is responsible for shareholder records, issuance of common stock, administration of the Dividend Reinvestment and Stock Purchase Plan, and the distribution of Unitil’s dividends and IRS Form 1099-DIV. Shareholders may contact Computershare at:

Computershare Investor Services

P.O. Box 43078

Providence, RI 02940-3078

Telephone: 800-736-3001

www.computershare.com/investor

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Investor Relations

For information about the Company, you may call the Company directly, toll-free, at: 800-999-6501 and ask for the Investor Relations Representative; visit the Investors page at www.unitil.com; or contact the transfer agent, Computershare, at the number listed above.

Special Services & Shareholder Programs Available to Holders of Record

If a shareholder’s shares of our common stock are registered directly in the shareholder’s name with the Company’s transfer agent, the shareholder is considered a holder of record of the shares. The following services and programs are available to shareholders of record:

•Internet Account Access is available at www.computershare.com/investor.

•Dividend Reinvestment and Stock Purchase Plan:

To enroll, please contact the Company’s Investor Relations Representative or Computershare.

•Dividend Direct Deposit Service:

To enroll, please contact the Company’s Investor Relations Representative or Computershare.

•Direct Registration:

For information, please contact Computershare at 800-935-9330 or the Company’s Investor Relations Representative at 800-999-6501.

Item 1A. Risk Factors

When considering an investment in our securities, investors should consider the following risk factors, as well as the information contained under the caption “Cautionary Statement” immediately following the Table of Contents in this Annual Report on Form 10-K. Additional risks not presently known to the Company or that the Company currently believes are immaterial may also impair business operations and financial results. If any of the following risks actually occur, the Company’s business, financial condition or results of operations could be adversely affected. In such case, the trading price of the Company’s common stock could decline and investors could lose all or part of their investment. The risk factors below are categorized by operational, regulatory, financial and general.

OPERATIONAL RISKS

A substantial disruption or lack of growth in interstate natural gas pipeline transmission and storage capacity and electric transmission capacity may impair the Company’s ability to meet customers’ existing and future requirements.

To meet existing and future customer demands for electricity and natural gas, the Company must acquire sufficient supplies of electricity and natural gas. In addition, the Company must contract for reliable and adequate upstream transmission and transportation capacity for its distribution systems while considering the dynamics of the natural gas interstate pipelines and storage, the electric transmission markets and its own on-system resources. The Company’s financial condition or results of operations may be adversely affected if the future availability of electric and natural gas supply were insufficient to meet future customer demands for electricity and natural gas.

The Company’s electric and natural gas distribution activities (including storing natural gas and supplemental gas supplies) involve numerous hazards and operating risks that may result in accidents and other operating risks and costs. Any such accident or costs could adversely affect the Company’s financial position or results of operations.

Inherent in the Company’s electric and natural gas distribution activities are a variety of hazards and operating risks, including leaks, explosions, electrocutions, mechanical problems and aging infrastructure. These hazards and risks could result in loss of human life, significant damage to property, environmental pollution, damage to natural resources and impairment of the Company’s operations, which could adversely affect the Company’s financial position or results of operations.

The Company maintains insurance against some, but not all, of these risks and losses in accordance with customary industry practice. The location of pipelines, storage facilities and electric distribution equipment near populated areas (including residential areas, commercial business centers and industrial sites) could increase the level of damages associated with these

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hazards and operating risks. The occurrence of any of these events could adversely affect the Company’s financial position or results of operations.

The Company’s operational and information systems on which it relies to conduct its business and serve customers could fail to function properly due to technological problems, a cyber-attack, acts of terrorism, severe weather, a solar event, an electromagnetic event, a natural disaster, the age and condition of information technology assets, human error, or other reasons, that could disrupt the Company’s operations and cause the Company to incur unanticipated losses and expense.

The operation of the Company’s extensive electric and natural gas systems rely on evolving information and operating technology systems and network infrastructure that are likely to become more complex as new technologies and systems are developed. The Company’s business is highly dependent on its ability to process and monitor, on a daily basis, a very large number of transactions, many of which are highly complex. The failure of these systems and networks could significantly disrupt operations; result in outages and/or damages to the Company’s assets or operations or those of third parties on which it relies; and subject the Company to claims by customers or third parties, any of which could have a material effect on the Company’s financial condition, results of operations, and cash flows.

The Company’s information systems, including its financial information, operational systems, metering, and billing systems, require constant maintenance, modification, and updating, which can be costly and increases the risk of errors and malfunction. Any disruptions or deficiencies in existing information systems, or disruptions, delays or deficiencies in the modification or implementation of new information systems, could result in increased costs, the inability to track or collect revenues, the diversion of management’s and employees’ attention and resources, and could negatively affect the effectiveness of the Company’s control environment, and/or the Company’s ability to timely file required regulatory reports. Despite implementation of security and mitigation measures, all of the Company’s technology systems are vulnerable to impairment or failure due to cyber-attacks, computer viruses, human errors, acts of war or terrorism and other reasons. If the Company’s information technology systems were to fail or be materially impaired, the Company might be unable to fulfill critical business functions and serve its customers, which could have a material effect on the Company’s financial condition, results of operations, and cash flows.

In the ordinary course of its business, the Company collects and retains sensitive electronic data including personal identification information about customers and employees, customer energy usage, and other confidential information. The theft, damage, or improper disclosure of sensitive electronic data through security breaches or other means could subject the Company to penalties for violation of applicable privacy laws or claims from third parties and could harm the Company’s reputation and adversely affect the Company’s financial condition and results of operations.

In addition, the Company’s electric and natural gas distribution and transmission delivery systems are part of an interconnected regional grid and pipeline system. If these neighboring interconnected systems were to be disrupted due to cyber-attacks, computer viruses, human errors, acts of war or terrorism or other reasons, the Company’s operations and its ability to serve its customers would be adversely affected, which could have a material effect on the Company’s financial condition, results of operations, and cash flows.

We outsource certain business functions to third-party suppliers and service providers, and substandard performance by those third parties could harm our business, reputation and results of operations.

We outsource certain services to third parties in areas including information technology, telecommunications, networks, transaction processing, human resources, payroll and payroll processing and other areas. Outsourcing of services to third parties could expose us to substandard quality of service delivery or substandard deliverables, which may result in missed deadlines or other timeliness issues, non-compliance (including with applicable legal requirements and industry standards) or reputational harm, which could negatively affect our results of operations. We also continue to pursue enhancements to modernize our systems and processes. If any difficulties in the operation of these systems were to occur, they could adversely affect our results of operations, or adversely affect our ability to work with regulators, unions, customers or employees.

The inability to attract and retain a qualified workforce including, but not limited to, executive officers, key employees and employees with specialized skills, could have an adverse effect on the Company’s operations.

The success of our business depends on the leadership of our executive officers and other key employees to implement our business strategies. The inability to maintain a qualified workforce including, but not limited to, executive officers, key

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employees and employees with specialized skills, may negatively affect our ability to service our existing or new customers, or successfully manage our business or achieve our business objectives. There may not be sufficiently skilled employees available internally to replace employees when they retire or otherwise leave active employment. Shortages of certain highly skilled employees may also mean that qualified employees are not available externally to replace these employees when they are needed. In addition, shortages in highly skilled employees coupled with competitive pressures may require the Company to incur additional employee recruiting and compensation expenses.

The Company may be adversely affected by work stoppages, labor disputes, and/or pandemic illness to which it may not be able to promptly respond.

Approximately one-third of the Company’s employees are represented by labor unions and are covered by collective bargaining agreements. Disputes with the unions over terms and conditions of the agreements could result in instability in the Company’s labor relationships and work stoppages that could affect the timely delivery of electricity and natural gas, which could strain relationships with customers and state regulators and cause a loss of revenues. The Company’s collective bargaining agreements also may increase the cost of employing its union workforce, affect its ability to continue offering market-based salaries and employee benefits, limit its flexibility in dealing with its workforce, and limit its ability to change work rules and practices and implement other efficiency-related improvements to successfully compete in today’s challenging marketplace, which may negatively affect the Company’s financial condition and results of operations.

Additionally, pandemic illness could result in part, or all, of the Company’s workforce being unable to operate or maintain the Company’s infrastructure or perform other tasks necessary to conduct the Company’s business. A slow or inadequate response to this type of event may adversely affect the Company’s financial condition, results of operations, and cash flows.

REGULATORY RISKS

The Company is subject to comprehensive regulation, which could adversely affect the rates it is able to charge, its authorized rate of return and its ability to recover costs. In addition, certain regulatory authorities have the statutory authority to impose financial penalties and other sanctions on the Company, which could adversely affect the Company’s financial condition, results of operations, and cash flows.

The Company is subject to comprehensive regulation by federal regulatory authorities (including the FERC) and state regulatory authorities (including the NHPUC, MDPU and MPUC). These authorities regulate many aspects of the Company’s operations, including the rates that the Company can charge customers, the Company’s authorized rates of return, the Company’s ability to recover costs from its customers, construction and maintenance of the Company’s facilities, the Company’s safety protocols and procedures, including environmental compliance, the Company’s ability to issue securities, the Company’s accounting matters, and transactions between the Company and its affiliates. The Company is unable to predict the effect on its financial condition and results of operations from the regulatory activities of any of these regulatory authorities. Changes in regulations, the imposition of additional regulations, regulatory proceedings regarding fossil fuel use and system electrification, or regulatory decisions particular to the Company could adversely affect the Company’s financial condition and results of operations.

The Company’s ability to obtain rate adjustments to maintain its current authorized rates of return depends upon action by regulatory authorities under applicable statutes, rules and regulations. These regulatory authorities are authorized to leave the Company’s rates unchanged, to grant increases in such rates, or to order decreases in such rates. The Company may be unable to obtain favorable rate adjustments or to maintain its current authorized rates of return, which could adversely affect its financial condition, results of operations, and cash flows.

Regulatory authorities also have authority with respect to the Company’s ability to recover its electricity and natural gas supply costs, as incurred by Unitil Energy, Fitchburg, Unitil Power, and Northern Utilities. If the Company is unable to recover a significant amount of these costs, or if the Company’s recovery of these costs is significantly delayed, the Company’s financial condition, results of operations, or cash flows could be adversely affected.

In addition, certain regulatory authorities have the statutory authority to impose financial penalties and other sanctions on the Company if the Company is found to have violated statutes, rules or regulations governing its utility operations. Any such penalties or sanctions could adversely affect the Company’s financial condition, results of operations, and cash flows.

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The Company’s business is subject to environmental regulation in all jurisdictions in which it operates and its costs of compliance are significant. New, or changes to existing, environmental regulation, including those related to climate change or greenhouse gas emissions, and the incurrence of environmental liabilities could adversely affect the Company’s financial condition, results of operations, and cash flows.

The Company’s utility operations are generally subject to extensive federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, natural resources, and the health and safety of the Company’s employees. The Company’s utility operations also may be subject to new and emerging federal, state and local legislative and regulatory initiatives related to climate change or greenhouse gas emissions including the U.S. Environmental Protection Agency’s mandatory greenhouse gas reporting rule. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties and other sanctions; imposition of remedial requirements; and issuance of injunctions to ensure future compliance. Liability under certain environmental laws and regulations is strict, joint and several in nature. Although the Company believes it is in material compliance with all applicable environmental and safety laws and regulations, there is no assurance that the Company will not incur significant costs and liabilities in the future. Moreover, it is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations, including those related to climate change or greenhouse gas emissions, could result in increased environmental compliance costs. The Company has committed to reduce greenhouse gas emissions from 2019 levels by at least 50% by 2030 and to achieve net-zero greenhouse gas emissions by 2050. Unforeseen or changing circumstances could adversely affect the Company's ability to achieve these greenhouse gas emissions goals and changes in the regulatory environment could result in the costs associated with efforts to achieve these goals not qualifying for recovery.

FINANCIAL RISKS

The Company may not be able to obtain financing, or may not be able to obtain financing on acceptable terms, which could adversely affect the Company’s financial condition and results of operations.

The Company requires capital to fund utility plant additions, working capital and other utility expenditures. While the Company derives the capital necessary to meet these requirements primarily from internally generated funds, the Company supplements internally generated funds by incurring short-term and long-term debt, as needed. Additionally, from time to time the Company has accessed the public capital markets through public offerings of equity securities. A downgrade of our credit rating or events beyond our control, such as a disruption in global capital and credit markets, could increase our cost of borrowing and cost of capital or restrict our ability to access the capital markets and negatively affect our ability to maintain and to expand our businesses.

The Company’s short-term debt revolving credit facility typically has variable interest rates. Therefore, an increase or decrease in interest rates will increase or decrease the Company’s interest expense associated with its revolving credit facility. An increase in the Company’s interest expense could adversely affect the Company’s financial condition and results of operations. As of December 31, 2023, the Company had approximately $162.0 million in short-term debt outstanding under its revolving credit facility. If the lending counterparties under the Company’s current credit facility are unwilling or unable to meet their funding obligations, the Company may be unable to, or limited in its ability, to borrow under its credit facility. This situation could hinder or prevent the Company from meeting its current and future capital needs, which could correspondingly adversely affect the Company’s financial condition, results or operations, and cash flows.

Also, from time to time the Company repays portions of its short-term debt with the proceeds it receives from long-term debt financings or equity financings. General economic conditions, conditions in the capital and credit markets and the Company’s operating and financial performance could negatively affect the Company’s ability to obtain such financings or the terms of such financings, which could correspondingly adversely affect the Company’s financial condition, results of operations, and cash flows. The Company’s long-term debt typically has fixed interest rates. Therefore, changes in interest rates will not affect the Company’s interest expense associated with its presently outstanding fixed rate long-term debt. However, an increase or decrease in interest rates may increase or decrease the Company’s interest expense associated with any new fixed rate long-term debt issued by the Company, which could adversely affect the Company’s financial condition, results of operations, and cash flows.

The Company may need to use a significant portion of its cash flow to repay its short-term debt and long-term debt, which would limit the amount of cash it has available for working capital, capital expenditures and other general corporate purposes and could adversely affect its financial condition, results of operations, and cash flows.

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Changes in taxation and the ability to quantify such changes could adversely affect the Company’s financial results.

The Company is subject to taxation by the various taxing authorities at the federal, state and local levels where it does business. Legislation or regulation which could affect the Company’s tax burden could be enacted by any of these governmental authorities. The Company cannot predict the timing or extent of such tax-related developments which could have a negative effect on the financial results. The Company uses its best judgment in attempting to quantify and reserve for these tax obligations. However, a challenge by a taxing authority, the Company’s ability to utilize tax benefits such as carryforwards or tax credits, or a deviation from other tax-related assumptions may cause actual financial results to deviate from previous estimates.

Declines in capital market valuations could require the Company to make substantial cash contributions to cover its pension and other post-retirement benefit obligations. If the Company is unable to recover a significant amount of pension and other post-retirement benefit obligation costs in its rates, or if the Company’s recovery of these costs in its rates is significantly delayed, its financial condition and results of operations could be adversely affected.

The amount of cash contributions the Company is required to make in respect of its pension and other post-retirement benefit obligations is dependent upon capital market valuations. Adverse changes in capital market valuations could result in the Company being required to make substantial cash contributions in respect to these obligations. These cash contributions could have an adverse effect on the Company’s financial condition, results of operations, and cash flows if the Company is unable to recover such costs in rates or if such recovery is significantly delayed. See section titled Critical Accounting Policies—Retirement Benefit Obligations in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 9 (Retirement Benefit Plans) to the accompanying Consolidated Financial Statements for a more detailed discussion of the Company’s pension obligations.

The terms of the Company’s and its subsidiaries’ indebtedness restrict the Company’s and its subsidiaries’ business operations (including their ability to incur material amounts of additional indebtedness), which could adversely affect the Company’s financial condition and results of operations.

The terms of the Company’s and its subsidiaries’ indebtedness impose various restrictions on the Company’s business operations, including the ability of the Company and its subsidiaries to incur additional indebtedness. These restrictions could adversely affect the Company’s financial condition, results of operations, and cash flows. See sections titled Liquidity, Commitments and Capital Requirements in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 4 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements for a more detailed discussion of these restrictions.

Unitil is a public utility holding company and has no operating income of its own. The Company’s ability to pay dividends on its common stock is dependent on dividends and other payments received from its subsidiaries and on factors directly affecting Unitil, the parent corporation. The Company cannot assure that its current annual dividend will be paid in the future.

The ability of the Company’s subsidiaries to pay dividends or make distributions to Unitil depends on, among other things:

•the actual and projected earnings and cash flow, capital requirements and general financial condition of the Company’s subsidiaries;

•the prior rights of holders of existing and future preferred stock, mortgage bonds, long-term notes and other debt issued by the Company’s subsidiaries;

•the restrictions on the payment of dividends contained in the existing loan agreements of the Company’s subsidiaries and that may be contained in future debt agreements of the Company’s subsidiaries, if any; and

•limitations that may be imposed by New Hampshire, Massachusetts and Maine state regulatory authorities.

In addition, before the Company can pay dividends on its common stock, it must satisfy its debt obligations and comply with any statutory or contractual limitations.

As of February 13, 2024, the Company’s current effective annualized dividend is $1.70 per share of common stock, payable quarterly. The Company’s Board of Directors reviews Unitil’s dividend policy periodically in light of a number of

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business and financial factors, including those referred to in this report, and the Company cannot assure the amount of dividends, if any, that may be paid in the future.

GENERAL RISKS

The Company’s electric and natural gas sales and revenues are highly correlated with the economy, and national, regional and local economic conditions may adversely affect the Company’s customers and correspondingly the Company’s financial condition, results of operations, and cash flows.

The Company’s business is influenced by the economic activity within its service territory. The level of economic activity in the Company’s electric and natural gas distribution service territories directly affects the Company’s business. As a result, adverse changes in the economy may adversely affect the Company’s financial condition, results or operations, and cash flows. Economic downturns or periods of high electric and gas supply costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency and self-generation by customers. This focus on conservation, energy efficiency and self-generation may result in a decline in electricity and gas sales in our service territories. If any such declines were to occur without corresponding adjustments in rates, our revenues would be reduced and our future growth prospects would be limited. In addition, a period of prolonged economic weakness could affect our customers’ ability to pay bills in a timely manner and increase customer bankruptcies, which may lead to increased bad debt expenses or other adverse effects on our financial position, results of operations, and cash flows.

A significant amount of the Company’s sales are temperature sensitive. Because of this, mild winter and summer temperatures could decrease the Company’s sales, which could adversely affect the Company’s financial condition and results of operations. Also, the Company’s sales may vary from year to year depending on weather conditions, and the Company’s results of operations generally reflect seasonality.

A significant amount of the Company’s natural gas sales are temperature sensitive. Therefore, mild winter temperatures could decrease the amount of natural gas sold by the Company, which could adversely affect the Company’s financial condition, results of operations, and cash flows. The Company’s electric sales also are temperature sensitive, but less so than its natural gas sales. The highest usage of electricity typically occurs in the summer months (due to air conditioning demand) and the winter months (due to heating-related and lighting requirements). Therefore, mild summer temperatures and mild winter temperatures could decrease the amount of electricity sold by the Company, which could adversely affect the Company’s financial condition, results of operations, and cash flows. Also, because of this temperature sensitivity, sales by the Company’s distribution utilities vary from year to year, depending on weather conditions.

The Company’s results of operations are expected to reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the colder weather seasons of the year as a result of higher sales of natural gas used for heating-related purposes. Accordingly, the results of operations are historically most favorable in the first and fourth quarters. Fluctuations in seasonal weather conditions may have a significant effect on the result of operations. Sales of electricity are generally less sensitive to weather than natural gas sales, but may also be affected by the weather conditions and the temperature in both the winter and summer seasons.

Catastrophic events could adversely affect the Company’s financial condition and results of operations.

The electric and natural gas utility industries are from time to time affected by catastrophic events, such as unusually severe weather and significant and widespread failures of plant and equipment. Other catastrophic occurrences, such as terrorist attacks on utility facilities, may occur in the future. Such events could inhibit the Company’s ability to deliver electricity or natural gas to its customers for an extended period, which could affect customer satisfaction and adversely affect the Company’s financial condition, results of operations, and cash flows. If customers, legislators, or regulators develop a negative opinion of the Company, this situation could result in increased regulatory oversight and could affect the equity returns that the Company is allowed to earn. Also, if the Company is unable to recover in its rates a significant amount of costs associated with catastrophic events, or if the Company’s recovery of such costs in its rates is significantly delayed, the Company’s financial condition, results or operations, or cash flows may be adversely affected.

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The Company’s business could be adversely affected if it is unable to retain its existing customers or attract new customers, or if customers’ demand for its current products and services significantly decreases.

The success of the Company’s business depends, in part, on its ability to maintain and increase its customer base and the demand that those customers have for the Company’s products and services. The Company’s failure to maintain or increase its customer base and/or customer demand for its products and services could adversely affect its financial condition, results of operations, and cash flows.

The electricity and natural gas supply requirements of the Company’s customers are fulfilled by the Company or, in some instances and as allowed by state regulatory authorities, by third-party suppliers who contract directly with customers. In either scenario, significant increases in electricity and natural gas commodity prices may negatively affect the Company’s ability to attract new customers and grow its customer base.

Developments in distributed generation, energy conservation, power generation and energy storage could affect the Company’s revenues and the timing of the recovery of the Company’s costs. Advancements in power generation technology are improving the cost-effectiveness of customer self-supply of electricity. Improvements in energy storage technology, including batteries and fuel cells, could also better position customers to meet their around-the-clock electricity requirements. Such developments could reduce customer purchases of electricity, but may not necessarily reduce the Company’s investment and operating requirements due to the Company’s obligation to serve customers, including those self-supply customers whose equipment has failed for any reason, to provide the power they need. In addition, because a portion of the Company’s costs are recovered through charges based upon the volume of power delivered, reductions in electricity deliveries will affect the timing of the Company’s recovery of those costs and may require changes to the Company’s rate structures.

Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity

For purposes of the following disclosure, the terms “cybersecurity incident” and “cybersecurity threat” have the meanings given to such terms in Item 106 of Regulation S-K promulgated under the Securities Exchange Act of 1934.

Risk management and strategy

The Company has a Cybersecurity Plan for assessing, identifying, and managing material risks from cybersecurity threats. The intent of the Cybersecurity Plan is to provide a proactive and systemic approach to meet the evolving requirements for cybersecurity and related compliance in the utility industry. The Cybersecurity Plan’s objectives include:

·adopting and using established cybersecurity standards and industry best practices;

·protecting personally identifiable information;

·protecting infrastructure operations, including Supervisory Control and Data Acquisition (SCADA) systems at electric substations and natural gas plants;

·securing customers’, employees’, and the Company’s data;

·complying with North American Reliability Corporation Critical Infrastructure Protection Reliability Standards and standards for the protection of Bulk Electric System Cyber Systems; and

·continually assessing and, as necessary, enhancing the Company’s cybersecurity through a managed process integrated with the Company’s risk management principles.

The Cybersecurity Plan includes annual assessments using (i) the Department of Energy’s Cybersecurity Capability Maturity Model, (ii) the National Institute of Standards and Technology Cybersecurity Framework, and (iii) the Center for Internet Security Controls. The Company uses the results of these assessments to benchmark the Company’s cybersecurity posture, to identify risks from cybersecurity threats, to prioritize any such risks that may have potential material effects on the Company, and to establish effective controls to manage, mitigate and remediate such risks.

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The Cybersecurity Plan is part of the Company’s corporate Enterprise Risk Management (ERM) program. The Company’s ERM program includes an annual review of new or emerging risks (including risks from cybersecurity threats), the assessment of such risks and their potential effects on the Company, the velocity of potential cybersecurity incidents resulting from such risks, and risk mitigation strategies.

The Company maintains a Cybersecurity Employee Awareness Program, which provides targeted education and mandatory quarterly training to employees. The Cybersecurity Employee Awareness Program also conducts monthly phishing test exercises with employees, which includes an escalation procedure for repeated failures. Additionally, the Company performs an annual cyber knowledge assessment of all employees to address any identified knowledge gaps.

The Company engages or otherwise collaborates with cybersecurity consultants, cybersecurity experts, energy sector leaders, and other third parties in connection with the Cybersecurity Plan. Unitil Corporation also is a member of the cyber committees of both the American Gas Association and the Edison Electric Institute.

Third party entities that provide hardware, software or related support services to the Company or hold the Company’s customer data represent material cybersecurity risks to the Company. To help mitigate those risks, the Company has robust procurement processes and requirements for such third-parties (which include a formal assessment of the third-party’s cyber posture, cyber liability insurance, and breach reporting protocols) that help the Company to oversee and identify cybersecurity risks associated with its use of such third party entities.

During the fiscal year ended, and as of, December 31, 2023, there were no risks from cybersecurity threats (including as a result of previous cybersecurity incidents) that have materially affected or are reasonably likely to materially affect the Company (including its business strategy, results of operations, or financial condition).

Governance

Unitil Corporation’s Board of Directors (the “Board”) is responsible for oversight of the Company’s ERM program, including risks from cybersecurity threats. The Board has not assigned that responsibility to any committee or subcommittee of the Board. The Company’s management generally provides the Board with updates on and assessments of ongoing and emerging risks from cybersecurity threats at regularly scheduled Board meetings.

The Company’s cybersecurity management team is responsible for assessing and managing the Company’s material risks from cybersecurity threats, including implementing the Cybersecurity Plan. The team includes the Company’s Chief Technology Officer and Vice President of Information Technology (the “CTO”), the Director of Information Security, and two Cybersecurity Analysts, all of whom have an educational background relevant to, professional experience in, or other expertise in cybersecurity. This team is supported by the Company’s Information Technology department. The CTO holds a Master of Business Administration and a Bachelor of Science in Electrical Engineering with over 30 years of professional experience in the utility industry with extensive management experience in engineering, operations and information technology. The CTO also assumes responsibilities as the Company’s Chief Information Security Officer and its Chief Cyber Security Officer. The CTO has overall management responsibility for the Company’s cybersecurity. The CTO reports to the Company’s Chief Executive Officer. The Director of Information Security holds a Bachelor of Science in Computer Science and a Masters Certificate in Cyber Security with a concentration in Power Systems and has over 30 years of experience in the information technology field. The Director of Information Security has primary responsibility for the cyber security program including threat and vulnerability management, vendor security posture assessment, Industrial Control System (ICS) and SCADA infrastructure protection at electric substations and natural gas plants, as well as leading the Cyber Incident Response Team. One of the Cybersecurity Analysts has a Bachelor of Science in Information Technology and the other has a Bachelor of Science in Criminal Justice / Computer Crime and Digital Forensics, and the Cybersecurity Analysts have a combined 25 years of experience in various information technology and cyber roles.

The Company’s cybersecurity management team assesses and manages the Company’s material risks from cybersecurity threats through or by:

·active monitoring of cyber threat alerts, warnings, advisories, notices, vulnerability assessments, incident bulletins, security briefings, reports and white papers from industry and national organizations, including: downstream

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Natural Gas Information Sharing and Analysis Center; Electricity Information Sharing and Analysis Center; Cybersecurity and Infrastructure Security Agency; and Federal Bureau of Investigation;

·threat and vulnerability management;

·vendor security posture assessment;

·Industrial Control System and Supervisory Control and Data Acquisition infrastructure protection at electric substations and natural gas plants; and

·leading the Company’s Cyber Incident Response Team.

In addition, the Company uses (i) a Security Operations Center vendor with 24x7 monitoring and response capabilities to identify any suspicious activity on the Company’s networks and (ii) a security consulting firm for assessments, penetration testing and incident response. In the event of a cybersecurity threat, the CTO and these parties would collaborate to assess and manage the risk with ultimate responsibility residing with the Board.

Also, in the event of a cybersecurity threat or cybersecurity incident, the Company’s cybersecurity management team will conduct an investigation and impact analysis and, as necessary, the CTO will activate the Company’s Cyber Incident Response Team. The Cyber Incident Response Team is a subset of the Company’s Crisis Response Team, which has responsibility for operational and business resilience, as well as tactical and strategic response. A foundational aspect of the Crisis Response Team is prompt and comprehensive communications to all concerned parties, both internal and external, including direction for management to inform the Board about risks from cybersecurity threats.

In the event that a cybersecurity incident occurs which results in damage to the Company’s data or infrastructure, the Cyber Incident Response Team would follow the Company’s Cyber Incident Response Plan. The Cyber Incident Response Plan was developed using the guidelines described in the National Institute of Standards and Technology Special Publication 800-61 Revision 2 Computer Security Incident Handling Guide, has been reviewed and assessed by outside experts, is updated annually, and is used to train for cybersecurity incidents. The Cyber Incident Response Plan details the identification, containment, eradication and recovery processes specific to the Company’s environment with prioritization of critical assets. The Cyber Incident Response Plan also details emergency actions required to isolate and protect industrial control system environments, should the incident pose a risk to electric or gas operations. The Company participates in annual industry drill exercises to test the Cyber Incident Response Plan.

The Company’s determination of the materiality of a cybersecurity incident would generally include an evaluation of the incident’s effect on the Company (including (i) its business strategy, results of operations, or financial condition, (ii) the integrity, confidentiality, resiliency, and security of the Company’s networks and systems, and (iii) the Company’s operations).

Item 2. Properties

As of December 31, 2023, Unitil owned through its natural gas and electric distribution utilities, five utility operating centers located in New Hampshire, Maine and Massachusetts. The Company’s real estate subsidiary, Unitil Realty, owns the Company’s corporate headquarters building and the land on which it is located in Hampton, New Hampshire. Unitil Realty also owns land for future use in Kingston, New Hampshire.

The following tables detail certain of the Company’s electric and natural gas operations properties.

Electric Operations

Description	Unitil Energy		Fitchburg		Total
Primary Transmission and Distribution Pole Miles—Overhead		1,288		452		1,740
Conduit Distribution Bank Miles—Underground		242		69		311
Transmission and Distribution Substations*		26		11		37
Transformer Capacity of Transmission and Distribution Substations** (MVA)		454.6		414.4		869.0

* Includes locations that are normally in-service sources of distribution circuits through the use of transformer(s).

** Does not include load served directly from sub-transmission.

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Natural Gas Operations

	Northern Utilities
Description	NH		ME		Fitchburg		Granite State		Total
Underground Natural Gas Mains—Miles		582		617		271		—		1,470
Natural Gas Transmission Pipeline—Miles		—		—		—		85		85
Service Pipes		24,855		24,156		11,255		—		60,266

Unitil Energy’s electric substations are located on land owned by Unitil Energy or land occupied by Unitil Energy pursuant to perpetual easements in the southeastern seacoast and state capital regions of New Hampshire. Unitil Energy’s electric distribution lines are located in, on or under public highways or private lands pursuant to lease, easement, permit, municipal consent, tariff conditions, agreement or license, expressed or implied through use by Unitil Energy without objection by the owners. In the case of certain distribution lines, Unitil Energy owns only a part interest in the poles upon which its wires are installed, the remaining interest being owned by telecommunication companies.

The physical utility properties of Unitil Energy, with certain exceptions, and its franchises are subject to its indenture of mortgage and deed of trust under which the respective series of first mortgage bonds of Unitil Energy are outstanding.

Fitchburg’s electric substations, with minor exceptions, are located in north central Massachusetts on land owned by Fitchburg or occupied by Fitchburg pursuant to perpetual easements. Fitchburg’s electric distribution lines and gas mains are located in, on, or under public highways or private lands pursuant to lease, easement, permit, municipal consent, tariff conditions, agreement or license, express or implied through use by Fitchburg without objection by the owners. Fitchburg owns full interest in the poles upon which its wires are installed.

The Company’s natural gas operations property includes two liquefied propane gas plants and two liquid natural gas plants. Northern Utilities also owns a propane air gas plant and an LNG storage and vaporization facility. Fitchburg owns a propane air gas plant and an LNG storage and vaporization facility, both of which are located on land owned by Fitchburg in north central Massachusetts.

Northern Utilities’ gas mains are primarily made up of polyethylene plastic (83.8%), coated and wrapped cathodically protected steel (15.2%), cast/wrought iron (0.9%), and unprotected bare and coated steel (0.1%). FG&E’s gas mains are primarily made up of polyethylene plastic (45.0%), coated steel (43.3%), cast iron (10.4%), bare steel (1.1%), and wrought and ductile iron (0.2%).

Granite State’s underground natural gas transmission pipeline, regulated by the FERC, is located primarily in Maine and New Hampshire.

The Company believes that its facilities are currently adequate for their intended uses.

Item 3. 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.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

The Company’s common stock is listed on the New York Stock Exchange under the symbol “UTL.” As of December 31, 2023, there were 1,143 shareholders of record of our common stock.

Common Stock Data

Dividends per Common Share	2023		2022
1st Quarter	$	0.405	$	0.39
2nd Quarter		0.405		0.39
3rd Quarter		0.405		0.39
4th Quarter		0.405		0.39
Total for Year	$	1.62	$	1.56

See “Dividends” in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations).

Information regarding securities authorized for issuance under our equity compensation plans, as of December 31, 2023, is set forth in the following table.

Equity Compensation Plan Information

	(a)		(b)		(c)
Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders(1)		—		—		91,893
Equity compensation plans not approved by security holders		—		—		—
Total		—		—		91,893

NOTES: (also see Note 5 (Equity) to the accompanying Consolidated Financial Statements)

(1)Consists of the Second Amended and Restated 2003 Stock Plan (the Plan). On April 19, 2012, shareholders approved the Plan, and a total of 677,500 shares of our common stock were reserved for issuance pursuant to awards of restricted stock, restricted stock units and common stock under the Plan. A total of 541,285 shares of restricted stock have been awarded and 58,272 restricted stock units have been settled and issued as shares of common stock by Plan participants through December 31, 2023. As of December 31, 2023, a total of 13,950 shares of restricted stock were forfeited and once again became available for issuance under the Plan.

Stock Performance Graph

The following graph compares Unitil Corporation’s cumulative stockholder return since December 31, 2018 with the Peer Group index, comprised of the S&P 500 Utilities Index, and the S&P 500 index. The graph assumes that the value of the

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investment in the Company’s common stock and each index (including reinvestment of dividends) was $100 on December 31, 2018.

 

NOTE:

(1)The graph above assumes $100 invested on December 31, 2018, in each category and the reinvestment of all dividends during the five-year period. The Peer Group is comprised of the S&P 500 Utilities Index.

Unregistered Sales of Equity Securities and Uses of Proceeds

There were no sales of unregistered equity securities by the Company for the fiscal period ended December 31, 2023.

Issuer Purchases of Equity Securities

Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted and announced by the Company on June 1, 2023, the Company will periodically repurchase shares of its Common Stock on the open market related to the stock portion of the Directors’ annual retainer for those Directors who elected to receive common stock. There is no pool or maximum number of shares related to these purchases; however, the trading plan will terminate when $614,000 in value of shares have been purchased or, if sooner, on May 31, 2024.

The Company may suspend or terminate this trading plan at any time, so long as the suspension or termination is made in good faith and not as part of a plan or scheme to evade the prohibitions of Rule 10b-5 under the Exchange Act, or other applicable securities laws.

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The following table provides information regarding repurchases by the Company of shares of its common stock pursuant to the trading plan for each month in the quarter ended December 31, 2023.

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
10/1/23 – 10/31/23		14,680	$	41.788		14,680	$	547
11/1/23 – 11/30/23		—		—		—	$	547
12/1/23 – 12/31/23		—		—		—	$	547
Total		14,680	$	41.788		14,680

Item 6. Reserved

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) (Note references are to the Notes to the Consolidated Financial Statements included in Item 8.)

OVERVIEW

Unitil is a public utility holding company headquartered in Hampton, New Hampshire. Unitil is subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005.

Unitil’s principal business is the local distribution of electricity and natural gas to approximately 196,900 customers throughout its service territory in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of three wholly-owned distribution utilities:

i)Unitil Energy, which provides electric service in the southeastern seacoast and state capital regions of New Hampshire;

ii)Fitchburg, which provides both electric and natural gas service in the greater Fitchburg area of north central Massachusetts; and

iii)Northern Utilities, which provides natural gas service in southeastern New Hampshire and portions of southern and central Maine, including the city of Portland and the Lewiston-Auburn area.

Unitil Energy, Fitchburg and Northern Utilities are collectively referred to as the “distribution utilities.” Together, the distribution utilities serve approximately 108,500 electric customers and 88,400 natural gas customers in their service territories. The distribution utilities are local “wires and pipes” operating companies.

In addition, Unitil is the parent company of Granite State, a natural gas transmission pipeline, regulated by the FERC, 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 North American pipeline supplies.

Unitil had an investment in Net Utility Plant of $1,420.9 million at December 31, 2023. Unitil’s total revenue was $557.1 million in 2023, which includes revenue to recover the approved cost of purchased electricity and natural gas in rates on a fully reconciling basis. As a result of this reconciling rate structure, the Company’s earnings are not affected by changes in the cost of purchased electricity and natural gas. Earnings from Unitil’s utility operations are derived from the return on investment in the three distribution utilities and Granite State.

The Company’s other subsidiaries include Unitil Service, which provides, at cost, a variety of administrative and professional services to Unitil’s affiliated companies, Unitil Resources, the Company’s non-regulated subsidiary, which currently does not have any activity, and Unitil Realty, which owns and manages Unitil’s corporate office building and property located in Hampton, New Hampshire. Unitil’s consolidated net income includes the earnings of the holding company and these subsidiaries.

Regulation

Unitil is subject to comprehensive regulation by federal and state regulatory authorities. Unitil and its subsidiaries are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005 with regard to certain bookkeeping, accounting and reporting requirements. Unitil’s utility operations related to wholesale and interstate energy business activities are also regulated by the FERC. Unitil’s distribution utilities are subject to regulation by the applicable state public utility commissions, with regard to their rates, issuance of securities and other accounting and operational matters: Unitil Energy is subject to regulation by the NHPUC; Fitchburg is subject to regulation by the MDPU; and Northern Utilities is regulated by the NHPUC and MPUC. Granite State, Unitil’s interstate natural gas transmission pipeline, is subject to regulation by the FERC with regard to its rates and operations. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations, financial position, and cash flows.

Unitil’s distribution utilities deliver electricity and/or natural gas to all customers in their service territories, at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil’s distribution utilities are provided the opportunity to recover the cost of providing distribution service to their customers based on a historical test year, and earn a return on their capital investment in utility assets. In addition, the Company’s distribution utilities and its natural gas

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transmission pipeline company also may recover certain base rate costs, including capital project spending and enhanced reliability and vegetation management programs, through annual step adjustments and cost tracker rate mechanisms.

Most of Unitil’s customers have the opportunity to purchase their electricity or natural gas supplies from third-party energy suppliers. Many of Unitil’s distribution utilities’ largest C&I customers purchase their electricity or gas supply from third-party suppliers, while most small C&I customers, as well as residential customers, purchase their electricity or gas supply from the distribution utilities under regulated rates and tariffs. Unitil’s distribution utilities purchase electricity or natural gas from unaffiliated wholesale energy suppliers and recover the actual approved costs of these supplies on a pass-through basis, through reconciling rate mechanisms that are periodically adjusted.

Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or gas sales. The difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recognized as an increase or a decrease in Accrued Revenue, which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases and other authorized adjustments that the Company files with the MDPU and NHPUC. Fitchburg has been subject to revenue decoupling since 2011. Unitil Energy 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%

Also see Regulatory Matters in this section and Note 7 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information on rates and regulation.

RESULTS OF OPERATIONS

The following discussion of the Company’s financial condition and results of operations should be read in conjunction with the accompanying Consolidated Financial Statements and the accompanying Notes to Consolidated Financial Statements included in Part II, Item 8 of this report.

The Company’s results of operations are expected to reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the colder weather seasons of the year as a result of higher sales of natural gas used for heating-related purposes. Accordingly, the results of operations are historically most favorable in the first and fourth quarters. Fluctuations in seasonal weather conditions may have a significant effect on the result of operations. Sales of electricity are generally less sensitive to weather than natural gas sales, but may also be affected by weather conditions and the temperature in the winter and summer seasons.

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

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$5.9 million. The proceeds were used to make equity capital contributions to the Company’s regulated utility subsidiaries, to repay debt and for other general corporate purposes. Overall, the results of operations and earnings for the years ended December 31, 2023, December 31, 2022 and December 31, 2021 reflect the higher number of average shares outstanding.

The Company analyzes operating results using Electric and Gas Adjusted Gross Margins, which are non-GAAP financial measures. Electric Adjusted Gross Margin is calculated as Total Electric Operating Revenue less Cost of Electric Sales. Gas Adjusted Gross Margin is calculated as Total Gas Operating Revenues less Cost of Gas Sales. The Company’s management believes Electric and Gas Adjusted Gross Margins provide useful information to investors regarding profitability. Also, the Company’s management believes Electric and Gas Adjusted Gross Margins are important financial measures to analyze revenue from the Company’s ongoing operations because the approved cost of electric and gas sales are tracked, reconciled and passed through directly to customers in electric and gas tariff rates, resulting in an equal and offsetting amount reflected in Total Electric and Gas Operating Revenue.

In the following tables the Company has reconciled Electric and Gas Adjusted Gross Margin to GAAP Gross Margin, which we believe to be the most comparable GAAP financial measure. GAAP Gross Margin is calculated as Revenue less Cost of Sales, and Depreciation and Amortization. The Company calculates Electric and Gas Adjusted Gross Margin as Revenue less Cost of Sales. The Company believes excluding Depreciation and Amortization, which are period costs and not related to volumetric sales, is a meaningful financial measure to inform investors of the Company’s profitability from electric and gas sales in the period.

Twelve Months Ended December 31, 2023 ($ millions)
	Electric			Gas			Other			Total
Total Operating Revenue	$	306.5		$	250.6		$	—		$	557.1
Less: Cost of Sales		(202.4	)		(96.1	)		—			(298.5	)
Less: Depreciation and Amortization		(26.0	)		(40.4	)		(1.0	)		(67.4	)
GAAP Gross Margin		78.1			114.1			(1.0	)		191.2
Depreciation and Amortization		26.0			40.4			1.0			67.4
Adjusted Gross Margin	$	104.1		$	154.5		$	—		$	258.6

Twelve Months Ended December 31, 2022 ($ millions)
	Electric			Gas			Other			Total
Total Operating Revenue	$	297.9		$	265.3		$	—		$	563.2
Less: Cost of Sales		(199.1	)		(121.4	)		—			(320.5	)
Less: Depreciation and Amortization		(25.4	)		(36.3	)		(0.9	)		(62.6	)
GAAP Gross Margin		73.4			107.6			(0.9	)		180.1
Depreciation and Amortization		25.4			36.3			0.9			62.6
Adjusted Gross Margin	$	98.8		$	143.9		$	—		$	242.7

Twelve Months Ended December 31, 2021 ($ millions)
	Electric			Gas			Other			Total
Total Operating Revenue	$	248.5		$	224.8		$	—		$	473.3
Less: Cost of Sales		(151.1	)		(91.7	)		—			(242.8	)
Less: Depreciation and Amortization		(25.9	)		(32.6	)		(1.0	)		(59.5	)
GAAP Gross Margin		71.5			100.5			(1.0	)		171.0
Depreciation and Amortization		25.9			32.6			1.0			59.5
Adjusted Gross Margin	$	97.4		$	133.1		$	—		$	230.5

Electric GAAP Gross Margin was $78.1 million in 2023, an increase of $4.7 million compared to 2022. The increase was driven by higher rates and customer growth of $5.3 million, partially offset by higher depreciation and amortization expense of $0.6 million.

Electric GAAP Gross Margin was $73.4 million in 2022, an increase of $1.9 million compared to 2021. The increase was driven by higher rates and customer growth of $1.7 million and lower depreciation and amortization expense of $0.5 million, partially offset by the unfavorable effect on sales from cooler spring weather of $0.3 million when rates were not yet decoupled.

Gas GAAP Gross Margin was $114.1 million in 2023, an increase of $6.5 million compared to 2022. The increase was driven by higher rates and customer growth of $14.1 million, partially offset by the unfavorable effects of warmer winter

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weather in 2023 of $1.1 million, higher depreciation and amortization of $4.1 million, and the recognition, in the second quarter of 2022, of $2.4 million in higher rates resulting from the Company’s base rate case in New Hampshire.

Gas GAAP Gross Margin was $107.6 million in 2022, an increase of $7.1 million compared to 2021. The increase was driven by higher rates of $9.0 million and $1.8 million from customer growth and the favorable effect of colder winter weather in 2022, partially offset by higher depreciation and amortization of $3.7 million.

Net Income and EPS Overview

2023 Compared to 2022—The Company’s Net Income was $45.2 million, or $2.82 in Earnings Per Share (EPS), for the year ended December 31, 2023, an increase of $3.8 million in Net Income, or $0.23 in EPS, compared to 2022. The Company’s earnings in 2023 reflect higher Electric and Gas Adjusted Gross Margins (a non-GAAP financial measure), partially offset by higher operating expenses.

Electric Adjusted Gross Margin (a non-GAAP financial measure) was $104.1 million in 2023, an increase of $5.3 million compared with 2022. The increase was driven by higher rates from base rate cases and capital tracker mechanisms.

Gas Adjusted Gross Margin (a non-GAAP financial measure) was $154.5 million in 2023, an increase of $10.6 million compared to 2022. The increase was driven by higher rates and customer growth of $14.1 million, partially offset by the unfavorable effects of warmer winter weather in 2023 of $1.1 million and the recognition, in the second quarter of 2022, of $2.4 million in higher rates resulting from the Company’s base rate case in New Hampshire.

Operation and Maintenance (O&M) expenses increased $1.9 million, or 2.6%, in 2023 compared to 2022, reflecting higher utility operating costs of $1.2 million, higher professional fees of $0.4 million and higher labor costs of $0.3 million.

Depreciation and Amortization expense increased $4.8 million in 2023 compared to 2022, reflecting additional depreciation associated with higher levels of utility plant in service and higher amortization of rate case and other deferred costs.

Taxes Other Than Income Taxes increased $2.6 million in 2023 compared to 2022, reflecting higher local property taxes on higher utility plant in service and higher payroll, excise and other taxes.

Interest Expense, Net increased $3.2 million in 2023 compared to 2022 primarily reflecting higher interest on short-term borrowings, partially offset by higher interest income on regulatory assets and other.

Other Expense (Income), Net decreased $2.4 million in 2023 compared to 2022, reflecting lower retirement benefit costs.

Federal and State Income Taxes increased $2.0 million in 2023 compared to 2022, reflecting higher pre-tax earnings in 2023 and higher flow back, in 2022, of excess Accumulated Deferred Income Taxes per regulatory orders in New Hampshire.

In 2023, Unitil’s annual common dividend was $1.62 per share, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock. 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.

2022 Compared to 2021—The Company’s Net Income was $41.4 million, or $2.59 in Earnings Per Share (EPS), for the year ended December 31, 2022, an increase of $5.3 million in Net Income, or $0.24 in EPS, compared to 2021. The Company’s earnings in 2022 reflect higher Electric and Gas Adjusted Gross Margins (a non-GAAP financial measure), partially offset by higher operating expenses.

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Electric Revenues, Adjusted Gross Margin and Sales

Electric Operating Revenues and Electric Adjusted Gross Margin—The following table details Total Electric Operating Revenue and Electric Adjusted Gross Margin for the last three years by major customer class:

							Change
Electric Operating Revenues and Electric Adjusted Gross Margin							2023 vs. 2022						2022 vs. 2021
(millions)	2023		2022		2021		$			%			$		%
Electric Operating Revenue:
Residential	$	184.5	$	174.8	$	140.8	$	9.7			5.5	%	$	34.0		24.1	%
Commercial & Industrial		122.0		123.1		107.7		(1.1	)		(0.9	)%		15.4		14.3	%
Total Electric Operating Revenue	$	306.5	$	297.9	$	248.5	$	8.6			2.9	%	$	49.4		19.9	%
Cost of Electric Sales	$	202.4	$	199.1	$	151.1	$	3.3			1.7	%	$	48.0		31.8	%
Electric Adjusted Gross Margin	$	104.1	$	98.8	$	97.4	$	5.3			5.4	%	$	1.4		1.4	%

Electric Adjusted Gross Margin (a non-GAAP financial measure) was $104.1 million in 2023, an increase of $5.3 million compared with 2022. The increase was driven by higher rates and customer growth.

The increase in Total Electric Operating Revenue of $8.6 million, or 2.9%, in 2023 compared to 2022 reflects higher costs of electric sales, which are tracked and reconciled costs as a pass-through to customers, and higher electric distribution rates.

Electric Adjusted Gross Margin (a non-GAAP financial measure) was $98.8 million in 2022, an increase of $1.4 million compared with 2021. The increase was driven by higher rates and customer growth of $1.7 million, partially offset by the unfavorable effect on sales from cooler spring weather of $0.3 million when rates were not yet decoupled.

The increase in Total Electric Operating Revenue of $49.4 million, or 19.9%, in 2022 compared to 2021 primarily reflects higher cost of electric sales, which are tracked and reconciled costs as a pass-through to customers.

Kilowatt-hour Sales—Unitil’s total electric kWh sales decreased 3.2% in 2023 compared to 2022. Sales to Residential customers decreased 4.6% and sales to C&I customers decreased 2.1% in 2023 compared to 2022. The decreases in electric kWh sales reflect lower average usage, partially offset by customer growth. As of December 31, 2023, the number of electric customers served increased by approximately 350 over the previous year. Sales margins derived from decoupled unit sales are not sensitive to changes in electric kWh sales, although those sales margins are sensitive to changes in the number of customers served. As of June 1, 2022, substantially all of the Company's electric kWh sales volumes are decoupled.

Unitil’s total electric kWh sales decreased 1.0% in 2022 compared to 2021. Sales to Residential customers decreased 2.0% and sales to C&I customers decreased 0.3% in 2022 compared to 2021. The decreases in electric kWh sales reflect lower average usage, partially offset by customer growth. As of December 31, 2022, the number of electric customers served increased by approximately 400 over the previous year. Sales margins derived from decoupled unit sales are not sensitive to changes in electric kWh sales, although those sales margins are sensitive to changes in the number of customers served.

The following table details total kWh sales for the last three years by major customer class:

							Change
							2023 vs. 2022						2022 vs. 2021
kWh Sales (millions)	2023		2022		2021		kWh			%			kWh			%
Residential		649.3		680.5		694.2		(31.2	)		(4.6	)%		(13.7	)		(2.0	)%
Commercial & Industrial		914.2		933.9		936.8		(19.7	)		(2.1	)%		(2.9	)		(0.3	)%
Total kWh Sales		1,563.5		1,614.4		1,631.0		(50.9	)		(3.2	)%		(16.6	)		(1.0	)%

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Gas Revenues, Adjusted Gross Margin and Sales

Gas Operating Revenues and Adjusted Gross Margin—The following table details total Gas Operating Revenue and Gas Adjusted Gross Margin for the last three years by major customer class:

							Change
Gas Operating Revenues and Gas Adjusted Gross Margin							2023 vs. 2022						2022 vs. 2021
(millions)	2023		2022		2021		$			%			$		%
Gas Operating Revenue:
Residential	$	100.7	$	103.4	$	90.6	$	(2.7	)		(2.6	)%	$	12.8		14.1	%
Commercial & Industrial		149.9		161.9		134.2		(12.0	)		(7.4	)%		27.7		20.6	%
Total Gas Operating Revenue	$	250.6	$	265.3	$	224.8	$	(14.7	)		(5.5	)%	$	40.5		18.0	%
Cost of Gas Sales	$	96.1	$	121.4	$	91.7	$	(25.3	)		(20.8	)%	$	29.7		32.4	%
Gas Adjusted Gross Margin	$	154.5	$	143.9	$	133.1	$	10.6			7.4	%	$	10.8		8.1	%

Gas Adjusted Gross Margin (a non-GAAP financial measure) was $154.5 million in 2023, an increase of $10.6 million compared to 2022. The increase reflects higher rates and customer growth of $14.1 million, partially offset by the unfavorable effects of warmer winter weather in 2023 of $1.1 million and the recognition, in the second quarter of 2022, of $2.4 million in higher rates resulting from the Company’s base rate case in New Hampshire.

The decrease in Total Gas Operating Revenues of $14.7 million, or 5.50%, in 2023 compared to 2022 reflects lower costs of gas sales, which are tracked and reconciled as a pass-through to customers, partially offset by higher gas distribution rates.

Gas Adjusted Gross Margin (a non-GAAP financial measure) was $143.9 million in 2022, an increase of $10.8 million compared to 2021. The increase was driven by higher rates of $9.0 million, and $1.8 million from customer growth and the favorable effect of colder winter weather in 2022.

The increase in Total Gas Operating Revenues of $40.5 million, or 18.0%, in 2022 compared to 2021 reflects higher cost of gas sales, which are tracked and reconciled costs as a pass-through to customers, and higher gas sales volumes.

Therm Sales—Unitil’s total gas therm sales decreased 1.5% in 2023 compared to 2022. Sales to Residential customers decreased 3.8% and sales to C&I customers decreased 0.9% in 2023 compared to 2022. The decreases in gas therm sales reflect warmer winter weather in 2023 compared to 2022, partially offset by customer growth. Based on weather data collected in the Company’s gas service areas, on average there were 6.5% fewer EDD in 2023 compared to 2022. The Company estimates that weather-normalized gas therm sales for Northern Utilities’ Maine division, the Company’s only non-decoupled gas service area, increased 3.0% in 2023 compared to 2022. As of December 31, 2023, the number of gas customers served increased by approximately 950 over the previous year. Sales margins derived from decoupled unit sales (currently representing approximately 42% of total annual therm sales volume) are not sensitive to changes in gas therm sales, although those sales margins are sensitive to changes in the number of customers served.

Unitil’s total gas therm sales increased 1.3% in 2022 compared to 2021. Sales to Residential customers increased 0.5% and sales to C&I customers increased 1.5% in 2022 compared to 2021. The overall increase in gas therm sales reflects customer growth and colder winter weather in 2022. As of December 31, 2022, the number of gas customers served increased by approximately 850 over the previous year. Based on weather data collected in the Company’s gas service areas, on average there were 2.6% more EDD in 2022 compared to 2021, although 5.1% fewer EDD compared to normal. The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were essentially unchanged in 2022 compared to 2021. Sales margins derived from decoupled unit sales (currently representing approximately 42% of total annual therm sales volume) are not sensitive to changes in gas therm sales, although those sales margins are sensitive to changes in the number of customers served.

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The following table details total therm sales for the last three years, by major customer class:

							Change
							2023 vs. 2022						2022 vs. 2021
Therm Sales (millions)	2023		2022		2021		Therms			%			Therms		%
Residential		42.9		44.6		44.4		(1.7	)		(3.8	)%		0.2		0.5	%
Commercial & Industrial		178.6		180.2		177.5		(1.6	)		(0.9	)%		2.7		1.5	%
Total Therm Sales		221.5		224.8		221.9		(3.3	)		(1.5	)%		2.9		1.3	%

Operating Expenses

Cost of Electric Sales—Cost of Electric Sales includes the cost of electric supply as well as other energy supply related restructuring costs, including power supply buyout costs, and spending on energy efficiency programs. Cost of Electric Sales increased $3.3 million, or 1.7%, in 2023 compared to 2022. This increase reflects higher wholesale electricity prices, partially offset by lower electric sales and an increase in the amount of electricity purchased by customers directly from third-party suppliers. The Company reconciles and recovers the approved Cost of Electric Sales in its rates at cost on a pass through basis and therefore changes in approved expenses do not affect earnings.

In 2022, Cost of Electric Sales increased $48.0 million, or 31.8%, compared to 2021. This increase reflects higher wholesale electricity prices, partially offset by lower electric sales and an increase in the amount of electricity purchased by customers directly from third-party suppliers.

Cost of Gas Sales—Cost of Gas Sales includes the cost of natural gas purchased to supply the Company’s total gas supply requirements and spending on energy efficiency programs. Cost of Gas Sales decreased $25.3 million, or 20.8%, in 2023 compared to 2022. This decrease reflects lower gas sales, lower wholesale gas commodity prices, partially offset by a decrease in the amount of gas purchased by customers directly from third-party suppliers. The Company reconciles and recovers the approved Cost of Gas Sales in its rates at cost on a pass through basis and therefore changes in approved expenses do not affect earnings.

In 2022, Cost of Gas increased $29.7 million, or 32.4%, compared to 2021. This increase reflects higher gas sales and higher wholesale gas commodity prices, partially offset by an increase in the amount of gas purchased by customers directly from third-party suppliers.

Operation and Maintenance—O&M expense includes electric and gas utility operating costs, and the operating costs of the Company’s other subsidiaries. Total O&M expenses increased $1.9 million, or 2.6%, in 2023 compared to 2022, reflecting higher utility operating costs of $1.2 million, higher professional fees of $0.4 million and higher labor costs of $0.3 million.

In 2022, total O&M expenses increased $5.0 million, or 7.3%, compared to 2021, reflecting higher labor costs of $1.9 million, higher utility operating costs of $1.6 million, and higher professional fees of $1.5 million.

Depreciation and Amortization—Depreciation and Amortization expense increased $4.8 million, or 7.7%, in 2023 compared to 2022, reflecting additional depreciation associated with higher levels of utility plant in service and higher amortization of rate case and other deferred costs.

In 2022, Depreciation and Amortization expense increased $3.1 million, or 5.2%, compared to 2021, reflecting additional depreciation associated with higher levels of utility plant in service and higher amortization of rate case costs.

Taxes Other Than Income Taxes—Taxes Other Than Income Taxes increased $2.6 million, or 10.0%, in 2023 compared to 2022, reflecting higher local property taxes on higher utility plant in service and higher payroll, excise and other taxes.

In 2022, Taxes Other Than Income Taxes increased $1.4 million, or 5.7%, compared to 2021, reflecting higher payroll taxes and higher local property taxes on higher utility plant in service.

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Interest Expense, Net

Interest expense is presented in the Consolidated Financial Statements net of interest income. Interest expense is mainly comprised of interest on long-term debt and short-term borrowings (See Note 4 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements). Certain reconciling rate mechanisms used by the Company’s distribution utilities give rise to regulatory assets and regulatory liabilities on which interest is calculated.

Interest Expense, Net increased $3.2 million, or 12.6%, in 2023 compared to 2022 primarily reflecting higher interest on short-term borrowings, partially offset by higher interest income on regulatory assets and other.

Interest Expense, Net decreased $0.1 million, or 0.4%, in 2022 compared to 2021 primarily reflecting lower interest on long-term debt and higher interest income, on regulatory assets, partially offset by higher interest on short-term borrowings.

Other (Income) Expense, Net

Other Expense (Income), Net decreased $2.4 million in 2023 compared to 2022, reflecting lower retirement benefit costs.

Other Expense (Income), Net decreased $2.2 million, or 47.8% in 2022 compared to 2021, reflecting lower retirement benefit costs.

Provision for Income Taxes

Federal and State Income Taxes increased $2.0 million in 2023 compared to 2022, reflecting higher pre-tax earnings in 2023 and higher flow back, in 2022, of excess Accumulated Deferred Income Taxes per regulatory orders in New Hampshire.

Federal and State Income Taxes decreased $0.3 million in 2022 compared to 2021, reflecting lower taxes associated with the flowback of excess Accumulated Deferred Income Taxes.

LIQUIDITY, COMMITMENTS AND CAPITAL REQUIREMENTS

Sources of Capital

Unitil requires capital to fund utility plant additions, working capital and other utility expenditures recovered in subsequent periods through regulated rates. The capital necessary to meet these requirements is derived primarily from internally generated funds, which consist of cash flows from operating activities. The Company initially supplements internally generated funds through short-term bank borrowings, as needed, under its unsecured revolving Credit Facility. Periodically, the Company replaces portions of its short-term debt with long-term financings more closely matched to the long-term nature of its utility assets. Additionally, from time to time the Company has accessed the public capital markets through public offerings of equity securities. The Company’s utility operations are seasonal in nature and are therefore subject to seasonal fluctuations in cash flows. The amount, type and timing of any future financing will vary from year to year based on capital needs and maturity or redemptions of securities.

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 and was 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 over-allotment option to purchase additional shares. The underwriters exercised the over-allotment 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 over-allotment sales was approximately $5.9 million and was used to make equity capital contributions to the Company’s regulated utility subsidiaries, to repay debt and for other general corporate purposes.

The Company and its subsidiaries are individually and collectively members of the Unitil Cash Pool (Cash Pool). The Cash Pool is the financing vehicle for day-to-day cash borrowing and investing. The Cash Pool allows for an efficient exchange

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of cash among the Company and its subsidiaries. The interest rates charged to the subsidiaries for borrowing from the Cash Pool are based on actual interest costs from lenders under the Company’s revolving Credit Facility. At December 31, 2023 and December 31, 2022, the Company and all of its subsidiaries were in compliance with the regulatory requirements governing participation in the Cash Pool.

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. (See also “Credit Arrangements” in Note 4 Debt and Financing Arrangements.)

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.

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.

The continued availability of various methods of financing, as well as the choice of a specific form of security for such financing, will depend on many factors, including, but not limited to: security market conditions; general economic climate; regulatory approvals; the ability to meet covenant issuance restrictions; the level of earnings, cash flows and financial position; and the competitive pricing offered by financing sources. The Company believes it has sufficient sources of working capital to fund its operations.

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Contractual Obligations

The Company and its subsidiaries have material obligations for payment of principal and interest on its long-term debt as well as for operating and capital leases that are discussed in Note 4 (Debt and Financing Arrangements).

The Company and its subsidiaries have material energy supply commitments that are discussed in Note 6 (Energy Supply) and Note 7 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements. 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 one year.

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.

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.

Benefit Plan Funding

The Company, along with its subsidiaries, made cash contributions to its Pension Plan in the amounts of $3.9 million and $3.8 million in 2023 and 2022, respectively. The Company, along with its subsidiaries, contributed $2.8 million and $12.2 million to Voluntary Employee Benefit Trusts (VEBTs) in 2023 and 2022, respectively. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan and the VEBTs in 2024 and future years at least at minimum required amounts. See Note 9 (Retirement Benefit Plans) to the accompanying Consolidated Financial Statements.

Off-Balance Sheet Arrangements

The Company and its subsidiaries do not currently use, and are not dependent on the use of, off-balance sheet financing arrangements such as securitization of receivables or obtaining access to assets or cash through special purpose entities or variable interest entities. As of December 31, 2023 there were no guarantees outstanding. See Note 4 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

Cash Flows

Unitil’s utility operations, taken as a whole, are seasonal in nature and subject to seasonal fluctuations in cash flows. The tables below summarize the major sources and uses of cash (in millions) for 2023 and 2022.

	2023		2022
Cash Provided by Operating Activities	$	107.0	$	97.7

Cash Provided by Operating Activities - Cash Provided by Operating Activities was $107.0 million in 2023, an increase of $9.3 million compared to 2022.

Cash flow from Net Income, adjusted for the total of non-cash charges was $120.0 million in 2023 compared to $115.0 million in 2022, an increase of $5.0 million. The change to Net Income is primarily attributable to increases in electric and gas sales margin. The increase in depreciation and amortization of $4.8 million in 2023 compared to 2022 reflects higher

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depreciation on higher utility plant in service. The decrease in the deferred tax provision of $3.6 million in 2023 compared to 2022 is primarily driven by the use of net operating loss carryforwards in 2023.

Changes in working capital items resulted in a ($4.6) million use of cash in 2023 compared to a ($6.0) million use of cash in 2022, representing an increase in sources of cash of $1.4 million. The change in working capital in 2023 compared to 2022 is primarily related to the net change in accrued revenue, accounts payable and exchange gas receivable and is reflective of the effect of the current macroeconomic environment including lower commodity costs on business and operating conditions.

Deferred Regulatory and Other Charges decreased by $2.0 million in 2023 compared to 2022, primarily driven by changes in Regulatory Assets and Liabilities, and the change in Other, net in 2023 compared to 2022 was $4.9 million.

	2023			2022
Cash Used in Investing Activities	$	(141.0	)	$	(122.1	)

Cash Used in Investing Activities - Cash Used in Investing Activities was ($141.0) million in 2023 compared to ($122.1) million in 2022, an increase of $18.9 million. The higher spending in 2023 is primarily related to normal utility capital expenditures for electric and gas utility system additions. The Company’s projected capital spending range for 2024 is $165 million to $170 million.

	2023		2022
Cash Provided by Financing Activities	$	31.5	$	26.9

Cash Provided by Financing Activities - Cash Provided by Financing Activities was $31.5 million in 2023 compared to cash provided of $26.9 million in 2022. The higher cash provided from financing activities in 2023 compared to 2022 of $4.6 million is primarily attributable to, proceeds from the issuance of long-term debt of $25.0 million, lower repayment of long-term debt of $3.5 million, a decrease in exchange gas financing of $17.2 million, and lower proceeds from short-term borrowings of 5.9 million. Other changes in financing activities in 2023 total a use of 0.8 million.

FINANCIAL COVENANTS AND RESTRICTIONS

The agreements under which the Company and its subsidiaries issue long-term debt 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, business combinations and covenants restricting the ability to (i) pay dividends, (ii) incur indebtedness and liens, (iii) merge or consolidate with another entity or (iv) sell, lease or otherwise dispose of all or substantially all assets. See Note 4 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

Unitil’s 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 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 and its subsidiaries are currently in compliance with all such covenants in these debt instruments.

DIVIDENDS

Unitil’s annual common dividend was $1.62 per common share in 2023, $1.56 per common share in 2022, and $1.52 per share in 2021. Unitil’s dividend policy is reviewed periodically by the Board of Directors. Unitil has maintained an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock. 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

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increase of $0.02 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $1.70 from $1.62. The amount and timing of all dividend payments are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. In addition, the ability of the Company’s subsidiaries to pay dividends or make distributions to Unitil, and, therefore, Unitil’s ability to pay dividends, depends on, among other things:

•the actual and projected earnings and cash flow, capital requirements and general financial condition of the Company’s subsidiaries;

•the prior rights of holders of existing and future preferred stock, mortgage bonds, long-term notes and other debt issued by the Company’s subsidiaries;

•the restrictions on the payment of dividends contained in the existing loan agreements of the Company’s subsidiaries and that may be contained in future debt agreements of the Company’s subsidiaries, if any; and

•limitations that may be imposed by New Hampshire, Massachusetts and Maine state regulatory agencies.

In addition, before the Company can pay dividends on its common stock, it must satisfy its debt obligations and comply with any statutory or contractual limitations. See Financial Covenants and Restrictions in this report, as well as Note 4 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

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. Refer to “Legal Proceedings” in Note 7 (Commitments and Contingencies) of the Consolidated Financial Statements for a discussion of legal proceedings.

REGULATORY MATTERS

See Note 7 (Commitments and Contingencies) to the Consolidated Financial Statements.

CRITICAL ACCOUNTING POLICIES

The preparation of the Company’s Consolidated Financial Statements in conformity with generally accepted accounting principles in the United States of America requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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. In making those estimates and assumptions, the Company is sometimes required to make subjective and/or complex judgments about the effect of matters that are inherently uncertain and for which different estimates that could reasonably have been used could have resulted in material differences in its financial statements. If actual results were to differ significantly from those estimates, assumptions and judgment, the financial position of the Company could be materially affected and the results of operations of the Company could be materially different than reported. The following is a summary of the Company’s most critical accounting policies, which are defined as those policies where judgments or uncertainties could materially affect the application of those policies. For a complete discussion of the Company’s significant accounting policies, refer to the financial statements and Note 1 (Summary of Significant Accounting Policies).

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 NHPUC, and Northern Utilities is regulated by the 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 Financial Accounting Standards Board Accounting Standards Codification (FASB Codification). In accordance with 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.

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The FASB Codification specifies the economic effects that result from the cause and effect relationship of costs and revenues in the rate-regulated environment and the related accounting for a regulated enterprise. Revenues intended to cover certain costs may be recorded either before or after the costs are incurred. If regulation provides assurance that incurred costs will be recovered in the future, these costs would be recorded as deferred charges or “regulatory assets.” If revenues are recorded for costs that are expected to be incurred in the future, these revenues would be recorded as deferred credits or “regulatory liabilities.”

The Company’s principal regulatory assets and liabilities are included on the Company’s Consolidated Balance Sheet and a summary of the Company’s Regulatory Assets is provided in Note 1 (Summary of Significant Accounting Policies) to the consolidated financial statements. Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. 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.

Retirement Benefit Obligations—The Company sponsors the Unitil Corporation Retirement Plan (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 two non-qualified retirement plans, the Unitil Corporation Supplemental Executive Retirement Plan (SERP), and the Unitil Corporation Deferred Compensation Plan, covering certain executives of the Company, and an employee 401(k) savings plan. Additionally, the Company sponsors the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan), primarily to provide health care and life insurance benefits to retired employees.

The FASB Codification requires companies to record on their balance sheets as an asset or liability the overfunded or underfunded status of their retirement benefit obligations (RBO) based on the projected benefit obligation. The Company has recognized a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas rates. The Company’s RBO and reported costs of providing retirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. The Company has made critical estimates related to actuarial assumptions, including assumptions of expected returns on plan assets, future compensation, health care cost trends, and appropriate discount rates. The Company’s RBO is affected by actual employee demographics, the level of contributions made to the plans, earnings on plan assets, and health care cost trends. Changes made to the provisions of these plans may also affect current and future costs. If these assumptions were changed, the resulting change in benefit obligations, fair values of plan assets, funded status and net periodic benefit costs could have a material effect on the Company’s financial statements. 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 the year ended December 31, 2023, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $113,000 in the Net Periodic Benefit Cost for the Pension Plan. Similarly, a change of 0.50% in the expected long-term rate of return on plan assets would have resulted in an increase or decrease of approximately $713,000 in the Net Periodic Benefit Cost for the Pension Plan. (See Note 9 (Retirement Benefit Plans) to the accompanying Consolidated Financial Statements.)

Refer to “Recently Issued Pronouncements” in Note 1 of the Notes of Consolidated Financial Statements for information regarding recently issued accounting standards.

For additional information regarding the foregoing matters, see Note 1 (Summary of Significant Accounting Policies), Note 6 (Energy Supply), and Note 9 (Retirement Benefit Plans) to the Consolidated Financial Statements.

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Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Please also refer to Part I, Item 1A. “Risk Factors”.

INTEREST RATE RISK

Unitil meets its external financing needs, in part, by issuing short-term and long-term debt. The majority of debt outstanding represents long-term notes bearing fixed rates of interest. Changes in market interest rates do not affect interest expense resulting from these outstanding long-term debt securities. However, the Company periodically repays its short-term debt borrowings through the issuance of new long-term debt securities. Changes in market interest rates may affect the interest rate and corresponding interest expense on any new issuances of long-term debt securities. In addition, short-term debt borrowings bear a variable rate of interest. As a result, changes in short-term interest rates will increase or decrease interest expense in future periods. For example, if the average amount of short-term debt outstanding was $25 million for the period of one year, a change in interest rates of 1% would result in a change in annual interest expense of approximately $250,000. The average interest rate on short-term borrowings and intercompany money pool transactions was 6.4%, 3.3%, and 1.2% during 2023, 2022, and 2021, respectively.

COMMODITY PRICE RISK

Although Unitil’s three distribution utilities are subject to commodity price risk as part of their traditional operations, the current regulatory framework within which these companies operate allows for full collection of electric power and natural gas supply costs in rates on a pass-through basis. Consequently, there is limited commodity price risk after consideration of the related rate-making. Additionally, as discussed in the section entitled Rates and Regulation in Part I, Item 1 (Business) and in Note 7 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements, the Company has divested its long-term power supply contracts and therefore, further reduced its exposure to commodity risk.

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Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

To the shareholders and the Board of Directors of Unitil Corporation:

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Unitil Corporation and subsidiaries (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of earnings, changes in common stock equity, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

Basis for Opinions

The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit

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preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Impact of Rate-Regulation on Various Account Balances and Disclosures — Refer to Notes 1 and 7 to the financial statements

Critical Audit Matter Description

The Company’s principal business is the distribution of electricity and natural gas and is subject to regulation by the Massachusetts, New Hampshire and Maine Public Service Commissions as well as the Federal Energy Regulatory Commission (collectively, the “Commissions”). Accordingly, the Company accounts for their regulated operations in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 980, Regulated Operations, and has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable Commission. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, 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. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

Accounting for the economics of rate regulation affects multiple financial statement line items, including property, plant, and equipment; regulatory assets and liabilities; operating revenues; and depreciation expense, and affects multiple disclosures in the Company’s financial statements. While the Company has indicated that it expects to recover costs and a return on its investments, there is a risk that the Commissions’ will not approve full recovery of the costs of providing utility service or recovery of all amounts invested in the utility business and a reasonable return on that investment. As a result, we identified the impact of rate regulation as a critical audit matter due to the high degree of subjectivity involved in assessing the impact of current and future regulatory orders on events that have occurred as of December 31, 2023, and the judgments made by management to support its assertions about impacted account balances and disclosures. Management judgments included assessing the likelihood of (1) recovery in future rates of incurred costs or (2) refunds to customers or future reduction in rates. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the commissions, auditing these judgments require specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions focused on the base rate proceedings for Northern Maine and Fitchburg Gas and Electric and included the following, among others:

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

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•We made inquiries of management and read relevant regulatory orders and settlements issued by the Commissions in Massachusetts, New Hampshire and Maine, regulatory statutes, interpretations, procedural memorandums, filings made by interveners or the Company, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated this external information and compared to management’s recorded regulatory asset and liability balances and searched for any evidence that might contradict management’s assertions.

•We obtained an analysis from management describing the orders and filings that support management’s assertions regarding the probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

/s/ Deloitte & Touche LLP

Boston, MA
February 13, 2024

We have served as the Company's auditor since 2014.

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CONSOLIDATED STATEMENTS OF EARNINGS

(Millions, except per share data)

Year Ended December 31,	2023		2022		2021
Operating Revenues:
Electric	$	306.5	$	297.9	$	248.5
Gas		250.6		265.3		224.8
Total Operating Revenues		557.1		563.2		473.3
Operating Expenses:
Cost of Electric Sales		202.4		199.1		151.1
Cost of Gas Sales		96.1		121.4		91.7
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		—		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 and Diluted	$	2.82	$	2.59	$	2.35
Weighted Average Common Shares Outstanding - (Basic)		16.0		16.0		15.4
Weighted Average Common Shares Outstanding - (Diluted)		16.1		16.0		15.4

(The accompanying Notes are an integral part of these consolidated financial statements.)

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CONSOLIDATED BALANCE SHEETS (Millions)

ASSETS

December 31,	2023		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

(The accompanying Notes are an integral part of these consolidated financial statements.)

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CONSOLIDATED BALANCE SHEETS (cont.) (Millions, except number of shares)

LIABILITIES AND CAPITALIZATION

December 31,	2023		2022
Current Liabilities:
Accounts Payable	$	47.7	$	68.6
Short-Term Debt		162.0		116.0
Long-Term Debt, Current Portion		4.9		6.7
Regulatory Liabilities		13.5		15.0
Energy Supply Obligations		15.0		24.1
Environmental Obligations		0.6		0.6
Operating Lease Obligations		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		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		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

(The accompanying Notes are an integral part of these consolidated financial statements.)

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions)

Year Ended December 31,	2023			2022			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 Short-Term Debt, net		46.0			51.9			9.4
Issuance of Long-Term Debt		25.0			—			—
Repayment of Long-Term Debt		(6.9	)		(10.4	)		(25.8	)
Long-Term Debt Issuance Costs		(0.2	)		—			—
Increase (Decrease) in Capital Lease Obligations		0.3			(0.1	)		(0.1	)
Net (Decrease) Increase 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 Financing Activities		31.5			26.9			7.7
Net (Decrease) Increase 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	$	—		$	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

(The accompanying Notes are an integral part of these consolidated financial statements.)

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CONSOLIDATED STATEMENTS OF

CHANGES IN COMMON STOCK EQUITY (Millions, except shares data)

	Common Equity		Retained Earnings			Total
Balance at January 1, 2021	$	285.3	$	103.7		$	389.0
Net Income for 2021				36.1			36.1
Dividends ($1.52 per Common Share)				(23.6	)		(23.6	)
Shares Issued Under Stock Plans		1.3					1.3
Issuance of 942,316 Common Shares (See Note 5)		45.5					45.5
Balance at December 31, 2021		332.1		116.2			448.3
Net Income for 2022				41.4			41.4
Dividends ($1.56 per Common Share)				(25.1	)		(25.1	)
Shares Issued Under Stock Plans		1.8					1.8
Issuance of 18,853 Common Shares (See Note 5)		1.0					1.0
Balance at December 31, 2022		334.9		132.5			467.4
Net Income for 2023				45.2			45.2
Dividends ($1.62 per Common Share)				(26.2	)		(26.2	)
Shares Issued Under Stock Plans		1.6					1.6
Issuance of 21,321 Common Shares (See Note 5)		1.1					1.1
Balance at December 31, 2023	$	337.6	$	151.5		$	489.1

(The accompanying Notes are an integral part of these consolidated financial statements.)

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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.

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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.

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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%

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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

46

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.

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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.

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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.

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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

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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.

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.

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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

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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.

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.

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.

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.

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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.

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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

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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

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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.

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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.

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.

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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.

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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.

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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

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

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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.

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

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.

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

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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

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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.

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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,

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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.

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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

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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.

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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.

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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.

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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

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	%

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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

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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.

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.

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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.

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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.

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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.

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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.

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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.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

Management of the Company, under the supervision and with the participation of the Company’s Chief Executive Officer, Chief Financial Officer, and Chief Accounting Officer, conducted an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as of December 31, 2023. Based on this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer, and Chief Accounting Officer concluded as of December 31, 2023 that the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective.

Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f).

Under the supervision and with the participation of management, including the Chief Executive Officer, Chief Financial Officer, and Chief Accounting Officer, Unitil management has evaluated the effectiveness of the Company’s internal control over financial reporting as of December 31, 2023, based upon criteria established in the “Internal Control–Integrated Framework” (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, Unitil management concluded that Unitil’s internal control over financial reporting was effective as of December 31, 2023.

Deloitte & Touche LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2023, as stated in their report which appears in Part II, Item 8 herein.

Changes in Internal Control over Financial Reporting

There have been no changes in Unitil’s internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the fiscal quarter ended December 31, 2023 that have materially affected, or are reasonably likely to materially affect, Unitil’s internal control over financial reporting.

Item 9B. Other Information

(a) On February 13, 2024, the Company issued a press release announcing its results of operations for the year ended December 31, 2023. The press release is furnished with this Annual Report on Form 10-K as Exhibit 99.1.

(b) During the quarter ended December 31, 2023, no director or officer (as defined in Rule 16a-1(f) promulgated under the Securities Exchange Act of 1934) adopted or terminated a Rule10b5-1 trading arrangement (as defined in Item 408(a)(1)(i) of Regulation S-K promulgated under the Securities Exchange Act of 1934) or any non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K promulgated under the Securities Exchange Act of 1934).

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.

Not applicable.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information required by this Item is set forth in the “Proposal 1: Election of Directors” section and the “Description of Management” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held May 1, 2024. Information regarding compliance with Section 16(a) of the Securities Exchange Act of 1934, is set forth in the “Corporate Governance and Policies of the Board—Section 16(a) Beneficial Ownership Reporting Compliance” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held May 1, 2024. Information regarding the Company’s Audit Committee is set forth in the “Committees of the Board—Audit Committee” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held May 1, 2024. Information regarding the Company’s Code of Ethics is set forth in the “Corporate Governance and Policies of the Board—Code of Ethics” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held May 1, 2024. Information regarding procedures by which shareholders may recommend nominees to the Company’s Board of Directors is set forth in the “Corporate Governance and Policies of the Board—Nominations” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held May 1, 2024.

Item 11. Executive Compensation

Information required by this Item is set forth in the “Compensation Discussion and Analysis” and “Compensation of Named Executive Officers” sections of the Proxy Statement relating to the Annual Meeting of Shareholders to be held May 1, 2024.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information required by this Item is set forth in the “Beneficial Ownership” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held May 1, 2024, as well as the Equity Compensation Plan Information table in Part II, Item 5 of this Form 10-K.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information required by this Item is set forth in the “Corporate Governance and Policies of the Board—Transactions with Related Persons” and the “Corporate Governance and Policies of the Board—Director Independence” sections of the Proxy Statement relating to the Annual Meeting of Shareholders to be held May 1, 2024.

Item 14. Principal Accountant Fees and Services

Information required by this Item is set forth in the “Audit Committee Report—Principal Accountant Fees and Services” and the “Audit Committee Report—Audit Committee Pre-Approval Policy” sections of the Proxy Statement relating to the Annual Meeting of Shareholders to be held May 1, 2024.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) (1) and (2)—LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

The following financial statements are included herein under Part II, Item 8, Financial Statements and Supplementary Data:

•Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP; PCAOB ID No. 34)

•Consolidated Statements of Earnings for the years ended December 31, 2023, 2022 and 2021

•Consolidated Balance Sheets—December 31, 2023 and 2022

•Consolidated Statements of Cash Flows for the years ended December 31, 2023, 2022 and 2021

•Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2023, 2022 and 2021

•Notes to Consolidated Financial Statements

All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions, are not applicable, or information required is included in the financial statements or notes thereto and, therefore, have been omitted.

(3)—LIST OF EXHIBITS

Exhibit Number	Description of Exhibit	Reference (1)
3.1 (P)	Articles of Incorporation of Unitil Corporation.	Exhibit 3.1 to Form S-14 Registration Statement No. 2-93769 dated October 12, 1984
3.2 (P)	Articles of Amendment to the Articles of Incorporation of Unitil Corporation filed on March 4, 1992.	Exhibit 3.2 to Form 10-K for 1991 (SEC File No. 1-8858)
3.3	Articles of Amendment to the Articles of Incorporation of Unitil Corporation filed on September 23, 2008.	Exhibit 3.3 to Form S-3/A Registration Statement No. 333-152823 dated November 25, 2008
3.4	Articles of Amendment to the Articles of Incorporation of Unitil Corporation filed on April 27, 2011.	Exhibit 4.4 to Post-Effective Amendment No. 1 to Form S-3 Registration Statement No. 333-168394, dated January 28, 2014
3.5	Fourth Amended and Restated By-Laws of Unitil Corporation.	Exhibit 3.1 to Form 8-K dated April 29, 2020 (SEC File No. 1-8858)
4.1	Twelfth Supplemental Indenture of Unitil Energy Systems, Inc., successor to Concord Electric Company, dated as of December 2, 2002, amending and restating the Concord Electric Company Indenture of Mortgage and Deed of Trust dated as of July 15, 1958.	Exhibit 4.1 to Form 10-K for 2002 (SEC File No. 1-8858)
4.2	Fitchburg Note Agreement dated January 15, 1999 for the 7.37% Notes due January 15, 2029.	Exhibit 4.25 to Form 10-K for 1999 (SEC File No. 1-8858)

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Exhibit Number	Description of Exhibit	Reference (1)
4.3	Fitchburg Note Agreement dated June 1, 2001 for the 7.98% Notes due June 1, 2031.	Exhibit 4.6 to Form 10-Q for June 30, 2001 (SEC File No. 1-8858)
4.4	Fitchburg Note Agreement dated October 15, 2003 for the 6.79% Notes due October 15, 2025.	Exhibit 4.7 to Form 10-K for 2003 (SEC File No. 1-8858)
4.5	Fitchburg Note Agreement dated December 21, 2005 for the 5.90% Notes due December 15, 2030.	(2)
4.6	Thirteenth Supplemental Indenture of Unitil Energy Systems, Inc., dated as of September 26, 2006.	(2)
4.7	Northern Utilities Note Purchase Agreement, dated as of December 3, 2008, for the 6.95% Senior Notes, Series A due December 3, 2018 and the 7.72% Senior Notes, Series B due December 3, 2038.	Exhibit 4.1 to Form 8-K dated December 3, 2008 (SEC File No. 1-8858)
4.8	Fourteenth Supplemental Indenture of Unitil Energy Systems, Inc., dated as of March 2, 2010.	Exhibit 4.4 to Form 8-K dated March 2, 2010 (SEC File No. 1-8858)
4.9	Northern Utilities form of Note Purchase Agreement, dated as of October 15, 2014, for the 4.42% Senior Notes, due October 15, 2044.	Exhibit 4.1 to Form 8-K dated October 15, 2014 (SEC File No. 1-8858)
4.10	Northern Utilities form of Note issued pursuant to the Note Purchase Agreement, dated as of October 15, 2014, for the 4.42% Senior Notes, due October 15, 2044.	Exhibit 4.2 to Form 8-K dated October 15, 2014 (SEC File No. 1-8858)
4.11	Note Purchase Agreement dated August 1, 2016 by and among Unitil Corporation and the several purchasers named therein for the 3.70% Senior Notes, Series 2016, due August 1, 2026.	Exhibit 4.1 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
4.12	3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by Metropolitan Life Insurance Company in the principal amount of $11,200,000.	Exhibit 4.2 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
4.13	3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by Lincoln Benefit Life Company in the principal amount of $4,000,000.	Exhibit 4.3 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
4.14	3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by Lincoln Benefit Life Company in the principal amount of $3,800,000.	Exhibit 4.4 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
4.15	3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by Lincoln Benefit Life Company in the principal amount of $1,000,000.	Exhibit 4.5 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
4.16	3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by United of Omaha Life Insurance Company in the principal amount of $5,000,000.	Exhibit 4.6 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)

83

Exhibit Number	Description of Exhibit	Reference (1)
4.17	3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by United of Omaha Life Insurance Company in the principal amount of $3,000,000.	Exhibit 4.7 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
4.18	3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by Companion Life Insurance Company in the principal amount of $2,000,000.	Exhibit 4.8 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
4.19	Note Purchase Agreement dated July 14, 2017 by and among Northern Utilities, Inc. and the several purchasers named therein for the 3.52% Senior Notes, Series 2017A, due November 1, 2027 and the 4.32% Senior Notes, Series 2017B, due November 1, 2047.	Exhibit 4.1 to Form 8-K dated July 14, 2017 (SEC File No. 1-8858)
4.20	Note Purchase Agreement dated July 14, 2017 by and among Fitchburg Gas and Electric Light Company and the several purchasers named therein for the 3.52% Senior Notes, Series 2017A, due November 1, 2027 and the 4.32% Senior Notes, Series 2017B, due November 1, 2047.	Exhibit 4.2 to Form 8-K dated July 14, 2017 (SEC File No. 1-8858)
4.21	Note Purchase Agreement dated July 14, 2017 by and among Granite State Gas Transmission, Inc. and the several purchasers named therein for the 3.72% Senior Notes, Series 2017A, due November 1, 2027.	Exhibit 4.3 to Form 8-K dated July 14, 2017 (SEC File No. 1-8858)
4.22 (4)	3.52% Senior Note, Series 2017A, due November 1, 2027, issued by Northern Utilities, Inc. to Great-West Life & Annuity Insurance Company.	Exhibit 4.2 to Form 8-K dated November 1, 2017 (SEC File No. 1-8858)
4.23 (4)	4.32% Senior Note, Series 2017B, due November 1, 2047, issued by Northern Utilities, Inc. to The Canada Life Insurance Company of Canada.	Exhibit 4.3 to Form 8-K dated November 1, 2017 (SEC File No. 1-8858)
4.24 (4)	3.52% Senior Note, Series 2017A, due November 1, 2027, issued by Fitchburg Gas and Electric Light Company to Great-West Life & Annuity Insurance Company.	Exhibit 4.5 to Form 8-K dated November 1, 2017 (SEC File No. 1-8858)
4.25 (4)	4.32% Senior Note, Series 2017B, due November 1, 2047, issued by Fitchburg Gas and Electric Light Company to The Great-West Life Assurance Company.	Exhibit 4.6 to Form 8-K dated November 1, 2017 (SEC File No. 1-8858)
4.26 (4)	3.72% Senior Note, Series 2017A, due November 1, 2027, issued by Granite State Gas Transmission, Inc. to Thrivent Financial for Lutherans.	Exhibit 4.8 to Form 8-K dated November 1, 2017 (SEC File No. 1-8858)
4.27	Bond Purchase Agreement dated November 30, 2018 by and among Unitil Energy Systems, Inc. and the several purchasers named therein for the $30,000,000 aggregate principal amount of first mortgage bonds, Series Q, due November 30, 2048.	Exhibit 4.1 to Form 8-K dated November 30, 2018 (SEC File No. 1-8858)
4.28	Fifteenth Supplemental Indenture dated November 29, 2018 by and between Unitil Energy Systems, Inc. and U.S. Bank National Association (as trustee).	Exhibit 4.2 to Form 8-K dated November 30, 2018 (SEC File No. 1-8858)
4.29 (4)	First Mortgage Bond, Series Q, 4.18%, due November 30, 2048, issued by Unitil Energy Systems, Inc. to United of Omaha Life Insurance Company.	Exhibit 4.3 to Form 8-K dated November 30, 2018 (SEC File No. 1-8858)

84

Exhibit Number	Description of Exhibit	Reference (1)
4.30	Note Purchase Agreement dated September 12, 2019 by and among Northern Utilities, Inc. and the several purchasers named therein.	Exhibit 4.1 to Form 8-K dated September 12, 2019 (SEC File No. 1-8858)
4.31 (4)	4.04% Senior Note, Series 2019, due September 12, 2049, issued by Northern Utilities, Inc. to Pacific Life Insurance Company.	Exhibit 4.2 to Form 8-K dated September 12, 2019 (SEC File No. 1-8858)
4.32	Note Purchase Agreement dated December 18, 2019 by and among Unitil Corporation and the several purchasers named therein.	Exhibit 4.1 to Form 8-K dated December 18, 2019 (SEC File No. 1-8858)
4.33 (4)	3.43% Senior Note, Series 2019, due December 18, 2029, issued by Unitil Corporation to CHIMEFISH & CO, as nominee for American Equity Investment Life Insurance Company.	Exhibit 4.2 to Form 8-K dated December 18, 2019 (SEC File No. 1-8858)
4.34	Note Purchase Agreement dated September 15, 2020 by and among Northern Utilities, Inc. and the several purchasers named therein.	Exhibit 4.1 to Form 8-K dated September 15, 2020 (SEC File No. 1-8858)
4.35 (4)	3.78% Senior Note, Series 2020, due September 15, 2040, issued by Northern Utilities, Inc. to Metropolitan Life Insurance Company.	Exhibit 4.2 to Form 8-K dated September 15, 2020 (SEC File No. 1-8858)
4.36	Note Purchase Agreement dated September 15, 2020 by and among Fitchburg Gas and Electric Light Company and the several purchasers named therein.	Exhibit 4.3 to Form 8-K dated September 15, 2020 (SEC File No. 1-8858)
4.37 (4)	3.78% Senior Note, Series 2020A, due September 15, 2040, issued by Fitchburg Gas and Electric Light Company to Brighthouse Life Insurance Company of NY.	Exhibit 4.4 to Form 8-K dated September 15, 2020 (SEC File No. 1-8858)
4.38	Bond Purchase Agreement dated September 15, 2020 by and among Unitil Energy Systems, Inc., U.S. Bank National Association (as trustee), and the several purchasers named therein.	Exhibit 4.5 to Form 8-K dated September 15, 2020 (SEC File No. 1-8858)
4.39	Sixteenth Supplemental Indenture dated September 15, 2020 by and between Unitil Energy Systems, Inc. and U.S. Bank National Association (as trustee).	Exhibit 4.6 to Form 8-K dated September 15, 2020 (SEC File No. 1-8858)
4.40 (4)	First Mortgage Bond, Series R, 3.58%, due September 15, 2040, issued by Unitil Energy Systems, Inc. to CUDD and CO (as nominee for Symetra Life Insurance Company).	Exhibit 4.7 to Form 8-K dated September 15, 2020 (SEC File No. 1-8858)
4.41 (5)	Note Purchase Agreement dated July 6, 2023 by and among Fitchburg Gas and Electric Light Company and the several purchasers named therein.	Exhibit 4.1 to Form 8-K dated July 6, 2023 (SEC File No. 1-8858)
4.42 (4)	5.70% Senior Note, Series 2023A, due July 2, 2033, issued by Fitchburg Gas and Electric Light Company to MetLife Reinsurance Company of Hamilton, Ltd.	Exhibit 4.2 to Form 8-K dated July 6, 2023 (SEC File No. 1-8858)
4.43 (4)	5.96% Senior Note, Series 2023B, due July 2, 2053, issued by Fitchburg Gas and Electric Light Company to Mutual of Omaha Insurance Company	Exhibit 4.3 to Form 8-K dated July 6, 2023 (SEC File No. 1-8858)

85

Exhibit Number	Description of Exhibit	Reference (1)
4.44	Amended and Restated Note issued to Bank of America, N.A.	Exhibit 4.2 to Form 8-K dated July 25, 2018 (SEC File No. 1-8858)
4.45	Loan Agreement dated December 18, 2020 between Unitil Realty Corp. and TD Bank, N.A.	Exhibit 4.48 to Form 10-K for 2020 (SEC File No. 1-8858)
4.46	Mortgage and Security Agreement dated December 18, 2020 between Unitil Realty Corp. and TD Bank, N.A.	Exhibit 4.49 to Form 10-K for 2020 (SEC File No. 1-8858)
4.47	Mortgage Loan Note dated December 18, 2020 issued to TD Bank, N.A.	Exhibit 4.50 to Form 10-K for 2020 (SEC File No. 1-8858)
4.48	Description of Registrant’s Securities	Exhibit 4.50 to Form 10-K for 2021 (SEC File No. 1-8858)
4.49 (5)	Third Amended and Restated Credit Agreement dated September 29, 2022 among Unitil Corporation, Bank of America, N.A., as administrative agent, and the Lenders	Exhibit 4.1 to Form 8-K dated September 29, 2022 (SEC File No. 1-8858)
4.50	Second Amended and Restated Note issued to Citizens Bank, N.A.	Exhibit 4.2 to Form 8-K dated September 29, 2022 (SEC File No. 1-8858)
4.51	Second Amended and Restated Note issued to TD Bank, N.A.	Exhibit 4.3 to Form 8-K dated September 29, 2022 (SEC File No. 1-8858)
10.1 (3)	Amended and Restated Form of Severance Agreement between the Company and the persons listed at the end of such Agreement.	Exhibit 10.2 to Form 8-K dated June 19, 2008 (SEC File No. 1-8858)
10.2 (3)	Amended and Restated Form of Severance Agreement between the Company and the persons listed at the end of such Agreement.	Exhibit 10.3 to Form 8-K dated June 19, 2008 (SEC File No. 1-8858)
10.3 (3)	Amended and Restated Form of Severance Agreement (Three-Year Term).	Exhibit 10.1 to Form 8-K dated July 25, 2018 (SEC File No. 1-8858)
10.4 (3)	Amended and Restated Form of Severance Agreement (Two-Year Term).	Exhibit 10.2 to Form 8-K dated July 25, 2018 (SEC File No. 1-8858)
10.5 (3)	Amended and Restated Form of Severance Agreement (Two-Year Term; Non Pension).	Exhibit 10.3 to Form 8-K dated July 25, 2018 (SEC File No. 1-8858)
10.6 (3)	Severance Agreement dated March 23, 2020, between the Company and Daniel J. Hurstak.	Exhibit 10.1 to Form 8-K dated March 19, 2020 (SEC File No. 1-8858)
10.7 (3)	Severance Agreement dated July 29, 2020, between the Company and Robert B. Hevert.	Exhibit 10.1 to Form 8-K dated July 29, 2020 (SEC File No. 1-8858)

86

Exhibit Number	Description of Exhibit	Reference (1)
10.8 (3)	Amended and Restated Unitil Corporation Supplemental Executive Retirement Plan effective as of December 31, 2016.	Exhibit 10.1 to Form 10-Q for March 31, 2017 (SEC File No. 1-8858)
10.9 (3)	Amended and Restated Supplemental Executive Retirement Plan.	Exhibit 10.5 to Form 8-K dated July 25, 2018 (SEC File No. 1-8858)
10.10 (3)	Unitil Corporation Deferred Compensation Plan.	Exhibit 10.6 to Form 8-K dated July 25, 2018 (SEC File No. 1-8858)
10.11 (3)	Unitil Corporation Management Incentive Plan (amended and restated as of June 5, 2013).	Exhibit 10.2 to Form 8-K dated June 5, 2013 (SEC File No. 1-8858)
10.12 (3)	Unitil Corporation Second Amended and Restated 2003 Stock Plan.	Appendix 1 to the Proxy Statement filed on Schedule 14A dated March 13, 2012 (SEC File No. 1-8858)
10.13 (3)	Form of Restricted Stock Unit Agreement under the Unitil Corporation Second Amended and Restated 2003 Stock Plan.	Exhibit 4.7 to Form S-8 Registration Statement No. 333-184849 dated November 9, 2012
10.14 (3)	Form of Restricted Stock Agreement under the Unitil Corporation Second Amended and Restated 2003 Stock Plan.	Exhibit 4.8 to Form S-8 Registration Statement No. 333-184849 dated November 9, 2012
10.15 (3)	Unitil Corporation Tax Deferred Savings and Investment Plan, as amended and restated effective as of January 1, 2021.	Exhibit 10.15 to Form 10-K for 2021 (SEC File No. 1-8858)
10.16 (3)	Unitil Corporation Tax Deferred Savings and Investment Plan Trust Agreement.	Exhibit 4.2 to Form S-8 Registration Statement No. 333-234391 dated October 31, 2019
10.17 (3)	Unitil Corporation Incentive Plan (amended and restated as of January 26, 2015).	Exhibit 10.1 to Form 10-Q for March 31, 2015 (SEC File No. 1-8858)
10.18 (3)	Employment Agreement effective April 25, 2021 between Unitil Corporation and Thomas P. Meissner, Jr.	Exhibit 10.1 to Form 8-K dated April 28, 2021 (SEC File No. 1-8858)
10.19 (3)	Unitil Corporation—Compensation of Directors effective as of January 1, 2022.	Exhibit 10.21 to Form 10-K for 2021 (SEC File No. 1-8858)
10.20 (3)	Unitil Corporation - Compensation of Directors effective as of January 1, 2024	Filed herewith

87

Exhibit Number	Description of Exhibit	Reference (1)
10.21	Underwriting Agreement dated August 4, 2021 among Unitil Corporation, on the one hand, and RBC Capital Markets, LLC and BofA Securities, Inc., on the other hand, for themselves and as representatives of the several underwriters named therein.	Exhibit 1.1 to Form 8-K dated August 3, 2021 (File No. 1-8858)
10.22 (3)	Form of Restricted Stock Agreement (Time Vesting)	Exhibit 10.1 to Form 8-K dated January 24, 2023 (SEC File No. 1-8858)
10.23 (3)	Form of Restricted Stock Agreement (Performance Vesting)	Exhibit 10.2 to Form 8-K dated January 24, 2023 (SEC File No. 1-8858)
19.1	Unitil Corporation Corporate Governance Guidelines and Policies of the Board of Directors (includes the Registrant’s insider trading policies and procedures)	Filed herewith
21.1	Statement Re: Subsidiaries of Registrant.	Filed herewith
23.1	Consent of Independent Registered Public Accounting Firm.	Filed herewith
31.1	Certification of Chief Executive Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	Filed herewith
31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	Filed herewith
31.3	Certification of Chief Accounting Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	Filed herewith
32.1	Certifications of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	Filed herewith
97.1	Executive Compensation Recovery Policy	Filed herewith
99.1	Unitil Corporation Press Release Dated February 13, 2024 Announcing Earnings For the Year Ended December 31, 2023.	Furnished herewith
	3
101.INS	Inline XBRL Instance Document – The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.	Filed herewith
101.SCH	Inline XBRL Taxonomy Extension Schema With Embedded Linkbase Documents.	Filed herewith
104	Cover Page Interactive Data File – The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.	Filed herewith

(1) The exhibits referred to in this column by specific designations and dates have heretofore been filed with or furnished to the Securities and Exchange Commission under such designations and are hereby incorporated by reference.

88

(2) In accordance with Item 601(b)(4)(iii)(A) of Regulation S-K, the instrument defining the debt of the Registrant and its subsidiary, described above, has been omitted but will be furnished to the Commission upon request.

(3) These exhibits represent a management contract or compensatory plan.

(4) This Note or Bond (each, an “Instrument”) is substantially identical in all material respects to other Instruments that are otherwise required to be filed as exhibits, except as to the registered payee of such Instrument, the identifying number of such Instrument, and the principal amount of such Instrument. In accordance with instruction no. 2 to Item 601 of Regulation S-K, the registrant has filed a copy of only one of such Instruments, with a schedule identifying the other Instruments omitted and setting forth the material details in which such Instruments differ from the Instrument that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any Instruments so omitted.

(5) In accordance with Item 601(a)(5) of Regulation S-K, this exhibit omits certain of its schedules and exhibits. This exhibit’s table of contents includes a brief description of the subject matter of all of its schedules and exhibits, including the omitted schedules and exhibits. The Registrant acknowledges that it must provide a copy of any omitted schedules or exhibits to the Securities and Exchange Commission or its staff upon request.

(P) Paper exhibit.

(P)

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	UNITIL CORPORATION
Date February 13, 2024	By	/S/ THOMAS P. MEISSNER, JR.
		Thomas P. Meissner, Jr.
		Chairman of the Board of Directors and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Capacity	Date
/s/ THOMAS P. MEISSNER, JR.	Principal Executive Officer; Director	February 13, 2024
Thomas P. Meissner, Jr.
/S/ DANIEL J. HURSTAK Daniel J. Hurstak	Principal Financial Officer	February 13, 2024
/S/ TODD R. DIGGINS Todd R. Diggins	Principal Accounting Officer	February 13, 2024
/S/ MICHAEL B. GREEN Michael B. Green	Director	February 13, 2024
/S/ EDWARD F. GODFREY Edward F. Godfrey	Director	February 13, 2024
/S/ WINFIELD S. BROWN Winfield S. Brown	Director	February 13, 2024
/S/ NEVEEN F. AWAD Neveen F. Awad	Director	February 13, 2024
/S/ DAVID A. WHITELEY David A. Whiteley	Director	February 13, 2024
/S/ SUZANNE FOSTER Suzanne Foster	Director	February 13, 2024
/S/ JUSTINE VOGEL Justine Vogel	Director	February 13, 2024
/S/ MARK H. COLLIN Mark H. Collin	Director	February 13, 2024
/s/ ANNE L. ALONZO	Director	February 13, 2024
Anne L. Alonzo

90

EX-10.20

Exhibit 10.20

UNITIL CORPORATION

Compensation of Directors

On November 1, 2023, the Board of Directors of Unitil Corporation (“Unitil”) approved and adopted a revised compensation arrangement for members of the Board of Directors. The revised compensation arrangement became effective as of January 1, 2024.

The revised compensation arrangement applies to members of the Board of Directors who are not employees of Unitil or any of its subsidiaries.

The following table summarizes the material terms of the revised compensation arrangement.

Category	Description	Amount
Board of Directors—Annual Cash Retainer	Each member of the Board of Directors will receive an annual cash retainer. Unitil will pay one-fourth of the annual cash retainer on the first business day of each fiscal quarter.	$65,000 per year
Board of Directors—Annual Equity Retainer	Each member of the Board of Directors will receive an annual equity retainer. Unitil will issue the equity retainer on the first business day of October each year. Each member of the Board may elect to receive restricted stock units (with any phantom dividends reinvested in additional restricted stock units), in lieu of Unitil’s common stock, as his or her annual equity retainer.	$95,000 per year (payable in kind as common stock or restricted stock units)
Board of Directors— Lead Director—Annual Cash Retainer Premium	The Lead Director of the Board of Directors will receive an annual cash retainer premium. Unitil will pay one-fourth of the annual cash retainer premium on the first business day of each fiscal quarter.	$25,000 per year
Board of Directors—Special Meetings	Each member of the Board of Directors will receive a fee for each special meeting of	$2,000 per special meeting

	the Board of Directors that such member attends.
Audit, Compensation, Nominating and Governance, and Pension Committees—Annual Cash Retainer for Chair	Each chair of the Audit, Compensation, Nominating and Governance, and Pension committees of the Board of Directors will receive an annual cash retainer. Unitil will pay one-fourth of the annual cash retainer on the first business day of each fiscal quarter.	$16,000 per committee per year
Audit, Compensation, Nominating and Governance, and Pension Committees—Annual Cash Retainer for Non-Chair Members	Each non-chair Board member who serves on the Audit, Compensation, Nominating and Governance, and/or Pension committees of the Board of Directors will receive an annual cash retainer for each committee upon which he or she serves. Unitil will pay one-fourth of the annual cash retainer on the first business day of each fiscal quarter.	$7,000 per committee per year
Executive Committee—Meetings	Each member of the Executive Committee will receive a fee for each meeting of the Executive Committee that such member attends.	$1,500 per meeting

In addition, Unitil will reimburse each member of the Board of Directors for reasonable expenses that such member incurs in connection with attending meetings of the Board of Directors or committees thereof.

EX-19.1

Exhibit 19.1

Unitil Corporation

Corporate Governance Guidelines and

Policies of the Board of Directors

Last Updated on November 1, 2023

Unitil Corporation (“Unitil” or the “Company”) is committed to comprehensive and effective corporate governance practices. The Board of Directors (the “Board”) and the management team firmly believe that solid corporate governance is key to the transparent and ethical operation of the Company and have set a high standard for this important element in the long-term sustainability and growth of the Company.

The ethical character, integrity and principles of the Board, senior management, and employees remain the most important safeguards of good corporate governance. These attributes are inherent to engaged leadership, effective management structure, and a committed, carefully-trained workforce.

The Corporate Governance Guidelines and Policies of the Board (the “Governance Guidelines”) inform the pursuit of superior Board function, management accountability, effective and transparent disclosure, and financial integrity. Together with the Bylaws and the Code of Ethics Policy, the Governance Guidelines provide a meaningful governance framework upon which the Company operates.

New developments and requirements are monitored, as well as emerging issues concerning corporate governance best practices and financial disclosure, and changes and new policies are adopted, as appropriate. The Company’s corporate governance policies and systems are implemented in compliance with SEC regulations, New York Stock Exchange (“NYSE”) listing standards, as well as other applicable requirements and best practices.

Directors’ Responsibilities

The Board shall be responsible for oversight of the management of the property, business and affairs of the Corporation. The Board is vested in such management with all the powers which the Corporation

1

Exhibit 19.1

itself possesses so far as such delegation of power is not incompatible with the provisions of the By-Laws of the Company or the statutes of the State of New Hampshire.

In the pursuit of excellence in corporate governance, members of the Board are expected to:

•fulfill their fiduciary duties to the Company and its shareholders with proper oversight of the development of Company policy and strategy, and assessment of the Company’s operational effectiveness and financial strength;

•apply superior business judgment and leadership, and effectively exercise the duties of loyalty and care for the benefit of all stakeholders (shareholders, customers, employees) of the Company;

•avoid any conflict of interest;

•promote a high standard of personal integrity and adhere to the letter and spirit of Unitil’s Code of Ethics; and

•challenge management to commit to the highest attainable goals, and hold management accountable for its commitments.

Director Independence

•A majority of the members of the Board, as well as all members of the Audit, Compensation, and Nominating and Governance Committees shall, at minimum, meet the independence requirements as defined in Section 303A of the NYSE Listed Company Manual and all other applicable regulations.

•Using this requirement as a framework, the Board has formally adopted an enhanced independence criterion which is applied during the Board’s annual independence review and affirmation. Under these criteria, the members of the Board who qualify as independent shall be free from any relationship that would interfere with the exercise of independent judgment as a member of the Board. An independent Director is one for whom the Board has affirmatively determined that he or she, individually or through a member of his or her immediate family, does not have or has not had management responsibility with the Company or otherwise been affiliated with the Company for the past three years and who has no material relationship with the Company, either directly or indirectly as a partner, shareholder or officer of an organization with such a relationship with the Company. This definition generally allows the Board the discretion to determine, on a case-by-case basis, what constitutes a “material relationship” with the Company. The Board exercises this discretion in a manner that is consistent with applicable New York Stock Exchange regulations and standards.

•For the purpose of standing Board committee assignments, the NYSE three-year separation requirement shall be set aside and a Board member who has had management responsibility with the Company or has been otherwise been affiliated with the Company as described above for less than five years will not be assigned to the Audit, Compensation, or Nominating and Governance committees until the five-year separation threshold has been reached.

2

Exhibit 19.1

Board Structure & Functioning

•Article III of the Company’s By-Laws provide for a Board of between nine and fifteen Directors divided into three classes, each class being as nearly equal in number as possible, and each with their respective terms of office arranged so that the term of office of one class expires in each year, at which time a corresponding number of Directors is elected for a term of three years.

•Directors are not subject to specific term limits. Due to the complexity and highly regulated nature of the utility business, the insight and experience that a director is able to develop over a period of time is valued. A lengthy tenure on the Board provides an increasing contribution to the Board and is therefore in the best interest of shareholders. The Board is, however, subject to de-facto term limits through the mandatory retirement age policy, which is discussed in greater detail under the heading “Retirement Policy” on the following pages of these Guidelines.

•Independent members of the Board may not serve on more than four boards of for-profit companies in addition to the boards of Unitil and its subsidiaries. Non-independent members of the Board may not serve on more than two boards of for-profit companies in addition to the boards of Unitil and its subsidiaries. Service on boards of non-profit organizations, other industry associations, and community or civic groups is not limited.

•The Unitil Board shall also serve as the Board for each of the Company’s subsidiary distribution companies.

•The Board shall have full access to all members of management.

Access to Independent Advisors

•The Board has the authority to independently retain, engage, or obtain the advice of outside legal counsel, special consultants or other experts or advisors (each, an “Advisor”) to advise the Board on various matters as it may deem appropriate or necessary in its sole discretion; direct responsibility for the appointment, terms of retention, and oversight of the work of any Advisor retained by the Board; and sole authority to determine appropriate funding to be provided by the Company for the compensation of an Advisor retained by the Board.

Board Meetings

•The Unitil Board shall meet a minimum of four times annually at regularly scheduled meetings. The Board of Directors shall approve the schedule of regularly scheduled meetings for the following year at the October Board meeting. Additional meetings may be scheduled as needed.

•Serving on the Board involves a significant time commitment. Directors are expected to attend all Board meetings, as well as meetings of the Committees upon which they serve. Directors are expected to manage their commitments in order to devote adequate time and attention to properly discharge their responsibilities. All meetings shall include sufficient time for full and open discussion.

3

Exhibit 19.1

•Materials which are prepared for the Directors’ full understanding of the agenda items to be discussed at the Board meeting shall be provided, to the extent practical, at least five business days in advance of the meeting to allow sufficient time for review and preparation.

•Remote participation in regularly scheduled Board meetings is generally discouraged, unless extraordinary circumstances are present. Remote participation in non-regularly scheduled meetings and emergency meetings is permitted without exception.

Meetings in Executive Session

•The members of the Board have the opportunity, if desired, to meet in executive session, without members of management present in conjunction with each meeting of the Board, or at any other time at the Board’s discretion. The Lead Director shall preside at the meetings in executive session. In addition, at every committee meeting, each committee of the Board has the opportunity to meet in executive session, if desired.

Committees of the Board

•The standing committees of the Board shall include the Audit Committee, Compensation Committee, Executive Committee, and the Nominating and Governance Committee. The Audit, Compensation and Nominating and Governance committees shall each have a minimum of three members. The Audit, Compensation and Nominating and Governance committees shall consist solely of directors who meet the independence requirements currently defined by the Board as described above in the Director Independence section of these Guidelines.

•Each committee shall have a written charter that details the responsibilities of the committee. Each committee shall review its charter on an annual basis and make appropriate revisions, as needed. Each committee shall approve its own charter in principle, and the Board will ratify all charters on an annual basis.

Appointment of Committee Members

•The Nominating and Governance Committee will review, following the annual meeting of shareholders, and at other times as necessary, management’s proposal for committee membership. Committees will be appointed by the Board upon recommendation of the Nominating and Governance Committee at the first meeting following the annual meeting of shareholders, and at other times as necessary. It is policy for each Director to have at least one committee assignment, as appropriate. Additional information concerning the appointment of committee members can be found in the Director Independence and Committees of the Board sections of these Guidelines.

•The Board does not have a specific policy with regard to rotation of committee membership. While rotating committee assignments will be considered periodically, committee rotation is not

4

Exhibit 19.1

mandatory as there are significant benefits attributable to continuity and experience gained for service on a particular committee(s).

Director Candidate Criteria and Selection Process of the Nominating and Governance Committee

•The Nominating and Governance Committee will from time to time recommend to the Board the desired number of Board members. The Company’s By-Laws currently limit the number of Directors to a minimum of nine and a maximum of fifteen.

•The Nominating and Governance Committee will review the number of Directors, if any, expected to retire within the next year, as well as recommend the required selection criteria and desired qualifications of director nominees based upon the needs of the Company at the time, or the anticipated needs of the Company in the near future.

•The Nominating and Governance Committee will also review a skills matrix with regard to professional experience and expertise, specific skill sets, and other defined attributes of current Board members, and identify any gaps or potential gaps based upon the needs of the Company at the time, or the anticipated needs of the Company in the near future. The Committee shall also consider the importance of gender, racial and ethnic diversity of the Board in its review process. The Committee shall ensure there is a robust and diverse initial pool of director candidates, including gender, racially and/or ethnically diverse candidates. Diversity is discussed and defined in greater detail under the heading “Diversity Policy” on the following pages of these Guidelines.

•Minimum criteria for director nominees are that he or she must possess the ability to apply good business judgment and must be in a position to properly exercise his or her duties of loyalty and care. Candidates with potential conflicts of interest will be disqualified, and those who do not meet independence criteria will be identified and evaluated on a case-by-case basis. In addition to independence criteria, the Nominating and Governance Committee will consider criteria including integrity, judgment, proven leadership capabilities, business experience, areas of expertise, availability for service, factors relating to the composition of the Board, such as size and structure, as well as the Board’s philosophy concerning diversity. The Board seeks to include an optimal mix of backgrounds, perspectives, experience and skills, as well as gender, race and ethnicity, among its members. The Nominating and Governance Committee will consider these criteria for nominees identified by the Committee, by other directors, by shareholders, or through some other source.

•The Nominating and Governance Committee will conduct a preliminary assessment of each proposed nominee based upon resume and biographical information, an indication of the individual’s willingness to serve, and other background information. This information is evaluated against the criteria set forth above as well as the specific needs of the Company at the time. Based upon a preliminary assessment of the candidate(s), those who appear best suited to meet the needs of the Company may be invited to participate in a series of interviews, which will be used for further evaluation. On the basis of information learned during this process, the Nominating and Governance Committee will determine the nominee(s) to recommend to the Board for consideration and approval to submit to shareholders for election at the next annual meeting.

5

Exhibit 19.1

•The following procedure is employed for the selection of nominees to be recommended to the Board:

•Determine the skills, experience, and other pertinent attributes (as noted above) desired for a new director(s). Those persons with potential conflicts of interest should be identified and disqualified. Those persons who do not meet independence criteria will be evaluated on a case-by-case basis. The Company’s auditors, attorneys and consultants will be disqualified.

•Establish a timeline for the selection process and designate the Board meeting at which the candidates’ names should be presented.

•Solicit names of proposed candidates from the Nominating and Governance Committee, other Board members, or an outside source. After reviewing the initial pool of candidates, the Nominating and Governance Committee will agree upon the candidate(s) to approach.

•A Nominating and Governance Committee member or members, or a designated representative appointed by the Committee, will approach the prospective candidate(s) and determine his or her availability and/or interest without an expressed or implied commitment from the Company.

•The Chairman of the Board, the Lead Director, and the members of the Nominating and Governance Committee will meet with selected candidate(s) in a series of interviews to determine suitability and cultural fit.

•The Chairman of the Nominating and Governance Committee will issue a formal invitation to the selected candidate(s) for appointment as a member of the Board, subject to Board approval, at an upcoming meeting.

•The candidate(s) should be available for introduction to and election by shareholders at the next annual meeting.

Board Diversity

•The Board’s policy is to ensure the composition of the Board reflects gender, racial and ethnic diversity. To advance the Board’s policy, the Nominating and Governance Committee shall ensure that the initial list of candidates from which Board nominees are chosen includes one or more qualified candidates with diversity of gender, and race and/or ethnicity. Also, the Nominating and Governance Committee shall instruct any external search firm that it retains to include in its initial list of candidates one or more qualified candidates with diversity of gender, race and/or ethnicity.

•All aspects of diversity are considered in the goal to maintain a well-functioning board, for the creation of shareholder value, and ultimately, for the sustainability of Unitil over the long term. The Board seeks to achieve and maintain an optimal diversity mix through a constructive balance of all aspects of diversity among its members. The Board considers many interconnected factors including, but not limited to, diversity of gender, race, ethnicity, age, areas of expertise and competency, and life and professional experience in the evaluation of all candidates for Board membership. The Board also considers how the experience and skill set of any new Director nominee complements those of existing Directors and fellow Director nominees to create a balanced and effective Board with diverse viewpoints and deep expertise.

6

Exhibit 19.1

New Director Orientation

•New directors shall attend an orientation program consisting of a presentation covering the different aspects of the Company with various management personnel. Included, among other things, shall be a review of corporate governance, the strategic plan, sustainability, utility regulation, financial outlook, and enterprise risk management. The orientation shall take place in a private venue with the new director meeting individually with the management participants.

•New directors may request any additional information that they feel is relevant, desirable, or helpful to them as a member of the Board during the orientation program or anytime thereafter.

Directors’ Compensation

•The Directors’ current compensation consists of a combination of cash and stock-based compensation designed to align Directors’ interests with those of the Company’s shareholders, as well as to attract and retain qualified candidates to serve on the Board. Compensation paid to directors at comparable peer group companies within the utility industry is considered and used for benchmarking and evaluation purposes with a target range of the 25th percentile to the median of peer group companies. The cash retainer, equity retainer and total Board service compensation are evaluated and compared to the target range described above. Committee membership and chair positions, as well as the Lead Director retainer premium, are also evaluated and compared to the target range.

•Directors’ compensation is reviewed by the Nominating and Governance Committee annually and all changes are approved by the Board and properly disclosed.

Retirement Policy

•The Board of Directors mandatory retirement age policy stipulates no person is eligible to be nominated as a candidate for director, or for reelection to an additional term as part of the slate of directors proposed by the Company, if he or she has reached the age of 75, or if he or she shall reach the age of 75 at any time during the applicable calendar year of nomination. A director reaching age 75 during his or her current term may complete the service of that term, but must retire upon the expiration of the term during which he or she reaches age 75.

Stock Ownership Policy

•All independent Board members must own shares of Unitil common stock in the equivalent value of three times the current annual cash retainer. Shares of restricted stock and restricted stock units will be counted towards this total. New Directors will have four years from the date of first election by shareholders to obtain the required shares of Unitil common stock.

7

Exhibit 19.1

Resignation Policy

•A Director shall tender his or her resignation if he or she should receive a “withhold” vote of greater than 50% of the shares voted at the annual meeting of shareholders in an uncontested election. If an incumbent Director fails to receive the required vote for re-election, the Nominating and Governance Committee will act on an expedited basis to determine whether to accept the Director’s resignation and will submit such recommendation for prompt consideration by the Board. The Director whose resignation is under consideration shall abstain from participating in any decision regarding his or her resignation. The Nominating and Governance Committee and the Board may consider any factors they deem relevant in deciding whether to accept a Director’s resignation.

•The Board shall nominate for election or re-election as Director only candidates who agree to tender, promptly following the annual meeting at which they are on the meeting ballot for election or re-election, an irrevocable resignation that will be effective upon (i) the failure to receive the required vote at the annual meeting at which they face election or re-election and (ii) Board acceptance of such resignation. In addition, the Board shall fill board seat vacancies and new directorships only with candidates who agree to tender, promptly following their appointment to the Board, the same form of irrevocable resignation tendered by other Directors in accordance with this Board Policy.

•The Board, in its sole discretion, may approve a waiver to this policy in the event of extraordinary circumstance.

Annual Board & Committee Evaluation

•The Board shall conduct an annual evaluation (the “Evaluation”) on key Board and committee-related issues. The Evaluation is designed in question/narrative response format to inspire independent thoughts and elicit opinions regarding various issues facing the industry, the Company, and the Board as a whole. The Evaluation is also intended to facilitate assessment and discussion by the entire Board with regard to its effectiveness as a group in fulfilling its responsibilities and to identify areas for improvement, if applicable.

•The Lead Director will approve the Evaluation format and questions annually, and will communicate the responses in summary form to the full Board. The calculation of responses will be handled confidentially by the Corporate Secretary.

Management Succession Planning

•Due to the critical importance of executive leadership to the success of the Company, the Board shall oversee the succession planning process to ensure that effective plans are in place for succession of the Chief Executive Officer, as well as other senior management and key positions within the Company. The applicable plan shall address contingencies such as the retirement, departure, death, disability, or other untimely departure of the Chief Executive Officer and/or other members of senior management for a smooth transition on both an interim and long-term basis, as applicable.

8

Exhibit 19.1

Executive Stock Ownership Requirement

•All Named Executive Officers of the Company are required to own shares of Unitil common stock in the equivalent value of a multiple of base salary as follows:

Chairman, CEO and President 4X

Chief Financial Officer 3X

All Other Named Executive Officers 2X

•All shares of Unitil common stock that are owned directly or beneficially, shares of restricted stock that are awarded, whether vested or unvested, as well any shares of Unitil common stock held in the Tax Deferred Savings and Investment Plan will be counted towards the required total. Any newly appointed Named Executive Officer will have four years, or another phase-in period as determined by the Board in its sole discretion, from the date of appointment to obtain the required shares of stock. The required equivalent value will be based on the starting base salary of Named Executive Officer on the effective date his or her appointment as a Named Executive Officer.

•The Board, in its sole discretion, may approve a waiver to this policy in the event of financial hardship or other extraordinary circumstance.

Executive Compensation Recovery Policy

•In the event the Company is required to prepare an accounting restatement of its financial statements due to the Company's material non-compliance with any financial reporting requirement under the securities laws, the Company shall be entitled to recover any excess performance-based compensation received by any current or former Covered Executive during the three-year period immediately preceding the date on which the Company is required to prepare an accounting restatement. All actions taken under this policy will comply with Section 10D of the Securities Exchange Act of 1934 and the listing standards of the New York Stock Exchange (the “NYSE”).

•“Performance-based compensation” is defined as all annual incentives and long‑term incentives (whether in cash, in equity, or otherwise) granted, earned, vested or unvested with performance features based wholly or in part on the Company’s or a group’s attainment of a financial reporting measure. Financial reporting measures is defined as measures that are determined and presented in accordance with the accounting principles used in preparing the Company’s financial statements, and any measure(s) that are derived wholly or in part from such measures.

•To the extent required by applicable law and the listing standards of the NYSE, the Company shall recover any erroneously awarded performance-based compensation, provided that the Compensation Committee has determined that recovery would not be impractical.

Stock Holding Requirement

9

Exhibit 19.1

•All members of the Board and all Named Executive Officers of the Company are required to hold all forms of equity received from the Companyuntil retirement or other separation from the Company. For Board members, this shall include all forms of equity received as part of the annual retainer for Board service. For Named Executive Officers, this shall include all forms of equity received as compensation. The Board, in its sole discretion, may approve a waiver to this policy in the event of financial hardship or other extraordinary circumstance.

Prohibition of Hedging and/or Pledging Company Stock

•All members of the Board and executive officers of the Company are prohibited from engaging in short sales or engaging in any hedging transaction with respect to Unitil common stock, as well as engaging in any transactions that result in pledging, or using as collateral, shares of Company stock in order to secure personal loans or other obligations, including any shares that may be a margin account.

Insider Trading Guidelines

•Officers, Directors and 10% shareholders are considered to be public company insiders, and those individuals have certain reporting responsibilities for transactions involving Company stock under Section 16(a) of the Securities Exchange Act of 1934. Company insiders are prohibited from engaging in any transaction involving Unitil common stock during a period of restriction, which includes (i) thirty business days (six weeks) preceding and two business days following quarterly earnings announcements, (ii) any other duration for any other planned announcement of material financial consequence (as determined at the Company’s discretion), or (iii) any other duration for any unscheduled, unplanned, or ongoing matter of material or material financial consequence (as determined at the Company’s discretion).

•Company insiders are required to know and execute their reporting responsibilities. Insiders must notify the Company prior to making any transaction involving Unitil common stock, and promptly report any and all transactions involving Unitil common stock to the Securities and Exchange Commission.

Evaluation of Transactions with Related Persons

•Transactions between the Company or one or more of its subsidiaries and one or more related persons may present risks or conflicts of interest, or the appearance of conflicts of interest. The Company's Code of Ethics requires all employees, officers and directors, without exception, to avoid engagement in activities or relationships that conflict, or would be perceived to conflict, with the Company's interests or adversely affect its reputation. It is understood, however, that certain relationships or transactions may arise that would be deemed acceptable and appropriate upon full disclosure of the transaction, following review and approval to ensure there is a legitimate business reason for the transaction, and that the terms of the transaction are no less favorable to the Company than could be obtained from an unrelated person.

10

Exhibit 19.1

•As a result, all related person transactions must be communicated to the Audit Committee, including, but not limited to, all material terms and facts of the transaction, and the related person's direct or indirect interest in, or relationship to, the related person transaction. Each related person transaction, and any material amendment or modification to any related person transaction, shall be reviewed and approved by the Audit Committee, and, as appropriate, disclosed as prescribed in the NYSE Listed Company Manual, Section 314, Related Person Transactions.

Communication with the Board

•Any shareholder or other interested party desiring to communicate with the Board, a specified committee, or a specified individual Director, including the Lead Director, may do so in writing by sending a letter addressed to:

c/o Corporate Secretary

Unitil Corporation

6 Liberty Lane West

Hampton, NH 03842

or via email to the following address: whitney@unitil.com

•All mail addressed to the Board, a specified committee, or a specified individual Director, including the Lead Director, is screened for security purposes and to ensure that the communication relates to defined business matters that are relevant to the Company. The Corporate Secretary has been instructed by the Board to promptly forward communications that satisfy the screening criteria to the appropriate Director(s).

Shareholder Nomination of Director Candidates

•Nominations of persons for election to the Board may be made by any shareholder of the Company entitled to vote for the election of directors at the annual meeting. Nominations by shareholders of the Company must be made in compliance with all procedures set forth in Article IV –Nomination of Directors of the Company’s By-Laws.

•Additionally, the Nominating and Governance Committee will consider qualified candidates for possible nomination that are recommended by shareholders. Candidates must meet minimum criteria as set forth in the section of these Guidelines entitled “Director Candidate Criteria and Selection Process of the Nominating and Governance Committee” in order to be deemed a qualified candidate for consideration. Shareholders wishing to make such a recommendation may do so by sending the following information to the Nominating and Governance Committee, c/o Corporate Secretary, 6 Liberty Lane West, Hampton, NH 03842:

•name of the candidate with brief biographical information and resume;

•contact information for the candidate and a document evidencing the candidate’s willingness to serve as a director if elected; and

•a signed statement as to the submitting shareholder’s current status as a shareholder and definitive proof of the number of shares currently held.

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Exhibit 19.1

Annual Meeting of Shareholders

•Article I of the Company’s By-Laws provides that the annual meeting of shareholders shall be held on a date each year as a majority of the Board of Directors, in their discretion, shall determine annually.

•At any meeting, the holders of record of a majority of the shares entitled to vote at the meeting, present in person or by proxy, shall constitute a quorum.

•Article I of the Company’s By-Laws provides for statutory voting.

•Members of the Board are strongly encouraged to attend the annual meeting of shareholders, although there is no formal requirement to attend.

Independent Registered Public Accounting Firm

•The Company’s independent registered public accounting firm is Deloitte & Touche LLP (“Deloitte”). Deloitte has been formally engaged by the Audit Committee. The Audit Committee has full oversight of Deloitte during the term of its engagement as the Company’s independent registered public accounting firm.

Last Revised and Approved: November 1, 2023

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EX-21.1

Exhibit 21.1

Subsidiaries of Registrant

The Company or the registrant has eight wholly-owned subsidiaries, seven of which are corporations organized under the laws of the State of New Hampshire: Unitil Energy Systems, Inc., Northern Utilities, Inc., Granite State Gas Transmission, Inc., Unitil Power Corp., Unitil Realty Corp., Unitil Resources, Inc. and Unitil Service Corp. The eighth, Fitchburg Gas and Electric Light Company, is organized under the laws of the Commonwealth of Massachusetts.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-258405 and 333-274020 on Form S-3 and Nos. 333-234391 and 333-184849 on Form S-8 of our report dated February 13, 2024, relating to the consolidated financial statements of Unitil Corporation and subsidiaries and the effectiveness of Unitil Corporation and subsidiaries’ internal control over financial reporting appearing in this Annual Report on Form 10-K of Unitil Corporation for the year ended December 31, 2023.

/s/ Deloitte & Touche LLP

Boston, Massachusetts

February 13, 2024

EX-31.1

Exhibit 31.1

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Thomas P. Meissner, Jr., certify that:

1)I have reviewed this annual report on Form 10-K of Unitil Corporation;

2)Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3)Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4)The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any changes in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonable likely to materially affect, the registrant’s internal controls over financial reporting; and

5)The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 13, 2024

/s/ Thomas P. Meissner, Jr.

Thomas P. Meissner, Jr.

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Daniel J. Hurstak, certify that:

1)I have reviewed this annual report on Form 10-K of Unitil Corporation;

2)Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3)Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4)The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any changes in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonable likely to materially affect, the registrant’s internal controls over financial reporting; and

5)The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 13, 2024

/s/ Daniel J. Hurstak

Daniel J. Hurstak

Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Todd R. Diggins, certify that:

1)I have reviewed this annual report on Form 10-K of Unitil Corporation;

2)Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3)Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4)The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any changes in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonable likely to materially affect, the registrant’s internal controls over financial reporting; and

5)The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 13, 2024

/s/ Todd R. Diggins

Todd R. Diggins

Chief Accounting Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Unitil Corporation (the "Company") on Form 10-K for the year ended December 31, 2023 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each of the undersigned Thomas P. Meissner, Jr., Chief Executive Officer, Daniel J. Hurstak, Chief Financial Officer, and Todd R. Diggins, Chief Accounting Officer, certifies, to the best knowledge and belief of the signatory, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Signature	Capacity	Date
/s/ Thomas P. Meissner, Jr.
Thomas P. Meissner, Jr.	Chief Executive Officer	February 13, 2024
/s/ Daniel J. Hurstak
Daniel J. Hurstak	Chief Financial Officer	February 13, 2024
/s/ Todd R. Diggins
Todd R. Diggins	Chief Accounting Officer	February 13, 2024

EX-97.1

System Policy

Exhibit 97.1

Subject: Executive Compensation Recovery Policy
To: All Executive Officers (“Covered Officers”)	Policy Number: HR 1.61
From: Human Resources	Effective Date: November 1, 2023

PURPOSE

The purpose of this Executive Compensation Recovery Policy (the “Policy”) is to provide for the recovery of certain executive compensation in the event of an accounting restatement resulting from material noncompliance with financial reporting requirements under the securities laws. This Policy is designed to comply with Section 10D of the Securities Exchange Act of 1934 (the “Exchange Act”) and the listing standards of the New York Stock Exchange (the “NYSE”).

SCOPE AND APPLICATION

The Board of Directors (the “Board”) of Unitil Corporation (the “Company”) adopted this policy

which shall be administered by the Board or, if so designated by the Board, the Compensation Committee, in which case references herein to the Board shall be deemed references to the Compensation Committee. Any determinations made by the Board shall be final and binding on all affected individuals.

Covered Executives

This Policy applies to the Company’s current and former executive officers, as determined by the Board in accordance with Section 10D of the Exchange Act and the listing standards of the NYSE (“Covered Executives”).

In general, executive officers include the Company’s chief executive officer, president, principal financial officer, principal accounting officer, any vice-president of the Company in charge of a principal business unit, division, or function (as of the date this policy was last updated, determined by the Board to consist of vice president–electric operations and vice president–gas operations), or any other officer or non-officer who performs a policy-making function for the Company. Policy-making function is not intended to include policymaking functions that are not significant.

Executive officers of the Company’s subsidiaries are deemed executive officers of the Company if they perform such policy making functions for the Company.

Page 1 of NUMPAGES 2

System Policy

POLICY

Recovery; Accounting Restatement

In the event the Company is required to prepare an accounting restatement of its financial statements due to the Company’s material noncompliance with any financial reporting requirement under the securities laws (including any required accounting restatement to correct an error in previously issued financial statements that is material to the previously issued financial statements or that would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period), the Company will recover reasonably promptly the amount of any erroneously awarded Incentive Compensation received by any Covered Executive (a) during the three completed fiscal years immediately preceding the date on which the Company is required to prepare an accounting restatement or (b) during any transition period required by Section 10D of the Exchange Act or the listing standards of the NYSE.

Incentive Compensation

For purposes of this Policy, “Incentive Compensation” means any compensation that is granted, earned, or vested based wholly or in part on the attainment of a Financial Reporting Measure. Incentive Compensation may include, without limitation, short-term or long-term cash incentives, restricted shares, and restricted stock units.

For purposes of this Policy, “Financial Reporting Measures” means measures that are determined and presented in accordance with the accounting principles used in preparing the Company’s financial statements, and any measures that are derived wholly or in part from such measures. Stock price and total shareholder return are also Financial Reporting Measures. Financial Reporting Measures may include, without limitation:

·stock price;

·total shareholder return;

·revenues;

·net income;

·earnings before interest, taxes, depreciation, and amortization (EBITDA);

·funds from operations;

·liquidity measures such as working capital or operating cash flow;

·return measures such as return on invested capital or return on assets; and

·earnings measures such as earnings per share.

Erroneously Awarded Incentive Compensation: Amount Subject to Recovery

The amount to be recovered will be the excess of the Incentive Compensation received by the Covered Executive based on the Company’s material noncompliance with any financial reporting requirement under the securities laws over the Incentive Compensation that would have been received by the Covered Executive had it been based on the restated results (computed without regard to any taxes paid).

Page 2 of NUMPAGES 2

System Policy

If the amount of erroneously awarded Incentive Compensation cannot be determined directly from the information in the accounting restatement, then, to the extent permitted by Section 10D of the Exchange Act and the listing standards of the NYSE, the Company will make its determination based on a reasonable estimate of the effect of the accounting restatement.

For Incentive Compensation based on stock price or total shareholder return, where the amount of erroneously awarded Incentive Compensation is not subject to mathematical recalculation directly from the information in an accounting restatement, the amount will be based on a reasonable estimate of the effect of the accounting restatement on the stock price or total shareholder return upon which the Incentive Compensation was received.

Method of Recovery

To the extent permitted bylaw, the methods for recovering Incentive Compensation under this Policy may include, without limitation:

•requiring reimbursement of cash Incentive Compensation previously received;

•seeking recovery of any gain realized on the vesting, exercise, settlement, sale, transfer, or other disposition of any equity-based awards;

•offsetting the recovered amount from any compensation otherwise owed by the Company to the Covered Executive;

•forfeiting or cancelling outstanding vested or unvested equity awards; and/or

•taking any other remedial and recovery action permitted by law.

Other Recovery Rights

The Board intends that this Policy will be applied to the fullest extent permitted by law. The Board may require that any employment agreement, equity award agreement, or similar agreement entered into on or after the Effective Date shall, as a condition to the grant of any benefit thereunder, require a Covered Executive to agree to abide by the terms of this Policy. Any right of recovery under this Policy is in addition to, and not in lieu of, any other remedies or rights of recovery that may be available to the Company pursuant to the terms of any similar policy or in any employment agreement, equity award agreement, or similar agreement and any other legal remedies available to the Company.

Recovery; Impracticability

The Company shall recover any erroneously awarded Incentive Compensation in accordance with this Policy except to the extent that the conditions of Rule 10D-1 of the Exchange Act and the listing standards of the NYSE are met and the Compensation Committee has determined (in accordance with Rule 10D-1 of the Exchange Act and the listing standards of the NYSE) that recovery would be impractical.

No Indemnification

The Company shall not indemnify any Covered Executives against the loss of any incorrectly awarded Incentive Compensation.

Page 3 of NUMPAGES 2

System Policy

Interpretation

The Board is authorized to interpret and construe this Policy and to make all determinations necessary, appropriate, or advisable for the administration of this Policy. It is intended that this Policy comply with, and be interpreted in a manner that is consistent with, the requirements of Section 10D of the Exchange Act and any applicable rules or standards adopted by the Securities and Exchange Commission or the NYSE.

Successors

This Policy shall be binding and enforceable against all Covered Executives and their beneficiaries, heirs, executors, administrators or other legal representatives.

Effective Date

This Policy shall be effective as of the date it is adopted by the Board (the “Effective Date”) and shall apply to Incentive Compensation that is approved, awarded or granted to Covered Executives on or after that date.

Amendment; Termination

The Board may amend this Policy from time to time in its discretion and shall amend this Policy as it deems necessary to reflect rules and regulations adopted by the Securities and Exchange Commission under Section 10D of the Exchange Act and to comply with any rules or standards adopted by the NYSE. The Board may terminate this Policy at any time to the extent permitted under the Exchange Act and any rules or standards adopted by the Securities and Exchange Commission or the NYSE.

Page 4 of NUMPAGES 2

EX-99.1

 

Page 1 of 5

Exhibit 99.1

FOR RELEASE

Unitil Reports Year-End Earnings

Hampton, N.H., february 13, 2024 -- Unitil Corporation (NYSE: UTL) (unitil.com) today announced Net Income of $45.2 million, or $2.82 in Earnings Per Share (EPS), for the year ended December 31, 2023, an increase of $3.8 million in Net Income, or $0.23 in EPS, compared to 2022. The Company’s 2023 Electric and Gas GAAP Gross Margins were $78.1 million and $114.1 million, respectively.

“We delivered strong financial and operating results in 2023 by executing on our strategies, and focusing on operational excellence and best-in-class service,” said Thomas P. Meissner, Jr., Unitil’s Chairman and Chief Executive Officer. “As we head into 2024, we remain focused on the issues that matter most — safety, reliability, affordability and financial discipline. We believe that by doing so, we will continue to create long-term sustainable value for all stakeholders.”

Electric GAAP Gross Margin was $78.1 million in 2023, an increase of $4.7 million compared to 2022. The increase was driven by higher rates and customer growth of $5.3 million, partially offset by higher depreciation and amortization expense of $0.6 million.

Electric Adjusted Gross Margin (a non-GAAP financial measure1) was $104.1 million in 2023, an increase of $5.3 million compared with 2022. The increase was driven by higher rates and customer growth.

Gas GAAP Gross Margin was $114.1 million in 2023, an increase of $6.5 million compared to 2022. The increase was driven by higher rates and customer growth of $14.1 million, partially offset by the unfavorable effects of warmer winter weather in 2023 of $1.1 million, higher depreciation and amortization of $4.1 million, and the recognition, in the second quarter of 2022, of $2.4 million in higher rates resulting from the Company’s base rate case in New Hampshire.

1The accompanying Supplemental Information more fully describes the non-GAAP financial measures used in this press release and includes a reconciliation of the non-GAAP financial measures to the financial measures that the Company’s management believes are the most comparable GAAP financial measures. The Supplemental Information also includes a discussion of the changes in the most comparable GAAP financial measures for the periods presented.

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

unitil.com

Page 2 of 5

Gas Adjusted Gross Margin (a non-GAAP financial measure1) was 154.5 million in 2023, an increase of $10.6 million compared to 2022. The increase was driven by higher rates and customer growth of $14.1 million, partially offset by the unfavorable effects of warmer winter weather in 2023 of $1.1 million and the recognition, in the second quarter of 2022, of $2.4 million in higher rates resulting from the Company’s base rate case in New Hampshire.

Operation and Maintenance (O&M) expenses increased $1.9 million, or 2.6%, in 2023 compared to 2022, reflecting higher utility operating costs of $1.2 million, higher professional fees of $0.4 million and higher labor costs of $0.3 million.

Depreciation and Amortization expense increased $4.8 million in 2023 compared to 2022, reflecting additional depreciation associated with higher levels of utility plant in service and higher amortization of rate case and other deferred costs.

Taxes Other Than Income Taxes increased $2.6 million in 2023 compared to 2022, reflecting higher local property taxes on higher utility plant in service and higher payroll and other taxes.

Interest Expense, Net increased $3.2 million in 2023 compared to 2022 primarily reflecting higher interest on short-term borrowings, partially offset by higher interest income on regulatory assets and other.

Other Expense (Income), Net decreased $2.4 million in 2023 compared to 2022, reflecting lower retirement benefit costs.

Federal and State Income Taxes increased $2.0 million in 2023 compared to 2022, reflecting higher pre-tax earnings in 2023 and higher flow back, in 2022, of excess Accumulated Deferred Income Taxes per regulatory orders in New Hampshire.

In 2023, Unitil’s annual common dividend was $1.62 per share, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock. 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.

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

The Company will hold a quarterly conference call to discuss fourth quarter and full year 2023 results on Tuesday, February 13, 2024, at 10:00 a.m. Eastern Time. This call is being webcast. This call, financial and other statistical information contained in the Company’s presentation on this call, and information required by Regulation G regarding non-GAAP financial measures can be accessed in the Investor Relations section of Unitil’s website, unitil.com.

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

unitil.com

Page 3 of 5

About Unitil Corporation

Unitil Corporation provides energy for life by safely and reliably delivering electricity and natural gas in New England. We are committed to the communities we serve and to developing people, business practices, and technologies that lead to the delivery of dependable, more efficient energy.Unitil Corporation is a public utility holding company with operations in Maine, New Hampshire and Massachusetts. Together, Unitil’s operating utilities serve approximately 108,500 electric customers and 88,400 natural gas customers. For more information about our people, technologies, and community involvement please visit unitil.com.

Forward-Looking Statements

This press release may contain forward-looking statements. All statements, other than statements of historical fact, included in this press release are forward-looking statements. Forward-looking statements include declarations regarding Unitil’s beliefs and current expectations. These forward-looking statements are subject to the inherent risks and uncertainties in predicting future results and conditions that could cause the actual results to differ materially from those projected in these forward-looking statements. Some, but not all, of the risks and uncertainties include the following: Unitil’s regulatory environment (including regulations relating to climate change, greenhouse gas emissions and other environmental matters); fluctuations in the supply of, the demand for, and the prices of, energy commodities and transmission and transportation capacity and Unitil’s ability to recover energy commodity costs in its rates; customers’ preferred energy sources; severe storms and Unitil’s ability to recover storm costs in its rates; general economic conditions; variations in weather; long-term global climate change; unforeseen or changing circumstances, which could adversely affect the reduction of company-wide direct greenhouse gas emissions; Unitil’s ability to retain its existing customers and attract new customers; increased competition; and other risks detailed in Unitil's filings with the Securities and Exchange Commission. These forward looking statements speak only as of the date they are made. Unitil undertakes no obligation, and does not intend, to update these forward-looking statements except as required by law.

For more information please contact:
Todd Diggins – Investor Relations	Alec O’Meara – External Affairs
Phone: 603-773-6504	Phone: 603-773-6404
Email: diggins@unitil.com	Email: omeara@unitil.com

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

unitil.com

Page 4 of 5

Supplemental Information; Non-GAAP Financial Measures

The Company analyzes operating results using Electric and Gas Adjusted Gross Margins, which are non-GAAP financial measures. Electric Adjusted Gross Margin is calculated as Total Electric Operating Revenue less Cost of Electric Sales. Gas Adjusted Gross Margin is calculated as Total Gas Operating Revenues less Cost of Gas Sales. The Company’s management believes Electric and Gas Adjusted Gross Margins provide useful information to investors regarding profitability. Also, the Company’s management believes Electric and Gas Adjusted Gross Margins are important measures to analyze revenue from the Company’s ongoing operations because the approved cost of electric and gas sales are tracked, reconciled and passed through directly to customers in electric and gas tariff rates, resulting in an equal and offsetting amount reflected in Total Electric and Gas Operating Revenue.

In the following tables the Company has reconciled Electric and Gas Adjusted Gross Margin to GAAP Gross Margin, which we believe to be the most comparable GAAP financial measure. GAAP Gross Margin is calculated as Revenue less Cost of Sales, and Depreciation and Amortization. The Company calculates Electric and Gas Adjusted Gross Margin as Revenue less Cost of Sales. The Company believes excluding Depreciation and Amortization, which are period costs and not related to volumetric sales, is a meaningful measure to inform investors of the Company’s profitability from electric and gas sales in the period.

Twelve Months Ended December 31, 2023 ($ millions)
	Electric			Gas			Other			Total
Total Operating Revenue	$	306.5		$	250.6		$	—		$	557.1
Less: Cost of Sales		(202.4	)		(96.1	)		—			(298.5	)
Less: Depreciation and Amortization		(26.0	)		(40.4	)		(1.0	)		(67.4	)
GAAP Gross Margin		78.1			114.1			(1.0	)		191.2
Depreciation and Amortization		26.0			40.4			1.0			67.4
Adjusted Gross Margin	$	104.1		$	154.5		$	—		$	258.6

Twelve Months Ended December 31, 2022 ($ millions)
	Electric			Gas			Other			Total
Total Operating Revenue	$	297.9		$	265.3		$	—		$	563.2
Less: Cost of Sales		(199.1	)		(121.4	)		—			(320.5	)
Less: Depreciation and Amortization		(25.4	)		(36.3	)		(0.9	)		(62.6	)
GAAP Gross Margin		73.4			107.6			(0.9	)		180.1
Depreciation and Amortization		25.4			36.3			0.9			62.6
Adjusted Gross Margin	$	98.8		$	143.9		$	—		$	242.7

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

unitil.com

Page 5 of 5

Selected financial data for 2023 and 2022 is presented in the following table:

Unitil Corporation - Condensed Consolidated Financial Data

(Millions, except Per Share data) (Unaudited)

	Twelve Months Ended December 31,
	2023		2022		Change
Electric kWh Sales:
Residential		649.3		680.5		(4.6	%)
Commercial/Industrial		914.2		933.9		(2.1	%)
Total Electric kWh Sales		1,563.5		1,614.4		(3.2	%)
Gas Therm Sales:
Residential		42.9		44.6		(3.8	%)
Commercial/Industrial		178.6		180.2		(0.9	%)
Total Gas Therm Sales		221.5		224.8		(1.5	%)
Electric Revenues	$	306.5	$	297.9	$	8.6
Cost of Electric Sales		202.4		199.1		3.3
Electric Adjusted Gross Margin (a non-GAAP financial measure1):		104.1		98.8		5.3
Gas Revenues		250.6		265.3		(14.7	)
Cost of Gas Sales		96.1		121.4		(25.3	)
Gas Adjusted Gross Margin (a non-GAAP financial measure1):		154.5		143.9		10.6
Total Adjusted Gross Margin: (a non-GAAP financial measure1):		258.6		242.7		15.9
Operation & Maintenance Expenses		75.6		73.7		1.9
Depreciation & Amortization		67.4		62.6		4.8
Taxes Other Than Income Taxes		28.5		25.9		2.6
Other Expense (Income), Net		—		2.4		(2.4	)
Interest Expense, Net		28.7		25.5		3.2
Income Before Income Taxes		58.4		52.6		5.8
Provision for Income Taxes		13.2		11.2		2.0
Net Income	$	45.2	$	41.4	$	3.8
Earnings Per Share	$	2.82	$	2.59	$	0.23

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

unitil.com

XML

Cover Page - USD ($)
$ in Millions

12 Months Ended

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

XML

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

XML

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	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	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.

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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

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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

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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

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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

XML

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

XML

Insider Trading Arrangements	12 Months Ended
	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

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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.

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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

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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.

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.

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.

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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.

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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

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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.

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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

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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.

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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.

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Summary Of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Nature of Operations

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

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

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

Granite State is an interstate natural gas transmission pipeline company, operating 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.

Principles of Consolidation

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

Use of Estimates

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

Fair Value

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

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

Level 2 -	Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly.
Level 3 -	Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.

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

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

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

Utility Revenue Recognition

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

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

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

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

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

	Twelve Months Ended
	December 31, 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 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

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

Income Taxes

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

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

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

Dividends

Dividends - The Company’s dividend policy is reviewed periodically by the Board of Directors. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. For the year ended December 31, 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 - 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

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 - 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

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

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

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

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

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

Derivatives

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

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

Investments in Marketable Securities

Investments in Marketable Securities - The Company maintains a trust through which it invests in a money market fund 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

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

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

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

Commitments and Contingencies

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

Environmental Matters

Environmental Matters - The Company’s past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. The Company has recovered or will recover substantially all of the costs of the environmental remediation work performed to date from customers or from its insurance carriers. The Company believes it is in compliance with all applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 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

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.

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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

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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

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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

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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

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

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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

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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

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Provisions for Federal and State Income Taxes

Provisions for Federal and State Income Taxes reflected as operating expenses in the accompanying consolidated statements of earnings for the years ended December 31, 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

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

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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	$	—	$	—

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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

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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

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Estimated Percentage of Decoupled Sales (Details)	12 Months Ended
	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%

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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.

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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

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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

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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.

XML

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

XML

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

XML

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

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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

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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

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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	$ 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.

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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

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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

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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	30.0
3.43% Senior Notes, Due December 18, 2029
Debt Instrument [Line Items]
Total Long-Term Debt		30.0	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	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	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	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	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	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	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	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	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	20.0
Northern Utilities Inc | 3.78% Senior Notes, Due September 15, 2040
Debt Instrument [Line Items]
Total Long-Term Debt		40.0	40.0
Northern Utilities Inc | 4.32% Senior Notes, Due November 1, 2047
Debt Instrument [Line Items]
Total Long-Term Debt		30.0	30.0
Northern Utilities Inc | 7.72% Senior Notes, Due December 3, 2038
Debt Instrument [Line Items]
Total Long-Term Debt		50.0	50.0
Northern Utilities Inc | 4.42% Senior Notes, Due October 15, 2044
Debt Instrument [Line Items]
Total Long-Term Debt		50.0	50.0
Northern Utilities Inc | 4.04% Senior Notes, Due September 12, 2049
Debt Instrument [Line Items]
Total Long-Term Debt		40.0	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	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.

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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

XML

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)

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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

XML

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

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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

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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

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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

XML

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

XML

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

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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

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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

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Energy Supply - Additional Information (Detail) - 12 months ended Dec. 31, 2023 Bcfe in Billions	Total	Total	BTU	Bcfe
Northern Utilities Inc
Gas and Oil Acreage [Line Items]
Natural gas available under firm contract per day of year-round and seasonal transportation and underground storage capacity to distribution facilities			85,500,000,000
Natural gas, underground storage			44,000	6.3
Northern Utilities Inc | Maximum
Gas and Oil Acreage [Line Items]
Purchases of natural gas, contract duration	1 year
Fitchburg Gas and Electric Light Company
Gas and Oil Acreage [Line Items]
Natural gas available under firm contract per day of year-round and seasonal transportation and underground storage capacity to distribution facilities			14,439
Natural gas, underground storage | 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

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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

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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

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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

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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

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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%

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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

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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%

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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%

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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%

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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

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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)

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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

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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

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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%	100.00%	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%	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%	100.00%	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.

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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

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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