10-K

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

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

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 ☐

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.

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.

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:

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.

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:

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.

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.

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.

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.

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.

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.

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.

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 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, as of December 31, 2023, of electric and gas sales that are subject to revenue decoupling for the periods presented.

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.

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.

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.

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:

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.

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”.

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.

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:

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.

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:

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

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

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.

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

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

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.

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.

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.

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.

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:

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

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.

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.

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.

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.

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

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

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

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

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

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

The Company engages or otherwise collaborates with cybersecurity consultants, cybersecurity experts, energy sector leaders, and other third parties in connection with the Cybersecurity Plan. Unitil Corporation 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).

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

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

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

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).

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.

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

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.

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 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.

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.

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

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

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

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

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.

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.

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.)

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:

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.

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

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.

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.

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.

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.

$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.

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

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.

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.

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:

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:

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:

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.

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

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.

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 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.

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.

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

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:

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.

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.

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.

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.

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.

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

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.

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.

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.

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.

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

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:

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.

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

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.

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.

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.

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.

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.

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.

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

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.

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

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.

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:

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

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

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.

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

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 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

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.

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

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

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

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

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.

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

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 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.

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.

(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).

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.

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.

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.

(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:

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.

(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.

(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.

(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.

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.

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.



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)



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


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


	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


	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


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


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


	(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


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


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


							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	%


							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	%


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


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


	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


	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 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


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



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)


	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


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