10-Q

Please wait

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

☒ QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2026

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

For the transition period from to

Commission File Number 1-8858

UNITIL CORPORATION

(Exact name of registrant as specified in its charter)



New Hampshire	02-0381573
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)



6 Liberty Lane West, Hampton, New Hampshire	03842-1720
(Address of principal executive office)	(Zip Code)

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

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



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

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

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

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



Large accelerated filer	☒	Accelerated filer	☐

Non-accelerated filer	☐	Smaller reporting company	☐

		Emerging growth company	☐

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.



Class	Outstanding at May 1, 2026
Common Stock, no par value	17,990,811 Shares

Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended March 31, 2026

Table of Contents


		Page No.
Cautionary Statement		2-3

Part I. Financial Information

Item 1.	Financial Statements—Unaudited

	Consolidated Statements of Earnings—Three months Ended March 31, 2026 and 2025	14
	4
	Consolidated Balance Sheets—March 31, 2026, March 31, 2025 and December 31, 2025	15-16

	Consolidated Statements of Cash Flows—Three Months Ended March 31, 2026 and 2025	17

	Consolidated Statements of Changes in Common Stock Equity – Three Months Ended March 31, 2026 and 2025	18

	Notes to Consolidated Financial Statements	19-44

Item 2.	Management’s Discussion and Analysis (MD&A) of Financial Condition and Results of Operations	3-13

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45

Item 4.	Controls and Procedures	45

Part II. Other Information

Item 1.	Legal Proceedings	45

Item 1A.	Risk Factors	45

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45

Item 3.	Defaults Upon Senior Securities	Inapplicable

Item 4.	Mine Safety Disclosures	Inapplicable

Item 5.	Other Information	45

Item 6.	Exhibits	46-47

Signatures		48

Table of Contents

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

Cautionary Statement

This report and the documents incorporated by reference into this report contain statements that 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, 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 II, Item 1A (Risk Factors) and the following:

•

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

•

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

•

catastrophic events;

•

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

•

outsourcing of services to third parties could expose the Company 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 the Company's results of operations;

•

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

•

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

•

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

•

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

•

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

•

the Company's payment of dividends in the future;

•

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

•

the Company's ability to consummate acquisitions or other strategic transactions, to successfully integrate any acquired assets or business, or derive value from strategic transactions and investment, including but not limited to the completed acquisitions of Bangor Natural Gas Company and Maine Natural Gas Corporation, and the pending acquisitions of Aquarion Water Company of Massachusetts, Inc., Aquarion Water Company of New Hampshire, Inc., and Abenaki Water Co., Inc.;

•

impairment of the Company's assets (including long-lived assets and goodwill), could negatively impact the Company's financial condition and results of operations;

Table of Contents

•

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

•

customers’ preferred energy sources;

•

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

•

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

•

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

•

macroeconomic events, including the imposition of tariffs;

•

employee workforce factors, including the ability to attract and retain key personnel;

•

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

•

increased competition; and

•

other presently unknown or unforeseen factors.

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

See the information beginning on page 14 of this Quarterly Report on Form 10-Q.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Unitil Corporation’s 2025 Annual Report on Form 10-K for additional information.

OVERVIEW

Unitil Corporation (Unitil or the Company) is a public utility holding company headquartered in Hampton, New Hampshire. 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 gas throughout its service territory in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of five wholly owned distribution utilities:

Unitil Energy Systems, Inc. (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 Gas and Electric Light Company (Fitchburg), which provides both electric and gas service in the greater Fitchburg area of north central Massachusetts;

iii)

Northern Utilities, Inc. (Northern Utilities), which provides 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;

iv)

Bangor Natural Gas Company (Bangor), which provides gas service in the Bangor area of central Maine; and

Maine Natural Gas Corporation (Maine Natural), which provides gas service in southern and central Maine, including the greater Portland region, as well as the capital city of Augusta.

Unitil Energy, Fitchburg, Northern Utilities, Bangor and Maine Natural are collectively referred to as the “distribution utilities.” Together, the distribution utilities serve approximately 110,100 electric customers and 105,000 gas customers.

Table of Contents

Unitil also is the parent company of Granite State Gas Transmission, Inc. (Granite State), an interstate 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 gas pipelines and access to domestic gas supplies in the south and Canadian gas supplies in the north.

At March 31, 2026, Unitil had an investment in Net Utility Plant of $1.8 billion. Earnings from Unitil’s utility operations are derived primarily from the return on investment in the utility assets of the five distribution utilities and Granite State. Unitil’s total operating revenue includes revenue to recover the approved cost of purchased electricity and gas in rates on a fully reconciling basis. As a result of this reconciling rate structure, the Company’s earnings are not directly affected by changes in the cost of purchased electricity and gas.

Unitil Resources is the Company’s wholly owned, non-regulated subsidiary, which currently does not have any activity. The Company’s other subsidiaries include Unitil Service Corp., which provides, at cost, a variety of administrative and professional services to Unitil’s affiliated companies; Unitil Realty Corp., which owns and manages Unitil’s corporate office building and property located in Hampton, New Hampshire and owns land in Kingston, New Hampshire, on which Unitil Energy’s solar facility is located; Unitil Power Corp., which formerly functioned as the full requirements wholesale power supply provider for Unitil Energy; and Unitil Water Corp., which currently does not have any activity. Unitil’s consolidated net income includes the earnings of the holding company and these subsidiaries.

RATES AND REGULATION

Regulation

Unitil is subject to comprehensive regulation by federal and state regulatory authorities. Unitil and its subsidiaries are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005 regarding 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 New Hampshire Public Utilities Commission (NHPUC); Fitchburg is subject to regulation by the Massachusetts Department of Public Utilities (MDPU); Northern Utilities is regulated by the NHPUC and the Maine Public Utilities Commission (MPUC); Bangor is subject to regulation by the MPUC; and Maine Natural is subject to regulation by the MPUC. Granite State, Unitil’s interstate gas transmission pipeline, is subject to regulation by FERC regarding 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 Energy, Fitchburg, Northern Utilities and Maine Natural's non-Augusta service area 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. Bangor and Maine Natural’s Augusta Service Area deliver natural gas to their customers at rates established under alternative rate plans, which provide multi-year rate changes designed to approximate market-based rates.

The Company's electric and gas sales in Massachusetts and New Hampshire are now largely decoupled. Revenue decoupling eliminates the dependency of distribution revenue on the volume of electricity or gas sold. 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.

RESULTS OF OPERATIONS

The following section of MD&A compares the results of operations for each of the two fiscal periods ended March 31, 2026 and March 31, 2025 and should be read in conjunction with the accompanying unaudited Consolidated Financial Statements and the accompanying Notes to unaudited Consolidated Financial Statements included in Part I, Item 1 of this report, which are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).

Table of Contents

The Company’s results of operations historically have reflected the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the heating season as a result of higher sales of natural gas due to cold weather. 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 results of operations. Sales of electricity are generally less sensitive to weather than natural gas sales, but also may be affected by the weather conditions in both the winter and summer seasons.

Use of GAAP and Non-GAAP Financial Measures

The MD&A includes financial information prepared in accordance with generally accepted accounting principles in the United States (GAAP), as well as certain non-GAAP financial measures. The Company's management believes that the non-GAAP presentations of earnings and Earnings Per Share (EPS) and Electric and Gas Adjusted Gross Margins are a more meaningful representation of the Company's financial performance and provide additional and useful information to readers of this report in analyzing the historical and future performance of the business. The non-GAAP financial measures should be viewed as a supplement to, and not a substitute for, financial measures presented in accordance with GAAP. Non-GAAP measures as presented herein may not be comparable to similarly titled measures used by other companies.

The Company's earnings discussion includes Adjusted Net Income, a non-GAAP financial measure referencing the Company’s 2026 and 2025 GAAP Net Income adjusted for certain transaction costs related to the Company's acquisitions of Bangor Natural Gas Company (purchase completed as of January 31, 2025), Maine Natural Gas Corporation (Maine Natural) (purchase completed as of October 31, 2025), Aquarion Water Company of Massachusetts, Inc., Aquarion Water Company of New Hampshire, Inc., and Abenaki Water Co., Inc. (the Aquarion Companies) (see Note 7 - Regulatory Matters to the accompanying Consolidated Financial Statements). The Company's management believes that the transaction costs related to the acquisitions of Bangor, Maine Natural and the Aquarion Companies, which are included in Operation and Maintenance expense on the Consolidated Statements of Earnings, are not indicative of the Company's ongoing costs and not directly related to the ongoing operations of the business and therefore are not an indicator of baseline operating performance.

In the following tables the Company has reconciled Adjusted Net Income to GAAP Net Income, which we believe to be the most comparable GAAP financial measure.


Three Months Ended March 31, 2026 (millions, except per share data)
	Amount		Per Share
GAAP Net Income	$	33.2	$	1.85
Transaction Costs		0.6	$	0.03
Adjusted Net Income	$	33.8	$	1.88

Three Months Ended March 31, 2025 (millions, except per share data)
	Amount		Per Share
GAAP Net Income	$	27.5	$	1.69
Transaction Costs		0.9	$	0.05
Adjusted Net Income	$	28.4	$	1.74

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

Table of Contents

Company believes excluding Depreciation and Amortization, which are period costs and not related to volumetric sales, is a meaningful measure to inform investors of the Company’s profitability from electric and gas sales in the period.


Three Months Ended March 31, 2026 (millions)
	Electric			Gas			Total
Total Operating Revenue	$	65.5		$	151.4		$	216.9
Less: Cost of Sales		(35.9	)		(69.3	)		(105.2	)
Less: Depreciation and Amortization		(8.3	)		(15.0	)		(23.3	)
GAAP Gross Margin		21.3			67.1			88.4
Depreciation and Amortization		8.3			15.0			23.3
Adjusted Gross Margin	$	29.6		$	82.1		$	111.7


Three Months Ended March 31, 2025 (millions)
	Electric			Gas			Total
Total Operating Revenue	$	60.2		$	110.6		$	170.8
Less: Cost of Sales		(32.7	)		(39.7	)		(72.4	)
Less: Depreciation and Amortization		(7.9	)		(13.8	)		(21.7	)
GAAP Gross Margin		19.6			57.1			76.7
Depreciation and Amortization		7.9			13.8			21.7
Adjusted Gross Margin	$	27.5		$	70.9		$	98.4

Electric GAAP Gross Margin was $21.3 million in the three months ended March 31, 2026, an increase of $1.7 million compared to the same period in 2025. The increase was driven by higher rates of $2.8 million, partially offset by higher depreciation and amortization expense of $0.4 million and a one-time reduction of FERC transmission revenue of $0.7 million (see Note 7 Regulatory Matters: FERC Transmission Formula Rate Proceedings).

Gas GAAP Gross Margin was $67.1 million in the three months ended March 31, 2026, an increase of $10.0 million compared to the same period in 2025. The increase was driven by higher rates and customer growth of $10.3 million, the favorable effects of colder winter weather in 2026 of $0.9 million, partially offset by higher depreciation and amortization of $1.2 million. Included in gas operating revenue, cost of gas sales and depreciation and amortization for the three months ended March 31, 2026 was $18.3 million, $12.3 million and $0.7 million, respectively, related to Maine Natural.

Earnings Overview

The Company’s Net Income was $33.2 million, or $1.85 in Earnings Per Share (EPS) for the first quarter of 2026, an increase of $5.7 million in Net Income, or $0.16 in EPS, compared to the first quarter of 2025. The Company's Adjusted Net Income (a non-GAAP financial measure), which excluded transaction-related costs in connection with the acquisitions of Bangor, Maine Natural Gas and the Aquarion Companies, was $33.8 million, or $1.88 in EPS for the first quarter of 2026, an increase of $5.4 million, or $0.14 in EPS, compared to the first quarter of 2025.

Electric Adjusted Gross Margin (a non-GAAP financial measure) was $29.6 million in the first quarter of 2026, an increase of $2.1 million compared to the same period in 2025. The increase reflects higher rates of $2.8 million partially offset by a one-time reduction of FERC transmission revenue of $0.7 million (see Note 7 Regulatory Matters: FERC Transmission Formula Rate Proceedings).

Gas Adjusted Gross Margin (a non-GAAP financial measure) was $82.1 million in the first quarter of 2026, an increase of $11.2 million compared to the same period in 2025, driven by higher rates and customer growth of $10.3 million and the favorable effects of colder winter weather in 2026 of $0.9 million. Included in the Gas Adjusted Gross Margin for the three months ended March 31, 2026 was $6.0 million related to Maine Natural.

Operation and Maintenance (O&M) expenses increased $0.8 million in the three months ended March 31, 2026, compared to the same period in 2025. The increase reflects higher utility operating costs of $1.1 million, partially offset by lower acquisition costs of $0.3 million. Included in O&M expense for the three months ended March 31, 2026 was $1.3 million related to Maine Natural. Excluding O&M expenses for Maine Natural and transaction costs, O&M expenses for legacy operations would have decreased by $0.2 million for the three months ended March 31, 2026.

Depreciation and Amortization expense increased $1.6 million in the three months ended March 31, 2026, compared to the same period in 2025. The increase reflects higher levels of utility plant in service, partially offset by lower amortization of other deferred

Table of Contents

costs. Included in Depreciation and Amortization for the three months ended March 31, 2026 was $0.7 million related to Maine Natural.

Taxes Other Than Income Taxes increased $1.2 million in the three months ended March 31, 2026, compared to the same period in 2025. The increase reflects higher local property taxes on higher utility plant in service and higher payroll taxes. Included in Taxes Other Than Income Taxes for the three months ended March 31, 2026 was $0.4 million related to Maine Natural.

Interest Expense, Net increased $1.7 million in the three months ended March 31, 2026, compared to the same period in 2025, primarily reflecting higher levels of short-term borrowings and long-term debt, partially offset by lower interest expense on regulatory liabilities.

Other Expense (Income), Net decreased $0.1 million in the three months ended March 31, 2026, compared to the same period in 2025, primarily from lower retirement benefit costs.

Provision for Income Taxes increased $2.4 million in the three months ended March 31, 2026, compared with the same period in 2025, reflecting higher pre-tax earnings in 2026.

At its January 2026 and April 2026 meetings, the Unitil Corporation Board of Directors declared quarterly dividends on the Company’s common stock of $0.475 per share. These quarterly dividends result in a current effective annualized dividend rate of $1.90 per share, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock.

Electric Revenues, Adjusted Gross Margin and Sales

Electric Operating Revenues and Electric Adjusted Gross Margin (a non-GAAP financial measure) - The following table details Total Electric Operating Revenues and Electric Adjusted Gross Margin for the three months ended March 31, 2026 and 2025:


Electric Operating Revenues and Electric Adjusted Gross Margin (millions)
	Three Months Ended March 31,
	2026		2025		$ Change		% Change
Electric Operating Revenue:
Residential	$	38.3	$	35.3	$	3.0		8.5	%
Commercial / Industrial		27.2		24.9		2.3		9.2	%
Total Electric Operating Revenue		65.5		60.2		5.3		8.8	%
Cost of Electric Sales		35.9		32.7		3.2		9.8	%
Electric Adjusted Gross Margin	$	29.6	$	27.5	$	2.1		7.6	%

Total Electric Operating Revenue increased $5.3 million, or 8.8% in the three months ended March 31, 2026 compared to the same period in 2025, reflecting higher electric distribution rates, and higher costs of electric sales due to the decrease in the amount of electricity purchased by customers directly from third-party suppliers, which are tracked and reconciled to costs that are passed through directly to customers, partially offset by a one-time reduction of FERC transmission revenue.

Electric GAAP Gross Margin is discussed above in the section entitled “Use of GAAP and Non-GAAP Financial Measures”.

Electric Adjusted Gross Margin (a non-GAAP financial measure) was $29.6 million for the three months ended March 31, 2026, an increase of $2.1 million, compared with the same period in 2025. The increase reflects higher rates of $2.8 million partially offset by a one-time reduction of FERC transmission revenue of $0.7 million (see Note 7 Regulatory Matters: FERC Transmission Formula Rate Proceedings).

Kilowatt-hour Sales - Unitil’s total electric kWh sales decreased 3.1% in the three months ended March 31, 2026, compared to the same period in 2025. Sales to Residential customers increased 2.1% in the three months ended March 31, 2026, compared to the same period in 2025, reflecting colder winter weather for heating purposes in 2026 and customer growth. Sales to Commercial and Industrial (C&I) customers decreased 7.6% in the three months ended March 31, 2026, compared to the same period in 2025, reflecting the loss of a large industrial customer in the Fitchburg service area in 2025, partially offset by customer growth. As of March 31, 2026, the number of electric customers increased by approximately 550 over the previous year. Sales margins derived from decoupled unit sales are not sensitive to changes in electric kWh sales. Substantially all of the Company’s electric kWh sales volumes are decoupled.

Table of Contents

The following table details total kWh sales for the three months ended March 31, 2026 and 2025 by major customer class:


kWh Sales (millions)
	Three Months Ended March 31,
	2026		2025		Change			% Change
Residential		204.0		199.8		4.2			2.1	%
Commercial / Industrial		220.4		238.4		(18.0	)		(7.6	)%
Total		424.4		438.2		(13.8	)		(3.1	)%

Gas Revenues, Adjusted Gross Margin and Sales

Gas Operating Revenues and Adjusted Gross Margin (a non-GAAP financial measure) - The following table details Total Gas Operating Revenues and Gas Adjusted Gross Margin for the three months ended March 31, 2026 and 2025:


Gas Operating Revenues and Gas Adjusted Gross Margin (millions)
	Three Months Ended March 31,
	2026		2025		$ Change		% Change
Gas Operating Revenue:
Residential	$	64.0	$	48.9	$	15.1		30.9	%
Commercial / Industrial		87.4		61.7		25.7		41.7	%
Total Gas Operating Revenue		151.4		110.6		40.8		36.9	%
Cost of Gas Sales		69.3		39.7		29.6		74.6	%
Gas Adjusted Gross Margin	$	82.1	$	70.9	$	11.2		15.8	%

Total Gas Operating Revenue increased $40.8 million, or 36.9%, in the three months ended March 31, 2026, respectively, compared to the same period in 2025. The increase includes $18.3 million of gas operating revenue for Maine Natural, higher rates and customer growth, the favorable impact of colder winter weather in 2026 and higher costs of gas sales, which are tracked and reconciled costs that are passed through directly to customers.

Gas GAAP Gross Margin is discussed above in the section entitled “Use of GAAP and Non-GAAP Financial Measures”.

Therm Sales - Unitil’s total gas therm sales increased 13.4% in the three-month period ended March 31, 2026, compared to the same period in 2025. In the first quarter of 2026, sales to Residential and C&I customers increased 14.8% and 13.0%, respectively, compared to the same period in 2025, reflecting colder winter weather and customer growth. Included in the total gas therm sales increases were 10.6 million therms for the three months ended March 31, 2026, related to Maine Natural. Based on weather data collected in the Company’s gas service areas, on average there were 1.9% higher effective degree days in the first quarter of 2026 compared to the same period in 2025. As of March 31, 2026, the number of gas customers increased by approximately 7,140 over the previous year. Included in this increase was 6,400 customers related to Maine Natural. Sales margins derived from decoupled unit sales (currently representing approximately 38% 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 three months ended March 31, 2026 and 2025 by major customer class:


Therm Sales (millions)
	Three Months Ended March 31,
	2026		2025		Change		% Change
Residential		32.5		28.3		4.2		14.8	%
Commercial / Industrial		95.8		84.8		11.0		13.0	%
Total		128.3		113.1		15.2		13.4	%

The Company transported 62.9 million therms in the first three months of 2026 to two electric generation facilities in Maine. As these facilities were charged fixed fees and utilized third-party energy suppliers for natural gas, the therms were not included in the above table.

Table of Contents

Operating Expenses

Cost of Electric Sales - Cost of Electric Sales includes the cost of electric supply and spending on energy efficiency programs. Cost of Electric Sales increased $3.2 million, or 9.8%, in the three months ended March 31, 2026, compared to the same period in 2025. This increase reflects a decrease in the amount of electricity purchased by customers directly from third-party suppliers and an increase of energy efficiency spending, partially offset by lower wholesale electricity prices. Because the Company reconciles and recovers the approved Cost of Electric Sales in its rates at cost on a pass-through basis, changes in approved expenses do not affect earnings.

Cost of Gas Sales - Cost of Gas Sales includes the cost to supply the Company’s total gas requirements and spending on energy efficiency programs. Cost of Gas Sales increased $29.6 million, or 74.6%, in the three months ended March 31, 2026, compared to the same period in 2025. This increase reflects higher wholesale gas commodity prices and higher gas therm sales, including $12.3 million for Maine Natural. Because the Company reconciles and recovers the approved Cost of Gas Sales in its rates at cost on a pass-through basis, changes in approved expenses do not affect earnings.

Operation and Maintenance (O&M) - O&M expense includes electric and gas utility operating costs, and the operating cost of the Company’s corporate and other business activities. O&M expenses increased $0.8 million, or 3.5%, in the three months ended March 31, 2026, compared to the same period in 2025. The increase reflects higher utility operating costs of $1.1 million, partially offset by lower acquisition transaction costs of $0.3 million. Included in O&M expense for the three months ended March 31, 2026 was $1.3 million related to Maine Natural. Excluding O&M expenses for Maine Natural and transaction costs, O&M expenses for legacy operations would have decreased by $0.2 million for the three months ended March 31, 2026.

Depreciation and Amortization - Depreciation and Amortization expense increased $1.6 million, or 7.4%, in the three months ended March 31, 2026, compared to the same period in 2025. The increase reflects higher levels of utility plant in service, partially offset by lower amortization of other deferred costs. Included in Depreciation and Amortization for the three months ended March 31, 2026 was $0.7 million related to Maine Natural.

Taxes Other Than Income Taxes - Taxes Other Than Income Taxes increased $1.2 million, or 15.2%, in the three months ended March 31, 2026, compared to the same period in 2025. The increase reflects higher local property taxes on higher utility plant in service and higher payroll taxes. Included in Taxes Other Than Income Taxes for the three months ended March 31, 2026 was $0.4 million related to Maine Natural.

Other Expense (Income), Net - Other Expense (Income), Net decreased $0.1 million in the three months ended March 31, 2026, compared to the same period in 2025, primarily from lower retirement benefit costs.

Provision for Income taxes - Federal and State Income Taxes increased $2.4 million in the three months ended March 31, 2026, compared with the same period in 2025, reflecting higher pre-tax earnings in 2026.

Interest Expense, Net - Interest expense is presented in the Consolidated Financial Statements net of interest income. Interest expense is mainly comprised of interest on long-term debt and short-term borrowings. 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 accrued.

Unitil’s utility subsidiaries operate several 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 tracking and reconciling process will produce either an under-collected or an over-collected position. 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.

Table of Contents


Interest Expense, Net (millions)	Three Months Ended March 31,
	2026			2025			Change
Interest Expense
Long-term Debt	$	8.5		$	8.1		$	0.4
Short-term Debt		3.2			1.4			1.8
Regulatory Liabilities		0.6			1.2			(0.6	)
Subtotal Interest Expense		12.3			10.7			1.6
Interest (Income)
Regulatory Assets		(0.7	)		(0.9	)		0.2
AFUDC(1) and Other		(0.8	)		(0.7	)		(0.1	)
Subtotal Interest (Income)		(1.5	)		(1.6	)		0.1
Total Interest Expense, Net	$	10.8		$	9.1		$	1.7

(1)

AFUDC – Allowance for Funds Used During Construction.

Interest Expense, Net increased $1.7 million, or 18.7%, in the three months ended March 31, 2026, compared to the same period in 2025, primarily reflecting higher levels of short-term borrowings and long-term debt, partially offset by lower interest expense on regulatory liabilities.

LIQUIDITY, COMMITMENTS, AND Capital RequirementS

Sources of Capital

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

On August 18, 2025, the Company issued and sold 1,602,358 shares of its common stock at a price of $46.65 per share in a registered public offering (Offering). The Company’s net increase to Common Equity and Cash proceeds from the Offering was approximately $71.8 million. The proceeds 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 reflect the higher number of average shares outstanding, period over period.

On June 3, 2025, the Company entered into an at-the-market equity offering program (the ATM program) with sales agents under which the Company may, from time to time, offer and sell shares of Unitil's common stock having an aggregate offering price of up to $50 million. Sales of common stock under the ATM program, if any, are made pursuant to a shelf registration statement on Form S-3 (File No. 333-287753) and a related prospectus supplement filed with the Securities and Exchange Commission. As of March 31, 2026, the Company had sold an aggregate of 27,620 shares under the ATM program for net proceeds of $1.4 million. As of March 31, 2026, approximately $48.5 million remains available for future sales under the program. There were no shares sold during the three months ended March 31, 2026.

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 (as defined below). As of March 31, 2026, March 31, 2025 and December 31, 2025, the Company and all of its subsidiaries were in compliance with the regulatory requirements to participate 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 the prior facility in full, and on January 29, 2025, the Company executed an amendment that increased the borrowing limit from $200 million to $275 million and extended the maturity date from September 29, 2027 to September 29, 2028. Unitil may borrow under the Credit Facility through September 29, 2028, with the option

Table of Contents

for two additional one‑year extensions under certain conditions. The Credit Facility provides for a $275 million borrowing limit, including a $25 million sublimit for standby letters of credit, and permits Unitil to increase the borrowing limit by up to an additional $75 million under certain circumstances. Borrowings under the Credit Facility may bear interest at various rate options, including a daily fluctuating rate equal to the forward‑looking one‑month SOFR term rate (as administered by the Federal Reserve Bank of New York), plus 0.1000%, plus a margin ranging from 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 $112.9 million for the three months ended March 31, 2026. Total gross repayments were $110.6 million for the three months ended March 31, 2026. The following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of March 31, 2026, March 31, 2025 and December 31, 2025:


	Revolving Credit Facility ($ millions)
	March 31,				December 31,
	2026		2025		2025
Limit	$	275.0	$	275.0	$	275.0
Short-Term Borrowings Outstanding		172.0		172.9		169.7
Available	$	103.0	$	102.1	$	105.3

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 incur 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 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 March 31, 2026, March 31, 2025 and December 31, 2025, the Company was in compliance with the covenants contained in the Credit Facility in effect on those dates.

On April 30, 2026, Fitchburg issued $23.0 million of Notes due 2036 at 5.62% and $17.0 million of Notes due 2041 at 5.87%. Fitchburg used the net proceeds to refinance existing debt and for general corporate purposes. Approximately $0.2 million of costs associated with this issuance will be recorded as a reduction of Long-Term Debt on the Consolidated Balance Sheet in the second quarter of 2026.

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

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

Unitil and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State currently are rated “BBB+”, and Bangor is rated “BBB” by Standard & Poor’s Ratings Services. Unitil and Granite State currently are 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 provides limited guarantees on certain energy and gas storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of March 31, 2026, there were $50.3 million of guarantees outstanding.

Table of Contents

Northern Utilities and Bangor enter into asset management agreements under which Northern Utilities and Bangor release certain gas pipeline and storage assets, sell to an asset manager and subsequently repurchase the gas over the course of the gas heating season at the same price at which they sold the gas to the asset manager. There was $1.2 million of natural gas storage inventory and corresponding obligations at March 31, 2026 related to these asset management agreements. The amount of natural gas inventory released in March 2026, which was payable in April 2026, was $1.7 million and was recorded in Accounts Payable at March 31, 2026.

Off-Balance Sheet Arrangements

The Company and its subsidiaries do not currently use, and are not dependent on the use of, off-balance sheet financing arrangements such as securitization of receivables or obtaining access to assets or cash through special purpose entities or variable interest entities. Unitil’s subsidiaries conduct a portion of their operations in leased facilities, and lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements. As of March 31, 2026, there were $50.3 million of guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities outstanding. See Note 4 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

Critical Accounting Policies AND ESTIMATES

The preparation of the Company’s 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 sometimes is required to make difficult, 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 judgments, the financial position of the Company could be materially affected and the results of operations of the Company could be materially different than reported. As of March 31, 2026, the Company’s critical accounting policies and estimates had not changed significantly from December 31, 2025. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” in the Company’s 2025 Annual Report on Form 10-K for additional information.

EMPLOYEES

As of March 31, 2026, the Company and its subsidiaries had 603 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. The Company works diligently to attract the best talent from a diverse range of sources to meet the current and future demands of the Company's 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 March 31, 2026, 196 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 March 31, 2026:


	Employees Covered	CBA Expiration
Unitil Energy	41	5/31/2028
Fitchburg	47	5/31/2027
Northern Utilities NH Division	36	5/31/2030
Northern Utilities ME Division	41	3/31/2027
Bangor	13	5/31/2026
Maine Natural	8	3/31/2027
Granite State	5	3/31/2027
Unitil Service	5	5/31/2028

Table of Contents

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.

INTEREST RATE RISK

Unitil meets its external financing needs by issuing short-term and long-term debt. The majority of debt outstanding represents long-term notes or bonds 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 rates on the Company’s short-term borrowings and intercompany money pool transactions for the three months ended March 31, 2026 and March 31, 2025 were 4.9% and 5.6%, respectively. The average interest rate on the Company’s short-term borrowings for the twelve months ended December 31, 2025 was 5.4%.

COMMODITY PRICE RISK

Although Unitil’s five distribution utilities are subject to commodity price variations 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. The Company has divested its long-term power supply contracts and therefore, further reduced its exposure to commodity risk.

Regulatory Matters

Please refer to Note 7 to the Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of Regulatory Matters.

ENVIRONMENTAL MATTERS

Please refer to Note 8 to the Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of Environmental Matters.

Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF EARNINGS

(Millions, except per share data)

(UNAUDITED)


	Three Months Ended March 31,
	2026		2025
Operating Revenues
Electric	$	65.5	$	60.2
Gas		151.4		110.6
Total Operating Revenues		216.9		170.8
Operating Expenses
Cost of Electric Sales		35.9		32.7
Cost of Gas Sales		69.3		39.7
Operation and Maintenance		23.4		22.6
Depreciation and Amortization		23.3		21.7
Taxes Other Than Income Taxes		9.1		7.9
Total Operating Expenses		161.0		124.6
Operating Income		55.9		46.2
Interest Expense, Net		10.8		9.1
Other Expense (Income), Net		—		0.1
Income Before Income Taxes		45.1		37.0
Provision for Income Taxes		11.9		9.5
Net Income Applicable to Common Shares	$	33.2	$	27.5
Earnings Per Common Share – Basic and Diluted	$	1.85	$	1.69
Weighted Average Common Shares Outstanding – Basic and Diluted		17.9		16.2

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

Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Millions)

(UNAUDITED)


	March 31,				December 31,
	2026		2025		2025
ASSETS:
Current Assets:
Cash and Cash Equivalents	$	16.9	$	10.2	$	15.6
Accounts Receivable, Net		107.0		95.5		98.6
Accrued Revenue		78.2		60.5		87.0
Exchange Gas Receivable		1.4		1.6		9.8
Gas Inventory		0.6		0.4		1.3
Materials and Supplies		16.2		16.1		15.4
Prepayments and Other		16.6		11.2		12.4
Total Current Assets		236.9		195.5		240.1
Utility Plant:
Electric		758.4		705.8		752.2
Gas		1,440.3		1,273.8		1,413.0
Common		75.9		69.2		75.3
Construction Work in Progress		92.6		92.5		101.7
Utility Plant		2,367.2		2,141.3		2,342.2
Less: Accumulated Depreciation		554.4		522.4		543.7
Net Utility Plant		1,812.8		1,618.9		1,798.5
Other Noncurrent Assets:
Regulatory Assets		39.1		47.2		38.8
Operating Lease Right of Use Assets		6.5		6.2		7.0
Goodwill		4.3		—		4.3
Other Assets		56.2		22.9		45.5
Total Other Noncurrent Assets		106.1		76.3		95.6
TOTAL ASSETS	$	2,155.8	$	1,890.7	$	2,134.2

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

Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS (Cont.)

(Millions, except number of shares)

(UNAUDITED)


	March 31,				December 31,
	2026		2025		2025
LIABILITIES AND CAPITALIZATION:
Current Liabilities:
Accounts Payable	$	47.2	$	42.9	$	62.9
Short-Term Debt		258.0		172.9		255.7
Long-Term Debt, Current Portion		37.9		4.9		37.9
Regulatory Liabilities		23.4		23.8		16.7
Energy Supply Obligations		3.5		6.2		11.6
Interest Payable		8.2		7.9		9.4
Environmental Obligations		0.8		0.7		0.8
Operating Lease Obligations		2.0		1.8		2.1
Taxes Payable		11.2		10.4		0.6
Other Current Liabilities		23.7		23.5		28.1
Total Current Liabilities		415.9		295.0		425.8
Noncurrent Liabilities:
Deferred Income Taxes, net		198.3		184.6		196.7
Cost of Removal Obligations		156.5		143.9		153.0
Regulatory Liabilities		65.0		52.7		64.1
Retirement Benefit Obligations		33.3		25.8		32.9
Environmental Obligations		7.4		7.1		7.3
Operating Lease Obligations		4.5		4.4		4.9
Other Noncurrent Liabilities		7.5		5.9		7.3
Total Noncurrent Liabilities		472.5		424.4		466.2
Capitalization:
Long-Term Debt, Less Current Portion		631.4		637.2		632.6
Stockholders’ Equity:
Common Equity (No par value, Authorized: 25,000,000 and Outstanding: 17,989,863, 16,250,032 and 17,919,191 Shares)		419.9		342.6		418.2
Retained Earnings		215.9		191.3		191.2
Total Common Stock Equity		635.8		533.9		609.4
Preferred Stock		0.2		0.2		0.2
Total Stockholders’ Equity		636.0		534.1		609.6
Total Capitalization		1,267.4		1,171.3		1,242.2
Commitments and Contingencies (Notes 7 & 8)
TOTAL LIABILITIES AND CAPITALIZATION	$	2,155.8	$	1,890.7	$	2,134.2

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

Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions) (UNAUDITED)


	For the Three Months Ended March 31,
	2026			2025
Operating Activities:
Net Income	$	33.2		$	27.5
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization		23.3			21.7
Deferred Tax Provision		0.8			(2.3	)
Changes in Working Capital Items:
Accounts Receivable		(8.4	)		(16.7	)
Accrued Revenue		8.8			22.9
Regulatory Liabilities		5.6			6.6
Exchange Gas Receivable		8.4			4.8
Accounts Payable		(15.7	)		(12.3	)
Other Changes in Working Capital Items		2.7			(0.4	)
Deferred Regulatory and Other Charges		(11.0	)		(6.4	)
Other, net		2.4			6.7
Cash Provided by Operating Activities		50.1			52.1
Investing Activities:
Property, Plant and Equipment Additions		(32.4	)		(32.6	)
Acquisition, Net of Cash Acquired		—			(71.2	)
Cash Used in Investing Activities		(32.4	)		(103.8	)
Financing Activities:
Proceeds from Short-Term Debt, net		2.3			67.1
Repayment of Long-Term Debt		(1.3	)		(1.3	)
Net Decrease in Exchange Gas Financing		(8.1	)		(3.2	)
Dividends Paid		(8.5	)		(7.3	)
Proceeds from Issuance of Common Stock		0.3			0.3
Construction Advances		(1.1	)		—
Cash (Used In) Provided by Financing Activities		(16.4	)		55.6
Net Increase in Cash and Cash Equivalents		1.3			3.9
Cash and Cash Equivalents at Beginning of Period		15.6			6.3
Cash and Cash Equivalents at End of Period	$	16.9		$	10.2
Supplemental Cash Flow Information:
Interest Paid	$	12.7		$	10.4
Income Taxes Paid	$	—		$	—
Payments on Capital Leases	$	0.1		$	—
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$	6.5		$	7.2

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

Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

(Millions, except number of shares)

(UNAUDITED)


	Common Equity		Retained Earnings			Total
Three Months Ended March 31, 2026
Balance at January 1, 2026	$	418.2	$	191.2		$	609.4
Net Income				33.2			33.2
Dividends ($0.475 per Common Share)				(8.5	)		(8.5	)
Stock Compensation Plans		1.4					1.4
Issuance of 6,123 Common Shares		0.3					0.3
Balance at March 31, 2026	$	419.9	$	215.9		$	635.8
Three Months Ended March 31, 2025
Balance at January 1, 2025	$	341.2	$	171.1		$	512.3
Net Income				27.5			27.5
Dividends ($0.450 per Common Share)				(7.3	)		(7.3	)
Stock Compensation Plans		1.1					1.1
Issuance of 5,473 Common Shares		0.3					0.3
Balance at March 31, 2025	$	342.6	$	191.3		$	533.9

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

Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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), Bangor Natural Gas Company, (Bangor), Maine Natural Gas Corporation (Maine Natural), Granite State Gas Transmission, Inc. (Granite State), Unitil Power Corp. (Unitil Power), Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service), Unitil Water Corp. (Unitil Water), and its non-regulated business unit Unitil Resources, Inc. (Unitil Resources).

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

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

Granite State is an interstate 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 gas pipelines and access to domestic gas supplies in the south and Canadian gas supplies in the north. Granite State derives its revenues principally from transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.

A sixth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy, but ceased being the wholesale supplier of Unitil Energy with the implementation of industry restructuring and divested its long-term power supply contracts.

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

Basis of Presentation - The accompanying unaudited consolidated financial statements of Unitil have been prepared in accordance with the instructions to Form 10-Q and include the information and footnotes required by generally accepted accounting principles. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. The results of operations for the three months ended March 31, 2026 are not necessarily indicative of results to be expected for the year ending December 31, 2026. For additional information, refer to Note 1 of Part II to the Consolidated Financial Statements – “Summary of Significant Accounting Policies” of the Company’s Form 10-K for the year ended December 31, 2025, as filed with the Securities and Exchange Commission (SEC) on February 9, 2026, for a description of the Company’s Basis of Presentation.

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.

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

Table of Contents

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 980-605-25-3, 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 980-605-25-4. 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.


	Three Months Ended March 31, 2026
Electric and Gas Operating Revenues (millions):	Electric			Gas			Total
Billed and Unbilled Revenue:
Residential	$	38.4		$	63.9		$	102.3
Commercial and Industrial		27.2			87.4			114.6
Other		6.1			4.6			10.7
Total Billed and Unbilled Revenue		71.7			155.9			227.6
Rate Adjustment Mechanism Revenue		(6.2	)		(4.5	)		(10.7	)
Total Electric and Gas Operating Revenues	$	65.5		$	151.4		$	216.9


	Three Months Ended March 31, 2025
Electric and Gas Operating Revenues (millions):	Electric			Gas			Total
Billed and Unbilled Revenue:
Residential	$	33.2		$	55.8		$	89.0
Commercial and Industrial		23.4			70.3			93.7
Other		4.2			8.2			12.4
Total Billed and Unbilled Revenue		60.8			134.3			195.1
Rate Adjustment Mechanism Revenue		(0.6	)		(23.7	)		(24.3	)
Total Electric and Gas Operating Revenues	$	60.2		$	110.6		$	170.8

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

Income Taxes - The Company is subject to Federal and State income taxes and various other business taxes. The Company’s process for determining income tax amounts involves estimating the Company’s current tax liabilities and 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 Financial Accounting Standards Board (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 jurisdiction 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

Table of Contents

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.

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. As of March 31, 2026, March 31, 2025 and December 31, 2025, the Unitil subsidiaries had deposited $8.7 million, $6.6 million and $8.5 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 reflects management’s assessment of current and expected economic conditions, customer trends, or other factors such as the extent and duration of any shutoff or collection moratoriums. The Company also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities which are under traditional cost of service regulation are authorized by regulators to recover the costs of the energy commodity portion of bad debts through rate mechanisms. Also, the electric and gas divisions of Fitchburg are authorized to recover through rates past due amounts associated with protected hardship accounts. Evaluating the adequacy of the allowance for doubtful accounts requires judgment about the assumptions used in the analysis. The Company’s experience has been that the assumptions used in evaluating the adequacy of the allowance for doubtful accounts have proven to be reasonably accurate.

The Allowance for Doubtful Accounts as of March 31, 2026, March 31, 2025 and December 31, 2025, was as follows:


	March 31,				December 31,
(millions)	2026		2025		2025
Allowance for Doubtful Accounts	$	2.8	$	2.9	$	2.2

Accounts Receivable, Net includes $2.7 million, $2.8 million, and $2.1 million of the Allowance for Doubtful Accounts at March 31, 2026, March 31, 2025 and December 31, 2025, respectively. Unbilled Revenues, net (a component of Accrued Revenue) includes less than $0.1 million, $0.1 million and less than $0.1 million of the Allowance for Doubtful Accounts at March 31, 2026, March 31, 2025 and December 31, 2025, respectively.

Accrued Revenue - Accrued Revenue includes the current portion of Regulatory Assets and unbilled revenues. The following table shows the components of Accrued Revenue as of March 31, 2026, March 31, 2025 and December 31, 2025.


	March 31,				December 31,
Accrued Revenue (millions)	2026		2025		2025
Regulatory Assets – Current	$	70.6	$	53.7	$	78.1
Unbilled Revenues, net		7.6		6.8		8.9
Total Accrued Revenue	$	78.2	$	60.5	$	87.0

Exchange Gas Receivable - Northern Utilities, Bangor and Fitchburg have gas exchange and storage agreements whereby gas purchases during the months of April through October are delivered to a third party. The third party delivers 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 March 31, 2026, March 31, 2025 and December 31, 2025.


	March 31,				December 31,
Exchange Gas Receivable (millions)	2026		2025		2025
Northern Utilities	$	1.0	$	1.4	$	8.0
Bangor		0.2		—		1.3
Fitchburg		0.2		0.2		0.5
Total Exchange Gas Receivable	$	1.4	$	1.6	$	9.8

Table of Contents

Gas Inventory - The Company uses the weighted average cost methodology to value gas inventory. The following table shows the components of Gas Inventory as of March 31, 2026, March 31, 2025 and December 31, 2025.


	March 31,				December 31,
Gas Inventory (millions)	2026		2025		2025
Natural Gas	$	—	$	—	$	0.4
Propane		0.2		0.3		0.4
Liquefied Natural Gas & Other		0.4		0.1		0.5
Total Gas Inventory	$	0.6	$	0.4	$	1.3

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 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 March 31, 2026, March 31, 2025 and December 31, 2025, the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations, were estimated to be $156.5 million, $143.9 million, and $153.0 million, respectively.

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).

Regulatory Accounting - The Company’s principal business is the distribution of electricity and natural gas. 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, Northern Utilities is regulated by the Maine Public Utility Commission (MPUC) and NHPUC, Bangor is regulated by the MPUC and Maine Natural is regulated by the MPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the FASB Codification. The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission. The electric and gas divisions of Fitchburg are authorized to recover through rates past due amounts associated with hardship accounts that are protected from shut-off. As of March 31, 2026, March 31, 2025 and December 31, 2025, the Company has recorded $9.5 million, $8.2 million and $8.9 million, respectively, of hardship accounts in Regulatory Assets. These amounts are included in “Other Deferred Charges” in the following table. The Company currently receives recovery in rates or expects to receive recovery of these hardship accounts in future rate cases.


	March 31,				December 31,
Regulatory Assets consist of the following (millions)	2026		2025		2025
Energy Supply and Other Rate Adjustment Mechanisms	$	64.0	$	49.1	$	73.1
Retirement Benefits		14.1		19.5		14.6
Environmental		10.1		9.4		10.0
Deferred Storm Charges		5.1		7.7		6.0
Income Taxes		0.3		0.9		0.4
Other Deferred Charges		16.1		14.3		12.8
Total Regulatory Assets		109.7		100.9		116.9
Less: Current Portion of Regulatory Assets(1)		70.6		53.7		78.1
Regulatory Assets – noncurrent	$	39.1	$	47.2	$	38.8

(1)

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

Table of Contents


	March 31,				December 31,
Regulatory Liabilities consist of the following (millions)	2026		2025		2025
Income Taxes (Note 9)	$	50.4	$	50.3	$	51.1
Rate Adjustment Mechanisms & Other		16.6		20.4		11.1
Derivative Assets		20.2		—		17.7
Retirement Benefits		1.2		5.8		0.9
Total Regulatory Liabilities		88.4		76.5		80.8
Less: Current Portion of Regulatory Liabilities		23.4		23.8		16.7
Regulatory Liabilities – noncurrent	$	65.0	$	52.7	$	64.1

Generally, the Company receives a return on investment on its regulatory assets for which a cash outflow has been made. Included in Regulatory Assets as of March 31, 2026 are $8.6 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.

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

The Company has contracts that meet the definition of derivatives (see Note 6 Derivatives). Derivatives are recognized on the balance sheet at fair value as either assets or liabilities. The Company considers the amount of the derivative expected to be settled within the next twelve months as current and the remainder as long-term. Derivative instruments are presented on a gross basis in the consolidated balance sheets. Cash flows related to derivative settlements are classified as operating activities in the consolidated statements of cash flows. Regulatory assets or liabilities are recorded to offset the fair value of derivatives, as contract settlement amounts are tracked and reconciled as a pass-through to customers. Costs associated with the Purchase Power Agreement (PPA) are approved by the MDPU to be passed through to customers through the Company’s Long-Term Renewable Contract Adjustment Clause tariff and accounted for per FASB Accounting Standard Codification 980, Regulated Operations. Unrealized gains or losses resulting from the change in fair value are not recognized in the income statement. Instead, they are deferred and recorded as a regulatory asset for losses or a regulatory liability for gains.

The Company recognizes an environmental attribute asset at the allocated contract cost upon receipt of the associated certificates in the applicable registry and derecognizes the asset upon retirement, at which time the related cost is recognized in Cost of Electric Sales, which are tracked and reconciled costs as pass-through to customers. Please see Note 6 (Derivatives) for additional information.

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

At March 31, 2026, March 31, 2025 and December 31, 2025, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, was $6.5 million, $6.1 million and $6.7 million, respectively, as shown in the following table. These investments are valued based on quoted prices from active markets and are categorized in

Table of Contents

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 Expense, Net.


	March 31,				December 31,
Fair Value of Marketable Securities (millions)	2026		2025		2025
Money Market Funds	$	3.1	$	2.0	$	3.2
Fixed Income Funds		3.4		4.1		3.5
Total Marketable Securities	$	6.5	$	6.1	$	6.7

The Company also sponsors the Unitil Corporation Deferred Compensation Plan (the “DC Plan”). The DC Plan is a non-qualified deferred compensation plan that provides a vehicle for participants to accumulate tax-deferred savings to supplement retirement income. The DC Plan, which was effective January 1, 2019, is open to senior management or other highly compensated employees as determined by the Company’s Board of Directors, and may also be used for recruitment and retention purposes for newly hired senior executives. The DC Plan design mirrors the Company’s Tax Deferred Savings and Investment Plan formula, but provides for contributions on compensation above the IRS limit, which will allow participants to defer up to 85% of base salary, and up to 85% of any cash incentive for retirement. The Company may also elect to make discretionary contributions on behalf of any participant in an amount determined by the Company’s Board of Directors. A trust has been established to invest the funds associated with the DC Plan.

At March 31, 2026, March 31, 2025 and December 31, 2025, the fair value of the Company’s investments in these trading securities related to the DC Plan, which are recorded on the Consolidated Balance Sheets in Other Assets, were $3.9 million, $2.5 million and $3.5 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 Expense, Net.


	March 31,				December 31,
Fair Value of Marketable Securities (millions)	2026		2025		2025
Equity Funds	$	3.5	$	2.3	$	3.1
Fixed Income Funds		0.3		0.1		0.3
Money Market Funds		0.1		0.1		0.1
Total Marketable Securities	$	3.9	$	2.5	$	3.5

Goodwill - In January 2025, the Company completed the acquisition of Bangor Natural Gas Company resulting in the recognition of $1.6 million of goodwill. In October 2025, the Company completed the acquisition of Maine Natural Gas Corporation resulting in the recognition of $2.7 million of goodwill. Goodwill is tested for impairment at least annually, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. The Company performs the annual impairment assessment of goodwill on November 1 for the gas reporting unit. The Company generally uses a qualitative analysis assessment to determine if it was more likely than not that the fair value of the reporting unit exceeded its carrying value, including goodwill. The qualitative assessment did not identify any triggering events that would indicate potential impairment of the reporting unit. Therefore, it was determined that the fair value of the reporting unit exceeded its carrying value and no goodwill impairments were recognized during the three months ended March 31, 2026.

Energy Supply Obligations - The following discussion and table summarize the nature and amounts of the items recorded as Energy Supply Obligations (current portion) and Other Noncurrent Liabilities (noncurrent portion) on the Company’s Consolidated Balance Sheets.


	March 31,				December 31,
Energy Supply Obligations (millions)	2026		2025		2025
Current:
Exchange Gas Obligation	$	1.2	$	2.9	$	9.3
Renewable Energy Portfolio Standards		2.3		3.3		2.3
Total Energy Supply Obligations	$	3.5	$	6.2	$	11.6

Exchange Gas Obligation - Northern Utilities and Bangor enter into gas exchange agreements under which Northern Utilities and Bangor release certain gas pipeline and storage assets, resell the gas storage inventory to an asset manager and subsequently repurchase the inventory over the course of the natural gas heating season at the same price at which they sold the 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.

Table of Contents

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

Fitchburg has entered into long-term renewable contracts for the purchase of its pro rata share of clean energy and/or RECs under statewide procurement processes pursuant to Massachusetts legislation. The generating facilities associated with some of these contracts have been constructed and are now operating. Please see Note 7 (Regulatory Matters: Fitchburg - Massachusetts Request for Proposals) for additional details.

Recently Issued Pronouncements - In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures, and in January 2025, the FASB issued ASU 2025-01, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures: Clarifying the Effective Date. ASU 2024-03 requires public entities to disclose, in the notes to financial statements, certain costs and expenses, such as purchases of inventory, employee compensation, and costs related to depreciation and amortization. ASU 2024-03, as clarified by ASU 2025-01, is effective for the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2027, and subsequent interim periods, with early adoption permitted. The Company is currently evaluating the impact of these standards on its Consolidated Financial Statement disclosures.

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

In connection with this acquisition, the Company recorded $66.7 million of net utility plant, $3.8 million working capital, $1.6 million goodwill, $0.2 million noncurrent assets and $0.9 million noncurrent regulatory liabilities.

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

Acquisition of Maine Natural Gas Corporation - On October 31, 2025, the Company acquired all issued and outstanding shares of Maine Natural for $91.1 million. Through this acquisition, the Company expanded its service territory to include approximately 6,300 customers in the Portland area of central Maine, as well as the capital city of Augusta.

In connection with this acquisition, the Company recorded $82.1 million of net utility plant, $8.4 million working capital, $2.7 million goodwill, $1.4 million noncurrent assets and $3.5 million noncurrent regulatory liabilities.

Goodwill represents the amount by which the purchase price exceeds the estimated fair value of the net assets acquired. The goodwill related to Maine Natural is partially tax-deductible. The tax-deductible portion of goodwill is $1.9 million and will be amortized over 15 years.

In connection with Unitil’s acquisition of Maine Natural, the Company entered into a Transition Service Agreement (TSA) dated October 31, 2025 between Maine Natural and Avangrid Service Company (Avangrid). Pursuant to the TSA, Avangrid will provide Maine Natural with certain services at cost, for up to 12 months, in order to continue the operations and maintenance of Maine Natural substantially consistent with past practices until Unitil has completed the successful transition. The Company has recorded $0.3 million of TSA costs for the three months ended March 31, 2026.

Acquisition of Aquarion Water Companies - On May 6, 2025, Unitil entered into a definitive agreement to acquire Aquarion Water Company of Massachusetts, Inc., Aquarion Water Company of New Hampshire, Inc., and Abenaki Water Co., Inc. (the Aquarion Companies) from the Aquarion Water Authority (AWA), a quasi-public corporation and political subdivision of the State of

Table of Contents

Connecticut and a standalone, newly created water authority alongside the South Central Connecticut Regional Water Authority subject to certain closing adjustments. The aggregate enterprise value of the sale is approximately $100.0 million, which includes approximately $70.0 million in cash and the assumption of approximately $30.0 million of debt. The transaction has been approved, subject to certain conditions, by the MDPU, the NHPUC and the MPUC. The acquisition of the Aquarion Companies is contingent upon the initial sale of Aquarion by Eversource to the AWA, which is still pending. (See Note 7 Regulatory Matters: Unitil Corporation – Merger of Aquarion Water Companies.)

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, except for the Fitchburg issuance of $40.0 million of notes on April, 30, 2026, as disclosed in Note 4 (Debt and Financing Arrangements) and the procedural Order received in the distribution base rate case for Unitil Energy approving permanent rates on April 27, 2026, as disclosed in Note 7 (Regulatory Matters), that would result in adjustment to or disclosure in its Consolidated Financial Statements.

Note 2 - Dividends Declared Per Share


Declaration Date	Date Paid (Payable)	Shareholder of Record Date	Dividend Amount
04/29/26	05/26/26	05/14/26	$	0.475
01/28/26	02/27/26	02/12/26	$	0.475
10/29/25	11/28/25	11/13/25	$	0.450
07/29/25	08/28/25	08/14/25	$	0.450
04/30/25	05/30/25	05/15/25	$	0.450
01/29/25	02/28/25	02/13/25	$	0.450

note 3 - Segment Information

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

Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capital regions of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area, portions of central Maine including Augusta and the Bangor area, and in the greater Fitchburg area of north central Massachusetts. Unitil has five distribution utility subsidiaries: Unitil Energy, which operates in New Hampshire; Fitchburg, which operates in Massachusetts; Northern Utilities, which operates in New Hampshire and Maine; Bangor, which operates in Maine; and Maine Natural, which operates in Maine. Unitil Energy and the electric division of Fitchburg are included in the electric segment. Northern Utilities, Bangor, Maine Natural and the gas division of Fitchburg are included in the gas segment. Unitil Energy, Fitchburg, Northern Utilities, Bangor and Maine Natural have a well-diversified customer mix and are not dependent on a single customer, or a few customers, for their electric and natural gas sales. Granite State is an interstate natural gas transmission pipeline company, operating 85 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transmission services provided to Northern Utilities and, to a lesser extent, third-party marketers. Granite State is included in the utility gas operations segment.

Unitil (the holding company), and Unitil Resources are included in the “Other” category (ASC 280-10-50-15). The holding company has no operating income of its own. The earnings of the holding company are principally derived from income earned on short-term investments. Unitil Resources is the Company’s wholly owned non-regulated subsidiary and currently does not have any activity. Unitil Service provides centralized management and administrative services, including information systems management and financial record keeping, to support the affiliated Unitil companies. Unitil Realty owns certain real estate, principally the Company’s corporate headquarters in Hampton, New Hampshire and land in Kingston, New Hampshire, which holds Unitil Energy's solar facility. Unitil

Table of Contents

Service’s and Unitil Realty’s costs are allocated to the Electric and Gas segments based on cost allocation factors. Unitil Water does not have any activity.

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

The following table provides significant segment financial data for the three months ended March 31, 2026 and March 31, 2025.


	Electric			Gas			Total Reportable Segments			Other			Total
Three Months Ended March 31, 2026 (millions)
Total Operating Revenues	$	65.5		$	151.4		$	216.9		$	—		$	216.9
Energy Supply Costs		35.9			69.3			105.2			—			105.2
Operation and Maintenance		9.9			14.2			24.1			(0.7	)		23.4
Depreciation and Amortization		8.3			15.0			23.3			—			23.3
Other Segment Expenses (Income)		3.6			5.5			9.1			—			9.1
Interest Income		(0.6	)		(0.8	)		(1.4	)		(0.1	)		(1.5	)
Interest Expense		4.1			6.9			11.0			1.3			12.3
Provision for Income Taxes		0.9			11.2			12.1			(0.2	)		11.9
Net Income Attributable to Common Shares		3.4			30.1			33.5			(0.3	)		33.2

Segment Assets		752.4			1,371.2			2,123.6			32.2			2,155.8
Capital Expenditures		20.7			11.7			32.4			—			32.4

Three Months Ended March 31, 2025 (millions)
Total Operating Revenues	$	60.2		$	110.6			170.8		$	—		$	170.8
Energy Supply Costs		32.7			39.7			72.4			—			72.4
Operation and Maintenance		9.5			12.1			21.6			1.0			22.6
Depreciation and Amortization		7.9			13.8			21.7			—			21.7
Other Segment Expenses (Income)		3.2			4.8			8.0			—			8.0
Interest Income		(0.8	)		(0.8	)		(1.6	)		—			(1.6	)
Interest Expense		3.4			6.1			9.5			1.2			10.7
Provision for Income Taxes		0.7			9.4			10.1			(0.6	)		9.5
Net Income Attributable to Common Shares		3.6			25.5			29.1			(1.6	)		27.5

Segment Assets		669.6			1,188.5			1,858.1			32.6			1,890.7
Capital Expenditures		21.2			11.4			32.6			—			32.6

Table of Contents

Note 4 - Debt AND FINANCING ARRANGEMENTS

Details on long-term debt at March 31, 2026, March 31, 2025 and December 31, 2025 are shown below.


(millions)	March 31,				December 31,
	2026		2025		2025
Unitil Corporation:
3.70% Senior Notes, Due August 1, 2026	$	30.0	$	30.0	$	30.0
3.43% Senior Notes, Due December 18, 2029		30.0		30.0		30.0
5.99% Senior Notes, Due August 21, 2034		20.0		20.0		20.0
Unitil Energy First Mortgage Bonds:
6.96% Senior Secured Notes, Due September 1, 2028		6.0		8.0		6.0
8.00% Senior Secured Notes, Due May 1, 2031		9.0		10.5		9.0
6.32% Senior Secured Notes, Due September 15, 2036		15.0		15.0		15.0
3.58% Senior Secured Notes, Due September 15, 2040		27.5		27.5		27.5
4.18% Senior Secured Notes, Due November 30, 2048		30.0		30.0		30.0
5.69% Senior Secured Notes, Due August 21, 2054		40.0		40.0		40.0
Fitchburg:
3.52% Senior Notes, Due November 1, 2027		10.0		10.0		10.0
7.37% Senior Notes, Due January 15, 2029		3.6		4.8		4.8
5.90% Senior Notes, Due December 15, 2030		15.0		15.0		15.0
7.98% Senior Notes, Due June 1, 2031		14.0		14.0		14.0
5.70% Senior Notes, Due July 2, 2033		12.0		12.0		12.0
5.54% Senior Notes, Due August 21, 2034		12.5		12.5		12.5
3.78% Senior Notes, Due September 15, 2040		27.5		27.5		27.5
5.99% Senior Notes, Due August 21, 2044		12.5		12.5		12.5
4.32% Senior Notes, Due November 1, 2047		15.0		15.0		15.0
5.96% Senior Notes, Due July 2, 2053		13.0		13.0		13.0
Northern Utilities:
3.52% Senior Notes, Due November 1, 2027		20.0		20.0		20.0
5.54% Senior Notes, Due August 21, 2034		25.0		25.0		25.0
7.72% Senior Notes, Due December 3, 2038		50.0		50.0		50.0
5.74% Senior Notes, Due August 21, 2039		15.0		15.0		15.0
3.78% Senior Notes, Due September 15, 2040		40.0		40.0		40.0
4.42% Senior Notes, Due October 15, 2044		50.0		50.0		50.0
4.32% Senior Notes, Due November 1, 2047		30.0		30.0		30.0
4.04% Senior Notes, Due September 12, 2049		40.0		40.0		40.0
Bangor:
5.70% Senior Notes, Due July 8, 2030		14.0		—		14.0
6.31% Senior Notes, Due July 8, 2035		18.0		—		18.0
Granite State:
3.72% Senior Notes, Due November 1, 2027		15.0		15.0		15.0
5.74% Senior Notes, Due August 21, 2034		10.0		10.0		10.0
Unitil Realty Corp.:
2.64% Senior Secured Notes, Due December 18, 2030		3.5		3.7		3.5
Total Long-Term Debt		673.1		646.0		674.3
Less: Unamortized Debt Issuance Costs		3.8		3.9		3.8
Total Long-Term Debt, net of Unamortized Debt Issuance Costs		669.3		642.1		670.5
Less: Current Portion		37.9		4.9		37.9
Total Long-term Debt, Less Current Portion	$	631.4	$	637.2	$	632.6

Fair Value of Long-Term Debt - Currently, the Company believes 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

Table of Contents

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.


	March 31,				December 31,
Estimated Fair Value of Long-Term Debt (millions)	2026		2025		2025
Estimated Fair Value of Long-Term Debt	$	615.2	$	590.9	$	623.4

On September 29, 2022, the Company entered into a Third Amended and Restated Credit Agreement with a syndicate of lenders (collectively, the "Credit Facility”), which amended and restated the prior facility in full and on January 29, 2025, the Company executed an amendment that increased the borrowing limit under the Credit Facility from $200 million to $275 million and extended the maturity date from September 29, 2027 to September 29, 2028. Unitil may borrow under the Credit Facility through September 29, 2028, with the option for two additional one-year extensions under certain circumstances. The Credit Facility provides for a $275 million borrowing limit, including a $25 million sublimit for standby letters of credit and permits Unitil to increase the borrowing limit by up to an additional $75 million under certain circumstances. Borrowings under the Credit Facility may bear interest at various options, including a daily fluctuating rate equal to the forward-looking one-month secured overnight financing rate (SOFR) term rate (as administered by the Federal Reserve Bank of New York), plus 0.1000%, plus a margin ranging from 1.125% to 1.375% based on Unitil’s credit rating.

The Company accesses the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $112.9 million for the three months ended March 31, 2026. Total gross repayments were $110.6 million for the three months ended March 31, 2026. The following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of March 31, 2026, March 31, 2025 and December 31, 2025:


	Revolving Credit Facility (millions)
	March 31,				December 31,
	2026		2025		2025
Limit	$	275.0	$	275.0	$	275.0
Short-Term Borrowings Outstanding		172.0		172.9		169.7
Available	$	103.0	$	102.1	$	105.3

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 incur 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 March 31, 2026, March 31, 2025 and December 31, 2025, the Company was in compliance with the covenants contained in the Credit Facility in effect on those dates.

The average interest rates on all short-term borrowings and intercompany money pool transactions were 4.9% and 5.6% for the three months ended March 31, 2026 and March 31, 2025, respectively. The average interest rate on all short-term borrowings for the twelve months ended December 31, 2025 was 5.4%.

Table of Contents

Rate plus an applicable margin of 0.25% or based on a one-month Term SOFR plus a SOFR adjustment of 0.10% plus an applicable margin of 1.25%. The Base Rate is equal to the highest of the (a) Federal Funds Rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by The Bank of Nova Scotia as its "prime rate", or (c) one-month Term SOFR plus a SOFR adjustment of 0.10% plus 1.00%. The facility has a maturity date of October 31, 2026.

Guarantees

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 three months ended March 31, 2026 and March 31, 2025 amounted to $0.6 million and $0.6 million, respectively.

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


	March 31,				December 31,
Lease Obligations (millions)	2026		2025		2025
Operating Lease Obligations:
Operating Lease Obligations (current portion)	$	2.0	$	1.8	$	2.1
Operating Lease Obligations (long-term portion)		4.5		4.4		4.9
Total Operating Lease Obligations		6.5		6.2		7.0
Capital Lease Obligations:
Other Current Liabilities (current portion)		0.2		0.1		0.2
Other Noncurrent Liabilities (long-term portion)		0.4		0.3		0.4
Total Capital Lease Obligations		0.6		0.4		0.6
Total Lease Obligations	$	7.1	$	6.6	$	7.6

Cash paid for amounts included in the measurement of operating lease obligations for the three months ended March 31, 2026 and March 31, 2025 was $0.6 million and $0.6 million and was included in Cash Provided by Operating Activities on the Consolidated Statements of Cash Flows.

Assets under capital leases amounted to approximately $0.9 million, $0.6 million and $0.9 million as of March 31, 2026, March 31, 2025 and December 31, 2025, respectively, less accumulated amortization of $0.3 million, $0.1 million and $0.3 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheets.

The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of March 31, 2026. The payments for operating leases consist of $2.0 million of current Operating Lease Obligations and $4.5 million of noncurrent Operating Lease Obligations on the Company’s Consolidated Balance Sheets as of March 31, 2026. The payments for capital leases consist of $0.2 million of current capital lease obligations, which are included in Other Current Liabilities

Table of Contents

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 March 31, 2026.


Lease Payments ($000’s)	Operating		Capital
Year Ending December 31,	Leases		Leases
Rest of 2026	$	1,787	$	158
2027		2,082		197
2028		1,521		112
2029		1,150		89
2030		491		53
2031 - 2035		161		—
Total Payments		7,192		609
Less: Interest		682		50
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$	6,510	$	559

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 March 31, 2026, the weighted average remaining lease term is 3.6 years and the weighted average operating discount rate used to determine the operating lease obligations was 5.3%. As of March 31, 2025, the weighted average remaining lease term was 4.0 years and the weighted average operating discount rate used to determine the operating lease obligations was 5.1%.

Note 5 – equity

Common Stock

The Company’s common stock trades on the New York Stock Exchange under the symbol, “UTL.”

The Company had 17,989,863, 16,250,032 and 17,919,191 shares of common stock outstanding at March 31, 2026, March 31, 2025 and December 31, 2025, respectively.

The following table summarizes the Company's common shares activity for the three months ended March 31, 2026:


Common Stock	Shares
Shares as of December 31, 2025		17,919,191
Shares Issued - DRP		6,123
Shares Issued - Time Restricted		32,330
Shares Issued - Performance Restricted		33,150
Forfeited Shares - Time Restricted		—
Forfeited Shares - Performance Restricted		(931	)
Shares as of March 31, 2026		17,989,863

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

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

During the year ended December 31, 2025, the Company sold 27,620 shares of common stock under the ATM program at an average price of $53.00 per share, resulting in gross proceeds of $1.5 million and net proceeds of $1.4 million after deducting commissions and offering expenses. During the three months ended March 31, 2026, the Company sold zero shares of common stock under the ATM program. As of March 31, 2026, $48.5 million remains available for future sales under the program.

Table of Contents

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

Dividend Reinvestment and Stock Purchase Plan - During the first three months of 2026, the Company sold 6,123 shares of its common stock, at an average price of $51.69 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $316,000. 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.

Stock Plan - The Company maintains the Unitil Corporation Third 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); 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 May 1, 2024, 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 was 1,027,500 as of March 31, 2026. 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.

On January 27, 2026, there were 32,330 Time Restricted Shares issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of approximately $1.6 million. There were 24,703 and 25,170 non-vested Time Restricted Shares under the Stock Plan as of March 31, 2026 and 2025, respectively. The weighted average grant date fair value of these shares was $50.71 and $50.85 per share, respectively. The compensation expense associated with the issuance of Time Restricted Shares under the Stock Plan is recognized over the vesting period and was $1.5 million and $1.2 million for the three months ended March 31, 2026 and 2025, respectively. At March 31, 2026, there was approximately $1.5 million of total unrecognized compensation cost for Time Restricted Shares under the Stock Plan which is expected to be recognized over approximately 3.2 years. During the three months ended March 31, 2026 there were zero Time Restricted Shares forfeited and zero Time Restricted Shares cancelled under the Stock Plan.

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.

Table of Contents

The Performance Restricted Shares issued in January 2023 were fully vested as of December 31, 2025. During the first quarter, an additional 820 shares were awarded due to exceeding certain goals and 931 shares were forfeited due to retirements. The compensation expense associated with the additional shares was less than $0.1 million for the three months ended March 31, 2026.

On January 26, 2026, there were 32,330 Performance Restricted Shares issued under the Stock Plan with an aggregate market value of $1.6 million. There were 81,180 and 67,380 non-vested Performance Restricted Shares under the Stock Plan as of March 31, 2026 and 2025, respectively. The weighted average grant date fair value of these shares was $50.58 and $51.21 per share, respectively. The compensation expense associated with the issuance of Performance Restricted Shares under the Stock Plan is recognized over the vesting period and was $0.5 million and $0.4 million for the three months ended March 31, 2026 and March 31, 2025, respectively. At March 31, 2026, there was approximately $3.4 million of total unrecognized compensation cost for Performance Restricted Shares under the Stock Plan which is expected to be recognized over approximately 2.2 years. During the three months ended March 31, 2026 there were zero Performance Restricted Shares forfeited and zero Performance Restricted Shares cancelled under the Stock Plan.

The Time Restricted Shares and Performance Restricted Shares unvested activity during the three months ended March 31, 2026 in conjunction with the Stock Plan is presented in the following table:


	Time Restricted Shares					Performance Restricted Shares
	Units			Weighted Average Stock Price		Units			Weighted Average Stock Price
Restricted Shares as of December 31, 2025		17,883		$	50.94		67,380		$	51.21
Granted		—		$	—		820		$	51.83
Shares Issued		(6,460	)	$	49.89		(18,419	)	$	51.83
Forfeited		—		$	—		(931	)	$	51.83
Restricted Shares as of March 31, 2026		11,423		$	50.71		48,850		$	50.97

Restricted Stock Units

Non-management members of the Company’s Board of Directors (Directors) may elect to receive the equity portion of their annual retainer in the form of Restricted Stock Units (RSU). Restricted Stock Units earn dividend equivalents and will generally be settled by payment to each Director as soon as practicable following the Director’s separation from service to the Company. The Restricted Stock Units will be paid such that the Director will receive (i) 70% of the shares of the Company’s common stock underlying the restricted stock units and (ii) cash in an amount equal to the fair market value of 30% of the shares of the Company’s common stock underlying the Restricted Stock Units. The equity and liability portions of Restricted Stock Units activity during the three months ended March 31, 2026 in conjunction with the Stock Plan is presented in the following table:


Restricted Stock Units	(Equity Portion)				(Liability Portion)
	Units		Weighted Average Stock Price		Units		Weighted Average Stock Price
Restricted Stock Units as of December 31, 2025		36,052	$	45.17		15,450	$	48.44
Restricted Stock Units Granted		—	$	—		—	$	—
Dividend Equivalents Earned		327	$	52.31		141	$	52.31
Restricted Stock Units Settled		—	$	—		—	$	—
Restricted Stock Units as of March 31, 2026		36,379	$	45.23		15,591	$	52.24

There were 36,930 Restricted Stock Units outstanding as of March 31, 2025 with a weighted average stock price of $44.25. Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of March 31, 2026, March 31, 2025 and December 31, 2025 is $0.8 million, $0.9 million and $0.9 million, respectively, representing the fair value of liabilities associated with the portion of fully vested RSUs that will be settled in cash.

Preferred Stock

There were $0.2 million, or 1,727 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of March 31, 2026, March 31, 2025 and December 31, 2025. There were less than $0.1 million of total dividends declared on Preferred Stock in the three months ended March 31, 2026 and March 31, 2025, respectively.

Table of Contents

Earnings Per Share

Unitil has granted restricted stock awards prior to December 31, 2025 and restricted stock units with non-forfeitable dividend rights, which are considered participating securities. Restricted stock awards granted after January 1, 2026 have forfeitable dividend rights and are considered non-participating securities. Accordingly, earnings per share are computed using the two-class method as required by FASB ASC 260-10-45. Basic earnings per common share are calculated by dividing net income allocated to common shareholders by the weighted average number of common shares outstanding during the period, which excludes the participating securities. Diluted earnings per common share are adjusted for the dilutive effects of restricted stock.

The following table reconciles basic and diluted earnings per share:


	Three Months Ended
Earnings Per Share (millions, except shares and per share data)	March 31, 2026		March 31, 2025
Net Income	$	33.2	$	27.5
Less allocation of earnings and dividends to participating securities		0.2		0.2
Net income allocated to common shareholders	$	33.0	$	27.3

Weighted average common shares outstanding, gross		17,962,481		16,263,313
Less average participating securities		88,241		108,377
Weighted average number of shares outstanding used in the calculation of basic earnings per share		17,874,240		16,154,936
Add dilutive effect of:
Restricted stock and restricted stock units		3,407		3,639
Adjusted weighted average number of shares outstanding used in the calculation of diluted earnings per common share		17,877,647		16,158,575

Earnings per common share:
Basic	$	1.85	$	1.69
Diluted	$	1.85	$	1.69

NOTE 6: DERIVATIVES

In 2018, Fitchburg entered into a long-term power purchase agreement (PPA) with H.Q. Energy Services (U.S.) Inc. (HQUS) to procure bundled clean energy and associated environmental attributes pursuant to Section 83D of “An Act to Promote Energy Diversity” (2016). The PPA requires Fitchburg to purchase specified quantities of electric energy over the 20-year contract term and provides for the transfer of associated environmental attributes. (See Note 7 Regulatory Matters: Fitchburg - Massachusetts Request for Proposals.)

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

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

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

Table of Contents

The fair value of the derivative was $20.2 million and $17.7 million as of March 31, 2026 and December 31, 2025, respectively, with $3.9 million and $2.8 million recorded in Prepayments and Other related to the current portion and $16.3 million and $14.9 million in Other Assets related to the noncurrent portion. The Company has recorded corresponding Current and Noncurrent Regulatory Liabilities related to the fair value of the derivative. No derivative assets or liabilities were recognized as of March 31, 2025. The Company does not offset derivative assets and liabilities in the balance sheet.

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

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

note 7 – REgulatory Matters

Unitil’s Regulatory matters are described in Note 8 to the Financial Statements in Item 8 of Part II of Unitil Corporation’s Form 10-K for December 31, 2025 as filed with the Securities and Exchange Commission on February 9, 2026.

Rate Case Activity

Northern Utilities - Base Rates - Maine - On April 1, 2026, Northern Utilities’ Maine Division filed a Notice of Intent to File a General Rate Case with the MPUC. The Company plans to file its case on or about June 1, 2026. The filing is expected to request an increase in annual base revenues of approximately $7.5 million, or about 6.5% of the Company’s 2025 total operating revenues, including its cost of gas supply. The Company expects to request an overall rate of return on rate base of approximately 7.9%, including an approximate return on equity component of 10.6%.

Northern Utilities - Base Rates - New Hampshire - On April 1, 2026, Northern Utilities’ New Hampshire Division filed for an increase in distribution base rates with the NHPUC. The Company is seeking an increase in base rates of approximately $9.8 million or 9.6% above total annual revenue at present rates. The filing includes a proposed multi-year rate plan, continuation of a revenue decoupling mechanism, and other tariff and rate changes. Northern Utilities also requested implementation of temporary rates for service rendered on and after June 1, 2026, and until a final order on permanent rates is issued. As provided by statute, once a final order on permanent rates is issued, the permanent rate level is reconciled back to the effective date of the temporary rates. The Company requested a temporary rate increase in annual revenues of $6.1 million, or a 5.9% increase above total annual revenue at present rates. On May 1, 2026, a settlement agreement between the Company, the New Hampshire Department of Energy (NH DOE) and the Office of the Consumer Advocate reflecting a temporary rate level of $5.5 million, or 5.4% increase above total annual revenue at present rates was filed with the NHPUC. A hearing on temporary rates has been scheduled for May 12, 2026. This matter remains pending.

Unitil Energy - Base Rates - On April 27, 2026, the NHPUC issued a procedural Order in the distribution base rate case filed with the NHPUC on May 1, 2025 by Unitil Energy. The Order approves the settlement agreement filed on February 24, 2026 between the Company, the NH DOE and the Community Power Coalition of New Hampshire in its entirety.

In addition to authorizing an increase to permanent distribution rates of approximately $13.0 million effective May 1, 2026, the settlement agreement included: (1) a proposed multi-year rate plan, including two annual Step Adjustments to rates on September 1, 2026 and September 1, 2027, to recover total prudent investments completed and placed into service in 2025 and 2026 respectively, subject to a cap 2.50 percent of the Company’s prior year total revenue; (2) a continuation of its revenue decoupling mechanism; (3) an update to the previously approved suite of proposed time of use rates including rates for electric vehicles; (4) resiliency programs to further the Company’s commitment to reliability; (5) an Arrearage Management Program for financial hardship customers; and (6) other rate design and tariff changes. This distribution base rate case reflects the Company’s operating costs and investments in utility plant for a test year ended December 31, 2024 as adjusted for known and measurable changes. The Order provides for an overall cost of capital of 9.32% including a 9.45% return on equity. The increase in permanent rates will be reconciled back to July 1, 2025, the effective date of temporary rates previously approved in this docket, which will begin to be recovered effective August 1, 2026. Unitil Energy will record a net increase to pretax income of $1.7 million in the second quarter of 2026 reflecting the difference between the temporary and permanent rates.

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.

Table of Contents

On August 17, 2023, Fitchburg filed a petition with the MDPU seeking approval for a $6.8 million increase to base distribution rates, with new rates to be effective July 1, 2024. On June 28, 2024, the MDPU issued an Order providing for a $4.7 million increase to base rates, effective July 1, 2024, approving a performance-based ratemaking (PBR) plan for up to a five-year term and continuing the Company’s revenue decoupling mechanism. The Order also provided for a return on equity of 9.4% and a capital structure reflecting 52% equity and 48% long-term debt. Additionally, the MDPU found that allowing the Company to recover pension and PBOP expense through its Pension/PBOP Adjustment mechanism is no longer warranted and that these expenses should be recovered in base distribution rates. On July 18, 2024, the Company filed a Motion for Reconsideration and Recalculation requesting that the MDPU reconsider its decision to require the Company to absorb $1.4 million in negative excess accumulated deferred income taxes (ADIT) because the effect of the Order was to inappropriately claw back amounts that were previously approved by the MDPU for recovery from customers. The amount of $1.4 million is disaggregated between the Company’s gas division ($0.6 million) and the electric division ($0.8 million). The MDPU denied the motion, and on December 9, 2024, the Company filed an appeal with Massachusetts Supreme Judicial Court. This appeal is pending.

Fitchburg - Performance Base Rate Adjustment - Electric - On February 27, 2026, Fitchburg filed its second Performance Based Revenue Adjustment (PBRA) for rates effective July 1, 2026. The calculated PBRA adjustment resulted in a distribution revenue increase of $1.1 million. This matter remains pending.

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. On June 28, 2024, the MDPU issued an Order providing for a $10.1 million increase to base rates, effective July 1, 2024 approving a PBR plan for up to a five-year term and approving a continuation of the Company’s revenue decoupling mechanism subject to certain changes. The Order also provided for a return on equity of 9.4% and a capital structure reflecting 52% equity and 48% long-term debt. Additionally, the MDPU found that allowing the Company to recover pension and PBOP expense through its Pension/PBOP Adjustment mechanism is no longer warranted and that these expenses should be recovered in base distribution rates. On July 18, 2024, the Company filed a Motion for Reconsideration and Recalculation. The MDPU denied the motion and on December 9, 2024, the Company filed an appeal with Massachusetts Supreme Judicial Court. This appeal is pending.

Fitchburg - Performance Base Rate Adjustment - Gas - On February 27, 2026, Fitchburg filed its second PBRA for rates effective July 1, 2026. The calculated PBRA adjustment resulted in a distribution revenue increase of $1.7 million. This matter remains pending.

Fitchburg - Gas System Enhancement Program - Pursuant to statute and MDPU order, Fitchburg has an approved Gas System Enhancement Plan (GSEP) tariff through which it may recover certain gas infrastructure replacement and safety related investment costs, subject to an annual cap. Under the plan, the Company is required to make two annual filings with the MDPU: a forward-looking filing for the subsequent construction year, to be filed on or before October 31; and a filing, submitted on or before May 1, of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably and prudently incurred. The Company filed its most recent forward-looking cumulative revenue requirement filing on October 31, 2025, requesting recovery of approximately $5.4 million with an additional $1.0 million in prior deferrals for a total of approximately $6.4 million to be recovered. On April 30, 2026, the MDPU issued an order approving the filing, in part for rates effective May 1, 2026. The MDPU reduced the revenue cap from 2.5 percent to 2.0 percent, which reduced the Company’s requested recovery of prior deferrals from $1.0 million to $0.7 million. On May 1, 2026, the Company submitted its final project documentation for projects completed in 2025 and requested recovery of the remaining deferral effective November 1, 2026. These matters remain pending.

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

Other Matters

Massachusetts Inquiry into Gas and Electric Delivery Charge and Bill Redesign - On December 15, 2025, the MDPU opened an investigation to conduct a comprehensive review of gas and electric delivery rates and charges with the aims of containing customer costs, reducing utility bill volatility, and increasing utility bill transparency and accessibility. As directed, on February 13, 2026, each Distribution Company submitted a report including certain requested information regarding delivery related reconciling mechanisms

Table of Contents

and costs. Written comments from the Distribution Companies and other interested stakeholders responding to a list of questions regarding delivery related reconciling charges were filed on April 14, 2026. Public comments were filed on April 30, 2026. Reply comments are due on May 14, 2026.

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

Fitchburg - Grid Modernization - On November 20, 2024, the MA Legislature enacted the 2024 Climate Act that requires, among other things, the EDCs to jointly establish a centralized data repository in a cost-effective manner as approved by the MDPU, to allow customers and third parties, including competitive suppliers, access to detailed Advanced Metering Infrastructure (AMI) customer data in near-real time, subject to customer approval and protections. The EDCs jointly proposed an AMI data access protocol implementation plan on February 18, 2026. The Company also submitted a proposal supporting cost recovery of prudent and necessary expenses for the implementation of the repository. This matter is ongoing. On March 12, 2026, the MDPU opened an investigation into the use of AMI interval data to settle load with ISO-NE. On April 23, 2026, parties filed initial comments. This matter also remains pending.

Fitchburg - Grid Modernization Cost Recovery Factor - On April 15, 2025, Fitchburg filed its Grid Modernization Factor (GMF) rate adjustment and reconciliation filing for recovery of the costs incurred as a result of implementing the Company’s 2022-2025 GMP and continued recovery of meter-related costs. This filing seeks recovery of $1.4 million associated with its 2024 GMP revenue requirement as well as $1.5 million associated with its 2024 meter-related costs, effective June 1, 2025. On May 30, 2025, the MDPU issued an order approving the Company’s proposed rate changes effective June 1, 2025 subject to further investigation and reconciliation. On April 15, 2026, Fitchburg filed its GMF rate adjustment and reconciliation filing for recovery of the costs incurred as a result of implementing the Company’s 2022-2025 GMP and continued recovery of meter-related costs. This filing seeks recovery of $1.9 million associated with its 2025 GMP revenue requirement as well as $2.0 million associated with its 2025 meter-related costs, effective June 1, 2026. This matter remains pending.

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

On December 29, 2023, the LDCs filed a Joint Motion for Clarification. The Joint Motion requested clarification of three issues: (1) the MDPU’s directive concerning the NPAs analysis; (2) the timetable for establishing ‘incentives and disincentives’ for progress toward compliance with Climate Act mandates as part of a PBR framework and achievement of approved Climate Compliance Plans; and (3) the methodology for emissions reduction accounting for Climate Compliance Plans, with particular attention to Scope 1 and

Table of Contents

Scope 3 emissions accounting. On April 2, 2024, the MDPU issued an Order on the LDCs’ Joint Motion. In its Order, the MDPU clarified, among other things, that NPA analyses should be applied at the project level to all investment decisions going forward, and should be considered at project planning stage; that pending an approved NPA framework, LDCs should make all reasonable efforts to incorporate NPA analyses into investment decisions; and that LDCs will have the burden to demonstrate the prudence of implementing a traditional project instead of a NPA. The MDPU did not expressly exempt any category of project from the NPA analysis requirement.

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

On April 1, 2025, Fitchburg filed its first CCP. The Company’s plan presents a portfolio of initiatives that will help the Commonwealth meet its decarbonization goals over the next five-to-ten years, while maintaining a focus on customers’ long-term interests in safety, reliability, affordability, and equity. Fitchburg also filed a model CCP Tariff to establish a cost recovery mechanism for the development and implementation of the CCP, including costs associated with assessing and implementing NPAs. This matter remains pending. Hearings occurred in early March 2026.

In its D.P.U. 20-80-B Order, the MDPU directed each LDC to work with the relevant EDC to study the feasibility of piloting a targeted electrification project in its service territory, and to propose at least one demonstration project for decommissioning an area of its system through targeted electrification. On March 16, 2026, Fitchburg filed its proposed Targeted Electrification Pilot Project and Targeted Electrification Pilot Provision in compliance with the Order. The Company proposed implementing its pilot on Maryland Avenue in Fitchburg, MA on a segment of main serving eight customers. The identified segment is scheduled for replacement in 2029. This matter remains pending.

Fitchburg - Electric Sector Modernization Plan - Pursuant to M.G.L. c. 164 § 92B, Fitchburg submitted a draft Electric Sector Modernization Plan (ESMP) to the statutorily created Massachusetts Grid Modernization Advisory Council (Council) for the Council’s review, input, and recommendations. The ESMP is a plan intended to upgrade the Company’s distribution system to enable and accommodate increased distributed energy resources (DERs) and electrification technologies, improve grid reliability and resiliency, and assist the Commonwealth in achieving climate goals, among other objectives. On August 29, 2024, the MDPU issued a final order approving the Company’s ESMP. On March 31, 2026, the Company submitted its Biannual Report summarizing its progress on ESMP investments in the preceding year.

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

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

Table of Contents

Unitil Corporation – Merger of Aquarion Water Companies - On May 6, 2025, Unitil announced that it has entered into a definitive agreement to acquire Aquarion Water Company of Massachusetts Inc., Aquarion Water Company of New Hampshire, Inc., and Abenaki Water Co., Inc. (the Aquarion Companies) from the Aquarion Water Authority (AWA), a quasi-public corporation chartered by the Connecticut General Assembly in 2024 to acquire Aquarion and to operate as a water authority. Unitil’s acquisition of the Aquarion Companies is contingent upon the initial sale of Aquarion by Eversource Energy (Eversource) to the AWA (Initial Transaction), which will then simultaneously convey the Aquarion Companies to Unitil. On November 19, 2025, the Connecticut Public Utilities Regulatory Authority (PURA) denied approval of the Initial Transaction. On December 2, 2025, the joint applicants in the Connecticut proceeding filed a judicial appeal of PURA’s decision denying the Initial Transaction. On January 15, 2026, a decision was issued that remanded the case back to PURA for further deliberation. On March 6, 2026, PURA issued a Proposed Final Decision approving the application for a change of control over Aquarion Company. A Final Decision approving the application was issued on March 25, 2026. The Initial Transaction is still pending.

On May 8, 2025, Eversource, the AWA, and Unitil submitted an amended and restated petition to the MDPU for approval of a change of control of Aquarion Water Company of Massachusetts, Inc. (AWC-MA). On December 12, 2025, the MDPU issued an Order approving the stock sale of Aquarion by Eversource to AWA, and, in turn, AWA’s simultaneous sale of AWC-MA to Unitil. The approval is subject to certain conditions, including quarterly service quality reporting and a two-year rate case filing moratorium. The approval is also contingent upon, inter alia, approval of the Initial Transaction. The MDPU also declined to rule on the issue, raised by the MA Attorney General's Office, of ratemaking treatment of the gain on sale of certain assets that occurred under Eversource ownership. On January 2, 2026, Unitil, Eversource, and AWA filed a motion for reconsideration and clarification of the MDPU’s Order with respect to the rate case moratorium and ratemaking treatment of the gain on sale. The MDPU denied the motion for reconsideration on March 30, 2026.

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

Maine Inquiry Into the Future of Gas - On May 13, 2025, the MPUC initiated an inquiry to explore the implications of Maine’s decarbonization goals for natural gas utilities and their customers and solicit information from stakeholders. Specifically, the MPUC opened the inquiry with the goal of: 1) developing a consistent methodology or framework to incorporate and evaluate the GHG emissions impact in the MPUC’s decision-making around gas infrastructure investments and contractual commitments for supply or capacity needed to serve customers; 2) evaluating the consistency of these investments with state goals; and 3) assisting in evaluation of a broader path for the future of natural gas in Maine. Initial comments on the scope of the inquiry were submitted on June 17, 2025. On December 18, 2025, the MPUC issued a Procedural Order scheduling a workshop on January 21, 2026 to explore issues raised in comments. The Company submitted a second round of comments on March 20, 2026. This matter remains pending.

Reconciliation Filings - Fitchburg, Unitil Energy, Northern Utilities, Bangor and Maine Natural each have a number of regulatory reconciling accounts that require annual or semi-annual filings with the MDPU, NHPUC and MPUC, respectively, to reconcile revenues and costs, and to seek approval of any rate changes. These filings include: annual electric reconciliation filings by Fitchburg and Unitil Energy for a number of items, including default service, stranded cost changes and transmission charges; costs associated with energy efficiency programs in New Hampshire and Massachusetts, as directed by the NHPUC and MDPU; recovery of the ongoing costs of storm repairs incurred by Unitil Energy and Fitchburg; and the actual wholesale energy costs for electric power and gas incurred by each of the five companies. Fitchburg, Unitil Energy, Northern Utilities, Bangor and Maine Natural have been, and remain in full compliance with all directives and orders regarding these filings. The Company considers these to be routine regulatory proceedings, and there are no material issues outstanding.

Fitchburg - Massachusetts Request for Proposals (RFPs) - Pursuant to Section 83 of “An Act Relative to Green Communities,” St. 2008, c. 169, as amended, the Massachusetts EDCs, including Fitchburg, have conducted numerous procurements of long-term renewable energy and environmental attributes. “An Act to Promote Energy Diversity” (2016) (the Act) added Section 83C, which required the joint procurement of 1,600 MW of offshore wind by June 30, 2027 (this target has since been increased as explained below) and Section 83D, which required the joint procurement of cost-effective long-term contracts for an annual total of 9,450,000 megawatt-hours (MWh) of clean energy (hydroelectric, solar and land-based wind) by December 31, 2022. Fitchburg’s pro rata share of the contracts resulting from these procurements is approximately one percent.

Table of Contents

The EDCs issued the RFP for Section 83D Long-Term Contracts in March 2017, and transmission service agreements with NECEC Transmission LLC and power purchase agreements (PPAs) for 9,554,940 MWh annually of hydroelectric generation and associated environmental attributes with Hydro-Quebec Energy Services (U.S.), Inc. (together, the NECEC project) over a 20-year period, were filed for approval by the MDPU in July 2018. The MDPU approved the agreements in June 2019, including the EDCs’ proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market revenue to customers. The MDPU also approved the EDCs’ request for remuneration equal to 2.75% of the contract payments, as well as the EDCs’ proposal to recover costs associated with the contracts. The NECEC project achieved commercial operation on January 16, 2026.

The EDCs issued the first RFP for offshore wind energy generation pursuant to Section 83C in June 2017. In July 2018, the EDCs filed two long-term PPAs with Vineyard Wind, each for 400 MW for approval by the MDPU. In April 2019, the MDPU approved the offshore wind PPAs, including similar requirements for the EDCs to sell the energy procured and credit or charge net costs to customers including EDC remuneration of 2.75%. Vineyard Wind achieved commercial operation for both Facilities on April 24, 2026, at less than 100 percent of project capacity. The developer will continue construction to complete Facility 1 and Facility 2 to the full 800MW.

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

The EDCs issued a fourth offshore wind RFP in August 2023 seeking to procure at least 400 MW and up to the maximum amount remaining of the statutory requirement under Section 83C of 5,600 MW of Offshore Wind Energy Generation, pursuant to “An Act Driving Clean Energy and Offshore Wind” (2022), which increased the total solicitation target (including future solicitations) for offshore wind energy generation to 5,600 MW by June 30, 2027. The EDCs received bids for offshore wind energy generation from three developers as part of a multi-state solicitation with Rhode Island and Connecticut. In September 2024, the DOER selected a portfolio of projects totaling 2,678 MW from the three projects, one of which was dependent on commitments from Connecticut. In December 2024, Connecticut withdrew from contract negotiations resulting in the termination of the conditional project. Contract negotiations with the remaining two developers have been extended and are targeted to conclude by August 31, 2026.

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

Pursuant to Section 82 of Chapter 179 of the Acts of 2022 (An Act driving clean energy and offshore wind), the DOER is authorized to coordinate with other New England states issuing competitive solicitations for long-term clean energy generation, including nuclear power generation, associated environmental attributes, transmission or capacity for the benefit of residents of the Commonwealth and the region. If the DOER, in consultation with the EDCs and the office of the Attorney General, determines not later than December 31, 2027, that a project would satisfy the benefits listed in Section 82, the DOER may direct the EDCs to enter into cost-effective long-term contracts. The DOER is currently exploring procurements issued by Maine and Connecticut. In September 2025, Connecticut issued an Expedited Zero Carbon RFP and following selections made by Connecticut, the DOER selected two projects for Massachusetts. Negotiations between the EDCs and the project developers are underway.

FERC Transmission Formula Rate Proceedings- Pursuant to Section 206 of the Federal Power Act, there are several pending proceedings before the FERC concerning the justness and reasonableness of the Return on Equity (ROE) component of the ISO-New England, Inc. Participating Transmission Owners’ (PTOs) Regional Network Service and Local Network Service formula rates. In August 2013, FERC had found that the Transmission Owners' existing ROE was unlawful, and set a new ROE. On April 14, 2017, the U.S. Court of Appeals for the D.C. Circuit issued an opinion vacating and remanding FERC’s decision, finding that FERC had failed to articulate a satisfactory explanation for its orders. The ROE set in the vacated order was to remain in place until FERC took further action. 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 was granted. On March 19, 2026, the FERC issued an Order in Docket No. EL 11-66 reducing the ROE from 10.57% to 9.57% effective October 1, 2011 and established refund periods of October 1, 2011 to December 31, 2012 and October 16, 2014 to March 19, 2026. Fitchburg recorded a charge of $0.9 million in the three months

Table of Contents

ended March 31, 2026 related to the refund periods. A ROE of 9.57% will be used to calculate transmission revenue requirements effective for the remainder of 2026 and going forward.

The NETOs were directed to file refund reports by April 18, 2026. On April 2, 2026, the NETOs filed a motion to extend the refund deadline and requested an expedited comment period. The motion was granted on April 14, 2026 and set a refund date of May 20, 2027. Refund reports are due June 4, 2027. Also filed on April 2, 2026 was a motion for stay of refund obligations. FERC decisions on this matter is pending. On April 30, 2026, the NETOs submitted a 205 filing at FERC requesting an ROE of 11.39% based on recalculating March 19, 2026 Order results with current data. The Company does not believe these proceedings will have a material effect on its financial condition or results of operations.

On December 13, 2022, RENEW Northeast, Inc. (RENEW), a non-profit entity that advocates for the business interests of renewable power generators in New England filed a complaint with FERC against ISO-NE and the PTOs requesting a determination that certain open-access transmission tariff schedules are unjust and unreasonable to the extent they permit PTOs to directly assign to interconnection customers O&M costs associated with network upgrades. Fitchburg and Unitil Energy are PTOs, although Unitil Energy does not own transmission plant. The PTOs answered the complaint on January 23, 2023. FERC issued an Order December 19, 2024 and a compliance filing was made on February 18, 2025 revising the ISO-NE OATT accordingly. While most of the intervening parties supported the compliance filing a new issue was raised by one participant. RENEW and the NETO’s have resolved their issues and filed briefs in support of the compliance filing. This matter remains pending in Docket No. EL23-16. The Company does not believe these proceedings will have a material effect on its financial condition or results of operations.

Legal Proceedings

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

Note 8 – eNVIRONMENTAL MATTERS

Unitil’s Environmental matters are described in Note 8 to the Financial Statements in Item 8 of Part II of Unitil Corporation’s Form 10-K for December 31, 2025 as filed with the Securities and Exchange Commission on February 9, 2026.

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 March 31, 2026, 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 effect on the Company’s consolidated financial position or results of operations.

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

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

In May 2024, NH DES requested additional information in connection with the Company’s December 2022 remedial action plan (RAP), regarding groundwater contaminants at the Rochester site. In anticipation of the NH DES approval of one of the RAP alternatives and subsequent request for project design, the Company has accrued $5.9 million for estimated costs to complete the remediation at the Rochester site, which is included in Environmental Obligations on the Company’s Consolidated Balance Sheets. Due to extended regulatory review time periods, Northern Utilities anticipates the commencement of remediation activities in late 2026 or 2027.

Table of Contents

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

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

Fitchburg’s Manufactured Gas Plant Site - Fitchburg has worked with the Massachusetts Department of Environmental Protection (Mass DEP) to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring continues. Following submittal of the Immediate Response Action (IRA) plan in October 2023, and an update in November 2024, the Mass DEP, in May 2025, concurred with the proposed limited excavation and armoring of the riverbank at the identified seep area. Fitchburg has accrued $300,000 for estimated costs to complete the remediation at the Sawyer Passway site, which is included in Environmental Obligations on the Company’s Consolidated Balance Sheets. The Company has determined that the high end of the range of reasonably possible remediation costs for the Sawyer Passway site could be $3.7 million based on remediation alternatives. Fitchburg anticipates the commencement of the remediation activity in 2026.

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

Unitil Energy - Kensington Distribution Operations Center - Unitil Energy conducted a Phase I and II supplement environmental site assessment (ESA) in the second quarter of 2021 at its former distribution operations center in Kensington, NH. In November 2025, the NH DES requested additional investigation to further refine the Supplemental Site Investigation (SSI) submitted in June 2023, as well as develop a remedial action plan (RAP) based upon reported observations. Unitil Energy anticipates the commencement of remediation activities in 2027, following RAP approval by the NH DES. In its most recent rate case, Unitil Energy received approval from the NHPUC to create a regulatory asset for the remediation costs

The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the three months ended March 31, 2026 and 2025.


	March 31,
Environmental Obligations (millions)	2026		2025
Total Balance at Beginning of Period	$	8.1	$	7.8
Additions		0.3		0.2
Less: Payments / Reductions		0.2		0.2
Total Balance at End of Period		8.2		7.8
Less: Current Portion		0.8		0.7
Noncurrent Balance at End of Period	$	7.4	$	7.1

Note 9: INCOME TAXES

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

Table of Contents

ASU 2023-09 as of December 31, 2025 on a prospective basis. The following table presents the Company’s provisions for Income Taxes and the provisions calculated at the statutory federal tax rate for the three months ended March 31, 2026:


	For the Three Months Ended March 31,
	2026
(Dollars in thousands)	Amount			Rate
U.S. Federal Statutory Tax Rate	$	9,476			21.0	%
State Income Taxes, net of Federal Income Tax		2,954			6.5	%
Production Tax Credit		(41	)		(0.1	)%
Nontaxable and Nondeductible Items
Regulatory Amortization of Excess ADIT		(578	)		(1.3	)%
Other		115			0.3	%
Income Tax Expense and Effective Income Tax Rate	$	11,926			26.4	%

The differences between the Company’s provisions for Income Taxes and the provisions calculated at the statutory federal tax rate, expressed in percentages, are shown in the following table for the three months ended March 31, 2025:


	For the Three Months Ended March 31,
	2025
Statutory Federal Income Tax Rate		21	%
Income Tax Effects of:
State Income Taxes, net		7
Utility Plant Differences		(2	)
Effective Income Tax Rate		26	%

Under the Company’s Tax Sharing Agreement (the Agreement) which was approved upon the formation of Unitil as a public utility holding company, the Company files consolidated Federal and State tax returns and Unitil Corporation and each of its utility operating subsidiaries recognize the results of their operations in its tax returns as if it were a stand-alone taxpayer. The Agreement provides that the Company will account for income taxes in compliance with U.S. GAAP and regulatory accounting principles. The Company has evaluated its tax positions at December 31, 2025 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, de-recognition, settlement or foreseeable future events to any tax liabilities or assets as defined by the FASB Codification is required.

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

Income tax filings for the year ended December 31, 2024 have been filed with the IRS, Massachusetts Department of Revenue, the Maine Revenue Service, the Florida Department of Revenue and the New Hampshire Department of Revenue Administration. In the Company’s federal tax returns for the year ended December 31, 2024, which were filed with the IRS in October 2025, the Company utilized federal Net Operating Loss Carryforward (NOLC) assets of $5.6 million and $1.0 million of federal tax credit carryforward. As of December 31, 2025, the Company has fully utilized all NOLC and federal tax credits available. In addition, at December 31, 2025, the Company had $1.8 million of cumulative state tax credit carryforwards to offset future income taxes payable. If unused, the Company’s state tax credit carryforwards will begin to expire in 2027.

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

In December 2017, the Tax Cuts and Jobs Act (TCJA), which included a reduction of the corporate federal income tax rate to 21% effective January 1, 2018, was signed into law. In accordance with FASB Codification Topic 740, the Company revalued its Accumulated Deferred Income Taxes (ADIT) and recorded a net liability in the amount of $48.9 million at December 31, 2017. The Company expects to flow through to customers $47.1 million of excess ADIT in utility base rates. The benefit of protected excess ADIT amounts will be subject to flow back to customers in utility rates according to the Average Rate Assumption Method (ARAM).

Table of Contents

The Company estimates the ARAM flow back period for protected and unprotected excess ADIT to be between fifteen and twenty years over the remaining life of the related utility plant. As of March 31, 2026, the Company flowed back $14.5 million to customers in its Massachusetts, Maine, New Hampshire and federal jurisdictions.

Note 10: Retirement Benefit obligations

The Company co-sponsors the Unitil Corporation Retirement Plan (Pension Plan), the Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan), and the Unitil Corporation SERP to provide certain pension and postretirement benefits for its retirees and current employees. Please see Note 10 to the Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2025 as filed with the SEC on February 9, 2026 for additional information regarding these plans.

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


Used to Determine Plan Costs	2026			2025
Discount Rate		5.45	%		5.60	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		7.50	%		7.50	%

The health care cost trend rate used to determine benefit plan costs for 2026 for pre-65 retirees is 8.05%, with an ultimate rate of 4.50% in 2034, and for post-65 retirees, the health care cost trend rate is 7.15%, with an ultimate rate of 4.50% in 2034. The health care cost trend rate used to determine benefit plan costs for 2025 for pre-65 retirees was 8.50%, with an ultimate rate of 4.50% in 2034, and for post-65 retirees, the health care cost trend rate was 7.50%, with an ultimate rate of 4.50% in 2034.

The following tables provide the components of the Company’s Retirement plan costs ($000’s):


	Pension Plan						PBOP Plan						SERP
For the Three Months Ended March 31,	2026			2025			2026			2025			2026			2025
Service Cost	$	404		$	436		$	518		$	502		$	45		$	39
Interest Cost		2,005			2,016			1,163			992			173			172
Expected Return on Plan Assets		(2,859	)		(2,624	)		(1,211	)		(1,086	)		—			—
Prior Service Cost Amortization		92			64			—			—			—			2
Actuarial Loss Amortization		82			319			(20	)		(187	)		—			(53	)
Sub-total		(276	)		211			450			221			218			160
Amounts Capitalized and Deferred		339			109			(79	)		14			(68	)		(51	)
Net Periodic Benefit Cost Recognized	$	63		$	320		$	371		$	235		$	150		$	109

Employer Contributions

As of March 31, 2026, the Company had not made any contributions to its Pension Plan and PBOP Plan, respectively, in 2026. The Company, along with its subsidiaries, expects to make contributions to its Pension and PBOP Plans in 2026 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension and PBOP Plan costs.

As of March 31, 2026, the Company had made $0.2 million of benefit payments under the SERP Plan in 2026. The Company presently anticipates making an additional $0.5 million of benefit payments under the SERP Plan in 2026.

Table of Contents

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Reference is made to the “Interest Rate Risk” and “Commodity Price Risk” sections of Part II, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report (above).

Item 4. Controls and Procedures

Management of the Company, under the supervision and with the participation of the Company’s Chief Executive Officer, Chief Financial Officer, and Chief Accounting Officer, carried out an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as of March 31, 2026. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of March 31, 2026 that the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) are effective.

There have been no changes in the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) during the fiscal quarter covered by this Form 10-Q that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

The Company is involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. Certain specific matters are discussed in Notes 7 and 8 to the Consolidated Financial Statements. In the opinion of Management, based upon information furnished by counsel and others, the ultimate resolution of these claims will not have a material effect on the Company’s financial position.

Item 1A. Risk Factors

There have been no material changes to the risk factors disclosed in the Company’s Form 10-K for the year-ended December 31, 2025 as filed with the SEC on February 9, 2026.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Recent Sales of Unregistered Securities

There were no sales of unregistered equity securities by the Company for the fiscal period ended March 31, 2026.

Issuer Purchases of Equity Securities

There were no purchases of equity securities by the Company for the fiscal period ended March 31, 2026.

Item 5. Other Information

(a) On May 4, 2026, the Company issued a press release announcing its results of operations for the three-month period ended March 31, 2026. The press release is furnished with this Quarterly Report on Form 10-Q as Exhibit 99.1.

(b) During the quarter ended March 31, 2026, 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).

Table of Contents

Item 6. Exhibits

(a) Exhibits



Exhibit No.	Description of Exhibit	Reference*

2.1	Amendment No. 1 to Purchase and Sale Agreement, dated as of January 23, 2026, by and among Unitil Corporation, Aquarion Water Authority and South Central Connecticut Regional Water Authority.	Exhibit 2.1 to Form 8-K for January 23, 2026 (SEC File No. 1-8858)

2.2	Amendment No. 2 to Purchase and Sale Agreement, dated as of February 23, 2026, by and among Unitil Corporation, Aquarion Water Authority and South Central Connecticut Regional Water Authority.	Exhibit 2.1 to Form 8-K for February 19, 2026 (SEC File No. 1-8858)

10.1**	Form of Restricted Stock Agreement (Time Vesting)	Exhibit 10.1 to Form 8-K for January 27, 2026 (SEC File No. 1-8858)

10.2**	Form of Restricted Stock Agreement (Performance Vesting)	Exhibit 10.2 to Form 8-K for January 27, 2026 (SEC File No. 1-8858)

10.3	Amendment No. 1 to Distribution Agreement, dated February 19, 2026, with Huntington Securities, Inc. and Scotia Capital (USA) Inc. (as agents and/or forward sellers) and Huntington Securities, Inc. and The Bank of Nova Scotia (as forward purchasers)	Exhibit 10.1 to Form 8-K for February 19, 2026 (SEC File No. 1-8858)

31.1	Certification of Chief Executive Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

31.3	Certification of Chief Accounting Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

32.1	Certifications of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith

99.1	Unitil Corporation Press Release Dated May 4, 2026 Announcing Earnings for the Quarter Ended March 31, 2026.	Furnished herewith
	4
101.INS	Inline XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL document.	Filed herewith

101.SCH	Inline XBRL Taxonomy Extension Schema with Embedded Linkbase Documents.	Filed herewith

Table of Contents



Exhibit No.	Description of Exhibit	Reference*

104	Cover Page Interactive Data File – The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.	Filed herewith

* 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.

** These exhibits represent a management contract or compensatory plan.

Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



			UNITIL CORPORATION
			(Registrant)

Date: May 4, 2026			/s/ Daniel J. Hurstak
			Daniel J. Hurstak
			Chief Financial Officer



Date: May 4, 2026			/s/ Todd R. Diggins
			Todd R. Diggins
			Chief Accounting Officer