10-Q

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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 June 30, 2025

☐ 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 August 1, 2025
Common Stock, no par value	16,292,209 Shares

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended June 30, 2025

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		Page No.
Cautionary Statement		2-3

Part I. Financial Information

Item 1.	Financial Statements—Unaudited

	Consolidated Statements of Earnings—Three and Six Months Ended June 30, 2025 and 2024	15
	4
	Consolidated Balance Sheets—June 30, 2025, June 30, 2024 and December 31, 2024	16-17

	Consolidated Statements of Cash Flows—Six Months Ended June 30, 2025 and 2024	18

	Consolidated Statements of Changes in Common Stock Equity – Three and Six Months Ended June 30, 2025 and 2024	19

	Notes to Consolidated Financial Statements	20-48

Item 2.	Management’s Discussion and Analysis (MD&A) of Financial Condition and Results of Operations	3-14

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	49

Item 4.	Controls and Procedures	49

Part II. Other Information

Item 1.	Legal Proceedings	49

Item 1A.	Risk Factors	49

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49

Item 3.	Defaults Upon Senior Securities	Inapplicable

Item 4.	Mine Safety Disclosures	Inapplicable

Item 5.	Other Information	49

Item 6.	Exhibits	50-51

Signatures		52

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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 acquisition of Bangor Natural Gas Company and the acquisitions of Maine Natural Gas Company, 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;

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•

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 15 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 2024 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 four 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; and

iv)

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

Unitil Energy, Fitchburg, Northern Utilities, and Bangor are collectively referred to as the “distribution utilities.” Together, the distribution utilities serve approximately 109,400 electric customers and 97,600 gas customers. Included in gas customers are 8,500 customers related to the acquisition of Bangor.

In addition, Unitil 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.

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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.

Unitil had an investment in Net Utility Plant of $1,644.4 million at June 30, 2025. Earnings from Unitil’s utility operations are derived primarily from the return on investment in the utility assets of the four 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. 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, which became operational in May 2025; and Unitil Power Corp., which formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. 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 with regard to certain bookkeeping, accounting and reporting requirements. Unitil’s utility operations related to wholesale and interstate energy business activities are also regulated by the FERC. Unitil’s distribution utilities are subject to regulation by the applicable state public utility commissions with regard to their rates, issuance of securities and other accounting and operational matters: Unitil Energy is subject to regulation by the 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); and Bangor is subject to regulation by the MPUC. Granite State, Unitil’s interstate gas transmission pipeline, is subject to regulation by FERC with regard to its rates and operations. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations and financial position.

Unitil Energy, Fitchburg, and Northern Utilities deliver electricity and/or gas to all customers in their service territory, at rates established under cost of service regulation. Under this regulatory structure, Unitil’s distribution utilities recover the cost of providing distribution service to their customers based on historical test years, and earn a return on their capital investment in utility assets. The Company’s distribution utilities and its gas transmission pipeline company also may recover certain base rate costs, including capital project spending and enhanced reliability and vegetation management programs, through annual step adjustments or cost tracking rate mechanisms. Bangor has a multiyear rate plan approved by the MPUC which is designed to approximate market-based rates. The rate plan established maximum rates (price-cap rates) that form the basis for the rates that Bangor can charge for gas service during the rate plan.

The Company's electric and gas sales in Massachusetts and New Hampshire are now 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.

RESULTS OF OPERATIONS

The following section of MD&A compares the results of operations for each of the two fiscal periods ended June 30, 2025 and June 30, 2024 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).

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

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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 2025 GAAP Net Income adjusted for certain transaction costs related to the Company's acquisitions of Bangor Natural Gas Company, Maine Natural Gas Company (Maine Natural), Aquarion Water Company of Massachusetts, Inc., Aquarion Water Company of New Hampshire, Inc., and Abenaki Water Co., Inc. (the Aquarion Companies). 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.


(Millions, except per share data)
	Three Months Ended June 30, 2025				Three Months Ended June 30, 2024
	Amount		Per Share		Amount		Per Share
GAAP Net Income	$	4.0	$	0.25	$	4.3	$	0.27
Transaction Costs		0.7		0.04		—		—
Adjusted Net Income	$	4.7	$	0.29	$	4.3	$	0.27


	Six Months Ended June 30, 2025				Six Months Ended June 30, 2024
	Amount		Per Share		Amount		Per Share
GAAP Net Income	$	31.5	$	1.94	$	31.5	$	1.96
Transaction Costs		1.6		0.09		—		—
Adjusted Net Income	$	33.1	$	2.03	$	31.5	$	1.96

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

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

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Three Months Ended June 30, 2025 (millions)
	Electric			Gas			Other		Total
Total Operating Revenue	$	51.0		$	51.6		$	—	$	102.6
Less: Cost of Sales		(25.2	)		(14.4	)		—		(39.6	)
Less: Depreciation and Amortization		(7.8	)		(14.0	)		—		(21.8	)
GAAP Gross Margin		18.0			23.2			—		41.2
Depreciation and Amortization		7.8			14.0			—		21.8
Adjusted Gross Margin	$	25.8		$	37.2		$	—	$	63.0


Three Months Ended June 30, 2024 (millions)
	Electric			Gas			Other			Total
Total Operating Revenue	$	56.4		$	39.3		$	—		$	95.7
Less: Cost of Sales		(31.5	)		(8.0	)		—			(39.5	)
Less: Depreciation and Amortization		(7.1	)		(10.8	)		(0.2	)		(18.1	)
GAAP Gross Margin		17.8			20.5			(0.2	)		38.1
Depreciation and Amortization		7.1			10.8			0.2			18.1
Adjusted Gross Margin	$	24.9		$	31.3		$	—		$	56.2


Six Months Ended June 30, 2025 (millions)
	Electric			Gas			Other		Total
Total Operating Revenue	$	111.2		$	162.2		$	—	$	273.4
Less: Cost of Sales		(57.9	)		(54.1	)		—		(112.0	)
Less: Depreciation and Amortization		(15.7	)		(27.8	)		—		(43.5	)
GAAP Gross Margin		37.6			80.3			—		117.9
Depreciation and Amortization		15.7			27.8			—		43.5
Adjusted Gross Margin	$	53.3		$	108.1		$	—	$	161.4


Six Months Ended June 30, 2024 (millions)
	Electric			Gas			Other			Total
Total Operating Revenue	$	130.0		$	144.4		$	—		$	274.4
Less: Cost of Sales		(78.0	)		(52.1	)		—			(130.1	)
Less: Depreciation and Amortization		(14.1	)		(21.7	)		(0.3	)		(36.1	)
GAAP Gross Margin		37.9			70.6			(0.3	)		108.2
Depreciation and Amortization		14.1			21.7			0.3			36.1
Adjusted Gross Margin	$	52.0		$	92.3		$	—		$	144.3

Electric GAAP Gross Margin was $18.0 million in the three months ended June 30, 2025, an increase of $0.2 million compared to the same period in 2024. Electric GAAP Gross Margin was $37.6 million in the six months ended June 30, 2025, a decrease of $0.3 million compared to the same period in 2024. The three month period increase was driven by higher rates and customer growth of $0.9 million, partially offset by higher depreciation and amortization expense of $0.7 million. The six month period decrease was driven by higher depreciation and amortization expense of $1.6 million, partially offset by higher rates and customer growth of $1.3 million.

Gas GAAP Gross Margin was $23.2 million in the three months ended June 30, 2025, an increase of $2.7 million compared to the same period in 2024. Gas GAAP Gross Margin was $80.3 million in the six months ended June 30, 2025, an increase of $9.7 million compared to the same period in 2024. The increase in the three month period was driven by higher rates and customer growth of $5.9 million, partially offset by higher depreciation and amortization of $3.2 million. The increase in the six month period was driven by higher rates and customer growth of $13.8 million, the favorable effects of colder winter weather in 2025 of $2.0 million, partially offset by higher depreciation and amortization of $6.1 million. Included in gas operating revenue, cost of gas sales and depreciation and amortization for the three months ended June 30, 2025 is $4.7 million, $1.7 million and $0.7 million related to Bangor, respectively. Included in gas operating revenue, cost of gas sales and depreciation and amortization for the six months ended June 30, 2025 is $13.3 million, $7.4 million and $1.3 million related to Bangor, respectively.

Earnings Overview

The Company’s Net Income was $4.0 million, or $0.25 in Earnings Per Share (EPS) for the second quarter of 2025, a decrease of $0.3 million in Net Income, or $0.02 in EPS, compared to the second quarter of 2024. The Company's Adjusted Net Income (a non-GAAP

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financial measure), which excluded transaction-related costs in connection with the acquisitions of Bangor, Maine Natural Gas and the Aquarion Companies, was $4.7 million, or $0.29 in EPS for the second quarter of 2025, an increase of $0.4 million, or $0.02 in EPS, compared to the second quarter of 2024.

The Company’s Net Income was $31.5 million, or $1.94 in EPS for the first six months of 2025. Net income is unchanged and EPS decreased $0.02 when compared to the first six months of 2024. 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 $33.1 million, or $2.03 in EPS for the first six months of 2025, an increase of $1.6 million, or $0.07 in EPS, compared to the first six months of 2024.

Electric Adjusted Gross Margin (a non-GAAP financial measure) was $25.8 million and $53.3 million in the three and six months ended June 30, 2025, respectively, increases of $0.9 million and $1.3 million, respectively, compared to the same periods in 2024. This increase reflects higher rates and customer growth.

Gas Adjusted Gross Margin (a non-GAAP financial measure) was $37.2 million and $108.1 million in the three and six months ended June 30, 2025, respectively, increases of $5.9 million and $15.8 million, respectively, compared to the same periods in 2024. The increase in the three month period reflects higher rates and customer growth of $5.9 million. The increase in the six month period reflects higher rates and customer growth of $13.8 million and the favorable effects of colder winter weather of $2.0 million in 2025. Included in the Gas Adjusted Gross Margin for the three and six months ended June 30, 2025 is $3.0 million and $5.9 million, respectively, related to Bangor.

Operation and Maintenance (O&M) expenses increased $2.7 million and $7.1 million in the three and six months ended June 30, 2025, respectively, compared to the same periods in 2024. The increase in the three month period reflects higher utility operating costs of $1.5 million, higher labor costs of $0.6 million and higher professional fees of $0.6 million. The increase in the six month period reflects higher utility operating costs of $3.1 million, higher labor costs of $2.1 million and higher professional fees of $1.9 million. Included in O&M expense for the three months and six months ended June 30, 2025 is $0.8 million and $1.7 million, respectively, related to Bangor O&M expenses and $1.0 million and $2.2 million, respectively, in acquisition transaction costs.

Depreciation and Amortization expense increased $3.7 million and $7.4 million in the three and six months ended June 30, 2025, respectively, compared to the same periods in 2024, reflecting higher depreciation rates from recent base rate cases, additional depreciation associated with higher levels of utility plant in service and higher amortization of recoverable storm costs and other deferred costs. Included in Depreciation and Amortization for the three months and six months ended June 30, 2025 is $0.7 million and $1.3 million, respectively, related to Bangor.

Taxes Other Than Income Taxes decreased $0.5 million and $0.3 million in the three and six months ended June 30, 2025, respectively, compared to the same periods in 2024, primarily due to lower excise taxes.

Interest Expense, Net increased $1.9 million and $3.7 million in the three and six months ended June 30, 2025, respectively, compared to the same periods in 2024, primarily reflecting higher levels of long-term debt, higher interest expense on regulatory liabilities and lower interest income on AFUDC and other, partially offset by lower interest expense on short-term borrowings.

Other Expense (Income), Net decreased $0.8 million and $1.0 million in the three and six months ended June 30, 2025, respectively, compared to the same periods in 2024, reflecting lower retirement benefit costs.

Provision for Income Taxes increased $0.1 million and $0.2 million in the three and six months ended June 30, 2025, respectively, compared with the same periods in 2024. The increase in the six month period reflects higher pre-tax earnings in 2025.

At its January 2025, May 2025 and July 2025 meetings, the Unitil Corporation Board of Directors declared quarterly dividends on the Company’s common stock of $0.45 per share. These quarterly dividends result in a current effective annualized dividend rate of $1.80 per share, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock.

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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 and six months ended June 30, 2025 and 2024:


Electric Operating Revenues and Electric Adjusted Gross Margin (millions)
	Three Months Ended June 30,										Six Months Ended June 30,
	2025		2024		$ Change			% Change			2025		2024		$ Change			% Change
Electric Operating Revenue:
Residential	$	26.9	$	30.1	$	(3.2	)		(10.6	)%	$	62.2	$	73.6	$	(11.4	)		(15.5	)%
Commercial / Industrial		24.1		26.3		(2.2	)		(8.4	)%		49.0		56.4		(7.4	)		(13.1	)%
Total Electric Operating Revenue		51.0		56.4		(5.4	)		(9.6	)%		111.2		130.0		(18.8	)		(14.5	)%
Cost of Electric Sales		25.2		31.5		(6.3	)		(20.0	)%		57.9		78.0		(20.1	)		(25.8	)%
Electric Adjusted Gross Margin	$	25.8	$	24.9	$	0.9			3.6	%	$	53.3	$	52.0	$	1.3			2.5	%

Total Electric Operating Revenue decreased $5.4 million, or 9.6%, and $18.8 million, or 14.5% in the three months and six months ended June 30, 2025, respectively, compared to the same periods in 2024, reflecting lower costs of electric sales due to the increase 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 higher electric distribution rates.

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 $25.8 million and $53.3 million for the three and six months ended June 30, 2025, respectively, increases of $0.9 million and $1.3 million, respectively, compared with the same periods in 2024. These increases reflect higher rates and customer growth.

Kilowatt-hour Sales - Unitil’s total electric kWh sales decreased 4.4% and increased 1.6% in the three and six months ended June 30, 2025, compared to the same periods in 2024. Sales to Residential and Commercial and Industrial (C&I) customers decreased 1.3% and 6.4%, respectively, in the three months ended June 30, 2025, compared to the same period in 2024, reflecting lower average usage, partially offset by customer growth. Sales to Residential and C&I customers increased 5.6% and decreased 1.3%, respectively, in the six months ended June 30, 2025, compared to the same period in 2024, reflecting colder winter weather for heating purposes in 2025, and customer growth. As of June 30, 2025, the number of electric customers increased by approximately 730 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.

The following table details total kWh sales for the three and six months ended June 30, 2025 and 2024 by major customer class:


kWh Sales (millions)
	Three Months Ended June 30,										Six Months Ended June 30,
	2025		2024		Change			% Change			2025		2024		Change			% Change
Residential		138.9		140.8		(1.9	)		(1.3	)%		338.7		320.7		18.0			5.6	%
Commercial / Industrial		207.7		221.8		(14.1	)		(6.4	)%		446.1		451.8		(5.7	)		(1.3	)%
Total		346.6		362.6		(16.0	)		(4.4	)%		784.8		772.5		12.3			1.6	%

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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 and six months ended June 30, 2025 and 2024:


Gas Operating Revenues and Gas Adjusted Gross Margin (millions)
	Three Months Ended June 30,									Six Months Ended June 30,
	2025		2024		$ Change		% Change			2025		2024		$ Change		% Change
Gas Operating Revenue:
Residential	$	21.3	$	15.8	$	5.5		34.8	%	$	70.2	$	60.6	$	9.6		15.8	%
Commercial / Industrial		30.3		23.5		6.8		28.9	%		92.0		83.8		8.2		9.8	%
Total Gas Operating Revenue		51.6		39.3		12.3		31.3	%		162.2		144.4		17.8		12.3	%
Cost of Gas Sales		14.4		8.0		6.4		80.0	%		54.1		52.1		2.0		3.8	%
Gas Adjusted Gross Margin	$	37.2	$	31.3	$	5.9		18.8	%	$	108.1	$	92.3	$	15.8		17.1	%

Total Gas Operating Revenue increased $12.3 million, or 31.3%, and increased $17.8 million, or 12.3%, in the three and six months ended June 30, 2025, respectively, compared to the same periods in 2024. The increase in the three month period includes $4.7 million of gas operating revenue for Bangor, higher rates and customer growth, and higher costs of gas sales, which are tracked and reconciled costs that are passed through directly to customers. The increase in the six month period includes $13.3 million of gas operating revenue for Bangor, higher rates and customer growth, the favorable impact of colder winter weather in 2025 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 19.1% and 23.7% in the three and six months ended June 30, 2025, respectively, compared to the same periods in 2024. In the second quarter of 2025, sales to Residential and C&I customers increased 20.9% and 18.7%, respectively, compared to the same period in 2024, reflecting customer growth and colder spring weather in 2025. In the first six months of 2025, sales to Residential and C&I customers increased 29.9% and 22.0%, respectively, compared to the same period in 2025, reflecting colder winter weather in 2025 and customer growth. Included in the total gas therm sales increases is 8.6 million therms and 19.0 million therms, respectively, for three and six months ended June 30, 2025, related to Bangor. Based on weather data collected in the Company’s gas service areas, on average there were 10.7% higher effective degree days in the first six months of 2025 compared to the same period in 2024. The Company estimates weather-normalized gas therm sales for Northern Utilities' Maine division, the Company's largest non-decoupled gas service area, increased 3.0% in the first six months of 2025 compared to the same period in 2024. As of June 30, 2025, the number of gas customers increased by approximately 9,360 over the previous year. Included in this increase is 8,800 customers related to Bangor. Sales margins derived from decoupled unit sales (currently representing approximately 43% 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 and six months ended June 30, 2025 and 2024 by major customer class:


Therm Sales (millions)
	Three Months Ended June 30,									Six Months Ended June 30,
	2025		2024		Change		% Change			2025		2024		Change		% Change
Residential		10.4		8.6		1.8		20.9	%		38.7		29.8		8.9		29.9	%
Commercial / Industrial		45.0		37.9		7.1		18.7	%		129.8		106.4		23.4		22.0	%
Total		55.4		46.5		8.9		19.1	%		168.5		136.2		32.3		23.7	%

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 decreased $6.3 million, or 20.0%, and $20.1 million, or 25.8%, respectively, in the three and six months ended June 30, 2025, compared to the same periods in 2024. This decrease reflects an increase in the amount of electricity purchased by customers directly from third-party suppliers, partially offset by higher 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.

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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 $6.4 million, or 80.0%, and $2.0 million, or 3.8%, in the three and six months ended June 30, 2025, compared to the same periods in 2024. This increase reflects higher wholesale gas commodity prices and higher gas therm sales. 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 expense increased $2.7 million, or 14.5%, and $7.1 million, or 19.3%, respectively, in the three and six months ended June 30, 2025, compared to the same periods in 2024. The increase in the three month period reflects higher utility operating costs of $1.5 million, higher labor costs of $0.6 million and higher professional fees of $0.6 million. The increase in the six month period reflects higher utility operating costs of $3.1 million, higher labor costs of $2.1 million and higher professional fees of $1.9 million. Included in O&M expense for the three months and six months ended June 30, 2025 is $0.8 million and $1.7 million, respectively, related to Bangor O&M expenses and $1.0 million and $2.2 million, respectively, in acquisition transaction costs.

Depreciation and Amortization - Depreciation and Amortization expense increased $3.7 million, or 20.4%, and $7.4 million, or 20.5%, in the three and six months ended June 30, 2025, compared to the same periods in 2024, reflecting higher depreciation rates from recent base rate cases, additional depreciation associated with higher levels of utility plant in service and higher amortization of recoverable storm costs and other deferred costs. Included in Depreciation and Amortization expense for the three and six months ended June 30, 2025 is $0.7 million and $1.3 million, respectively, related to Bangor.

Taxes Other Than Income Taxes - Taxes Other Than Income Taxes decreased $0.5 million, or 7.0% and $0.3 million, or 2.0%, respectively, in the three and six months ended June 30, 2025, compared to the same periods in 2024, primarily due to lower excise taxes.

Other Expense (Income), Net - Other Expense (Income), Net decreased $0.8 million and $1.0 million, respectively, in the three and six months ended June 30, 2025, compared to the same periods in 2024, reflecting lower retirement benefit costs.

Provision for Income Taxes - Federal and State Income Taxes for the three and six months ended June 30, 2025 increased $0.1 million and $0.2 million, respectively, compared with the same periods in 2024. The increase in the six month period reflects higher pre-tax earnings in 2025.

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 a number of reconciling rate mechanisms to recover specifically identified costs on a pass-through basis. These reconciling rate mechanisms track costs and revenue on a monthly basis. In any given month, this 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.


Interest Expense, Net (millions)	Three Months Ended June 30,									Six Months Ended June 30,
	2025			2024			Change			2025			2024			Change
Interest Expense
Long-term Debt	$	8.1		$	6.3		$	1.8		$	16.2		$	12.5		$	3.7
Short-term Debt		2.0			3.1			(1.1	)		4.1			6.0			(1.9	)
Regulatory Liabilities		0.6			0.4			0.2			1.1			0.6			0.5
Subtotal Interest Expense		10.7			9.8			0.9			21.4			19.1			2.3
Interest (Income)
Regulatory Assets		(0.7	)		(1.0	)		0.3			(1.6	)		(2.0	)		0.4
AFUDC(1) and Other		(0.7	)		(1.4	)		0.7			(1.4	)		(2.4	)		1.0
Subtotal Interest (Income)		(1.4	)		(2.4	)		1.0			(3.0	)		(4.4	)		1.4
Total Interest Expense, Net	$	9.3		$	7.4		$	1.9		$	18.4		$	14.7		$	3.7

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(1)

AFUDC – Allowance for Funds Used During Construction.

Interest Expense, Net increased $1.9 million, or 25.7%, and $3.7 million, or 25.2%, in the three and six months ended June 30, 2025, compared to the same periods in 2024, primarily reflecting higher levels of long-term debt, higher interest expense on regulatory liabilities and lower interest income on AFUDC and other, partially offset by lower interest expense on short-term borrowings.

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 debt financings more closely matched to the long-term nature of its utility assets. Additionally, from time to time the Company accesses the public capital markets through public offerings of equity securities. The Company’s utility operations have a seasonal component and therefore are 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.

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). At June 30, 2025, June 30, 2024 and December 31, 2024, 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 in its entirety the prior credit facility. On January 29, 2025, the Company entered into an amendment to the Credit Facility, which (among other things) increased the borrowing limit under the Credit Facility from $200 million to $275 million and extended the term of the Credit Facility from September 29, 2027 until September 29, 2028. Unitil may borrow under the Credit Facility until September 29, 2028, subject to two one-year extensions under certain circumstances.

The Credit Facility has a borrowing limit of $275 million ($200 million as of December 31, 2024), which includes a $25 million sublimit for the issuance of standby letters of credit. Unitil may increase the borrowing limit under the Credit Facility by up to $75 million under certain circumstances. The Credit Facility generally provides Unitil with the ability to elect that borrowings under the Credit Facility bear interest under several options, including a daily fluctuating rate equal to (a) the forward-looking secured overnight financing rate (as administered by the Federal Reserve Bank of New York) term rate with a term equivalent to one month beginning on that date, plus (b) 0.1000%, plus (c) a margin of 1.125% to 1.375% (based on Unitil’s credit rating).

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $215.5 million for the six months ended June 30, 2025. Total gross repayments were $149.9 million for the six months ended June 30, 2025. The following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of June 30, 2025, June 30, 2024 and December 31, 2024:


	Revolving Credit Facility (millions)
	June 30,				December 31,
	2025		2024		2024
Limit	$	275.0	$	200.0	$	200.0
Short-Term Borrowings Outstanding		171.4		157.8		105.8
Available	$	103.6	$	42.2	$	94.2

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

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on a quarterly basis. At June 30, 2025, June 30, 2024 and December 31, 2024, the Company was in compliance with the covenants contained in the Credit Facility in effect on those dates.

On August 21, 2024, Unitil issued $20.0 million of Notes due 2034 at 5.99%; Fitchburg issued $12.5 million of Notes due 2034 at 5.54% and $12.5 million of Notes due 2044 at 5.99%; Unitil Energy issued $40.0 million of Bonds due 2054 at 5.69%; Northern Utilities issued $25.0 million of Notes due 2034 at 5.54% and $15.0 million of Notes due 2039 at 5.74%; and Granite State issued $10.0 million of Notes due 2034 at 5.74%.

The Company used the net proceeds from these offerings to refinance existing debt and for general corporate purposes. Approximately $1.0 million of costs associated with this issuance were recorded as a reduction of Long-Term Debt for presentation purposes on the Consolidated Balance Sheet in the third quarter of 2024.

On July 8, 2025, Bangor Natural Gas Company 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.

Unitil and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State currently are rated “BBB+”, and Bangor Natural Gas 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 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 June 30, 2025, there were no guarantees outstanding.

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 $8.7 million of natural gas storage inventory and corresponding obligations at June 30, 2025 related to these asset management agreements.

On June 3, 2025, the Company entered into an at-the-market (ATM) equity offering program with Janney Montgomery Scott LLC and Scotia Capital (USA) Inc., 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 June 30, 2025, the Company has sold an aggregate of 27,620 shares under the ATM program for net proceeds of $1.4 million. As of June 30, 2025, $48.5 million remains available for future sales under the program.

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. 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 judgment, the financial position of the Company could be materially affected and the results of operations of the Company could be materially different than reported. As of June 30, 2025, the Company’s critical accounting policies and estimates had not changed significantly from December 31, 2024. See Part II, Item 7. “Management’s

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Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” in the Company’s 2024 Annual Report on Form 10-K for additional information.

EMPLOYEES

As of June 30, 2025, the Company and its subsidiaries had 575 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

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

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

As of June 30, 2025, a total of 187 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 June 30, 2025:


	Employees Covered	CBA Expiration
Bangor	14	5/31/2026
Fitchburg	44	5/31/2027
Granite State	5	3/31/2026
Northern Utilities ME Division	40	3/31/2026
Northern Utilities NH Division	37	6/7/2030
Unitil Energy	42	5/31/2028
Unitil Service	5	5/31/2028

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

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 June 30, 2025 and June 30, 2024 were 5.6% and 6.7%, respectively. The average interest rates on the Company’s short-term borrowings and intercompany money pool transactions for the six months ended June 30, 2025 and June 30, 2024 were 5.6% and 6.7%, respectively. The average interest rate on the Company’s short-term borrowings for the twelve months ended December 31, 2024 was 6.5%.

COMMODITY PRICE RISK

Although Unitil’s four 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.

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Regulatory Matters

Please refer to Note 6 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 7 to the Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of Environmental Matters.

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF EARNINGS

(Millions, except per share data)

(UNAUDITED)


	Three Months Ended June 30,					Six Months Ended June 30,
	2025			2024		2025			2024
Operating Revenues
Electric	$	51.0		$	56.4	$	111.2		$	130.0
Gas		51.6			39.3		162.2			144.4
Total Operating Revenues		102.6			95.7		273.4			274.4
Operating Expenses
Cost of Electric Sales		25.2			31.5		57.9			78.0
Cost of Gas Sales		14.4			8.0		54.1			52.1
Operation and Maintenance		21.3			18.6		43.9			36.8
Depreciation and Amortization		21.8			18.1		43.5			36.1
Taxes Other Than Income Taxes		6.6			7.1		14.5			14.8
Total Operating Expenses		89.3			83.3		213.9			217.8
Operating Income		13.3			12.4		59.5			56.6
Interest Expense, Net		9.3			7.4		18.4			14.7
Other Expense (Income), Net		(0.7	)		0.1		(0.6	)		0.4
Income Before Income Taxes		4.7			4.9		41.7			41.5
Provision for Income Taxes		0.7			0.6		10.2			10.0
Net Income Applicable to Common Shares	$	4.0		$	4.3	$	31.5		$	31.5
Earnings Per Common Share – Basic and Diluted	$	0.25		$	0.27	$	1.94		$	1.96
Weighted Average Common Shares Outstanding – Basic and Diluted		16.2			16.1		16.2			16.1

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

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Millions)

(UNAUDITED)


	June 30,				December 31,
	2025		2024		2024
ASSETS:
Current Assets:
Cash and Cash Equivalents	$	8.5	$	2.8	$	6.3
Accounts Receivable, Net		66.0		60.0		75.0
Accrued Revenue		56.8		65.9		77.4
Exchange Gas Receivable		9.1		5.8		6.4
Gas Inventory		0.7		0.4		1.1
Materials and Supplies		15.9		14.2		14.2
Prepayments and Other		13.1		10.9		8.4
Total Current Assets		170.1		160.0		188.8
Utility Plant:
Electric		728.2		663.2		699.4
Gas		1,285.3		1,131.6		1,189.9
Common		72.3		67.8		69.0
Construction Work in Progress		89.5		92.2		92.9
Utility Plant		2,175.3		1,954.8		2,051.2
Less: Accumulated Depreciation		530.9		500.0		511.6
Net Utility Plant		1,644.4		1,454.8		1,539.6
Other Noncurrent Assets:
Regulatory Assets		46.6		53.0		41.9
Operating Lease Right of Use Assets		5.7		5.1		6.7
Goodwill		1.6		—		—
Other Assets		24.3		22.1		17.5
Total Other Noncurrent Assets		78.2		80.2		66.1
TOTAL ASSETS	$	1,892.7	$	1,695.0	$	1,794.5

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

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS (Cont.)

(Millions, except number of shares)

(UNAUDITED)


	June 30,				December 31,
	2025		2024		2024
LIABILITIES AND CAPITALIZATION:
Current Liabilities:
Accounts Payable	$	41.1	$	37.2	$	49.7
Short-Term Debt		171.4		157.8		105.8
Long-Term Debt, Current Portion		4.9		4.9		4.9
Regulatory Liabilities		21.0		24.5		17.2
Energy Supply Obligations		11.1		8.6		10.0
Interest Payable		8.6		6.0		8.4
Environmental Obligations		0.7		0.7		0.7
Operating Lease Obligations		1.7		1.7		1.8
Taxes Payable		6.0		8.0		—
Other Current Liabilities		27.0		24.9		30.2
Total Current Liabilities		293.5		274.3		228.7
Noncurrent Liabilities:
Retirement Benefit Obligations		26.3		46.4		25.5
Deferred Income Taxes, net		187.2		178.6		186.1
Cost of Removal Obligations		147.4		134.9		139.2
Regulatory Liabilities		52.5		33.3		46.8
Environmental Obligations		7.1		4.0		7.1
Operating Lease Obligations		4.0		3.4		4.9
Other Noncurrent Liabilities		6.1		4.9		5.3
Total Noncurrent Liabilities		430.6		405.5		414.9
Capitalization:
Long-Term Debt, Less Current Portion		635.8		506.4		638.4
Stockholders’ Equity:
Common Equity (No par value, Authorized: 25,000,000 and Outstanding: 16,291,395, 16,173,132 and 16,192,345 Shares)		344.6		339.3		341.2
Retained Earnings		188.0		169.3		171.1
Total Common Stock Equity		532.6		508.6		512.3
Preferred Stock		0.2		0.2		0.2
Total Stockholders’ Equity		532.8		508.8		512.5
Total Capitalization		1,168.6		1,015.2		1,150.9
Commitments and Contingencies (Notes 6 & 7)
TOTAL LIABILITIES AND CAPITALIZATION	$	1,892.7	$	1,695.0	$	1,794.5

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

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions) (UNAUDITED)


	For the Six Months Ended June 30,
	2025			2024
Operating Activities:
Net Income	$	31.5		$	31.5
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization		43.5			36.1
Deferred Tax Provision		(0.5	)		1.1
Changes in Working Capital Items:
Accounts Receivable		12.8			15.0
Accrued Revenue		25.3			(2.5	)
Regulatory Liabilities		3.8			11.0
Exchange Gas Receivable		(2.7	)		3.6
Accounts Payable		(13.7	)		(10.5	)
Other Changes in Working Capital Items		(3.5	)		1.4
Deferred Regulatory and Other Charges		(8.6	)		(11.3	)
Other, net		6.4			1.1
Cash Provided by Operating Activities		94.3			76.5
Investing Activities:
Property, Plant and Equipment Additions		(72.8	)		(56.9	)
Acquisition, Net of Cash Acquired		(71.4	)		—
Cash Used in Investing Activities		(144.2	)		(56.9	)
Financing Activities:
Proceeds from (Repayment of) Short-Term Debt, net		65.6			(4.2	)
Repayment of Long-Term Debt		(2.8	)		(2.8	)
Net Increase (Decrease) in Exchange Gas Financing		2.0			(3.2	)
Decrease in Capital Lease Obligations		(0.1	)		—
Dividends Paid		(14.6	)		(13.7	)
Proceeds from Issuance of Common Stock		2.0			0.6
Cash Provided by (Used In) Financing Activities		52.1			(23.3	)
Net Increase (Decrease) in Cash and Cash Equivalents		2.2			(3.7	)
Cash and Cash Equivalents at Beginning of Period		6.3			6.5
Cash and Cash Equivalents at End of Period	$	8.5		$	2.8
Supplemental Cash Flow Information:
Interest Paid	$	19.8		$	16.7
Income Taxes Paid	$	3.0		$	2.5
Payments on Capital Leases	$	0.1		$	0.1
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$	10.5		$	5.8
Right-of-Use Assets Obtained in Exchange for Lease Obligations	$	—		$	0.5

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

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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 June 30, 2025
Balance at April 1, 2025	$	342.6	$	191.3		$	533.9
Net Income				4.0			4.0
Dividends ($0.45 per Common Share)				(7.3	)		(7.3	)
Stock Compensation Plans		0.3					0.3
Issuance of 32,838 Common Shares		1.7					1.7
Balance at June 30, 2025	$	344.6	$	188.0		$	532.6
Three Months Ended June 30, 2024
Balance at April 1, 2024	$	338.7	$	171.9		$	510.6
Net Income				4.3			4.3
Dividends ($0.425 per Common Share)				(6.9	)		(6.9	)
Stock Compensation Plans		0.3					0.3
Issuance of 5,245 Common Shares		0.3					0.3
Balance at June 30, 2024	$	339.3	$	169.3		$	508.6


	Common Equity		Retained Earnings			Total
Six Months Ended June 30, 2025
Balance at January 1, 2025	$	341.2	$	171.1		$	512.3
Net Income				31.5			31.5
Dividends ($0.90 per Common Share)				(14.6	)		(14.6	)
Stock Compensation Plans		1.4					1.4
Issuance of 38,311 Common Shares		2.0					2.0
Balance at June 30, 2025	$	344.6	$	188.0		$	532.6
Six Months Ended June 30, 2024
Balance at January 1, 2024	$	337.6	$	151.5		$	489.1
Net Income				31.5			31.5
Dividends ($0.85 per Common Share)				(13.7	)		(13.7	)
Stock Compensation Plans		1.1					1.1
Issuance of 11,048 Common Shares		0.6					0.6
Balance at June 30, 2024	$	339.3	$	169.3		$	508.6

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

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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), Granite State Gas Transmission, Inc. (Granite State), Unitil Power Corp. (Unitil Power), Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) 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 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 gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and greater Bangor Area of central Maine and in the greater Fitchburg area of north central Massachusetts. Unitil has four 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; and Bangor, 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 three other wholly-owned subsidiaries: Unitil Service, Unitil Resources and Unitil Realty. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary, which currently does not have any activity. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Realty also owns land in Kingston, New Hampshire, on which Unitil Energy’s solar facility is located, which became operational in May 2025.

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 and six months ended June 30, 2025 are not necessarily indicative of results to be expected for the year ending December 31, 2025. 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, 2024, as filed with the Securities and Exchange Commission (SEC) on February 10, 2025, 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.

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

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

The Company’s billed and unbilled revenue meets the definition of “revenues from contracts with customers” as defined in Accounting Standards Codification (ASC) 606. Revenue recognized in connection with rate adjustment mechanisms is consistent with the definition of alternative revenue programs in ASC 980-605-25-3, 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 June 30, 2025
Electric and Gas Operating Revenues (millions):	Electric		Gas			Total
Billed and Unbilled Revenue:
Residential	$	23.4	$	21.1		$	44.5
Commercial and Industrial		21.0		30.0			51.0
Other		2.6		1.7			4.3
Total Billed and Unbilled Revenue		47.0		52.8			99.8
Rate Adjustment Mechanism Revenue		4.0		(1.2	)		2.8
Total Electric and Gas Operating Revenues	$	51.0	$	51.6		$	102.6


	Three Months Ended June 30, 2024
Electric and Gas Operating Revenues (millions):	Electric			Gas			Total
Billed and Unbilled Revenue:
Residential	$	30.4		$	18.4		$	48.8
Commercial and Industrial		26.3			27.0			53.3
Other		2.1			1.6			3.7
Total Billed and Unbilled Revenue		58.8			47.0			105.8
Rate Adjustment Mechanism Revenue		(2.4	)		(7.7	)		(10.1	)
Total Electric and Gas Operating Revenues	$	56.4		$	39.3		$	95.7


	Six Months Ended June 30, 2025
Electric and Gas Operating Revenues (millions):	Electric		Gas			Total
Billed and Unbilled Revenue:
Residential	$	56.6	$	76.8		$	133.4
Commercial and Industrial		44.5		100.4			144.9
Other		6.7		9.9			16.6
Total Billed and Unbilled Revenue		107.8		187.1			294.9
Rate Adjustment Mechanism Revenue		3.4		(24.9	)		(21.5	)
Total Electric and Gas Operating Revenues	$	111.2	$	162.2		$	273.4

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	Six Months Ended June 30, 2024
Electric and Gas Operating Revenues (millions):	Electric		Gas			Total
Billed and Unbilled Revenue:
Residential	$	71.0	$	59.4		$	130.4
Commercial and Industrial		54.3		82.2			136.5
Other		4.5		5.7			10.2
Total Billed and Unbilled Revenue		129.8		147.3			277.1
Rate Adjustment Mechanism Revenue		0.2		(2.9	)		(2.7	)
Total Electric and Gas Operating Revenues	$	130.0	$	144.4		$	274.4

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

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 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 June 30, 2025, June 30, 2024 and December 31, 2024, the Unitil subsidiaries had deposited $6.0 million, $2.3 million and $5.0 million, respectively to satisfy their ISO-NE obligations.

Allowance for Doubtful Accounts - The Company recognizes a provision for doubtful accounts that reflects the Company’s estimate of expected credit losses for electric and gas utility service accounts receivable. The allowance for doubtful accounts is calculated by applying a historical loss rate to customer account balances, and 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 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.

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The Allowance for Doubtful Accounts as of June 30, 2025, June 30, 2024 and December 31, 2024, was as follows:


	June 30,				December 31,
(millions)	2025		2024		2024
Allowance for Doubtful Accounts	$	1.9	$	2.2	$	2.4

Accounts Receivable, Net includes $1.9 million, $2.2 million, and $2.3 million of the Allowance for Doubtful Accounts at June 30, 2025, June 30, 2024 and December 31, 2024, respectively. Unbilled Revenues, net (a component of Accrued Revenue) includes less than $0.1 million, less than $0.1 million and $0.1 million of the Allowance for Doubtful Accounts at June 30, 2025, June 30, 2024 and December 31, 2024, 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 June 30, 2025, June 30, 2024 and December 31, 2024.


	June 30,				December 31,
Accrued Revenue (millions)	2025		2024		2024
Regulatory Assets – Current	$	52.6	$	61.1	$	70.1
Unbilled Revenues, net		4.2		4.8		7.3
Total Accrued Revenue	$	56.8	$	65.9	$	77.4

Exchange Gas Receivable - Northern Utilities 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 June 30, 2025, June 30, 2024 and December 31, 2024.


	June 30,				December 31,
Exchange Gas Receivable (millions)	2025		2024		2024
Northern Utilities	$	7.8	$	5.4	$	6.0
Fitchburg		0.4		0.4		0.4
Bangor		0.9		—		—
Total Exchange Gas Receivable	$	9.1	$	5.8	$	6.4

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 June 30, 2025, June 30, 2024 and December 31, 2024.


	June 30,				December 31,
Gas Inventory (millions)	2025		2024		2024
Natural Gas	$	0.2	$	0.1	$	0.2
Propane		0.3		0.2		0.4
Liquefied Natural Gas & Other		0.2		0.1		0.5
Total Gas Inventory	$	0.7	$	0.4	$	1.1

Utility Plant - The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost 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 June 30, 2025, June 30, 2024 and December 31, 2024, the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations, were estimated to be $147.4 million, $134.9 million, and $139.2 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).

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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, and Bangor 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 June 30, 2025, June 30, 2024 and December 31, 2024, the Company has recorded $8.3 million, $7.2 million and $7.9 million, respectively, of hardship accounts in Regulatory Assets. These amounts are included in “Other Deferred Charges” in the following table. The Company currently receives recovery in rates or expects to receive recovery of these hardship accounts in future rate cases.


	June 30,				December 31,
Regulatory Assets consist of the following (millions)	2025		2024		2024
Retirement Benefits	$	19.3	$	26.8	$	14.4
Energy Supply and Other Rate Adjustment Mechanisms		48.1		57.3		65.4
Deferred Storm Charges		7.0		10.1		8.3
Environmental		9.4		6.1		9.4
Income Taxes		0.7		0.7		0.4
Other Deferred Charges		14.7		13.1		14.1
Total Regulatory Assets		99.2		114.1		112.0
Less: Current Portion of Regulatory Assets(1)		52.6		61.1		70.1
Regulatory Assets – noncurrent	$	46.6	$	53.0	$	41.9

(1)

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


	June 30,				December 31,
Regulatory Liabilities consist of the following (millions)	2025		2024		2024
Income Taxes (Note 8)	$	49.7	$	37.2	$	50.4
Rate Adjustment Mechanisms & Other		17.8		20.6		13.6
Retirement Benefits		6.0		—		—
Total Regulatory Liabilities		73.5		57.8		64.0
Less: Current Portion of Regulatory Liabilities		21.0		24.5		17.2
Regulatory Liabilities – noncurrent	$	52.5	$	33.3	$	46.8

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 June 30, 2025 are $7.8 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 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 a normal purchase, or have contingencies that have not yet been met in order to establish a notional amount.

Fitchburg has entered into power purchase agreements for which contingencies exist (see Note 6, Regulatory Matters—Fitchburg— Massachusetts Request for Proposal (RFPs)). Until these contingencies are satisfied, these contracts will not qualify for derivative

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accounting. The Company believes that the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg.

Investments in Marketable Securities - The Company maintains a trust through which it invests in a money market fund and 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 9).

At June 30, 2025, June 30, 2024 and December 31, 2024, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, was $6.1 million, $5.8 million and $6.3 million, respectively, as shown in the following table. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other Expense, Net.


	June 30,				December 31,
Fair Value of Marketable Securities (millions)	2025		2024		2024
Money Market Funds	$	1.9	$	1.8	$	2.5
Fixed Income Funds		4.2		4.0		3.8
Total Marketable Securities	$	6.1	$	5.8	$	6.3

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

At June 30, 2025, June 30, 2024 and December 31, 2024, the fair value of the Company’s investments in these trading securities related to the DC Plan, which are recorded on the Consolidated Balance Sheets in Other Assets, were $2.9 million, $1.9 million and $2.2 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.


	June 30,				December 31,
Fair Value of Marketable Securities (millions)	2025		2024		2024
Equity Funds	$	2.7	$	1.7	$	2.0
Fixed Income Funds		0.1		0.1		0.1
Money Market Funds		0.1		0.1		0.1
Total Marketable Securities	$	2.9	$	1.9	$	2.2

Goodwill - In January, the Company completed the acquisition of Bangor Natural Gas Company resulting in the recognition of $1.6 million of goodwill. Goodwill is not amortized but is subject to an assessment for impairment at least annually and more frequently if indicators of impairment arise that would more likely than not reduce the fair value of the Company's reporting units below their carrying amounts (see Acquisition of Bangor Natural Gas).

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.


	June 30,				December 31,
Energy Supply Obligations (millions)	2025		2024		2024
Current:
Exchange Gas Obligation	$	8.7	$	5.5	$	6.0
Renewable Energy Portfolio Standards		2.4		3.1		4.0
Total Energy Supply Obligations	$	11.1	$	8.6	$	10.0

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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, sell the gas storage inventory to an asset manager and subsequently repurchase the inventory over the course of the 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.

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

Fitchburg has entered into long-term renewable contracts for the purchase of clean energy and/or RECs pursuant to Massachusetts legislation. The generating facilities associated with ten of these contracts have been constructed and are now operating. Three approved contracts are currently under development. These include long-term contracts filed with the MDPU in 2018, two for offshore wind generation (totaling 1,200 MW) and one for imported hydroelectric power and associated transmission, all three of which were approved in 2019. Four offshore wind contracts, totaling 2,400 MW, previously solicited for pursuant to the Green Communities Act and approved by the MDPU in 2021 and 2022, were subsequently terminated in 2023. In compliance with the Green Communities Act as amended by the Energy Diversity Act and the Act Driving Clean Energy and Offshore Wind in coordination with the other electric distribution companies (EDCs) in Massachusetts, on August 30, 2023, the Company issued a fourth offshore wind Request for Proposal seeking to procure at least 400 MW and up to the maximum amount remaining of the statutory requirement. The EDCs received bids for Offshore Wind Generation from three developers as part of a multi-state solicitation with Rhode Island and Connecticut and on September 6, 2024, the Department of Energy Resources selected a portfolio of projects totaling 2,678 MW from three projects. On December 20, 2024, Connecticut announced it was withdrawing from contract negotiations for its 400 MW portion of a 1,200 MW project jointly selected with Massachusetts. As the 800 MW selected by Massachusetts was conditioned upon Connecticut selecting the remaining 400 MW, Massachusetts also ceased negotiations with that developer. Contract negotiations with the remaining two developers are scheduled to be completed by December 31, 2025.

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 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.” The first solicitation will be for the environmental attributes associated with approximately 1,500 megawatts of mid-duration storage. The RFP for the first round of procuring energy storage was released on July 31, 2025.

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

In November 2023, the FASB issued ASU 2023-07, Segment Reporting – Improvements to Reportable Segment Disclosures (ASU 2023-07). The amendments in ASU 2023-07 are intended to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The amendments in ASU 2023-07 are effective for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024. The Company adopted this new guidance for the year-ended December 31, 2024 and it did not have a material effect on the Company’s Consolidated Financial Statements (see Note 3, Segment Information).

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

In connection with this acquisition, the Company recorded $66.7 million of net utility plant, $3.8 million working capital, $1.6 million goodwill, $0.2 million noncurrent assets and $0.9 million noncurrent regulatory liabilities. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions and purchase accounting adjustments. The financial results associated with this acquisition are included within the gas segment. The operating revenues and net income of this acquisition were not material to the consolidated results for the six months ended June 30, 2025.

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

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

Acquisition of Maine Natural Gas Company - On March 31, 2025, Unitil entered into a Stock Purchase Agreement (the “Purchase Agreement”) between the Company and Avangrid Enterprises, Inc. (the “Seller”). Pursuant to, and subject to the terms and conditions of, the Purchase Agreement, the Company agreed to acquire all of the issued and outstanding shares of capital stock of Maine Natural from the Seller for $86.0 million in cash, subject to certain adjustments as provided in the Purchase Agreement (the “Maine Acquisition”). In connection with the Maine Acquisition, Unitil entered into a Guaranty with Avangrid Networks, Inc. (“Avangrid Networks”), an affiliate of the Seller, pursuant to which Avangrid Networks guarantees the payment of Seller’s obligations under the Purchase Agreement, subject to the terms of the Guaranty. In addition, Unitil entered into a debt commitment letter with The Bank of Nova Scotia, whereby The Bank of Nova Scotia has committed to provide Unitil an $86.0 million senior unsecured delayed-draw term loan facility to fund the Maine Acquisition. The Maine Acquisition is subject to approval by the MPUC and other closing conditions.

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

Subsequent Events - 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 Bangor issuance of $32 million of Notes on July 8, 2025, as disclosed in Note 4, 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
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
10/30/24	11/29/24	11/14/24	$	0.425
07/31/24	08/29/24	08/15/24	$	0.425
05/1/24	05/31/24	05/16/24	$	0.425
01/31/24	02/29/24	02/14/24	$	0.425

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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, the greater Bangor area of central Maine and in the greater Fitchburg area of north central Massachusetts. Unitil has four distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire, Fitchburg, which operates in Massachusetts, Northern Utilities, which operates in New Hampshire and Maine and Bangor, which operates in Maine. Unitil Energy and the electric division of Fitchburg are included in the electric segment. Northern Utilities, Bangor and the gas division of Fitchburg are included in the gas segment. Unitil Energy, Fitchburg, Northern Utilities and Bangor 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 which became operational in May 2025. Unitil Service’s and Unitil Realty’s costs are allocated to the Electric and Gas segments based on cost allocation factors.

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 and six months ended June 30, 2025 and June 30, 2024.

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Three Months Ended June 30, 2025 (millions)	Electric			Gas			Total Reportable Segments			Other			Total
Total Operating Revenues	$	51.0		$	51.6		$	102.6		$	—		$	102.6
Energy Supply Costs		25.2			14.4			39.6			—			39.6
Operation and Maintenance		9.6			10.9			20.5			0.8			21.3
Depreciation and Amortization		7.8			14.0			21.8			—			21.8
Other Segment Expenses (Income)		2.2			3.9			6.1			(0.2	)		5.9
Interest Income		(0.8	)		(0.6	)		(1.4	)		—			(1.4	)
Interest Expense		3.8			5.9			9.7			1.0			10.7
Provision for Income Taxes		0.4			0.6			1.0			(0.3	)		0.7
Net Income Attributable to Common Shares		2.8			2.5			5.3			(1.3	)		4.0

Capital Expenditures		16.0			24.2			40.2			—			40.2

Three Months Ended June 30, 2024 (millions)
Total Operating Revenues	$	56.4		$	39.3		$	95.7		$	—		$	95.7
Energy Supply Costs		31.5			8.0			39.5			—			39.5
Operation and Maintenance		8.4			10.0			18.4			0.2			18.6
Depreciation and Amortization		7.1			10.8			17.9			0.2			18.1
Other Segment Expenses (Income)		3.0			4.7			7.7			(0.5	)		7.2
Interest Income		(0.9	)		(0.9	)		(1.8	)		(0.6	)		(2.4	)
Interest Expense		3.3			5.6			8.9			0.9			9.8
Provision for Income Taxes		0.6			0.1			0.7			(0.1	)		0.6
Net Income Attributable to Common Shares		3.4			1.0			4.4			(0.1	)		4.3

Capital Expenditures		11.7			24.0			35.7			1.0			36.7

Six Months Ended June 30, 2025 (millions)
Total Operating Revenues	$	111.2		$	162.2		$	273.4		$	—		$	273.4
Energy Supply Costs		57.9			54.1			112.0			—			112.0
Operation and Maintenance		19.1			23.0			42.1			1.8			43.9
Depreciation and Amortization		15.7			27.8			43.5			—			43.5
Other Segment Expenses (Income)		5.4			8.7			14.1			(0.2	)		13.9
Interest Income		(1.6	)		(1.4	)		(3.0	)		—			(3.0	)
Interest Expense		7.2			12.0			19.2			2.2			21.4
Provision for Income Taxes		1.1			10.0			11.1			(0.9	)		10.2
Net Income Attributable to Common Shares		6.4			28.0			34.4			(2.9	)		31.5

Segment Assets		677.3			1,185.5			1,862.8			29.9			1,892.7
Capital Expenditures		37.2			35.6			72.8			—			72.8

Six Months Ended June 30, 2024 (millions)
Total Operating Revenues	$	130.0		$	144.4		$	274.4		$	—		$	274.4
Energy Supply Costs		78.0			52.1			130.1			—			130.1
Operation and Maintenance		16.8			19.8			36.6			0.2			36.8
Depreciation and Amortization		14.1			21.7			35.8			0.3			36.1
Other Segment Expenses (Income)		6.3			9.3			15.6			(0.4	)		15.2
Interest Income		(1.7	)		(1.8	)		(3.5	)		(0.9	)		(4.4	)
Interest Expense		6.4			11.6			18.0			1.1			19.1
Provision for Income Taxes		1.8			8.3			10.1			(0.1	)		10.0
Net Income Attributable to Common Shares		8.3			23.4			31.7			(0.2	)		31.5

Segment Assets		632.9			1,035.3			1,668.2			26.8			1,695.0
Capital Expenditures		20.4			34.7			55.1			1.8			56.9

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Note 4 - Debt AND FINANCING ARRANGEMENTS

Details on long-term debt at June 30, 2025, June 30, 2024 and December 31, 2024 are shown below.


(millions)	June 30,				December 31,
	2025		2024		2024
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
Unitil Energy First Mortgage Bonds:
6.96% Senior Secured Notes, Due September 1, 2028		8.0		10.0		8.0
8.00% Senior Secured Notes, Due May 1, 2031		9.0		10.5		10.5
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
Fitchburg:
3.52% Senior Notes, Due November 1, 2027		10.0		10.0		10.0
7.37% Senior Notes, Due January 15, 2029		4.8		6.0		6.0
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
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
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
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
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
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
Unitil Realty Corp.:
2.64% Senior Secured Notes, Due December 18, 2030		3.7		3.9		3.8
Total Long-Term Debt		644.5		514.4		647.3
Less: Unamortized Debt Issuance Costs		3.8		3.1		4.0
Total Long-Term Debt, net of Unamortized Debt Issuance Costs		640.7		511.3		643.3
Less: Current Portion		4.9		4.9		4.9
Total Long-term Debt, Less Current Portion	$	635.8	$	506.4	$	638.4

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 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

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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.


(millions)	June 30,				December 31,
	2025		2024		2024
Estimated Fair Value of Long-Term Debt	$	579.7	$	462.7	$	598.9


	Revolving Credit Facility (millions)
	June 30,				December 31,
	2025		2024		2024
Limit	$	275.0	$	200.0	$	200.0
Short-Term Borrowings Outstanding		171.4		157.8		105.8
Available	$	103.6	$	42.2	$	94.2

The average interest rates on all short-term borrowings and intercompany money pool transactions were 5.6% and 6.7% for the three months ended June 30, 2025 and June 30, 2024, respectively. The average interest rates on all short-term borrowings and intercompany money pool transactions were 5.6% and 6.7% for the six months ended June 30, 2025 and June 30, 2024, respectively. The average interest rate on all short-term borrowings for the twelve months ended December 31, 2024 was 6.5%.

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Utilities issued $25.0 million of Notes due 2034 at 5.54% and $15.0 million of Notes due 2039 at 5.74%; and Granite State issued $10.0 million of Notes due 2034 at 5.74%.

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 June 30, 2025 and June 30, 2024 amounted to $0.6 million and $0.5 million, respectively. Total rental expense under operating leases charged to operations for the six months ended June 30, 2025 and June 30, 2024 amounted to $1.1 million and $1.1 million, respectively.

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


	June 30,				December 31,
Lease Obligations (millions)	2025		2024		2024
Operating Lease Obligations:
Operating Lease Obligations (current portion)	$	1.7	$	1.7	$	1.8
Operating Lease Obligations (long-term portion)		4.0		3.4		4.9
Total Operating Lease Obligations		5.7		5.1		6.7
Capital Lease Obligations:
Other Current Liabilities (current portion)		0.1		0.1		0.1
Other Noncurrent Liabilities (long-term portion)		0.3		0.3		0.4
Total Capital Lease Obligations		0.4		0.4		0.5
Total Lease Obligations	$	6.1	$	5.5	$	7.2

Cash paid for amounts included in the measurement of operating lease obligations for the six months ended June 30, 2025 and June 30, 2024 was $1.1 million and $1.1 million and was included in Cash Provided by Operating Activities on the Consolidated Statements of Cash Flows.

Assets under capital leases amounted to approximately $0.6 million, $0.7 million and $0.6 million as of June 30, 2025, June 30, 2024 and December 31, 2024, respectively, less accumulated amortization of $0.2 million, $0.2 million and $0.1 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 June 30, 2025. The payments for operating leases consist of $1.7 million of current Operating Lease Obligations and $4.0 million of noncurrent Operating Lease Obligations on the Company’s Consolidated Balance Sheets as of June 30, 2025. The payments for capital leases consist of $0.1 million of current capital lease obligations, which are included in Other Current Liabilities and $0.3 million of noncurrent capital lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of June 30, 2025.

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Lease Payments ($000’s)	Operating		Capital
Year Ending December 31,	Leases		Leases
Rest of 2025	$	1,617	$	123
2026		1,219		105
2027		1,533		131
2028		971		45
2029		641		22
2030 - 2034		409		—
Total Payments		6,390		426
Less: Interest		663		33
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$	5,727	$	393

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 June 30, 2025, the weighted average remaining lease term is 3.8 years and the weighted average operating discount rate used to determine the operating lease obligations was 5.0%. As of June 30, 2024, the weighted average remaining lease term was 3.6 years and the weighted average operating discount rate used to determine the operating lease obligations was 4.6%.

Note 5 – equity

Common Stock

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

The Company had 16,291,395, 16,173,132 and 16,192,345 shares of common stock outstanding at June 30, 2025, June 30, 2024 and December 31, 2024, respectively.

The following table summarizes the Company's common shares activity for the six months ended June 30, 2025:


Common Stock	Shares
Shares as of December 31, 2024		16,192,345
Shares Issued - DRP		10,691
Shares Issued - ATM		27,620
Shares Issued - RSU Settlement		8,525
Shares Issued - Time Restricted		26,430
Shares Issued - Performance Restricted		26,430
Forfeited Shares - Time Restricted		(396	)
Forfeited Shares - Performance Restricted		(250	)
Shares as of June 30, 2025		16,291,395

Dividend Reinvestment and Stock Purchase Plan - During the first six months of 2025, the Company sold 10,691 shares of its common stock, at an average price of $55.25 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $590,600. 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 Second Amended and Restated 2003 Stock Plan (the Stock Plan). Participants in the Stock Plan are selected by the Compensation Committee of the Board of Directors to receive awards under the Stock Plan, including: (i) awards of restricted shares that vest based on time (Time Restricted Shares); (ii) awards of restricted shares that vest based on performance (Performance Restricted Shares); 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

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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 June 30, 2025. 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 28, 2025, 26,430 Time Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of approximately $1.4 million. There were 25,170 and 59,163 non-vested Time Restricted Shares under the Stock Plan as of June 30, 2025 and 2024, respectively. The weighted average grant date fair value of these shares was $50.85 and $47.72 per share, respectively. The compensation expense associated with the issuance of Time Restricted Shares under the Stock Plan is being recognized over the vesting period and was $1.3 million and $1.2 million for the six months ended June 30, 2025 and 2024, respectively. At June 30, 2025, there was approximately $1.4 million of total unrecognized compensation cost for Time Restricted Shares under the Stock Plan which is expected to be recognized over approximately 2.7 years. During the six months ended June 30, 2025 there were 396 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. Initial awards of Performance Restricted Shares were granted January 24, 2023. On January 28, 2025, there were 26,430 Performance Restricted Shares issued under the Stock Plan with an aggregate market value of $1.4 million. There were 67,380 and 43,453 non-vested Performance Restricted Shares under the Stock Plan as of June 30, 2025 and 2024, respectively. The weighted average grant date fair value of these shares was $51.21 and $50.35 per share, respectively. The compensation expense associated with the issuance of Performance Restricted Shares under the Stock Plan is being recognized over the vesting period and was $0.8 million and $0.5 million for the six months ended June 30, 2025 and June 30, 2024, respectively. At June 30, 2025, there was approximately $2.5 million of total unrecognized compensation cost for Performance Restricted Shares under the Stock Plan which is expected to be recognized over approximately 1.9 years. During the six months ended June 30, 2025 there were 250 Performance Restricted Shares forfeited and zero Performance Restricted Shares cancelled under the Stock Plan.

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The Time Restricted Shares and Performance Restricted Shares activity during the six months ended June 30, 2025 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, 2024		19,933		$	48.09		41,200		$	50.28
Granted		26,430		$	52.65		26,430		$	52.65
Shares Issued		(20,797	)	$	50.57		—		$	—
Forfeited		(396	)	$	47.42		(250	)	$	50.35
Restricted Shares as of June 30, 2025		25,170		$	50.85		67,380		$	51.21

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 six months ended June 30, 2025 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, 2024		36,636		$	44.15		15,701		$	54.19
Restricted Stock Units Granted		—		$	—		—		$	—
Dividend Equivalents Earned		527		$	55.54		226		$	55.54
Restricted Stock Units Settled		(8,525	)	$	43.32		(3,654	)	$	58.97
Restricted Stock Units as of June 30, 2025		28,638		$	44.61		12,273		$	52.15

There were 33,921 Restricted Stock Units outstanding as of June 30, 2024 with a weighted average stock price of $42.89. Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of June 30, 2025, June 30, 2024 and December 31, 2024 is $0.6 million, $0.8 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.

At-the-Market Equity Offering Program

On June 3, 2025, the Company entered into an at-the-market (ATM) equity offering program with Janney Montgomery Scott LLC and Scotia Capital (USA) Inc., 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 three and six months ended June 30, 2025, the Company sold 27,620 shares of common stock under the ATM program at an average price of $53.00 per share, resulting in gross proceeds of $1.5 million and net proceeds of $1.4 million after deducting commissions and offering expenses. As of June 30, 2025, $48.5 million remains available for future sales under the program.

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

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Preferred Stock

There were $0.2 million, or 1,727 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of June 30, 2025, June 30, 2024 and December 31, 2024. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the three and six month periods ended June 30, 2025 and June 30, 2024, respectively.

Earnings Per Share

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

The following table reconciles basic and diluted earnings per share:


	Three Months		Six Months Ended
Earnings Per Share (millions, except shares and per share data)	June 30, 2025		June 30, 2025
Net Income	$	4.0	$	31.5
Less allocation of earnings and dividends to participating securities		—		0.2
Net income allocated to common shareholders	$	4.0	$	31.3

Weighted average common shares outstanding, gross		16,278,433		16,262,222
Less average participating securities		106,568		98,821
Weighted average number of shares outstanding used in the calculation of basic earnings per share		16,171,865		16,163,401
Add dilutive effect of:
Restricted stock and restricted stock units		3,246		6,653
Adjusted weighted average number of shares outstanding used in the calculation of diluted earnings per common share		16,175,111		16,170,054

Earnings per common share:
Basic	$	0.25	$	1.94
Diluted	$	0.25	$	1.94

note 6 – 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, 2024 as filed with the Securities and Exchange Commission on February 10, 2025.

Rate Case Activity

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

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

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Northern Utilities - Base Rates - New Hampshire - On July 20, 2022, the NHPUC issued an Order in the distribution base rate case filed with the NHPUC on August 2, 2021 by Northern Utilities. The Order approved a comprehensive Settlement Agreement between the Company, the New Hampshire Department of Energy (DOE), and the Office of the Consumer Advocate (OCA). As provided in the Settlement Agreement, in addition to authorizing an increase to permanent distribution rates of $6.1 million, effective August 1, 2022, the Order (1) approved a revenue decoupling mechanism and (2) allowed for a step adjustment effective September 1, 2022 covering the additional revenue requirement resulting from changes in Net Plant in Service associated with non-growth investments for the period January 1, 2021, through December 31, 2021. This distribution base rate case reflected the Company’s operating costs and investments in utility plant for a test year ended December 31, 2020 as adjusted for known and measurable changes. The Order provided for a return on equity of 9.3% and a capital structure reflecting 52% equity and 48% long-term debt. The increase in permanent rates was reconciled back to October 1, 2021, the effective date of temporary rates previously approved in this docket. On June 8, 2022, the Company filed for its step increase of approximately $1.6 million of annual revenue, for rates effective as of September 1, 2022, to recover eligible 2021 capital investments. On August 31, 2022, the NHPUC approved the Company’s filing.

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

Fitchburg - Base Rates - Electric - Fitchburg’s base rates are decoupled and subject to an annual revenue decoupling adjustment mechanism, which includes a cap on the amount that rates may be increased in any year. In addition, Fitchburg has an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions. On July 26, 2023, the MDPU issued an Order approving the Company's cumulative revenue requirement of $3.1 million associated with its 2019-2021 capital expenditures. On September 11, 2024, the MDPU issued a final order approving the cumulative revenue requirement of $3.5 million associated with its 2019-2022 capital expenditures. On November 1, 2024, Fitchburg filed its cumulative revenue requirement of $0.5 million associated with its 2023 capital expenditures, which reflects the transfer of capital expenditures associated with its 2019-2023 year investments into base distribution rates effective July 1, 2024. On December 23, 2024, the MDPU approved recovery through its capital cost recovery mechanism effective January 1, 2025.

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

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

Fitchburg - Base Rates - Gas - On August 17, 2023, Fitchburg filed a petition with the MDPU seeking approval for a $10.9 million increase to base distribution rates, with new rates anticipated to be effective July 1, 2024. Fitchburg proposed to transfer $4.2 million in revenue requirements recovered through its Gas System Enhancement Program to base distribution rates. Net of these transfers, the proposed overall increase to distribution revenues is $6.7 million. As part of this filing, Fitchburg is requesting approval for a PBR plan for up to a five-year term and continuation of its revenue decoupling mechanism. On June 28, 2024, the MDPU issued an Order providing for a $10.1 million increase to base rates, effective July 1, 2024. This includes a transfer of $4.9 million in costs from certain reconciling mechanisms to base distribution rates. In addition to authorizing an increase to base rates, the Order approved a PBR plan for up to a five-year term. The order approves continuation of the Company’s revenue decoupling mechanism but changes the structure from a revenue per customer benchmark to a total revenue cap. The Order provided for a return on equity of 9.4% and a capital structure reflecting 52% equity and 48% long-term debt. On July 5, 2024, the Company filed its compliance tariff filing and made further revisions as directed by the MDPU on July 15, 2024. On July 16, 2024, the MDPU approved its revised compliance filing. Part of the transfer of revenues from reconciling mechanisms to base rates included $0.9 million of pension/PBOP revenues. In its order, the MDPU found that allowing the Company to recover pension and PBOP expense through its Pension/PBOP Adjustment mechanism is no longer warranted. Instead, the MDPU concluded that these expenses should be recovered in base distribution rates, the mechanism should be discontinued and any unrecovered expenses existing as of the effective date of new rates will be recovered over two years. On July 18, 2024, the Company filed a Motion for Reconsideration and Recalculation in connection with this issue. The motion specifically requested that the MDPU reconsider its decision to require the Company to absorb $1.4 million in negative excess accumulated deferred income taxes (ADIT) because the effect of the Order was to inappropriately claw back amounts that were previously approved by the MDPU for recovery from customers. On November 26, 2024, the MDPU issued an Order on the Company’s motion holding, in part, that Pension/PBOP expenses shall be recovered in base distribution rates. On December 9, 2024, the Company filed an appeal with Massachusetts Supreme Judicial Court requesting that it reverse and remand the final decision issued by the MDPU on June 28, 2024 along with the MDPU’s decision on reconsideration, issued November 26, 2024, unlawfully denying the Company’s recovery of approximately $1.4 million of negative, excess ADIT. The amount of $1.4 million is disaggregated between the Company’s Gas Division ($0.6 million) and the Electric Division ($0.8 million). This motion is pending. The ruling on November 26, 2024 approved certain other recalculations, resulting in an additional increase to gas base rates of $0.1 million effective December 1, 2024.

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

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

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

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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. This matter remains pending.

Other Matters

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

On February 5, 2024, the NH Department of Environmental Services (NHDES) issued an Alteration of Terrain Permit for the project. On February 9, 2024, NHDES issued a Wetland and Non-Site Specific Permit for the project. On February 14, 2024, the United States Army Corps of Engineers issued a NH General Permit for the project. The facility became fully commissioned in May 2025. The Company has included a cost recovery proposal associated with the solar facility as part of its base rate proceeding filing.

Unitil Energy - Major Storm Cost Reserve Recovery - On February 28, 2025, Unitil Energy filed a request with the NHPUC to increase its Storm Recovery Adjustment Factor (SRAF) effective August 1, 2025. The Company proposes to reduce its Major Storm Cost Reserve deferral balance by transferring its April 2024 Nor’easter costs of approximately $1.8 million into the SRAF and recover the cost over the next three years. On May 9, 2025, the NHPUC issued a procedural Order stating that due to their schedule an effective date of August 1, 2025 was not feasible and instead an effective date of September 1, 2025 would be implemented. On June 27, 2025, the New Hampshire DOE filed a statement in support of the Company’s request. A hearing on the matter is scheduled in August. This matter remains pending.

Fitchburg - Grid Modernization - On July 1, 2021, Fitchburg submitted its Grid Modernization Plan (GMP) to the MDPU. The GMP includes a five-year strategic plan, including a plan for the full deployment of advanced metering functionality, and a four-year short-term investment plan, which focuses on foundational investments to facilitate the interconnection and integration of distributed energy resources, optimizing system performance through command and control and self-healing measures, and optimizing system demand by facilitating consumer price-responsiveness. On October 7, 2022, the MDPU issued a “Track 1” Order approving a budget cap of $9.3 million through 2025 for previously deployed or preauthorized grid modernization investments. On November 30, 2022, the MDPU issued its “Track 2” Order addressing new technologies and Advanced Metering Infrastructure (AMI) proposals. The MDPU preauthorizes a four-year $1.5 million budget for Fitchburg’s additional grid-facing investments. Any spending over the total budget cap is not eligible for targeted cost recovery through its Grid Modernization Factor (GMF), and instead, may be recovered by the Company in a base distribution rate proceeding subsequent to a prudency finding by the MDPU in a GMF filing or term review Order. The MDPU also preauthorized the Company’s AMI meter replacement investments, with a budget of $11.2 million through 2025. Additionally, the MDPU provided preliminary approval for the Company’s customer engagement and experience and data sharing platform investments, with a combined budget of $2.3 million through 2025. The Company may recover eligible costs incurred for preauthorized grid-facing investments and customer-facing investments that will be made during the 2022-2025 GMP term through the GMFs, subject to certain modifications to the Company’s GMF tariff and a final prudence review. The MDPU conducted a hearing on September 26, 2023 on the Company’s then-pending GMF filings and Grid Modernization Term Report. This matter remains pending.

On April 24, 2023, Fitchburg submitted its 2022 Grid Modernization Plan Annual Report to the MDPU. Among other things, the Company explained a modification to its implementation of the AMI plan that the MDPU preauthorized in D.P.U. 21-82. Due to a discontinuation of the meter technology upon which the Company’s initial AMI plan relied, the Company reported that it will need to replace its meters with a new meter technology and to implement a new communications system. On May 31, 2023, the MDPU issued an Order indicating its intent to explore the impact of the discontinuation and determine the appropriate next steps outside the GMF proceeding. On April 15, 2024, the Company submitted its annual Grid Modernization Filing seeking recovery of costs related to grid modernization investments placed into service in 2023. In connection with this filing, the Company submitted a request for preauthorization of the metering, communications systems, and head end system investments that will be implemented in connection with the Company’s advanced metering infrastructure replacement project. On March 28, 2025, the MDPU issued an Order approving, among other things, the Company’s request for preauthorization. Fitchburg submitted its 2024 Grid Modernization Plan Annual Report on July 1, 2025. This matter remains pending.

Fitchburg - Grid Modernization Cost Recovery Factor - On April 15, 2023, Fitchburg filed its GMF rate adjustment and reconciliation filing for recovery of the costs incurred as a result of implementing the Company’s 2022-2025 GMP, approved by the MDPU in Orders dated October 7, 2022 and November 30, 2022. On May 31, 2023, the MDPU approved, subject to further investigation and reconciliation, the cumulative recovery of $1.0 million associated with the Company’s 2022 GMP revenue requirement, effective June 1, 2023. The MDPU conducted a hearing on September 26, 2023 regarding the Company’s pending GMF filings and Grid Modernization Term Report. The matter remains pending. On April 15, 2024, Fitchburg filed its GMF rate adjustment

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and reconciliation filing for recovery of the costs incurred as a result of implementing the Company’s 2022-2025 GMP. On May 31, 2024, the MDPU approved, subject to further investigation and reconciliation, the cumulative recovery of $1.3 million associated with its 2023 revenue requirement, effective June 1, 2024. On June 28, 2024, the MDPU issued an Order in Fitchburg’s electric base rate case providing for the transfer of $1.6 million meter-related costs from base distribution rates to the GMF, effective July 1, 2024. On April 15, 2025, Fitchburg filed its GMF rate adjustment and reconciliation filing for recovery of the costs incurred as a result of implementing the Company’s 2022-2025 GMP and continued recovery of meter-related costs. This filing seeks recovery of $1.4 million associated with its 2024 GMP revenue requirement as well as $1.5 million associated with its 2024 meter-related costs, effective June 1, 2025. On May 30, 2025, the MDPU issued an order approving the Company’s proposed rate changes effective June 1, 2025 subject to further investigation and reconciliation.

Fitchburg - Investigation into the role of gas LDCs to achieve Commonwealth 2050 climate goals - The MDPU has opened an investigation to examine the role of Massachusetts gas local distribution companies (LDCs) in helping the Commonwealth achieve its 2050 climate goal of net-zero greenhouse gas (GHG) emissions. In its Order opening the inquiry, the MDPU stated it is required to consider new policies and structures as the Commonwealth reduces reliance on fossil fuels, including natural gas, which may require LDCs to make significant changes to their planning processes and business models. The LDCs, including Fitchburg, engaged an independent consultant to conduct a study and prepare a report (Consultant Report), including a detailed study of each LDC, that analyzes the feasibility of all identified pathways to help the Commonwealth achieve its net-zero GHG goal. The study includes an examination of the potential pathways identified in the 2050 Decarbonization Roadmap developed by the Massachusetts Executive Office of Energy and Environmental Affairs, in consultation with the Massachusetts Department of Environmental Protection and the Massachusetts Department of Energy Resources (DOER).

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 and Extension of Judicial Appeal Period. The Joint Motion requests clarification of three issues: (1) the MDPU’s directive concerning the NPAs analysis; (2) the timetable for establishing ‘incentives and disincentives’ for progress toward compliance with Climate Act mandates as part of a PBR framework and achievement of approved Climate Compliance Plans; and (3) the methodology for emissions reduction accounting for Climate Compliance Plans, with particular attention to Scope 1 and Scope 3 emissions accounting. On April 2, 2024, the MDPU issued an Order on the LDCs’ Joint Motion. In its Order, the MDPU clarified, among other things, that NPA analyses should be applied at the project level to all investment decisions going forward, and should be considered at project planning stage; that pending an approved NPA framework, LDCs should make all reasonable efforts to incorporate NPA analyses into investment decisions; and that LDCs will have the burden to demonstrate the prudence of implementing a traditional project instead of a NPA. The MDPU did not expressly exempt any category of project from the NPA analysis requirement.

On June 14, 2024, the MDPU directed the LDCs to provide certain information regarding the companies’ line extension policies for customers requesting new service. The LDCs provided responsive information on August 13, 2024; various interested parties provided comments on the companies’ policies on October 11, 2024, and the LDCs, including Fitchburg, provided reply comments on February 27, 2025. On February 5, 2025, the MDPU issued a memorandum setting a draft line extension policy that would require customers seeking new gas service to pay the entire cost of connecting to the distribution system. The Company provided comments on the draft policy on April 3, 2025. The MDPU intends to investigate this topic as part of the CCP proceeding.

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.

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

Following the stakeholder process related to long term system planning, Fitchburg and other EDCs submitted a draft Long Term System Planning Proposal for MDPU review and approval. This matter remains pending.

Fitchburg - Electric Vehicle (EV) Proceeding - On December 30, 2022, the MDPU issued an order approving Fitchburg’s five-year EV program with a $1.0 million budget consisting of: (1) public infrastructure offering ($0.5 million); (2) Electric Vehicle Supply Equipment incentives for residential segment ($0.3 million); and (3) marketing and outreach ($0.2 million). The Company may shift spending between program segments and between years over the five-year term of its program, subject to a 15% cap. Any spending above the approved EV program budget or above the 15% cap for each program segment is not eligible for targeted cost recovery through the GMF and, instead, may be recovered in a base distribution rate proceeding subsequent to a prudency finding by the MDPU. The MDPU’s Order directs the Companies to submit annual reports that document their performance and these reports are due on or before May 15th of each year. The MDPU accepted the Company’s Demand Charge Alternative proposal and directed implementation within six months. The Demand Charge Alternative is offered for a ten-year period beginning July 1, 2023 with tiered rates to separately-metered EV general delivery service customers. The MDPU also accepted the Company’s proposed residential EV TOU rate, effective April 1, 2023.

In June 2023, the MDPU convened an EV stakeholder process to finalize EV program performance metrics. On April 3, 2023, the electric companies filed comments on the MDPU’s proposed metrics. On December 15, 2023, the MDPU approved EV performance metrics. Following that approval, the MDPU required the electric companies to develop a joint state-wide program evaluation plan for MDPU approval and stakeholder input. On May 15, 2024, Fitchburg submitted its first annual report on the performance of its EV Program, and along with the other Massachusetts EDCs, a proposed statewide program evaluation plan for MDPU approval and stakeholder input. On September 30, 2024, the MDPU stamp approved the Joint Statewide Electric Vehicle Program Evaluation Plan. In addition, on October 1, 2024 the MDPU approved Fitchburg’s request for a supplemental budget increase to engage a consultant to assist with the Joint Statewide Electric Vehicle Program Evaluation Plan. On December 20, 2024, the Company submitted a request for approval to modify certain aspects of the public, residential, and income eligible offers of its EV program. Fitchburg does not anticipate any rate changes resulting from this filing, which is currently pending before the MDPU.

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

Fitchburg - Approval of Gas Supply Agreement with Constellation LNG - On February 16, 2024, Fitchburg filed a petition with the MDPU for approval of a six year agreement with Constellation LNG for the purchase of natural gas in the liquid or vapor form for the period June 1, 2024 through May 31, 2030 heating seasons. This request is for the approval of two contracts, the first for up to 3,400 Dth per day of natural gas peaking supply to the Company. This first contract will be broken out for 3,000 Dth per Day in the form of LNG for use at the Company’s Westminster LNG facility and 400 Dth per Day will be in the form of natural gas supply

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delivered to the city-gate connecting the Company’s system to the Tennessee Gas Pipeline. The second contract will provide up to 3,000 Dth per day of LNG trucking from the Everett Marine Terminal to the Company’s Westminster LNG facility.

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

In D.P.U. 20-80-B, the MDPU directed the Company and other LDCs to include in their inaugural CCPs the following information: (1) whether, and to what extent, the Agreements have facilitated the Companies’ plans to meet GHG emission reduction goals in compliance with the Global Warming Solutions Act; (2) a description of the Companies’ efforts to reduce customer demand for natural gas; and (3) a description of the Companies’ efforts to reduce or eliminate their reliance on EMT, including, but not limited to (i) the costs, feasibility, and timelines for each alternative identified; and (ii) a description of how each alternative identified would contribute to GHG emissions reductions. The Company reported this information to the MDPU in its inaugural CCP on April 1, 2025 and will continue to file this annually through 2030.

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

Unitil Corporation – Merger of Maine Natural Gas Company - On May 9, 2025, Unitil, Northern Utilities, Bangor, Avangrid Enterprises, Inc. and Maine Natural Gas filed a Joint Petition requesting that the MPUC approve the merger of Maine Natural Gas into Unitil pursuant to a Stock Purchase Agreement among Avangrid and Unitil. A procedural schedule has been established which includes discovery, technical conferences, testimonies and briefs. To comply with the statutory timeframe of 180 days, deliberations are scheduled to be held no later than early November 2025. This matter remains pending.

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).

On May 8, 2025, Eversource Energy (Eversource), the AWA, and Unitil submitted an amended and restated petition to the MDPU for approval of a change of control of Aquarion Water Company of Massachusetts, Inc. (AWC-MA). This matter remains pending.

On May 8, 2025, Unitil, Eversource, Aquarion Water Company of New Hampshire, Inc., (AWC-NH), Abenaki Water Company (Abenaki) and AWA filed a motion to amend the petition originally filed on April 10, 2025 by Eversource. AWC-NH, Abenaki and AWA, requesting that the NHPUC approve the acquisition of AWC-NH and Abenaki by Unitil. This matter remains pending.

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

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

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approval on a one-year extension for the period of November 1, 2025 through October 31, 2026. The Company received an order approving the one-year extension of its request on June 3, 2025.

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

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. This matter is ongoing.

Reconciliation Filings - Fitchburg, Unitil Energy, Northern Utilities and Bangor 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 four companies. Fitchburg, Unitil Energy, Northern Utilities and Bangor have been, and remain in full compliance with all directives and orders regarding these filings. The Company considers these to be routine regulatory proceedings, and there are no material issues outstanding.

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

The EDCs issued the RFP for Section 83D Long-Term Contracts in March 2017, and power purchase agreements (PPAs) for 9,554,940 MWh of hydroelectric generation and associated environmental attributes from Hydro-Quebec Energy Services (U.S.), Inc. were filed in July 2018 for approval by the MDPU. On June 25, 2019, the MDPU approved the PPAs, including the EDCs’ proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market revenue to customers. The MDPU also approved the EDCs’ request for remuneration equal to 2.75% of the contract payments, as well as the EDCs’ proposal to recover costs associated with the contracts. On January 13, 2023, NECEC Transmission LLC (NECEC), the company with which Fitchburg and the other EDCs entered into transmission service agreements (TSAs) for the delivery of the Hydro-Quebec energy, provided a letter to the EDCs purporting to give notice of a “change in applicable law” related to a Maine ballot initiative and requesting a negotiated amendment to the TSAs including a price adjustment. On June 27, 2023, NECEC sent a letter to the EDCs seeking schedule relief also in accordance with their “change in law” determination. On October 28, 2024, the EDCs filed a Settlement Agreement and Amendment 4 to the TSA with the MDPU, requesting cost recovery approval associated with the amendment. The amendment also addressed the schedule relief requested by NECEC. On January 27, 2025, the MDPU approved the Settlement Agreement and recovery of increased costs associated with the amendment.

Section 83C of “An Act Relative to Green Communities,” St. 2008, c. 169, as amended by St. 2016, c. 188, § 12 (Section 83C) requires the EDCs to jointly and competitively solicit proposals for offshore wind energy generation not later than June 30, 2017. The

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EDCs issued an initial RFP pursuant to Section 83C in June 2017. On July 23, 2018, the EDCs, filed two long-term contracts with Vineyard Wind, each for 400 MW of offshore wind energy generation, for approval by the MDPU. On April 12, 2019, the MDPU approved the offshore wind energy generation PPAs, including the EDCs’ proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market revenue to customers. The EDCs issued a second RFP pursuant to Section 83C to procure an additional 800 MW of offshore wind energy generation in May 2019. The EDCs filed for approval of two PPAs with Mayflower Wind Energy LLC (now known as SouthCoast Wind), each for 400 MW of offshore wind energy generation, on February 10, 2020. On November 5, 2020, the MDPU approved the PPAs. In both cases, the MDPU approved the EDCs’ request for remuneration equal to 2.75% of the contract payments, as well as the EDCs’ proposal to recover costs associated with the contracts. In April 2023, SouthCoast Wind engaged with the EDCs to explore options to mitigate impacts of global resource constraints and pricing challenges associated with the PPAs from this procurement. They cited an inability to finance the project within the terms set out in the PPA. The EDCs negotiated a termination agreement with SouthCoast Wind which was filed with the MDPU for approval on August 28, 2023 and which received approval on September 30, 2023.

In accordance with “An Act to Advance Clean Energy” (2018) the DOER recommended that the EDCs solicit up to 1,600 MW in additional offshore wind in 2022 and 2024. On May 7, 2021, the EDCs issued a third RFP for up to an additional 1,600 MW of offshore wind generation. On May 25, 2022, the EDCs sought approval of PPAs with Commonwealth Wind for 1,200 MW and with SouthCoast Wind for 400 MW. On December 16, 2022, Commonwealth Wind filed a motion requesting that the MDPU dismiss proceedings related to the approval of its contract, arguing that, due to various economic conditions, its contracts with the EDCs would no longer facilitate the financing of offshore wind energy generation. On December 30, 2022, the MDPU denied Commonwealth Wind’s motion and approved the PPAs. The MDPU also approved the EDCs’ request for remuneration equal to 2.25% as reasonable and in the public interest. On January 19, 2023, Commonwealth Wind filed a Petition for Appeal with the Massachusetts Supreme Judicial Court (SJC) seeking to set aside and vacate the MDPU’s Order approving the PPAs. In April 2023, SouthCoast Wind engaged with the EDCs to explore options to mitigate global resource constraints and pricing challenges associated with their PPAs from this procurement. SouthCoast Wind noted challenges around an inability to finance the projects under the current terms. The EDCs negotiated termination agreements with Commonwealth Wind and SouthCoast Wind and submitted the agreements to the MDPU for approval on July 13, 2023 and August 28, 2023, respectively. The MDPU approved both termination agreements on September 30, 2023.

The “Energy Diversity Act” (2021) and “An Act Driving Clean Energy and Offshore Wind” (2022) enacted by the Massachusetts legislature, increased the total solicitation target (including future solicitations) for offshore wind energy generation to 5,600 MW by June 30, 2027. On August 30, 2023, the EDCs issued a fourth offshore wind RFP seeking to procure at least 400 MW and up to the maximum amount remaining of the statutory requirement under Section 83C of 5,600 MW of Offshore Wind Energy Generation, and taking into account offshore wind generation under contract at the time when proposals are due. Bidders were allowed to offer proposals of at least 200 MW up to 2,400 MW of offshore wind generation. On January 18, 2024, the EDCs notified the MDPU of an extension to the bid submission date and subsequent solicitation schedule dates by an additional 56 days each to allow bidders the opportunity to gain more certainty around their eligibility for the investment tax credit and factor it into their proposals. The submission date was revised to March 27, 2024. The EDCs received bids for Offshore Wind Generation from three developers as part of a multi-state solicitation with Rhode Island and Connecticut and on September 6, 2024, the DOER selected a portfolio of projects totaling 2,678 MW from three projects, one of which was dependent on commitments from Connecticut. On December 20, 2024, Connecticut announced it was withdrawing from contract negotiations resulting in the termination of the conditional project. Contract negotiations with the remaining two developers are scheduled to be completed by December 2025.

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 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.” The first solicitation will be for the environmental attributes associated with approximately 1,500 megawatts of mid-duration storage. The RFP for the first round of procuring energy storage was released on July 31, 2025.

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

Fitchburg Energy Efficiency Programs - Both the electric and gas divisions of Fitchburg actively participate in the energy efficiency programs in Massachusetts, as directed by the MDPU. These programs require periodic filings and are subject to investigation and review. The Company considers these to be routine regulatory proceedings. The MDPU recently approved the

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Massachusetts utilities’ 2025-2027 three-year energy efficiency plan subject to certain modifications, including a $500 million reduction to the total residential sector budget.

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

On December 13, 2022, RENEW Northeast, Inc. (RENEW), a non-profit entity that advocates for the business interests of renewable power generators in New England filed a complaint with FERC against ISO-NE and the PTOs requesting a determination that certain open-access transmission tariff schedules are unjust and unreasonable to the extent they permit PTOs to directly assign to interconnection customers O&M costs associated with network upgrades. Fitchburg and Unitil Energy are PTOs, although Unitil Energy does not own transmission plant. The PTOs answered the complaint on January 23, 2023. FERC issued an Order December 19, 2024 and a compliance filing was made on February 18, 2025 revising the ISO-NE OATT accordingly. While most of the intervening parties supported the compliance filing a new issue was raised by one participant. RENEW and the NETO’s have resolved their issues and filed briefs in support of the compliance filing. This matter remains pending. The Company does not believe these proceedings will have a material adverse 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 7 – 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, 2024 as filed with the Securities and Exchange Commission on February 10, 2025.

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 June 30, 2025, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, the Company cannot assure that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs. Based on its current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, the Company does not believe that these environmental costs will have a material adverse effect on the Company’s consolidated financial position or results of operations.

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

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

In May 2024, NH DES requested additional information in connection with the Company’s December 2022 remedial action plan (RAP), regarding groundwater contaminants at the Rochester site. In anticipation of the NH DES approval of one of the RAP

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alternatives and subsequent request for project design, the Company has accrued $5.6 million for estimated costs to complete the remediation at the Rochester site, which is included in Environmental Obligations on the Company’s Consolidated Balance Sheets. Due to extended regulatory review time periods, Northern Utilities anticipates the commencement of remediation activities in 2026.

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

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

Fitchburg’s Manufactured Gas Plant Site - Fitchburg has worked with the Massachusetts Department of Environmental Protection (Mass DEP) to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring continues. Following submittal of the Immediate Response Action (IRA) plan in October 2023, and an update in November 2024, the Mass DEP in May 2025 concurred with the proposed limited excavation and armoring of the riverbank at the identified seep area. Fitchburg has accrued $40,000 for estimated costs to complete the remediation at the Sawyer Passway site, which is included in Environmental Obligations on the Company’s Consolidated Balance Sheets. The Company has determined that the high end of the range of reasonably possible remediation costs for the Sawyer Passway site could be $3.5 million based on remediation alternatives. Contingent upon resolution of the access issue detail in the Twin City Rail Trail discussion, Fitchburg anticipates the commencement of the remediation activity in late 2025 or 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 environmental site assessment (ESA) in the second quarter of 2021 at its former distribution operations center in Kensington, NH. The Company is awaiting a decision on a report, submitted to the NH DES in June 2023, as to whether there is a need to conduct further investigation or remedial actions regarding the impacts of soil and groundwater contaminants identified in the ESA. Unitil Energy anticipates the commencement of remediation activities in 2026, following work plan approval by the NH DES decision. The Company does not believe this investigation will have a material adverse effect on its financial condition, results of operations or cash flows.

The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the six months ended June 30, 2025 and 2024.


Environmental Obligations (millions)
	June 30,
	2025		2024
Total Balance at Beginning of Period	$	7.8	$	4.6
Additions		0.3		0.2
Less: Payments / Reductions		0.3		0.1
Total Balance at End of Period		7.8		4.7
Less: Current Portion		0.7		0.7
Noncurrent Balance at End of Period	$	7.1	$	4.0

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Note 8: INCOME TAXES

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 Six Months Ended June 30,
	2025			2024
Statutory Federal Income Tax Rate		21	%		21	%
Income Tax Effects of:
State Income Taxes, net		7			6
Utility Plant Differences		(4	)		(3	)
Effective Income Tax Rate		24	%		24	%

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 June 30, 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. The Company remains subject to examination by Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2023; December 31, 2022; and December 31, 2021.

Income tax filings for the year ended December 31, 2023 have been filed with the IRS, Massachusetts Department of Revenue, the Maine Revenue Service, and the New Hampshire Department of Revenue Administration. In the Company’s federal tax returns for the year ended December 31, 2023, which were filed with the IRS in October 2024, the Company generated federal Net Operating Loss Carryforward (NOLC) assets of $2.9 million increasing the total amount of NOLC to $7.3 million to offset future years' income. As of December 31, 2024, the Company recognized the utilization of approximately $6.6 million of the NOLC asset and $1.3 million of federal tax credits available to offset current taxes payable. In addition, at December 31, 2024, the Company had $1.6 million of cumulative state tax credit carryforwards to offset future income taxes payable. If unused, the Company’s state tax credit carryforwards will begin to expire in 2027.

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

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

In December 2017, the Tax Cuts and Jobs Act (TCJA), which included a reduction of the corporate federal income tax rate to 21% effective January 1, 2018, was signed into law. In accordance with FASB Codification Topic 740, the Company revalued its Accumulated Deferred Income Taxes (ADIT) and recorded a net liability in the amount of $48.9 million at December 31, 2017. The Company expects to flow through to customers $47.1 million of excess ADIT in utility base rates. The benefit of protected excess ADIT amounts will be subject to flow back to customers in utility rates according to the Average Rate Assumption Method (ARAM). The Company estimates the ARAM flow back period for protected and unprotected excess ADIT to be between fifteen and twenty years over the remaining life of the related utility plant. As of June 30, 2025, the Company flowed back $12.7 million to customers in its Massachusetts, Maine, New Hampshire and federal jurisdictions.

Note 9: 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 9 to the Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2024 as filed with the SEC on February 10, 2025 for additional information regarding these plans.

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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	2025			2024
Discount Rate		5.60	%		5.00	%
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 2025 for pre-65 retirees is 8.50%, with an ultimate rate of 4.50% in 2034, and for post-65 retirees, the health care cost trend rate is 7.50%, with an ultimate rate of 4.50% in 2034. The health care cost trend rate used to determine benefit plan costs for 2024 for pre-65 retirees was 8.00%, with an ultimate rate of 4.50% in 2033, and for post-65 retirees, the health care cost trend rate was 6.00%, with an ultimate rate of 4.50% in 2033.

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


	Pension Plan						PBOP Plan						SERP
For the Three Months Ended June 30,	2025			2024			2025			2024			2025			2024
Service Cost	$	436		$	497		$	501		$	497		$	40		$	55
Interest Cost		2,016			1,886			992			817			172			181
Expected Return on Plan Assets		(2,625	)		(2,649	)		(1,085	)		(969	)		—			—
Prior Service Cost Amortization		64			81			—			—			2			2
Actuarial Loss Amortization		319			362			(187	)		(218	)		(54	)		—
Sub-total		210			177			221			127			160			238
Amounts Capitalized and Deferred		26			27			(48	)		54			(50	)		(74	)
Net Periodic Benefit Cost Recognized	$	236		$	204		$	173		$	181		$	110		$	164


	Pension Plan						PBOP Plan						SERP
For the Six Months Ended June 30,	2025			2024			2025			2024			2025			2024
Service Cost	$	872		$	994		$	1,003		$	994		$	79		$	109
Interest Cost		4,032			3,772			1,984			1,634			344			362
Expected Return on Plan Assets		(5,249	)		(5,298	)		(2,171	)		(1,938	)		—			—
Prior Service Cost Amortization		128			162			—			—			4			4
Actuarial Loss Amortization		638			724			(374	)		(437	)		(107	)		—
Sub-total		421			354			442			253			320			475
Amounts Capitalized and Deferred		135			135			(34	)		178			(101	)		(148	)
Net Periodic Benefit Cost Recognized	$	556		$	489		$	408		$	431		$	219		$	327

Employer Contributions

As of June 30, 2025, the Company had not made any contributions to its Pension Plan and PBOP Plan, respectively, in 2025. The Company, along with its subsidiaries, expects to make contributions to its Pension and PBOP Plans in 2025 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension and PBOP Plan costs.

As of June 30, 2025, the Company had made $0.3 million of benefit payments under the SERP Plan in 2025. The Company presently anticipates making an additional $0.4 million of benefit payments under the SERP Plan in 2025.

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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 June 30, 2025. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of June 30, 2025 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 6 and 7 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, 2024 as filed with the SEC on February 10, 2025.

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 June 30, 2025.

Issuer Purchases of Equity Securities

There were no purchases of equity securities by the Company for the fiscal period ended June 30, 2025.

Item 5. Other Information

(a) On August 4, 2025, the Company issued a press release announcing its results of operations for the three and six month periods ended June 30, 2025. The press release is furnished with this Quarterly Report on Form 10-Q as Exhibit 99.1.

(b) During the quarter ended June 30, 2025, 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).

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Item 6. Exhibits

(a) Exhibits



Exhibit No.	Description of Exhibit	Reference*

2.1 (1)(2)	Purchase and Sale Agreement between Unitil Corporation and Aquarion Water Authority, and, solely with respect to Section 9.25 and Section 9.26 thereof, South Central Connecticut Regional Water Authority.	Exhibit 2.1 to Form 8-K for May 6, 2025 (SEC File No. 1-8858)

4.1 (2)(3)	Note Purchase Agreement dated July 8, 2025 by and among Bangor Natural Gas Company and the several purchasers named therein.	Exhibit 4.1 to Form 8-K for July 8, 2025 (SEC File No. 1-8858)

4.2	5.70% Senior Note, Series 2025A, due July 8, 2030, issued by Bangor Natural Gas Company to CoBank, ACB.	Exhibit 4.2 to Form 8-K for July 8, 2025 (SEC File No. 1-8858)

4.3	6.31% Senior Note, Series 2025B, due July 8, 2035, issued by Bangor Natural Gas Company to United of Omaha Life Insurance Company.	Exhibit 4.3 to Form 8-K for July 8, 2025 (SEC File No. 1-8858)

10.1	Distribution Agreement, dated June 3, 2025, by and among Unitil Corporation, Janney Montgomery Scott LLC and Scotia Capital (USA) Inc. (each as agent and/or forward seller) and Janney Montgomery Scott LLC and The Bank of Nova Scotia (each as forward purchaser).	Exhibit 10.1 to Form 8-K for June 3, 2025 (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 August 4, 2025 Announcing Earnings for the Quarter Ended June 30, 2025.	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

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Exhibit No.	Description of Exhibit	Reference*
101.SCH	Inline XBRL Taxonomy Extension Schema with Embedded Linkbase Documents.	Filed herewith

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

* 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.

(1) Certain schedules and exhibits to the Purchase and Sale Agreement have been omitted pursuant to Item 601(a)(5) of Regulation S-K. These schedules and exhibits consist of (i) the Seller Disclosure Schedule (as such term is defined in the Purchase and Sale Agreement) and (ii) the Operating Agreement (as such term is defined in the Purchase and Sale Agreement). Unitil Corporation hereby undertakes to furnish supplementally copies of any of the omitted schedules and exhibits upon request by the Securities and Exchange Commission or its staff.

(2) Certain information has been excluded from this exhibit pursuant to Item 601(b)(2)(ii) of Regulation S-K.

(3) In accordance with Item 601(a)(5) of Regulation S-K, this exhibit omits certain of its schedules and exhibits. This exhibit’s table of contents, or the cover page of its omitted schedules and exhibits, includes a brief description of the subject matter of all of its omitted schedules and exhibits. Unitil Corporation hereby undertakes to furnish supplementally copies of any of the omitted schedules and exhibits upon request by the Securities and Exchange Commission or its staff.

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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.