10-Q

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 September 30, 2021

or

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

For the transition period from                           to                          

Commission File Number 1-8858

UNITIL CORPORATION

(Exact name of registrant as specified in its charter)

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

6 Liberty Lane West, Hampton, New Hampshire	03842-1720
(Address of principal executive 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 October 29, 2021
Common Stock, no par value	15,973,019 Shares

 

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended September 30, 2021

Table of Contents

		Page No.
Cautionary Statement			2
Part I. Financial Information
Item 1.	Financial Statements - Unaudited
	Consolidated Statements of Earnings - Three and Nine Months Ended September 30, 2021 and 2020		18
	Consolidated Balance Sheets, September 30, 2021, September 30, 2020 and December 31, 2020		19-20
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2021 and 2020		21
	Consolidated Statements of Changes in Common Stock Equity – Three and Nine Months Ended September 30, 2021 and 2020		22-23
	Notes to Consolidated Financial Statements		24-51
Item 2.	Management’s Discussion and Analysis (MD&A) of Financial Condition and Results of Operations		3-17
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		52
Item 4.	Controls and Procedures		52
Part II. Other Information
Item 1.	Legal Proceedings		52
Item 1A.	Risk Factors		52
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		52
Item 3.	Defaults Upon Senior Securities		Inapplicable
Item 4.	Mine Safety Disclosures		Inapplicable
Item 5.	Other Information		53
Item 6.	Exhibits		53-54
Signatures			55

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, Section 21E of the Securities Exchange Act of 1934, as amended, 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 Company’s future operations, 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 Item 1A (Risk Factors) and the following:

• the novel coronavirus (COVID-19) pandemic could adversely affect Unitil’s business, financial condition, results of operations and cash flows, including by disrupting the Company’s employees’ and contractors’ ability to provide ongoing services to the Company, by reducing customer demand for electricity or natural gas, or by reducing the supply of electricity or natural gas;

• 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;

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

• customers’ preferred energy sources;

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

• declines in the valuation of capital markets, 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;

• 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;

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

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

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

• 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 reasons could disrupt the Company’s operations and cause the Company to incur unanticipated losses and expense;

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

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

• catastrophic events;

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

• increased competition.

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

OVERVIEW

Unitil Corporation (Unitil or the Company) is a public utility holding company headquartered in Hampton, New Hampshire. Unitil is 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 three wholly-owned distribution utilities:

i) 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; and

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.

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Unitil Energy, Fitchburg and Northern Utilities are collectively referred to as the “distribution utilities.” Together, the distribution utilities serve approximately 107,100 electric customers and 85,600 gas customers in their service territory.

In addition, Unitil is the parent company of Granite State Gas Transmission, Inc. (Granite State), an interstate gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to major gas pipelines and access to domestic gas supplies in the south and Canadian gas supplies in the north.

Unitil had an investment in Net Utility Plant of $1,237.3 million at September 30, 2021. 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. Earnings from Unitil’s utility operations are primarily derived from the return on investment in the utility assets of the three distribution utilities and Granite State.

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 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. 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); and Northern Utilities is regulated by the NHPUC and the Maine Public Utilities Commission (MPUC). Granite State, Unitil’s interstate gas transmission pipeline, is subject to regulation by the FERC with regard to its rates and operations. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations and financial position.

Unitil’s distribution utilities deliver electricity and/or 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 a historical test year, and earn a return on their capital investment in utility assets. In addition, the Company’s distribution utilities and its gas transmission pipeline company may also recover certain base rate costs, including capital project spending and enhanced reliability and vegetation management programs, through annual step adjustments and cost-tracking rate mechanisms.

Fitchburg is subject to revenue decoupling. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or gas sales. The difference between distribution revenue amounts billed to customers and 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. The Company estimates that revenue decoupling currently applies to approximately 27% and 11% of Unitil’s total annual electric and gas sales volumes, respectively.

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RESULTS OF OPERATIONS

The following section of MD&A compares the results of operations for each of the two fiscal periods ended September 30, 2021 and September 30, 2020 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 is responding to the novel coronavirus (COVID-19) pandemic (the “coronavirus pandemic”) by taking steps to mitigate the potential risks posed by its spread. The Company’s electric and gas service utility distribution operating systems have continued to provide service to customers without disruption due to the coronavirus pandemic through the date of this filing. The Company has implemented its Crisis Response Plan to address specific aspects of the coronavirus pandemic. The Crisis Response Plan guides emergency response, business continuity, and the precautionary measures being taken on behalf of employees and the public. The Company has initiated extra precautions to protect employees who work in the field and for employees who continue to work in operations, distribution and corporate facilities. The Company has implemented social distancing and work from home policies, where appropriate. The Company continues to implement strong physical and cyber-security measures to ensure that its systems remain functional in order to serve both operational needs with a remote workforce and to help ensure uninterrupted service to customers.

The extent to which the coronavirus pandemic affects the Company’s financial condition, results of operations, and cash flows will depend on future developments, which are highly uncertain and cannot be predicted with confidence, including the duration of the outbreak, new information which may emerge concerning the severity of the coronavirus pandemic, and the actions to contain the coronavirus pandemic or treat its effect, among others. In particular, the continued spread of the coronavirus could adversely affect the Company’s business, including (i) by disrupting the Company’s employees and contractors ability to provide ongoing services to the Company, (ii) by reducing customer demand for electricity or gas, or (iii) by reducing the supply of electricity or gas, each of which could have an adverse effect on the Company’s financial condition, results of operations, and cash flows.

The Company’s results of operations reflect 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 result of operations. Sales of electricity are generally less sensitive to weather than gas sales, but may also be affected by the weather conditions in both the winter and summer seasons. Also, as a result of recent rate cases, the Company’s gas GAAP gross margins and gas adjusted gross margins (a non-GAAP measure discussed below) are derived from a higher percentage of fixed billing components, including customer charges. Therefore, gas revenues and gas adjusted gross margin will be less affected by the seasonal nature of the gas business. As noted earlier, 27% and 11% of the Company’s total annual electric and gas sales volumes, respectively, are currently decoupled. Changes in sales to existing customers with decoupled rates do not affect GAAP gross margin and adjusted gross margin.

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

As part of the Offering, the Company granted the underwriters a 30-day option to purchase additional shares. The underwriters exercised the option and purchased an additional

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120,000 shares of the Company’s common stock on September 8, 2021. The Company’s net increase to Common Equity and Cash proceeds from the exercise of the option was approximately $5.9 million. The proceeds will be used to make equity capital contributions to the Company’s regulated utility subsidiaries, to repay debt and for other general corporate purposes. Overall, the results of operations and earnings reflect the higher number of average shares outstanding period over period.

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

In the following tables the Company has reconciled Gas and Electric Adjusted Gross Margin to GAAP Gross Margin, which we believe to be the most comparable GAAP measure. GAAP Gross Margin is calculated as Revenue less Cost of Sales, and Depreciation and Amortization. The Company calculates Gas and Electric 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 gas and electric sales in the period.

Three Months Ended September 30, 2021 ($ millions)
	Gas			Electric			Non- Regulated and Other			Total
Total Operating Revenue	$	32.6		$	65.5		$	—		$	98.1
Less: Cost of Sales		(13.2	)		(40.1	)		—			(53.3	)
Less: Depreciation and Amortization		(8.1	)		(6.5	)		(0.2	)		(14.8	)
GAAP Gross Margin		11.3			18.9			(0.2	)		30.0
Depreciation and Amortization		8.1			6.5			0.2			14.8
Adjusted Gross Margin	$	19.4		$	25.4		$	—		$	44.8

Three Months Ended September 30, 2020 ($ millions)
	Gas			Electric			Non- Regulated and Other			Total
Total Operating Revenue	$	27.5		$	59.9		$	—		$	87.4
Less: Cost of Sales		(9.5	)		(35.4	)		—			(44.9	)
Less: Depreciation and Amortization		(7.5	)		(6.0	)		(0.2	)		(13.7	)
GAAP Gross Margin		10.5			18.5			(0.2	)		28.8
Depreciation and Amortization		7.5			6.0			0.2			13.7
Adjusted Gross Margin	$	18.0		$	24.5		$	—		$	42.5

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Nine Months Ended September 30, 2021 ($ millions)
	Gas			Electric			Non- Regulated and Other			Total
Total Operating Revenue	$	151.3		$	182.2		$	—		$	333.5
Less: Cost of Sales		(59.1	)		(108.8	)		—			(167.9	)
Less: Depreciation and Amortization		(24.5	)		(19.4	)		(0.6	)		(44.5	)
GAAP Gross Margin		67.7			54.0			(0.6	)		121.1
Depreciation and Amortization		24.5			19.4			0.6			44.5
Adjusted Gross Margin	$	92.2		$	73.4		$	—		$	165.6

Nine Months Ended September 30, 2020 ($ millions)
	Gas			Electric			Non- Regulated and Other			Total
Total Operating Revenue	$	131.4		$	170.3		$	—		$	301.7
Less: Cost of Sales		(48.1	)		(100.3	)		—			(148.4	)
Less: Depreciation and Amortization		(22.3	)		(17.8	)		(0.6	)		(40.7	)
GAAP Gross Margin		61.0			52.2			(0.6	)		112.6
Depreciation and Amortization		22.3			17.8			0.6			40.7
Adjusted Gross Margin	$	83.3		$	70.0		$	—		$	153.3

Gas GAAP Gross Margin was $11.3 million and $67.7 million in the three and nine months ended September 30, 2021, respectively, increases of $0.8 million and $6.7 million compared to the same periods in 2020. The increase in the three month period was driven by higher rates and customer growth of $1.4 million, partially offset by higher depreciation and amortization expense of $0.6 million. The increase in the nine month period was driven by higher rates and customer growth of $7.5 million and $1.4 million from the favorable effect of colder winter weather, partially offset by higher depreciation and amortization expense of $2.2 million.

Electric GAAP Gross Margin was $18.9 million and $54.0 million in the three and nine months ended September 30, 2021, respectively, increases of $0.4 million and $1.8 million compared to the same periods in 2020. The increase in the three month period was driven by higher rates and customer growth of $1.3 million, partially offset by $0.4 million from the effect of milder summer weather and higher depreciation and amortization expense of $0.5 million. The increase in the nine month period was driven by higher rates and customer growth of $3.4 million, partially offset by higher depreciation and amortization expense of $1.6 million.

Earnings Overview

The Company reported breakeven Net Income and earnings per share (EPS) for the third quarter of 2021, a decrease of $0.3 million in Net Income, or $0.02 in EPS, compared to the third quarter of 2020. For the third quarter of 2021, higher Gas and Electric Adjusted Margins (a non-GAAP measure) were offset by higher operating expenses compared to the same period in 2020.

For the nine months ended September 30, 2021, the Company reported Net Income of $21.6 million, or $1.42 per share, an increase of $3.0 million, or $0.17 per share, compared to the same nine month period in 2020. The Company’s earnings in the first nine months of 2021 reflect higher Gas and Electric Adjusted Margins (a non-GAAP measure), partially offset by higher operating expenses. Also, EPS in 2021 reflects the sale of 920,000 common shares in the third quarter of 2021, discussed above.

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Gas Adjusted Gross Margin (a non-GAAP measure) was $19.4 million and $92.2 million in the three and nine months ended September 30, 2021, respectively, increases of $1.4 million and $8.9 million compared to the same periods in 2020. The increase in the three month period was driven by higher rates and customer growth of $1.4 million. The increase over the nine month period was driven by higher rates and customer growth of $7.5 million and $1.4 million from the favorable effect of colder winter weather.

Gas therm sales increased 5.0% and 4.3% in the three and nine month periods ended September 30, 2021, respectively, compared to the same periods in 2020. The increase in gas therm sales reflects colder winter weather in the first quarter of 2021 compared to the same period in 2020, and customer growth. Based on weather data collected in the Company’s gas service areas, on average there were 2.1% more Effective Degree Days (EDD) in the first nine months of 2021 compared to the same period in 2020, although 6.4% fewer EDD compared to normal. The Company estimates weather-normalized gas therm sales, excluding decoupled sales, increased 2.9% in the first nine months of 2021 compared to the same period in 2020. As of September 30, 2021, the number of gas customers increased by 592 over the previous year.

Electric Adjusted Gross Margin (a non-GAAP measure) was $25.4 million and $73.4 million in the three and nine months ended September 30, 2021, respectively, increases of $0.9 million and $3.4 million compared with the same periods in 2020. The increase in the three month period was driven by higher rates and customer growth of $1.3 million, partially offset by $0.4 million from the effect of milder summer weather. The increase over the nine month period was driven by higher rates and customer growth of $3.4 million.

Total electric kilowatt-hour (kWh) sales increased 0.2% and 2.0%, respectively in the three and nine month periods ended September 30, 2021 compared to the same periods in 2020. Sales to Residential customers decreased 3.5% and increased 0.4%, respectively, in the three and nine month periods ended September 30, 2021 compared to the same periods in 2020. Sales to Commercial and Industrial (C&I) customers increased 3.3% and 3.2%, respectively, in the three and nine month periods ended September 30, 2021 compared to the same periods in 2020. The changes in sales to Residential customers reflects customer growth and colder winter weather, offset by the effects of milder summer weather and lower Residential electric sales as the economy continues to reopen. The increase in sales to C&I customers reflects customer growth and increased usage due to improving economic conditions. Based on weather data collected in the Company’s electric service areas, on average there were 5.4% fewer Cooling Degree Days (CDD) in the first nine months of 2021 compared to the same period in 2020. As of September 30, 2021, the number of electric customers increased by 652 over the previous year.

Operation and Maintenance (O&M) expenses increased $0.6 million and $2.6 million in three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020. The increase in the three month period reflects higher labor costs of $0.8 million, higher utility operating costs of $0.2 million, and lower professional fees of $0.4 million. The increase in the nine month period reflects higher utility operating costs of $1.6 million, higher labor costs of $1.2 million, and lower professional fees of $0.2 million.

Depreciation and Amortization expense increased $1.1 million and $3.8 million in the three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020. These increases primarily reflect additional depreciation associated with higher levels of utility plant in service and higher amortization.

Taxes Other Than Income Taxes increased $0.8 million and $0.6 million for the three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020. The increase in the three month period reflects higher payroll taxes and higher local property taxes on higher utility plant in service. The increase in the nine month period reflects higher local property taxes on higher utility plant in service and slightly higher payroll taxes.

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Interest Expense, Net increased $0.9 million and $1.8 million, respectively, in the three and nine months ended September 30, 2021, compared to the same periods in 2020, reflecting higher interest on long-term debt, partially offset by lower rates on lower levels of short-term debt.

Other Expense (Income), Net decreased $0.1 million and $0.6 million, respectively for the three and nine months ended September 30, 2021 compared to the same periods in 2020, reflecting lower retirement benefit and other costs.

Federal and State Income Taxes increased $1.1 million for the nine months ended September 30, 2021, respectively, compared to the same period in 2020, reflecting higher pre-tax earnings in the current period.

At its January 2021, April 2021, July 2021 and October 2021 meetings, the Unitil Corporation Board of Directors declared quarterly dividends on the Company’s common stock of $0.38 per share. These quarterly dividends result in a current effective annualized dividend rate of $1.52 per share, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock.

Gas Sales, Revenues and Adjusted Gross Margin

Therm Sales - Unitil’s total gas therm sales increased 5.0% and 4.3% in the three and nine month periods ended September 30, 2021, respectively, compared to the same periods in 2020. In the third quarter of 2021, sales to Residential customers decreased 3.7% and sales to C&I customers increased 6.0%, compared to the same period in 2020. For the nine months ended September 30, 2021, sales to Residential and C&I customers increased 0.3% and 5.4%, respectively, compared to the same period in 2020. The increase in gas therm sales reflects colder winter weather in the first quarter of 2021 compared to the same period in 2020, and customer growth. Based on weather data collected in the Company’s gas service areas, on average there were 2.1% more EDD in the first nine months of 2021 compared to the same period in 2020, although 6.4% fewer EDD compared to normal. The Company estimates weather-normalized gas therm sales, excluding decoupled sales, increased 2.9% in the first nine months of 2021 compared to the same period in 2020. As of September 30, 2021, the number of gas customers increased by 592 over the previous year. Sales margins derived from decoupled unit sales (currently representing approximately 11% of total annual therm sales volume) are not sensitive to changes in gas therm sales.

The following table details total firm therm sales for the three and nine months ended September 30, 2021 and 2020, by major customer class:

Therm Sales (millions)
	Three Months Ended September 30,										Nine Months Ended September 30,
	2021		2020		Change			% Change			2021		2020		Change		% Change
Residential		2.6		2.7		(0.1	)		(3.7	%)		34.3		34.2		0.1		0.3	%
Commercial / Industrial		24.7		23.3		1.4			6.0	%		132.7		125.9		6.8		5.4	%
Total		27.3		26.0		1.3			5.0	%		167.0		160.1		6.9		4.3	%

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Gas Operating Revenues and Adjusted Gross Margin - The following table details Total Gas Operating Revenues and Gas Adjusted Gross Margin for the three and nine months ended September 30, 2021 and 2020:

Gas Operating Revenues and Gas Adjusted Gross Margin ($ millions)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2021		2020		$ Change		% Change			2021		2020		$ Change		% Change
Gas Operating Revenue:
Residential	$	12.0	$	10.2	$	1.8		17.6	%	$	61.4	$	54.3	$	7.1		13.1	%
Commercial / Industrial		20.6		17.3		3.3		19.1	%		89.9		77.1		12.8		16.6	%
Total Gas Operating Revenue	$	32.6	$	27.5	$	5.1		18.5	%	$	151.3	$	131.4	$	19.9		15.1	%
Cost of Gas Sales	$	13.2	$	9.5	$	3.7		38.9	%	$	59.1	$	48.1	$	11.0		22.9	%
Gas Adjusted Gross Margin	$	19.4	$	18.0	$	1.4		7.8	%	$	92.2	$	83.3	$	8.9		10.7	%

Gas Adjusted Gross Margin (a non-GAAP measure) was $19.4 million and $92.2 million in the three and nine months ended September 30, 2021, respectively, increases of $1.4 million and $8.9 million, respectively, compared to the same periods in 2020. The increase in the three month period was driven by higher rates and customer growth of $1.4 million. The increase over the nine month period was driven by higher rates and customer growth of $7.5 million and $1.4 million from the favorable effect of colder winter weather.

The increases in Total Gas Operating Revenue of $5.1 million and $19.9 million in the three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020, reflect higher costs of gas sales, which are tracked and reconciled costs that are passed through directly to customers, and higher gas sales volumes.

Electric Sales, Revenues and Adjusted Gross Margin

Kilowatt-hour Sales - Unitil’s total electric kWh sales increased 0.2% and 2.0%, respectively in the three and nine month periods ended September 30, 2021 compared to the same periods in 2020. Sales to Residential customers decreased 3.5% and increased 0.4%, respectively, in the three and nine month periods ended September 30, 2021 compared to the same periods in 2020. Sales to C&I customers increased 3.3% and 3.2%, respectively, in the three and nine month periods ended September 30, 2021 compared to the same periods in 2020. The changes in sales to Residential customers reflects customer growth and colder winter weather, offset by the effects of milder summer weather and lower Residential electric sales as the economy continues to reopen. The increase in sales to C&I customers reflects customer growth and increased usage due to improving economic conditions. Based on weather data collected in the Company’s electric service areas, on average there were 5.4% fewer CDD in the first nine months of 2021 compared to the same period in 2020. As of September 30, 2021, the number of electric customers increased by 652 over the previous year. Sales margins derived from decoupled unit sales (currently representing approximately 27% of total annual electric kWh sales volume) are not sensitive to changes in electric kWh sales.

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The following table details total kWh sales for the three and nine months ended September 30, 2021 and 2020 by major customer class:

kWh Sales (millions)
	Three Months Ended September 30,										Nine Months Ended September 30,
	2021		2020		Change			% Change			2021		2020		Change		% Change
Residential		199.7		207.0		(7.3	)		(3.5	%)		541.4		539.4		2.0		0.4	%
Commercial / Industrial		258.7		250.4		8.3			3.3	%		714.6		692.4		22.2		3.2	%
Total		458.4		457.4		1.0			0.2	%		1,256.0		1,231.8		24.2		2.0	%

Electric Operating Revenues and Electric Adjusted Gross Margin - The following table details Total Electric Operating Revenues and Electric Adjusted Gross Margin for the three and nine month periods ended September 30, 2021 and 2020:

Electric Operating Revenues and Electric Adjusted Gross Margin ($ millions)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2021		2020		$ Change		% Change			2021		2020		$ Change		% Change
Electric Operating Revenue:
Residential	$	37.6	$	36.1	$	1.5		4.2	%	$	105.3	$	102.3	$	3.0		2.9	%
Commercial / Industrial		27.9		23.8		4.1		17.2	%		76.9		68.0		8.9		13.1	%
Total Electric Operating Revenue	$	65.5	$	59.9	$	5.6		9.3	%	$	182.2	$	170.3	$	11.9		7.0	%
Cost of Electric Sales	$	40.1	$	35.4	$	4.7		13.3	%	$	108.8	$	100.3	$	8.5		8.5	%
Electric Adjusted Gross Margin	$	25.4	$	24.5	$	0.9		3.7	%	$	73.4	$	70.0	$	3.4		4.9	%

Electric Adjusted Gross Margin (a non-GAAP measure) was $25.4 million and $73.4 million in the three and nine months ended September 30, 2021, respectively, increases of $0.9 million and $3.4 million, respectively, compared with the same periods in 2020. The increase in the three month period was driven by higher rates and customer growth of $1.3 million, partially offset by $0.4 million from the effect of milder summer weather. The increase over the nine month period was driven by higher rates and customer growth of $3.4 million.

The increases in Total Electric Operating Revenue of $5.6 million and $11.9 million in the three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020 reflect higher costs of electric sales, which are tracked and reconciled to costs that are passed through directly to customers, and higher sales of electricity.

Operating Expenses

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 $3.7 million, or 38.9%, and $11.0 million, or 22.9%, in the three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020. These increases reflect higher sales of gas and higher wholesale gas commodity prices, partially offset by an increase in the amount of gas purchased by customers directly from third-party suppliers. 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.

Cost of Electric Sales - Cost of Electric Sales includes the cost of electric supply as well as other energy supply related restructuring costs, including power supply buyout costs, and spending on energy

11

efficiency programs. Cost of Electric Sales increased $4.7 million, or 13.3%, and $8.5 million, or 8.5% in the three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020. These increases reflect higher sales of electricity and higher wholesale electricity prices, partially offset by an increase in the amount of electricity purchased by customers directly from third-party suppliers. 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.

Operation and Maintenance (O&M) - O&M expense includes gas and electric utility operating costs, and the operating cost of the Company’s corporate and other business activities. O&M expense increased $0.6 million, or 3.7%, and $2.6 million, or 5.4%, in three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020. The increase in the three month period reflects higher labor costs of $0.8 million, higher utility operating costs of $0.2 million, and lower professional fees of $0.4 million. The increase in the nine month period reflects higher utility operating costs of $1.6 million, higher labor costs of $1.2 million, and lower professional fees of $0.2 million.

Depreciation and Amortization - Depreciation and Amortization expense increased $1.1 million, or 8.0%, and $3.8 million, or 9.3%, in the three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020. These increases reflect additional depreciation associated with higher levels of utility plant in service and higher amortization.

Taxes Other Than Income Taxes - Taxes Other Than Income Taxes increased $0.8 million, or 15.1%, and $0.6 million, or 3.4% for the three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020. The increase in the three month period reflects higher payroll taxes and higher local property taxes on higher utility plant in service. The increase in the nine month period reflects higher local property taxes on higher utility plant in service and slightly higher payroll taxes.

Other Expense (Income), Net - Other Expense (Income), Net decreased $0.1 million, or 9.1%, and $0.6 million, or 15.0%, respectively for the three and nine months ended September 30, 2021 compared to the same periods in 2020, reflecting lower retirement benefit and other costs.

Provision for Income Taxes - Federal and State Income Taxes for the three months ended September 30, 2021 decreased $0.7 million compared with the same period in 2020, reflecting lower pre-tax earnings in the current period. For the nine months ended September 30, 2021, Federal and State Income Taxes increased $1.1 million compared to the same period in 2020, reflecting higher pre-tax earnings in the current period.

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.

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Interest Expense, Net ($ millions)	Three Months Ended September 30,									Nine Months Ended September 30,
	2021			2020			Change			2021			2020			Change
Interest Expense
Long-term Debt	$	6.5		$	6.0		$	0.5		$	19.8		$	18.1		$	1.7
Short-term Debt		0.2			0.3			(0.1	)		0.5			1.3			(0.8	)
Regulatory Liabilities		0.1			0.1			—			0.3			0.2			0.1
Subtotal Interest Expense		6.8			6.4			0.4			20.6			19.6			1.0
Interest (Income)
Regulatory Assets		—			(0.2	)		0.2			(0.4	)		(0.6	)		0.2
AFUDC(1) and Other		(0.3	)		(0.6	)		0.3			(0.7	)		(1.3	)		0.6
Subtotal Interest (Income)		(0.3	)		(0.8	)		0.5			(1.1	)		(1.9	)		0.8
Total Interest Expense, Net	$	6.5		$	5.6		$	0.9		$	19.5		$	17.7		$	1.8

(1)  AFUDC – Allowance for Funds Used During Construction.

Interest Expense, Net increased $0.9 million, or 16.1%, and $1.8 million, or 10.2%, respectively, in the three and nine months ended September 30, 2021, compared to the same periods in 2020, primarily reflecting higher interest on long-term debt, partially offset by lower rates on lower levels of short-term debt.

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 are seasonal in nature 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.

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

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

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

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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). At September 30, 2021, September 30, 2020 and December 31, 2020, the Company and all of its subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

On July 25, 2018, the Company entered into a Second Amended and Restated Credit Agreement and related documents (collectively, the Credit Facility) with a syndicate of lenders, which amended and restated in its entirety the Company’s prior credit facility. The Credit Facility extends to July 25, 2023, subject to two one-year extensions under certain circumstances, and has a borrowing limit of $120 million, which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides the Company with the ability to elect that borrowings under the Credit Facility bear interest under several options, including at a daily fluctuating rate of interest per annum equal to one-month London Interbank Offered Rate plus 1.125%. The Company may increase the borrowing limit under the Credit Facility by up to $50 million under certain circumstances.

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $170.7 million for the nine months ended September 30, 2021. Total gross repayments were $194.9 million for the nine months ended September 30, 2021. The following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of September 30, 2021, September 30, 2020 and December 31, 2020:

	Revolving Credit Facility ($ millions)
	September 30,				December 31,
	2021		2020		2020
Limit	$	120.0	$	120.0	$	120.0
Short-Term Borrowings Outstanding		30.5		17.3		54.7
Letter of Credit Outstanding		—		0.1		0.1
Available	$	89.5	$	102.6	$	65.2

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, the Company’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on the Company’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility apply until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At September 30, 2021, September 30, 2020 and December 31, 2020, the Company was in compliance with the covenants contained in the Credit Facility in effect on those dates.

The Company is monitoring the coronavirus pandemic, and does not believe the pandemic will adversely affect its access to capital and funding sources, or its planned capital expenditures. The Company believes its future operating cash flows, its available borrowing capacity, and its access to private and public capital markets for the issuance of long-term debt and equity securities will be sufficient to meet its working capital and capital investment needs.

On December 18, 2020, Unitil Realty Corp. entered into a loan agreement in the amount of $4.7 million at 2.64%, with a maturity date of December 18, 2030. Less than $0.1 million of costs associated with this loan have been recorded as a reduction to the proceeds. Unitil Realty Corp. used the net proceeds from this loan for general corporate purposes.

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On September 15, 2020, Northern Utilities issued $40 million of Notes due 2040 at 3.78%. Fitchburg issued $27.5 million of Notes due 2040 at 3.78%. Unitil Energy issued $27.5 million of Bonds due 2040 at 3.58%. Northern Utilities, Fitchburg and Unitil Energy used the net proceeds from these offerings to repay short-term debt and for general corporate purposes. Approximately $0.5 million of costs associated with these issuances have been recorded as a reduction to Long-Term Debt on the Consolidated Balance Sheets.

Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State currently are rated “BBB+” by Standard & Poor’s Ratings Services. Unitil Corporation 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 September 30, 2021, there were approximately $0.7 million of guarantees outstanding with a duration less than one year.

Northern Utilities enters into asset management agreements under which Northern Utilities releases certain gas pipeline and storage assets, resells to an asset manager and subsequently repurchases the gas over the course of the gas heating season at the same price at which it sold the gas to the asset manager. There was $9.7 million, $6.0 million and $5.4 million of gas obligations at September 30, 2021, September 30, 2020 and December 31, 2020, respectively, related to these asset management agreements. The amount of gas released in September 2021 and payable in October 2021 is $0.1 million and is recorded in Accounts Payable at September 30, 2021. The amount of gas released in September 2020 and payable in October 2020 was less than $0.1 million and was recorded in Accounts Payable at September 30, 2020. The amount of gas released in December 2020 and payable in January 2021 was $1.0 million and was recorded in Accounts Payable at December 31, 2020.

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 Corporation’s subsidiaries conduct a portion of their operations in leased facilities, and lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements. As of September 30, 2021, there were approximately $0.7 million of guarantees on certain energy and gas storage management contracts entered into by the distribution utilities outstanding. See Note 4 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

CRITICAL ACCOUNTING POLICIES

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 is sometimes 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

15

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 September 30, 2021, the Company’s critical accounting policies and estimates had not changed significantly from December 31, 2020. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies” in the Company’s 2020 Form 10-K for additional information.

LABOR RELATIONS

Unitil’s commitment to excellence begins with its employees. As of September 30, 2021, the Company and its subsidiaries had 513 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions. Unitil’s employees are focused on the Company’s mission to safely and reliably deliver “energy for life” and provide customers with affordable and sustainable energy solutions.

The Company strives to be the employer of choice in the communities it serves – regardless of race, religion, color, gender identification, 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.

Employees at Unitil have the opportunity to be heard. 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 September 30, 2021, a total of 165 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 September 30, 2021:

	Employees Covered		CBA Expiration
Fitchburg		44		05/31/2022
Northern Utilities NH Division		36		06/07/2025
Northern Utilities ME Division		36		03/31/2026
Granite State		4		03/31/2026
Unitil Energy		40		05/31/2023
Unitil Service		5		05/31/2023

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

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

16

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 September 30, 2021 and September 30, 2020 were 1.2% and 1.3%, respectively. The average interest rates on the Company’s short-term borrowings for the nine months ended September 30, 2021 and September 30, 2020 were 1.2% and 1.8%, respectively. The average interest rate on the Company’s short-term borrowings for the twelve months ended December 31, 2020 was 1.7%.

COMMODITY PRICE RISK

Although Unitil’s three distribution utilities are subject to commodity price risk as part of their traditional operations, the current regulatory framework within which these companies operate allows for full collection of electric power and natural gas supply costs in rates on a pass-through basis. Consequently, there is limited commodity price risk after consideration of the related rate-making.

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 September 30,					Nine Months Ended September 30,
	2021			2020		2021		2020
Operating Revenues
Gas	$	32.6		$	27.5	$	151.3	$	131.4
Electric		65.5			59.9		182.2		170.3
Total Operating Revenues		98.1			87.4		333.5		301.7
Operating Expenses
Cost of Gas Sales		13.2			9.5		59.1		48.1
Cost of Electric Sales		40.1			35.4		108.8		100.3
Operation and Maintenance		16.7			16.1		51.2		48.6
Depreciation and Amortization		14.8			13.7		44.5		40.7
Taxes Other Than Income Taxes		6.1			5.3		18.5		17.9
Total Operating Expenses		90.9			80.0		282.1		255.6
Operating Income		7.2			7.4		51.4		46.1
Interest Expense, Net		6.5			5.6		19.5		17.7
Other Expense (Income), Net		1.0			1.1		3.4		4.0
Income (Loss) Before Income Taxes		(0.3	)		0.7		28.5		24.4
Provision (Benefit) for Income Taxes		(0.3	)		0.4		6.9		5.8
Net Income	$	—		$	0.3	$	21.6	$	18.6
Net Income Per Common Share (Basic and Diluted)	$	—		$	0.02	$	1.42	$	1.25
Weighted Average Common Shares Outstanding – (Basic and Diluted)		15.5			14.9		15.2		14.9

(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)

	September 30,				December 31,
	2021		2020		2020
ASSETS:
Current Assets:
Cash and Cash Equivalents	$	8.8	$	8.2	$	6.0
Accounts Receivable, Net		46.3		48.6		62.0
Accrued Revenue		38.6		39.1		50.9
Exchange Gas Receivable		10.5		6.5		4.9
Gas Inventory		0.9		0.6		0.6
Materials and Supplies		8.6		8.5		8.5
Prepayments and Other		7.3		5.8		6.4
Total Current Assets		121.0		117.3		139.3
Utility Plant:
Gas		932.8		876.8		920.2
Electric		581.0		545.9		575.9
Common		64.8		63.3		64.1
Construction Work in Progress		84.8		101.0		34.8
Utility Plant		1,663.4		1,587.0		1,595.0
Less: Accumulated Depreciation		426.1		401.7		401.8
Net Utility Plant		1,237.3		1,185.3		1,193.2
Other Noncurrent Assets:
Regulatory Assets		132.4		104.4		127.4
Operating Lease Right of Use Assets		5.1		5.6		5.2
Other Assets		13.2		11.3		12.8
Total Other Noncurrent Assets		150.7		121.3		145.4
TOTAL ASSETS	$	1,509.0	$	1,423.9	$	1,477.9

(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)

	September 30,				December 31,
	2021		2020		2020
LIABILITIES AND CAPITALIZATION:
Current Liabilities:
Accounts Payable	$	29.5	$	25.1	$	33.2
Short-Term Debt		30.5		17.3		54.7
Long-Term Debt, Current Portion		10.1		6.3		8.5
Regulatory Liabilities		13.1		10.6		5.5
Energy Supply Obligations		16.1		12.1		10.4
Interest Payable		6.7		7.2		5.0
Environmental Obligations		0.7		0.3		0.3
Other Current Liabilities		19.9		19.3		18.5
Total Current Liabilities		126.6		98.2		136.1
Noncurrent Liabilities:
Retirement Benefit Obligations		166.2		145.0		162.3
Deferred Income Taxes, net		115.7		109.4		109.0
Cost of Removal Obligations		108.2		107.1		105.2
Regulatory Liabilities		42.9		44.7		44.3
Environmental Obligations		1.7		1.9		1.8
Other Noncurrent Liabilities		6.8		7.8		6.9
Total Noncurrent Liabilities		441.5		415.9		429.5
Capitalization:
Long-Term Debt, Less Current Portion		501.3		529.0		523.1
Stockholders’ Equity:
Common Equity (Authorized: 25,000,000 and Outstanding: 15,971,962, 15,005,881 and 15,012,310 Shares)		331.6		284.8		285.3
Retained Earnings		107.8		95.8		103.7
Total Common Stock Equity		439.4		380.6		389.0
Preferred Stock		0.2		0.2		0.2
Total Stockholders’ Equity		439.6		380.8		389.2
Total Capitalization		940.9		909.8		912.3
Commitments and Contingencies (Notes 6 & 7)
TOTAL LIABILITIES AND CAPITALIZATION	$	1,509.0	$	1,423.9	$	1,477.9

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

20

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions) (UNAUDITED)

	Nine Months Ended September 30,
	2021			2020
Operating Activities:
Net Income	$	21.6		$	18.6
Adjustments to Reconcile Net Income to Cash
Provided by Operating Activities:
Depreciation and Amortization		44.5			40.7
Deferred Tax Provision		5.5			3.0
Changes in Working Capital Items:
Accounts Receivable		15.7			6.5
Accrued Revenue		12.3			10.9
Exchange Gas Receivable		(5.6	)		(0.4	)
Regulatory Liabilities		7.6			3.2
Accounts Payable		(3.7	)		(12.5	)
Other Changes in Working Capital Items		2.7			0.9
Deferred Regulatory and Other Charges		(8.0	)		5.3
Other, net		3.3			(1.3	)
Cash Provided by Operating Activities		95.9			74.9
Investing Activities:
Property, Plant and Equipment Additions		(81.5	)		(93.6	)
Cash (Used in) Investing Activities		(81.5	)		(93.6	)
Financing Activities:
Repayment of Short-Term Debt, net		(24.2	)		(41.3	)
Repayment of Long-Term Debt		(20.3	)		(15.9	)
Issuance of Long-Term Debt		—			95.0
Long-Term Debt Issuance Costs		—			(0.5	)
Net Increase in Exchange Gas Financing		5.2			0.5
Decrease in Capital Lease Obligations		(0.1	)		—
Dividends Paid		(17.5	)		(16.9	)
Proceeds from Issuance of Common Stock		45.3			0.8
Cash (Used in) Provided by Financing Activities		(11.6	)		21.7
Net Increase in Cash and Cash Equivalents		2.8			3.0
Cash and Cash Equivalents at Beginning of Period		6.0			5.2
Cash and Cash Equivalents at End of Period	$	8.8		$	8.2
Supplemental Cash Flow Information:
Interest Paid	$	17.9		$	15.3
Income Taxes Paid	$	1.4		$	0.8
Payments on Capital Leases	$	0.2		$	0.2
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$	4.2		$	0.6
Right-of-Use Assets Obtained in Exchange for Lease Obligations	$	0.9		$	1.6

(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 September 30, 2021
Balance at July 1, 2021	$	286.8	$	113.8		$	400.6
Net Income				—			—
Dividends on Common Shares ($0.38 per share)				(6.0	)		(6.0	)
Stock Compensation Plans		0.1					0.1
Issuance of 925,493 Common Shares		44.7					44.7
Balance at September 30, 2021	$	331.6	$	107.8		$	439.4
Three Months Ended September 30, 2020
Balance at July 1, 2020	$	284.4	$	101.1		$	385.5
Net Income				0.3			0.3
Dividends on Common Shares ($0.375 per share)				(5.6	)		(5.6	)
Stock Compensation Plans		0.1					0.1
Issuance of 6,650 Common Shares		0.3					0.3
Balance at September 30, 2020	$	284.8	$	95.8		$	380.6

(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
Nine Months Ended September 30, 2021
Balance at January 1, 2021	$	285.3	$	103.7		$	389.0
Net Income				21.6			21.6
Dividends on Common Shares ($1.14 per share)				(17.5	)		(17.5	)
Stock Compensation Plans		1.0					1.0
Issuance of 936,512 Common Shares		45.3					45.3
Balance at September 30, 2021	$	331.6	$	107.8		$	439.4
Nine Months Ended September 30, 2020
Balance at January 1, 2020	$	282.5	$	94.1		$	376.6
Net Income				18.6			18.6
Dividends on Common Shares ($1.125 per share)				(16.9	)		(16.9	)
Stock Compensation Plans		1.5					1.5
Issuance of 16,849 Common Shares		0.8					0.8
Balance at September 30, 2020	$	284.8	$	95.8		$	380.6

(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 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. The following companies are wholly-owned subsidiaries of Unitil: Unitil Energy Systems, Inc. (Unitil Energy), Fitchburg Gas and Electric Light Company (Fitchburg), Northern Utilities, Inc. (Northern Utilities), Granite State Gas Transmission, Inc. (Granite State), Unitil Power Corp. (Unitil Power), Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) and its non-regulated business unit Unitil Resources, Inc. (Unitil Resources).

The Company’s earnings are seasonal and are 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 in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire; Fitchburg, which operates in Massachusetts; and Northern Utilities, which operates in New Hampshire and Maine (collectively referred to as the “distribution utilities”).

Granite State is an interstate gas transmission pipeline company, operating 86 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 the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.

A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, on May 1, 2003 Unitil Power ceased being the wholesale supplier of Unitil Energy and divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers. In the period since, Unitil Power continued to flow revenues and expenses from remaining contracts to Unitil Energy under the Amended Unitil System Agreement. The last of those contracts expired October 31, 2020, and the Company no longer has material revenues or expenses associated with them.

Unitil also has three other wholly-owned subsidiaries: Unitil Service, Unitil Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary.

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 all of 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 nine months ended September 30, 2021 are not necessarily indicative of results to be expected for the year ending December 31, 2021. For further information, please 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, 2020, as filed with the Securities and Exchange Commission (SEC) on February 2, 2021, for a description of the Company’s Basis of Presentation.

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

Revenue is recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of 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.

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

	Three Months Ended September 30, 2021
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	7.9		$	35.0		$	42.9
C&I		14.4			26.8			41.2
Other		0.8			3.2			4.0
Total Billed and Unbilled Revenue		23.1			65.0			88.1
Rate Adjustment Mechanism Revenue		9.5			0.5			10.0
Total Gas and Electric Operating Revenues	$	32.6		$	65.5		$	98.1
	Three Months Ended September 30, 2020
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	7.0		$	35.3		$	42.3
C&I		11.6			24.1			35.7
Other		1.4			1.4			2.8
Total Billed and Unbilled Revenue		20.0			60.8			80.8
Rate Adjustment Mechanism Revenue		7.5			(0.9	)		6.6
Total Gas and Electric Operating Revenues	$	27.5		$	59.9		$	87.4
	Nine Months Ended September 30, 2021
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	60.5		$	104.0		$	164.5
C&I		86.2			78.2			164.4
Other		7.6			6.9			14.5
Total Billed and Unbilled Revenue		154.3			189.1			343.4
Rate Adjustment Mechanism Revenue		(3.0	)		(6.9	)		(9.9	)
Total Gas and Electric Operating Revenues	$	151.3		$	182.2		$	333.5
	Nine Months Ended September 30, 2020
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	52.4		$	99.9		$	152.3
C&I		72.9			68.7			141.6
Other		5.6			4.9			10.5
Total Billed and Unbilled Revenue		130.9			173.5			304.4
Rate Adjustment Mechanism Revenue		0.5			(3.2	)		(2.7	)
Total Gas and Electric Operating Revenues	$	131.4		$	170.3		$	301.7

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Fitchburg is subject to revenue decoupling. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or gas sales. The difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recorded 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 that the Company files with the MDPU.

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 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 include 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 September 30, 2021, September 30, 2020 and December 31, 2020, the Unitil subsidiaries had deposited $5.7 million, $4.7 million and $2.4 million, respectively to satisfy their ISO-NE obligations.

Financial Instruments - In June 2016, the Financial Accounting Standards Board issued ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326)”, which provides a new model for recognizing credit losses on financial instruments based on an estimate of current expected credit losses. Under the new guidance, immediate recognition of all credit losses expected over the life of a financial instrument is required. The Company adopted this standard on the accounting for credit losses on its financial instruments, including accounts receivable, on January 1, 2020, and it did not have a material effect on the financial statements.

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

27

associated with protected hardship accounts. Evaluating the adequacy of the allowance for doubtful accounts requires judgment about the assumptions used in the analysis. The Company’s experience has been that the assumptions used in evaluating the adequacy of the allowance for doubtful accounts have proven to be reasonably accurate.

The Allowance for Doubtful Accounts as of September 30, 2021, September 30, 2020 and December 31, 2020, was as follows:

($ millions)
	September 30,				December 31,
	2021		2020		2020
Allowance for Doubtful Accounts	$	4.3	$	1.6	$	3.3

Accounts Receivable, Net includes $4.2 million, $1.5 million, and $3.1 million of the Allowance for Doubtful Accounts at September 30, 2021, September 30, 2020 and December 31, 2020, respectively. Unbilled Revenues, net (a component of Accrued Revenue, shown in the table below) includes $0.1 million, $0.1 million and $0.2 million of the Allowance for Doubtful Accounts at September 30, 2021, September 30, 2020 and December 31, 2020, 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 September 30, 2021, September 30, 2020 and December 31, 2020.

	September 30,				December 31,
Accrued Revenue ($ millions)	2021		2020		2020
Regulatory Assets – Current	$	30.6	$	31.7	$	37.3
Unbilled Revenues		8.0		7.4		13.6
Total Accrued Revenue	$	38.6	$	39.1	$	50.9

Exchange Gas Receivable - Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers natural gas back to the Company during the months of November through March. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of September 30, 2021, September 30, 2020 and December 31, 2020.

	September 30,				December 31,
Exchange Gas Receivable ($ millions)	2021		2020		2020
Northern Utilities	$	9.7	$	6.0	$	4.4
Fitchburg		0.8		0.5		0.5
Total Exchange Gas Receivable	$	10.5	$	6.5	$	4.9

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Gas Inventory - The Company uses the weighted average cost methodology to value natural gas inventory. The following table shows the components of Gas Inventory as of September 30, 2021, September 30, 2020 and December 31, 2020.

	September 30,				December 31,
Gas Inventory ($ millions)	2021		2020		2020
Natural Gas	$	0.4	$	0.2	$	0.2
Propane		0.4		0.3		0.3
Liquefied Natural Gas & Other		0.1		0.1		0.1
Total Gas Inventory	$	0.9	$	0.6	$	0.6

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 September 30, 2021, September 30, 2020 and December 31, 2020, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $108.2 million, $107.1 million, and $105.2 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).

Regulatory Accounting - The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the Massachusetts Department of Public Utilities (MDPU), Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC) and Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the FASB Codification. The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission. The electric and gas divisions of Fitchburg are authorized to recover through rates past due amounts associated with hardship accounts that are protected from shut-off. As of September 30, 2021, September 30, 2020 and December 31, 2020, the Company has recorded $9.5 million, $7.1 million and $6.8 million, respectively, of hardship accounts in Regulatory Assets. These amounts are included in “Other Deferred Charges” in the table below. The Company currently receives recovery in rates or expects to receive recovery of these hardship accounts in future rate cases.

29

	September 30,				December 31,
Regulatory Assets consist of the following ($ millions)	2021		2020		2020
Retirement Benefits	$	107.0	$	81.0	$	103.7
Energy Supply & Other Rate Adjustment Mechanisms		27.3		28.9		34.1
Deferred Storm Charges		3.4		4.4		4.1
Environmental		4.8		6.1		5.2
Income Taxes		2.8		3.6		3.4
Other Deferred Charges		17.7		12.1		14.2
Total Regulatory Assets	$	163.0	$	136.1	$	164.7
Less: Current Portion of Regulatory Assets(1)		30.6		31.7		37.3
Regulatory Assets – noncurrent	$	132.4	$	104.4	$	127.4

(1) Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets.

	September 30,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2021		2020		2020
Income Taxes (Note 8)	$	44.6	$	45.8	$	45.5
Rate Adjustment Mechanisms		11.3		9.2		4.1
Other		0.1		0.3		0.2
Total Regulatory Liabilities	$	56.0	$	55.3	$	49.8
Less: Current Portion of Regulatory Liabilities		13.1		10.6		5.5
Regulatory Liabilities - noncurrent	$	42.9	$	44.7	$	44.3

Generally, the Company receives a return on investment on its regulatory assets for which a cash outflow has been made. Regulatory Assets at September 30, 2021 include $8.5 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 accounting rules for regulated operations, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

Derivatives - The Company’s regulated energy subsidiaries enter into energy supply contracts to serve their electric and gas customers. The Company follows a procedure for determining whether each contract qualifies as a derivative instrument under the guidance provided by the FASB Codification on Derivatives and Hedging. For each contract, the Company reviews and documents the key terms of the contract. Based on those terms and any additional relevant components of the contract, the Company 

30

determines and documents whether the contract qualifies as a derivative instrument as defined in the FASB Codification. The Company has determined that its energy supply contracts either do not qualify as a derivative instrument under the guidance set forth in the FASB Codification, have been elected as 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). Until these contingencies are satisfied, these contracts will not qualify for derivative accounting. The Company believes that the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg.

Investments in Marketable Securities - The Company has a trust through which it invests in a money market fund. These investments are intended to satisfy obligations under the Company’s Supplemental Executive Retirement Plan (SERP) (See further discussion of the SERP in Note 9.)

At September 30, 2021, September 30, 2020 and December 31, 2020, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $5.6 million, $5.7 million and $5.7 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.

	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2021		2020		2020
Money Market Fund	$	5.6	$	5.7	$	5.7
Total Marketable Securities	$	5.6	$	5.7	$	5.7

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

At September 30, 2021, September 30, 2020 and December 31, 2020, 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 $0.5 million, $0.5 million and $0.5 million, respectively, as shown in the following table. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other Expense, Net.

	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2021		2020		2020
Equity Funds	$	0.1	$	0.2	$	0.2
Money Market Funds		0.4		0.3		0.3
Total Marketable Securities	$	0.5	$	0.5	$	0.5

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

	September 30,				December 31,
Energy Supply Obligations ($ millions)	2021		2020		2020
Exchange Gas Obligation	$	9.7	$	6.0	$	4.4
Renewable Energy Portfolio Standards		6.4		5.8		5.7
Power Supply Contract Divestitures		—		0.3		0.3
Total Energy Supply Obligations	$	16.1	$	12.1	$	10.4

Exchange Gas Obligation - Northern Utilities enters into gas exchange agreements under which Northern Utilities releases certain gas pipeline and storage assets, resells the gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the gas heating season at the same price at which it 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 in Accrued Revenue with a corresponding liability in Energy Supply Obligations on the Company’s Consolidated Balance Sheets.

Fitchburg has entered into long-term renewable contracts for the purchase of clean energy and/or RECs pursuant to Massachusetts legislation, specifically, An Act Relative to Green Communities (Green Communities Act, 2008), An Act Relative to Competitively Priced Electricity in the Commonwealth (2012) and An Act to Promote Energy Diversity (Energy Diversity Act, 2016). The generating facilities associated with eight of these contracts have been constructed and are now operating. Two additional contracts are scheduled to become commercial in 2021. In 2020, three of the long-term contracts were terminated due to an inability to meet critical milestones. In 2018, the Company filed two long-term contracts with the MDPU, one for offshore wind generation and another for imported hydroelectric power and associated transmission. Those contracts were approved in 2019. In 2019, the Company participated in an additional statewide procurement for offshore wind generation and the resulting contracts were filed with the MDPU during the first quarter of 2020. An Order approving the contracts was issued by the MDPU in November 2020. On November 25, 2020 the Office of the Attorney General filed a Motion for Reconsideration of the MDPU’s order regarding remuneration, which was denied. The MDPU order is now final. In compliance with An Act to Promote a Clean Energy Future (2018), in late 2020 in coordination with the other electric utilities in Massachusetts, the Company began efforts on the next long-term renewable procurement which will seek up to an additional 1,600 megawatts (MW) of offshore wind generation. Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

Power Supply Contract Divestitures - Unitil Energy’s and Fitchburg’s customers are entitled to purchase their electric or gas supplies from third-party suppliers. In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil

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Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs. As of September 30, 2021, Fitchburg has fully recovered its power supply-related stranded costs and Unitil Energy has less than $0.1 million remaining to recover. The obligations related to these divestitures are recorded in Energy Supply Obligations on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue.

Subsequent Events - The Company evaluates all events or transactions through the date of the related filing. During the period subsequent to the balance sheet date and through the date of this filing, the Company did not have any material subsequent events that would result in adjustment to or disclosure in its Consolidated Financial Statements.

NOTE 2 – DIVIDENDS DECLARED PER SHARE

Declaration  Date	Date Paid (Payable)	Shareholder of Record Date	Dividend Amount
10/27/21	11/29/21	11/15/21	$ 0.380
07/28/21	08/27/21	08/13/21	$ 0.380
04/28/21	05/28/21	05/14/21	$ 0.380
01/27/21	02/26/21	02/12/21	$ 0.380
10/28/20	11/30/20	11/16/20	$ 0.375
07/29/20	08/28/20	08/14/20	$ 0.375
04/29/20	05/29/20	05/15/20	$ 0.375
01/29/20	02/28/20	02/14/20	$ 0.375

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NOTE 3 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three and nine months ended September 30, 2021 and September 30, 2020:

	Gas			Electric			Non- Regulated		Other			Total
Three Months Ended Sept. 30, 2021 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	23.1		$	65.0		$	—	$	—		$	88.1
Rate Adjustment Mechanism Revenue		9.5			0.5			—		—			10.0
Other Operating Revenue – Non-Regulated		—			—			—		—			—
Total Operating Revenues	$	32.6		$	65.5		$	—	$	—		$	98.1
Segment Profit (Loss)		(4.1	)		4.4			—		(0.3	)		—
Capital Expenditures		28.5			10.1			—		0.4			39.0
Three Months Ended Sept. 30, 2020 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	20.0		$	60.8		$	—	$	—		$	80.8
Rate Adjustment Mechanism Revenue		7.5			(0.9	)		—		—			6.6
Other Operating Revenue – Non-Regulated		—			—			—		—			—
Total Operating Revenues	$	27.5		$	59.9		$	—	$	—		$	87.4
Segment Profit (Loss)		(3.6	)		4.4			—		(0.5	)		0.3
Capital Expenditures		27.4			16.0			—		1.4			44.8
Nine Months Ended Sept. 30, 2021 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	154.3		$	189.1		$	—	$	—		$	343.4
Rate Adjustment Mechanism Revenue		(3.0	)		(6.9	)		—		—			(9.9	)
Other Operating Revenue – Non-Regulated		—			—			—		—			—
Total Operating Revenues	$	151.3		$	182.2		$	—	$	—		$	333.5
Segment Profit (Loss)		12.1			10.7			0.1		(1.3	)		21.6
Capital Expenditures		51.7			28.8			—		1.0			81.5
Segment Assets		906.2			583.6			—		19.2			1,509.0
Nine Months Ended Sept. 30, 2020 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	130.9		$	173.5		$	—	$	—		$	304.4
Rate Adjustment Mechanism Revenue		0.5			(3.2	)		—		—			(2.7	)
Other Operating Revenue – Non-Regulated		—			—			—		—			—
Total Operating Revenues	$	131.4		$	170.3		$	—	$	—		$	301.7
Segment Profit		8.6			10.1			—		(0.1	)		18.6
Capital Expenditures		50.0			39.9			—		3.7			93.6
Segment Assets		845.0			556.3			—		22.6			1,423.9

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NOTE 4 –DEBT AND FINANCING ARRANGEMENTS

Details on long-term debt at September 30, 2021, September 30, 2020 and December 31, 2020 are shown below:

($ millions)	September 30,				December 31,
	2021		2020		2020
Unitil Corporation:
6.33% Senior Notes, Due May 1, 2022	$	—	$	20.0	$	15.0
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
Unitil Energy First Mortgage Bonds:
8.49% Senior Secured Notes, Due October 14, 2024		3.0		4.5		3.0
6.96% Senior Secured Notes, Due September 1, 2028		14.0		16.0		16.0
8.00% Senior Secured Notes, Due May 1, 2031		15.0		15.0		15.0
6.32% Senior Secured Notes, Due September 15, 2036		15.0		15.0		15.0
3.58% Senior Secured Notes, Due September 15, 2040		27.5		27.5		27.5
4.18% Senior Secured Notes, Due November 30, 2048		30.0		30.0		30.0
Fitchburg:
6.75% Senior Notes, Due November 30, 2023		—		3.8		1.9
6.79% Senior Notes, Due October 15, 2025		10.0		10.0		10.0
3.52% Senior Notes, Due November 1, 2027		10.0		10.0		10.0
7.37% Senior Notes, Due January 15, 2029		9.6		10.8		10.8
5.90% Senior Notes, Due December 15, 2030		15.0		15.0		15.0
7.98% Senior Notes, Due June 1, 2031		14.0		14.0		14.0
3.78% Senior Notes, Due September 15, 2040		27.5		27.5		27.5
4.32% Senior Notes, Due November 1, 2047		15.0		15.0		15.0
Northern Utilities:
3.52% Senior Notes, Due November 1, 2027		20.0		20.0		20.0
7.72% Senior Notes, Due December 3, 2038		50.0		50.0		50.0
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
Unitil Realty Corp.:
2.64% Senior Secured Notes, Due December 18, 2030		4.5		—		4.7
Total Long-Term Debt		515.1		539.1		535.4
Less: Unamortized Debt Issuance Costs		3.7		3.8		3.8
Total Long-Term Debt, net of Unamortized Debt Issuance Costs		511.4		535.3		531.6
Less: Current Portion		10.1		6.3		8.5
Total Long-term Debt, Less Current Portion	$	501.3	$	529.0	$	523.1

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

($ millions)	September 30,				December 31,
	2021		2020		2020
Estimated Fair Value of Long-Term Debt	$	598.2	$	631.7	$	633.1

On July 25, 2018, the Company entered into a Second Amended and Restated Credit Agreement and related documents (collectively, the Credit Facility) with a syndicate of lenders, which amended and restated in its entirety the Company’s prior credit facility. The Credit Facility extends to
July 25, 2023, subject to two one-year extensions under certain circumstances, and has a borrowing limit of $120 million, which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides the Company with the ability to elect that borrowings under the Credit Facility bear interest under several options, including at a daily fluctuating rate of interest per annum equal to one-month London Interbank Offered Rate plus 1.125%. The Company may increase the borrowing limit under the Credit Facility by up to $50 million under certain circumstances.

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $170.7 million for the nine months ended September 30, 2021. Total gross repayments were $194.9 million for the nine months ended September 30, 2021. The following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of September 30 2021, September 30, 2020 and December 31, 2020:

	Revolving Credit Facility ($ millions)
	September 30,				December 31,
	2021		2020		2020
Limit	$	120.0	$	120.0	$	120.0
Short-Term Borrowings Outstanding		30.5		17.3		54.7
Letter of Credit Outstanding		—		0.1		0.1
Available	$	89.5	$	102.6	$	65.2

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, the Company’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on the Company’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility apply until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At September 30, 2021, September 30, 2020 and December 31, 2020, the Company was in compliance with the covenants contained in the Credit Facility in effect on those dates.

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The average interest rates on all short-term borrowings and intercompany money pool transactions were 1.2% and 1.3% for the three months ended September 30, 2021 and September 30, 2020, respectively. The average interest rates on all short-term borrowings and intercompany money pool transactions were 1.2% and 1.8% for the nine months ended September 30, 2021 and September 30, 2020, respectively. The average interest rate on all short-term borrowings for the twelve months ended December 31, 2020 was 1.7%.

On December 18, 2020, Unitil Realty Corp. entered into a loan agreement in the amount of $4.7 million at 2.64%, with a maturity date of December 18, 2030. Less than $0.1 million of costs associated with this loan have been recorded as a reduction to the proceeds. Unitil Realty Corp. used the net proceeds from this loan for general corporate purposes.

On September 15, 2020, Northern Utilities issued $40 million of Notes due 2040 at 3.78%. Fitchburg issued $27.5 million of Notes due 2040 at 3.78%. Unitil Energy issued $27.5 million of Bonds due 2040 at 3.58%. Northern Utilities, Fitchburg and Unitil Energy used the net proceeds from these offerings to repay short-term debt and for general corporate purposes. Approximately $0.5 million of costs associated with these issuances have been recorded as a reduction to Long-Term Debt on the Consolidated Balance Sheets.

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

Northern Utilities enters into asset management agreements under which Northern Utilities releases certain gas pipeline and storage assets, resells to an asset manager and subsequently repurchases the gas over the course of the gas heating season at the same price at which it sold the gas to the asset manager. There was $9.7 million, $6.0 million and $5.4 million of gas obligations at September 30, 2021, September 30, 2020 and December 31, 2020, respectively, related to these asset management agreements. The amount of gas released in September 2021 and payable in October 2021 is $0.1 million and is recorded in Accounts Payable at September 30, 2021. The amount of gas released in September 2020 and payable in October 2020 was less than $0.1 million and was recorded in Accounts Payable at September 30, 2020. The amount of gas released in December 2020 and payable in January 2021 was $1.0 million and was recorded in Accounts Payable at December 31, 2020.

Guarantees

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 September 30, 2021, there were approximately $0.7 million of guarantees outstanding with a duration less than one year.

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 September 30, 2021 and 2020 amounted to $0.5 million and $0.5 million, respectively. Total rental expense under operating leases charged to operations for the nine months ended September 30, 2021 and 2020 amounted to $1.4 million and $1.4 million, respectively.

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

	September 30,				December 31,
Lease Obligations ($ millions)	2021		2020		2020
Operating Lease Obligations:
Other Current Liabilities (current portion)	$	1.6	$	1.6	$	1.5
Other Noncurrent Liabilities (long-term portion)		3.5		4.0		3.7
Total Operating Lease Obligations	$	5.1	$	5.6	$	5.2
Capital Lease Obligations:
Other Current Liabilities (current portion)	$	0.2	$	0.2	$	0.2
Other Noncurrent Liabilities (long-term portion)		0.2		0.3		0.2
Total Capital Lease Obligations	$	0.4	$	0.5	$	0.4
Total Lease Obligations	$	5.5	$	6.1	$	5.6

Cash paid for amounts included in the measurement of operating lease obligations for the nine months ended September 30, 2021 and September 30, 2020 was $1.4 million and $1.4 million and was included in Cash Provided by Operating Activities on the Consolidated Statements of Cash Flows.

Assets under capital leases amounted to approximately $0.7 million, $1.1 million and $1.0 million as of September 30, 2021, September 30, 2020 and December 31, 2020, respectively, less accumulated amortization of $0.3 million, $0.6 million and $0.5 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 September 30, 2021. The payments for operating leases consist of $1.6 million of current operating lease obligations, which are included in Other Current Liabilities and $3.5 million of noncurrent operating lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of September 30, 2021. The payments for capital leases consist of $0.2 million of current capital lease obligations, which are included in Other Current Liabilities and $0.2 million of noncurrent capital lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of September 30, 2021.

Lease Payments ($000’s) Year Ending December 31,	Operating Leases		Capital Leases
Rest of 2021	$	479	$	39
2022		1,695		150
2023		1,399		107
2024		1,069		52
2025		503		20
2026-2030		320		—
Total Payments		5,465		368
Less: Interest		365		15
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$	5,100	$	353

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 September 30, 2021, the weighted average remaining lease term is 3.7 years and the weighted average operating discount rate used to determine the operating lease obligations was 4.0%. As of September 30, 2020, the weighted average remaining lease term was 4.0 years and the weighted average operating discount rate used to determine the operating lease obligations was 4.4%.

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NOTE 5 – COMMON STOCK AND PREFERRED STOCK

Common Stock

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

The Company had 15,971,962, 15,005,881 and 15,012,310 shares of common stock outstanding at September 30, 2021, September 30, 2020 and December 31, 2020, respectively.

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

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

Dividend Reinvestment and Stock Purchase Plan - During the first nine months of 2021, the Company sold 16,512 shares of its common stock, at an average price of $48.52 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $801,200. 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 awards of restricted shares (Restricted Shares), or of restricted stock units (Restricted Stock Units). The Compensation Committee has the authority to determine the sizes of awards; determine the terms and conditions of awards in a manner consistent with the Stock Plan; construe and interpret the Stock Plan and any agreement or instrument entered into under the Stock Plan as they apply to participants; establish, amend, or waive rules and regulations for the Stock Plan’s administration as they apply to participants; and, subject to the provisions of the Stock Plan, amend the terms and conditions of any outstanding award to the extent such terms and conditions are within the discretion of the Compensation Committee as provided for in the Stock Plan. On April 19, 2012, the Company’s shareholders approved an amendment to the Stock Plan to, among other things, increase the maximum number of shares of common stock available for awards to plan participants.

The maximum number of shares available for awards to participants under the Stock Plan is 677,500. The maximum number of shares that may be awarded in any one calendar year to any one participant is 20,000. In the event of any change 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.

Restricted Shares

Outstanding awards of Restricted Shares fully vest over a period of four years at a rate of 25% each year. During the vesting period, dividends on Restricted Shares underlying the award may be credited to a

39

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. For purposes of compensation expense, Restricted Shares vest immediately upon a participant becoming eligible for retirement, as defined in the Stock Plan. Prior to the end of the vesting period, the restricted shares are subject to forfeiture if the participant ceases to be employed by the Company other than due to the participant’s death.

On January 26, 2021, 23,140 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of approximately $0.9 million. There were 57,408 and 59,813 non-vested shares under the Stock Plan as of September 30, 2021 and 2020, respectively. The weighted average grant date fair value of these shares was $49.61 and $54.41, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $1.4 million and $2.1 million for the nine months ended September 30, 2021 and 2020, respectively. At September 30, 2021, there was approximately $0.7 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.7 years. During the nine months ended September 30, 2021 there were zero restricted shares forfeited and zero restricted shares cancelled under the Stock Plan.

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 portion of Restricted Stock Units activity during the nine months ended September 30, 2021 in conjunction with the Stock Plan is presented in the following table:

Restricted Stock Units (Equity Portion)

	Units		Weighted Average Stock Price
Restricted Stock Units as of December 31, 2020		43,192	$	41.34
Restricted Stock Units Granted		—		—
Dividend Equivalents Earned		1,032	$	48.10
Restricted Stock Units Settled		—		—
Restricted Stock Units as of September 30, 2021		44,224	$	41.49

There were 39,057 Restricted Stock Units outstanding as of September 30, 2020 with a weighted average stock price of $41.54. Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of September 30, 2021, September 30, 2020 and December 31, 2020 is $0.8 million, $0.6 million and $0.8 million, respectively, representing the fair value of liabilities associated with the portion of fully vested RSUs that will be settled in cash.

Preferred Stock    

There were $0.2 million, or 1,861 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of September 30, 2021. There were $0.2 million, or 1,887 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of September 30, 2020 and December 31, 2020. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the three and nine month periods ended September 30, 2021 and September 30, 2020, respectively.

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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, 2020 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 2, 2021.

Tax Cuts and Jobs Act of 2017

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (TCJA) was signed into law. Among other things, the TCJA substantially reduced the corporate income tax rate to 21%, effective January 1, 2018. Each state public utility commission, with jurisdiction over the areas that are served by Unitil’s electric and gas subsidiary companies, issued orders directing how the tax law changes were to be reflected in rates. Unitil has complied with these orders and has made the required changes to its rates as directed by the commissions. The FERC issued a Notice of Proposed Rulemaking that would allow it to determine which pipelines under the Natural Gas Act may be collecting unjust and unreasonable rates in light of the corporate tax reduction. This matter was resolved for Granite State in its May 2, 2018 uncontested rate settlement filing, which accounted for the effect of the TCJA.

On November 21, 2019, the FERC issued Order No. 864, a final rule on Public Utility Transmission Rate Changes to Address Accumulated Deferred Income Taxes. The new rule requires public utilities with formula transmission rates to revise their formula rates to include a transparent methodology to address the TCJA and future tax law changes on customer rates by accounting for “excess” or “deficient” Accumulated Deferred Income Taxes (ADIT). FERC also required transmission providers with stated rates to account for TCJA’s effect on ADIT in their next rate case. The Company is complying with the new rule and there is no material effect on its financial position, operating results, or cash flows.

Rate Case Activity

Northern Utilities - Base Rates - Maine - On March 26, 2020, the MPUC approved an increase to base revenue of $3.6 million, a 3.6% increase over the Company’s test year operating revenues, effective April 1, 2020. The order approved a Return on Equity of 9.48%, and a hypothetical capital structure of 50% equity and 50% debt. As part of the order and increase in base revenue, the MPUC provided for recovery of some, but not all, of the Company’s implementation costs associated with its customer information system pending the completion of an investigation, including a third-party audit. On March 9, 2021, the MPUC opened a new docket to investigate the amount of customer information system costs that will be allowed in rates and released the third-party audit report. The audit report findings included highlighting the Company’s effective implementation efforts while also suggesting potential excess costs of approximately $5.0 million out of the total cost of $36.8 million. The total cost for the customer information system is allocated across all of Unitil’s distribution utility subsidiary companies. The Company disagrees with many of the characterizations of findings contained in the audit report, as well as many of the report’s opinions and conclusions concerning those findings. On June 30, 2021, the Company filed testimony and exhibits with the MPUC rebutting the assertions made in the audit. The Company continues to believe that the customer information system costs were prudently incurred and continues to pursue recovery of the customer information system costs in rates. The Company believes that the ultimate outcome of the investigation will not have a material effect on its financial position, operating results or cash flows.

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 $1.1 million for 2020 eligible facilities, was approved by the MPUC effective May 1, 2021.

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Northern Utilities - Base Rates - New Hampshire - On August 2, 2021, Northern Utilities filed a base rate case with the NHPUC, requesting a permanent increase in total annual revenues of $7.8 million, which represents an increase of 8.1% over total annual revenue at present rates. The multi-year rate filing includes a revenue decoupling mechanism and an Arrearage Management Program for financial hardship customers. Northern Utilities also requested implementation of temporary rates for service rendered on and after October 1, 2021. On September 30, 2021, the NHPUC approved a settlement providing for a temporary rate increase of $2.6 million, effective October 1, 2021. 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.

Unitil Energy - Base Rates - On April 2, 2021, Unitil Energy filed a base rate case with the NHPUC, requesting a permanent increase in total annual revenues of $12.0 million, which represents an increase of 4.4% above present rates. Unitil Energy also requested implementation of temporary rates for service rendered on and after June 1, 2021, and until a final order on permanent rates is issued. The filing includes (1) a proposed multi-year rate plan, (2) a revenue decoupling mechanism, (3) a Grid Modernization plan that includes a group of foundational grid modernization projects, (4) a suite of proposed time of use (TOU) rates including rates for electric vehicles (EV), (5) an EV infrastructure development program which includes rebates for residential customers for the installation of smart charging equipment and a public “make-ready” program for general service customers under which the Company will install the infrastructure required to connect an EV charger, (6) a Marketing, Communications, and Education Plan to engage with customers about the TOU rates and EV program offerings, (7) resiliency programs to further the Company’s commitment to reliability, (8) an Arrearage Management Program for financial hardship customers, and (9) other rate design and tariff changes. On April 24, 2020, the Governor of New Hampshire issued an executive order that extended the NHPUC’s authority to suspend rate schedules by six months, from 12 to 18 months, to conduct its investigation of a utility company’s request to increase rates. On April 6, 2021, the NHPUC determined that the extension applies to this proceeding, but stated it will endeavor to set final rates as expeditiously as possible. On May 27, 2021, the NHPUC approved a settlement agreement providing for a temporary rate increase of $4.5 million in annual electric distribution revenues, effective June 1, 2021. 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.

Fitchburg - Base Rates - Electric - Fitchburg’s base rates are decoupled in order to mitigate economic, weather and energy efficiency affect to the Company’s revenues and subject to an annual revenue decoupling adjustment mechanism, which includes a cap on the amount that rates may be increased in any year. In addition, Fitchburg has an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions. On November 1, 2018, Fitchburg filed its cumulative revenue requirement of $0.9 million associated with the Company’s 2015-2017 capital expenditures. On December 22, 2020, final approval of the filing was issued. On October 29, 2019, Fitchburg filed its cumulative revenue requirement of $1.1 million associated with the Company’s 2015-2018 capital expenditures. On December 22, 2020, final approval of the filing was issued. On November 2, 2020, Fitchburg filed its cumulative revenue requirement of $1.4 million associated with its 2019 capital expenditures. On June 15, 2021, final approval of the filing was issued, effective January 1, 2021.

On April 17, 2020, the MDPU approved a settlement agreement entered into by the Company and the Massachusetts Office of the Attorney General providing for a distribution increase of $1.1 million, effective November 1, 2020. The Company’s subsequent Compliance Filing reflected an adjusted distribution increase of $0.9 million, a decrease of $0.2 million from the original settlement amount. On May 21, 2020, the MDPU approved the Company’s Compliance Filing. The agreement provides for a Return on Equity of 9.7% and a capital structure reflecting 52.45% equity and 47.55% long-term debt. Under the agreement, the Company will not increase or redesign base distribution rates to become effective prior to November 1, 2023, though the Company may seek cost recovery for certain exogenous events that meet a revenue threshold of $0.1 million. The agreement also provides for the implementation of a major storm reserve fund, whereby the Company may recover the costs of restoration for qualifying storm events. In addition, the agreement provides for the extension of the annual capital cost recovery mechanism, modified to allow the recovery of property tax on the cumulative net capital expenditures.

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Fitchburg - Base Rates - Gas - Pursuant to its revenue decoupling adjustment clause tariff, as approved in its last base rate case, the Company is allowed to modify, on a semi-annual basis, its base distribution rates to an established revenue per customer target in order to mitigate economic, weather and energy efficiency affect to the Company’s revenues. The MDPU consistently has found the Company’s filings are in accord with its approved tariffs, applicable law and precedent, and that they result in just and reasonable rates.

On February 28, 2020, the MDPU approved a settlement agreement between the Company and the Massachusetts Office of the Attorney General. The agreement provides for an annual distribution revenue increase of $4.6 million to be phased in over two years: (1) an increase of $3.7 million, which became effective on March 1, 2020; and (2) an increase of $0.9 million, which became effective on March 1, 2021. Under the agreement, the Company will not increase or redesign base distribution rates to become effective prior to March 1, 2023, though the Company may seek cost recovery for certain exogenous events that meet a revenue effect threshold of $40,000. The agreement provides for a Return on Equity of 9.7% and a capital structure reflecting 52.45% equity and 47.55% long-term debt.

Fitchburg - Gas System Enhancement Program - Pursuant to statute and MDPU order, Fitchburg has an approved Gas System Enhancement Plan tariff through which it may recover certain gas infrastructure replacement and safety related investment costs, subject to an annual cap. Under the plan, the Company is required to make two annual filings with the MDPU: a forward-looking filing for the subsequent construction year, to be filed on or before October 31; and a filing, submitted on or before May 1, of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably and prudently incurred. Fitchburg’s most recent forward-looking filing, filed on October 30, 2020, requested recovery of approximately $2.2 million, and received final approval on April 29, 2021, effective May 1, 2021. The Company considers these to be routine regulatory proceedings, and there are no material issues outstanding.

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

On August 24, 2021, the FERC accepted Granite State’s first limited Section 4 rate adjustment pursuant to the Settlement Agreement, for an annual revenue increase of $0.1 million, effective September 1, 2021.

Other Matters

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. The GMP is subject to review and approval by the MDPU and remains pending.

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Fitchburg - Grid Modernization Cost Recovery Factor - On April 15, 2021, Fitchburg filed its Grid Modernization Factor (GMF) rate adjustment and reconciliation filing pursuant to the Company’s proposed GMF Tariff, for recovery of the costs incurred as a result of implementing the Company’s 2018-2021 GMP, previously approved by the MDPU on February 7, 2019. The proposed GMF was approved on May 27, 2021, effective June 1, 2021, 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, have engaged an independent consultant to conduct a study and prepare a report (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 is to include an examination of the potential pathways identified in the 2050 Decarbonization Roadmap developed by the MA Executive Office of Energy and Environmental Affairs, in consultation with the Massachusetts Department of Environmental Protection and the Massachusetts Department of Energy Resources. On or before March 1, 2022, each LDC is required to submit a proposal to the MDPU that includes the LDCs’ recommendations and plans for helping the Commonwealth achieve its 2050 climate goals, supported by the Report. Prior to filing the Report and the LDCs’ proposals, the LDCs are directed to engage in a stakeholder process to solicit feedback and advice on both the Report and the proposals. Fitchburg is actively involved in the LDCs’ joint effort to respond to the MDPU’s directives.

Financial Effects of COVID-19 Pandemic - The NHPUC and the MDPU have opened proceedings to consider the revenue and cost effects on the regulated gas and electric utilities within their respective jurisdictions of the requirement to continue the availability of gas, electric and water service to customers during the COVID-19 pandemic. Among the effects under investigation are the revenue effects associated with service disconnection moratoriums, the waiver of fees and expanded customer payments arrangements; the increased cost of customer accounts that cannot be collected, including the cost of bad debt reserves and increased working capital costs; and increased operating and maintenance costs incurred for employees to work safely and protect the public. Fitchburg, Unitil Energy and Northern Utilities are active participants in these proceedings, and are in full compliance with all regulatory orders governing service shut-off moratoriums and other customer service protection measures. These matters remain pending. On December 31, 2020, in docket DPU 20-58, the MDPU issued an order which, among other provisions, allows the utility companies to defer for future recovery bad debt expense in excess of a baseline. On July 7, 2021, the NHPUC issued an order which declined to authorize New Hampshire’s rate-regulated utilities’ establishment of a regulatory asset for incremental bad debt or waived late payment fees related to the COVID-19 pandemic. The NHPUC stated that these costs will be addressed in each utility’s next rate case. On September 7, 2021, the NHPUC clarified its July 7 Order, determining that it has not foreclosed rate-regulated utilities from utilizing accounting mechanisms to defer costs in order to seek recovery in a future rate proceeding, and that Unitil Energy’s and Northern Utilities’ respective pending rate cases are the appropriate venue to address incremental bad debt and/or waived late payment fees resulting from the COVID-19 public health emergency orders and directives.

Northern Utilities / Granite State - Firm Capacity Contract - Northern Utilities relies on the transport of gas supply over its affiliate Granite State pipeline to serve its customers in the Maine and New Hampshire service territories. 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 30, 2021, Northern Utilities submitted an annual informational report requesting approval on a one-year extension for the period of November 1, 2021 through October 31, 2022. The MPUC approved the request on June 29, 2021.

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Reconciliation Filings - Fitchburg, Unitil Energy and Northern Utilities each have a number of regulatory reconciling accounts that require annual or semi-annual filings with the MDPU, NHPUC and MPUC, respectively, to reconcile costs and revenues, 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 the actual wholesale energy costs for electric power and gas incurred by each of the three companies. Fitchburg, Unitil Energy and Northern Utilities have been, and remain in full compliance with all directives and orders regarding these filings. The Company considers these to be routine regulatory proceedings, and there are no material issues outstanding.

Fitchburg - Massachusetts RFPs - Pursuant to a comprehensive energy law enacted in 2016, “An Act to Promote Energy Diversity,” (the Act) under Section 83C, the Massachusetts electric distribution companies (EDCs), including Fitchburg, are required to jointly solicit proposals for long-term contracts for at least 400 MW) of offshore wind energy generation by June 30, 2017, as part of a total of 1,600 MW of offshore wind the EDCs are directed to procure by June 30, 2027. Under Section 83D of the Act, the EDCs are required to jointly seek proposals for cost-effective clean energy (hydroelectric, solar and land-based wind) long-term contracts via one or more staggered solicitations for a total of 9,450,000 megawatt-hours (MWh) by December 31, 2022. Unitil’s pro rata share of these contracts is approximately one percent. The EDCs issued the RFP for Section 83D Long-Term Contracts for Qualified Clean Energy Projects in March 2017, and after selection of final projects and negotiation, final contracts for 9,554,940 MWh of Qualified Clean Energy and associated Environmental Attributes from hydroelectric generation were filed in July 2018 for approval by the MDPU. On June 25, 2019, the MDPU approved the power purchase agreements, 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 costs to customers. The MDPU also determined that the EDCs’ request for remuneration equal to 2.75% of the contract payments is reasonable and in the public interest and approved the EDCs’ proposal to amend their respective tariffs to include the recovery of costs associated with the contracts. The Massachusetts Supreme Judicial Court upheld the MDPU’s approval in an Order dated September 3, 2020. The Company believes the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg, once certain conditions and contingencies are met.

The EDCs issued the RFP pursuant to Section 83C for Long-Term Contracts for Offshore Wind Energy Generation in June 2017. The EDCs selected an 800 MW project submitted by Vineyard Wind in May 2018, contracts were signed in July 2018 and on July 23, 2018, the EDCs, including Fitchburg, filed two long-term contracts, each for 400 MW of offshore wind energy generation with the MDPU for approval. On April 12, 2019, the MDPU approved the offshore wind energy generation power purchase agreements, 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 costs to customers. The MDPU also determined that the EDCs’ request for remuneration equal to 2.75% of the contract payments is reasonable and in the public interest and approved the EDCs’ proposal to amend their respective tariffs to include the recovery of costs associated with the contracts. The Company believes the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg, once certain conditions and contingencies are met.

The EDCs issued a second RFP pursuant to Section 83C for Long-Term Contracts for Offshore Wind Energy Generation on May 23, 2019. This solicitation sought to procure the remaining obligation under 83C to procure an additional 800 MW of offshore wind energy generation. The EDCs selected an 800 MW project submitted by Mayflower Wind and contracts were executed on January 10, 2020. A filing with the MDPU for approval of two long-term contracts, each for 400 MW of offshore wind energy generation,

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was made on February 10, 2020. On November 5, 2020, the MDPU approved the Offshore Wind Energy Generation power purchase agreements. The MDPU also determined that the EDCs’ request for remuneration equal to 2.75% is reasonable and in the public interest. On November 25, 2020 the Office of the Attorney General filed a Motion for Reconsideration of the MDPU’s order regarding remuneration, which was denied. The MDPU order is now final. The Company believes the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg, once certain conditions and contingencies are met.

In accordance with the requirement of Chapter 227 of the Acts of 2018, An Act to Advance Clean Energy, signed August 9, 2018, Massachusetts Department of Energy Resources (MDOER) prepared a report on the necessity, benefits and costs of requiring the EDCs to competitively conduct offshore wind generation RFPs for up to an additional 1,600 MW. The MDOER filed its report with the Legislature in May, 2019, recommending that, “the EDCs should proceed with additional offshore wind solicitations for up to 1,600 MW of offshore wind in 2022 and 2024 and only enter into contracts if found to be cost-effective.” On March 10, 2021, Fitchburg, along with the other MA EDCs, filed a petition with the MDPU for approval of a proposed timetable and method of solicitation and execution of long-term contracts for up to an additional 1,600 MW of off shore wind generation. On May 5, 2021, the DPU approved the proposed timetable and method for the solicitation, and the RFP was issued on May 7, 2021. Responsive proposals were received on September 16, 2021, and project selection is scheduled for December 17, 2021.

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’ Regional Network Service and Local Network Service formula rates. On April 14, 2017, the U.S. Court of Appeals for the D.C. Circuit (the Court) issued an opinion vacating a decision of the FERC with respect to the ROE, and remanded it for further proceedings. The FERC had found that the Transmission Owners existing ROE was unlawful, and set a new ROE. The Court found that the 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. Separately, on March 15, 2018, the Transmission Owners filed a petition for review with the Court of certain orders of the FERC setting for hearing other complaints challenging the allowed Return on Equity component of the formula rates. 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. In response to the FERC order in EL 14-12, the New England Transmission Owners (NETOs) filed a motion to reopen the record, which has been granted. This matter remains pending.

The FERC Section 206 proceeding concerning the justness and reasonableness of ISO-New England, Inc. Participating Transmission Owners’ Regional Network Service and Local Network Service formula rates and to develop formula rate protocols for these rates has been resolved. On August 17, 2018 a joint settlement agreement among a number of the parties was filed with the FERC. FERC rejected the settlement agreement on May 22, 2019 and remanded the proceeding to the Chief Administrative Law Judge to resume hearing procedures. On May 24, 2019 the judge appointed a Dispute Resolution Facilitator to aid parties in settlement negotiations. The procedural schedule was suspended September 24, 2019 in order to allow participants to focus on settlement negotiations. On October 24, 2019, the NETO’s filed an unopposed motion to suspend the procedural schedule and waiver of answer period indicating that the NETO’s, Municipal Pool Transmission Facility Owners and the Commission Trial Staff have reached agreement in principle on the terms of a settlement to resolve all open issues in the proceeding. On June 15, 2020 a settlement was filed. The FERC approved the settlement agreement on December 28, 2020. Under the terms of the settlement agreement, the negotiated formula rates will take effect on January 1, 2022. Fitchburg and Unitil Energy are Participating Transmission Owners, although Unitil Energy does not own transmission plant. To the extent that these proceedings result in any changes to the rates being charged, a retroactive reconciliation may be required. The Company does not believe these proceedings will have a material adverse effect on its financial condition or results of operations. 

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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, 2020 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 2, 2021.

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 September 30, 2021, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, the Company cannot assure that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs. Based on its current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, the Company does not believe that these environmental costs will have a material adverse effect on the Company’s consolidated financial position or results of operations.

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

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

In July 2019, the NH DES requested that Northern Utilities review modeled expectations for groundwater contaminants against observed data at the Rochester site. In June 2020, the NH DES coupled the submittal of the review to a proposed extension of the gas distribution system by Northern Utilities. Northern Utilities anticipates submittal of the review by November 2021. In anticipation of the NH DES approval of the work plan, the Company has accrued $0.8 million for estimated costs to complete the remediation at the Rochester site, which is included in Environmental Obligations.

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 shows the 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.

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Fitchburg’s Manufactured Gas Plant Site - Fitchburg has worked with the Massachusetts Department of Environmental Protection (Mass DEP) to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring continues. In April 2020, Fitchburg received notification from the Massachusetts Department of Transportation (Mass DOT) that a portion of the site may be incorporated into the proposed Twin City Rail Trail with an anticipated completion in 2023. Depending upon the final agreement between Fitchburg and Mass DOT, additional minor costs are expected prior to completion.

In August 2021, the Mass DEP issued a Notice of Non-compliance to FGE following a November 2020 audit of the September 2015 Response Action Outcome on the MGP site. Mass DEP directed Fitchburg to further define the extent of MGP site contaminants in the sediment and riverbank of an abutting watercourse, which should be completed by June 2022.

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

Unitil Energy - Kensington Distribution Operations Center - Unitil Energy conducted a Phase I and II environmental site assessment (ESA) in the second quarter of 2021. The ESA results identified soil and groundwater contaminants in excess of state regulatory standards. In September 2021, the NH DES directed Unitil Energy to conduct a supplemental site investigation and identify whether there is a need to conduct further investigation or remedial actions, which should be completed by June 2022.

The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the nine months ended September 30, 2021 and 2020.

Environmental Obligations ($ millions)
	September 30,
	2021		2020
Total Balance at Beginning of Period	$	2.1	$	2.7
Additions		0.6		0.1
Less: Payments / Reductions		0.3		0.6
Total Balance at End of Period		2.4		2.2
Less: Current Portion		0.7		0.3
Noncurrent Balance at End of Period	$	1.7	$	1.9

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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:

	Nine Months Ended September 30
	2021			2020
Statutory Federal Income Tax Rate		21	%		21	%
Income Tax Effects of:
State Income Taxes, net		6			6
Utility Plant Differences		(3	)		(5	)
Other, net		—			1
Effective Income Tax Rate		24	%		23	%

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 September 30, 2021 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, 2018, December 31, 2019, and December 31, 2020.

In March 2020, the Coronavirus Aid, Relief and Economic Security (CARES) Act was signed into law. The CARES Act included several tax changes as part of its economic package. These changes principally related to expanded Net Operating Loss carryback periods, increases to interest deductibility limitations, and accelerated Alternative Minimum Tax refunds. The Company has evaluated these items and determined that the items do not have a material effect on the Company’s financial statements as of December 31, 2020. Additionally, the CARES Act enacted the Employee Retention Credit (ERC) to incentivize companies to retain employees. The ERC is a 50% credit on employee wages for employees that are retained and cannot perform their job duties at 100% capacity as a result of coronavirus pandemic restrictions.

In December 2020, the Consolidated Appropriations Act, 2021 (CAA) was signed into law. The CAA included additional funding through tax credits as part of its economic package for 2021. These changes include the temporary removal of deduction limitations on business meals through December 2022 and additional funding for the ERC with expanded benefits extended through June 30, 2021. The expanded ERC is a 70% credit on employee wages for employees that are retained and cannot perform their job duties at 100% capacity as a result of coronavirus pandemic restrictions.

In March 2021, the American Rescue Plan Act of 2021 (ARPA) was signed into law. The ARPA included certain provisions that provide economic relief for the ongoing COVID-19 pandemic, such as extending the ERC through December 31, 2021, and other future governmental revenue producing provisions, such as expanding the scope for deduction limitations on executive compensation in future years.

The Company has evaluated each of the CARES, CAA and ARPA provisions and determined that they do not have a material effect on the Company’s financial statements as of September 30, 2021. The Company has recorded a reduction in payroll taxes related to the ERC for $0.6 million in the third quarter of 2020 and $0.4 million in the nine months ended September 30, 2021. These were recorded as a reduction to payroll tax expense which is recorded in Taxes Other Than Income Taxes in the Consolidated Statements of Earnings.

49

Income tax filings for the year ended December 31, 2020 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, 2020 which were filed with the IRS in October 2021, the Company generated federal Net Operating Loss Carryforward (NOLC) assets of $5.4 million principally due to tax repairs expensing and tax depreciation. In addition, at September 30, 2021, the Company had $0.3 million of cumulative state tax credit carryforwards to offset against future income taxes payable. If unused, the Company’s state tax credit carryforwards will begin to expire in 2023.

In December 2017, the Tax Cuts and Jobs Act (TCJA), which included a reduction to 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) at the new 21% tax rate at which the ADIT will be reversed in future periods. The Company recorded a net Regulatory Liability in the amount of $48.9 million at December 31, 2017 as a result of the ADIT revaluation. The Company expects to flow through to customers $47.1 million of excess ADIT in utility base rates. Approximately $1.8 million of excess ADIT was created through reconciling mechanisms at December 31, 2017, which had not been previously collected from customers through utility rates. The Company reconciled these excess ADIT amounts through the specific reconciliation mechanisms in each of those individual reconciling mechanisms which were reviewed by state regulators. In addition to the $48.9 million of net excess ADIT, as of December 31, 2018, there was $2.0 million of remaining excess ADIT created by the recognition of NOLC, and related to the implementation of the new federal tax rate of the TCJA, which had not been previously included in utility rates. The Company recognized the benefit of this excess ADIT in accordance with the regulatory treatment of excess ADIT for each jurisdiction. In 2019, the Company recognized $1.7 million of this amount and the remaining $0.3 million was recognized in 2020.

Based on communications received by the Company from its state regulators in rate cases and other regulatory proceedings in the first quarter of 2018 and, as prescribed in the TCJA, recent FERC guidance and IRS normalization rules, the benefit of these protected excess ADIT amounts will be subject to flow back to customers in future utility rates according to the Average Rate Assumption Method (ARAM). ARAM reconciles excess ADIT at the reversal rate of the underlying book/tax temporary timing differences. 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. Subject to regulatory approval, the Company expects to flow back to customers a net $47.1 million of protected excess ADIT created as a result of the lowering of the statutory tax rate by the TCJA over periods estimated to be fifteen to twenty years. As of September 30, 2021, the Company flowed back $2.7 million to customers in its Massachusetts, Maine, and federal jurisdictions. New Hampshire liabilities will begin to flow back once rate proceedings have finalized in that jurisdiction.

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 10 to the Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2020 as filed with the SEC on February 2, 2021 for additional information regarding these plans.

50

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	2021			2020
Discount Rate		2.50	%		3.25	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		7.50	%		7.40	%
Health Care Cost Trend Rate Assumed for Next Year		6.60	%		7.00	%
Ultimate Health Care Cost Trend Rate		4.50	%		4.50	%
Year that Ultimate Health Care Cost Trend Rate is reached		2029			2029

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

	Pension Plan						PBOP Plan						SERP
Three Months Ended September 30,	2021			2020			2021			2020			2021			2020
Service Cost	$	868		$	829		$	759		$	673		$	89		$	70
Interest Cost		1,250			1,445			685			782			114			137
Expected Return on Plan Assets		(2,422	)		(2,254	)		(627	)		(515	)		—			—
Prior Service Cost Amortization		76			80			302			301			14			15
Actuarial Loss Amortization		2,021			1,618			260			187			372			259
Sub-total		1,793			1,718			1,379			1,428			589			481
Amounts Capitalized and Deferred		(944	)		(861	)		(904	)		(860	)		(178	)		(144	)
Net Periodic Benefit Cost Recognized	$	849		$	857		$	475		$	568		$	411		$	337

 

	Pension Plan						PBOP Plan						SERP
Nine Months Ended September 30,		2021			2020			2021			2020			2021			2020
Service Cost	$	2,604		$	2,491		$	2,275		$	2,023		$	266		$	212
Interest Cost		3,752			4,332			2,055			2,341			343			412
Expected Return on Plan Assets		(7,268	)		(6,764	)		(1,881	)		(1,547	)		—			—
Prior Service Cost Amortization		226			240			906			907			42			43
Actuarial Loss Amortization		6,065			4,854			784			559			1,117			777
Sub-total		5,379			5,153			4,139			4,283			1,768			1,444
Amounts Capitalized and Deferred		(2,544	)		(2,298	)		(2,358	)		(2,087	)		(534	)		(434	)
Net Periodic Benefit Cost Recognized	$	2,835		$	2,855		$	1,781		$	2,196		$	1,234		$	1,010

Employer Contributions

As of September 30, 2021, the Company had made $4.1 million and $2.8 million of contributions to its Pension Plan and PBOP Plan, respectively, in 2021. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2021 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 September 30, 2021, the Company had made $0.5 million of benefit payments under the SERP Plan in 2021. The Company presently anticipates making an additional $0.1 million of benefit payments under the SERP Plan in 2021.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Reference is made to the “Interest Rate Risk” and “Market Risk” sections of Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (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 September 30, 2021. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of September 30, 2021 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, 2020 as filed with the SEC on February 2, 2021.

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 during the fiscal quarter ended September 30, 2021.

Issuer Purchases of Equity Securities

Pursuant to the Company’s written trading plan under Rule 10b5-1 under the Exchange Act, adopted and announced by the Company on May 1, 2021, the Company will periodically repurchase shares of its Common Stock on the open market related to the stock portion of the Directors’ annual retainer for those Directors who elected to receive common stock. There is no pool or maximum number of shares related to these purchases; however, the trading plan will terminate when $350,500 in value of shares have been purchased or, if sooner, on May 1, 2022.

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

The following table shows information regarding repurchases by the Company of shares of its common stock pursuant to the trading plan for each month in the quarter ended September 30, 2021.

52

	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
7/1/21 – 7/31/21		—		—		—	$	808
8/1/21 – 8/31/21		—		—		—	$	350,500
9/1/21 – 9/30/21		—		—		—	$	350,500
Total		—		—		—

Item 5. Other Information

On November 2, 2021, the Company issued a press release announcing its results of operations for the three and nine month periods ended September 30, 2021. The press release is furnished with this Quarterly Report on Form 10-Q as Exhibit 99.1.

Item 6. Exhibits

(a) Exhibits

Exhibit No.	Description of Exhibit	Reference
1.1	Underwriting Agreement dated April 4, 2021 among Unitil Corporation, on the one hand, and RBC Capital Markets, LLC and BofA Securities, Inc., on the other hand, for themselves and as representatives of the several underwriters named therein.	Exhibit 1.1 to Form 8-K dated August 3, 2021 (File No. 1-8858)
11	Computation of Earnings Per Average Common Share	Filed herewith
31.1	Certification of Chief Executive Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
31.3	Certification of Chief Accounting Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
32.1	Certifications of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
99.1	Unitil Corporation Press Release Dated November 2, 2021 Announcing Earnings For the Quarter Ended September 30, 2021.	Furnished herewith

53

101.INS	Inline XBRL Instance Document. The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.	Filed herewith
101.SCH	Inline XBRL Taxonomy Extension Schema Document.	Filed herewith
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document.	Filed herewith
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document	Filed herewith
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document.	Filed herewith
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document.	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

54

SIGNATURES

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

	UNITIL CORPORATION
	(Registrant)
Date: November 2, 2021	/s/ Robert B. Hevert
	Robert B. Hevert
	Chief Financial Officer

Date: November 2, 2021	/s/ Daniel J. Hurstak
	Daniel J. Hurstak
	Chief Accounting Officer

55

EX-11

EXHIBIT 11

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

COMPUTATION OF EARNINGS PER WEIGHTED AVERAGE COMMON SHARE OUTSTANDING

(Millions except common shares and per share data)

(UNAUDITED)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Net Income	$	—	$	0.3	$	21.6	$	18.6
Weighted Average Number of Common Shares Outstanding – Basic (000’s)		15,541		14,954		15,182		14,946
Dilutive Effect of Stock Options and Restricted Stock (000’s)		3		—		3		1
Weighted Average Number of Common Shares Outstanding – Diluted (000’s)		15,544		14,954		15,185		14,947
Earnings Per Share – Basic and Diluted	$	—	$	0.02	$	1.42	$	1.25

EX-31.1

Exhibit 31.1

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

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

1) I have reviewed this quarterly report on Form 10-Q of Unitil Corporation;

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

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

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

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

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

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

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

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

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

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

Date: November 2, 2021

/s/ Thomas P. Meissner, Jr.

Thomas P. Meissner, Jr.

Chief Executive Officer and President

EX-31.2

Exhibit 31.2

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

I, Robert B. Hevert, certify that:

1) I have reviewed this quarterly report on Form 10-Q of Unitil Corporation;

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

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

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

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

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

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

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

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

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

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

Date: November 2, 2021

/s/ Robert B. Hevert

Robert B. Hevert

Chief Financial Officer

EX-31.3

Exhibit 31.3

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

I, Daniel J. Hurstak, certify that:

1) I have reviewed this quarterly report on Form 10-Q of Unitil Corporation;

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

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

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

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

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

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

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

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

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

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

Date: November 2, 2021

/s/ Daniel J. Hurstak

Daniel J. Hurstak

Chief Accounting Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Unitil Corporation (the “Company”) on Form 10-Q for the period ending September 30, 2021 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned Thomas P. Meissner, Jr., Chief Executive Officer and President, Robert B. Hevert, Chief Financial Officer and Daniel J. Hurstak, Chief Accounting Officer, certifies, to the best knowledge and belief of the signatory, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Signature	Capacity	Date
/s/ Thomas P. Meissner, Jr
Thomas P. Meissner, Jr.	Chief Executive Officer and President	November 2, 2021
/s/ Robert B. Hevert
Robert B. Hevert	Chief Financial Officer	November 2, 2021
/s/ Daniel J. Hurstak
Daniel J. Hurstak	Chief Accounting Officer	November 2, 2021

EX-99.1

Page 1 of 8

Exhibit 99.1

FOR RELEASE

Unitil Reports Third Quarter Earnings

HAMPTON, N.H., NOVEMBER 2, 2021 — Unitil Corporation (NYSE: UTL) (Unitil.com) today announced breakeven Net Income and earnings per share (EPS) for the third quarter of 2021, a decrease of $0.3 million in Net Income, or $0.02 in EPS, compared to the third quarter of 2020. For the nine months ended September 30, 2021, the Company reported Net Income of $21.6 million, or $1.42 per share, an increase of $3.0 million, or $0.17 per share, compared to the same nine month period in 2020. The Company’s Gas and Electric GAAP Gross Margins for the third quarter of 2021 were $11.3 million and $18.9 million, respectively. For the nine months ended September 30, 2021, the Company’s Gas and Electric GAAP Gross Margins were $67.7 million and $54.0 million, respectively. Weighted average common shares outstanding at September 30, 2021 reflect the issuance of 920,000 common shares during the third quarter.

“The Company’s strong results through the first nine months of 2021 reflect execution of our strategic plan and regulatory initiatives, the delivery of safe, reliable, and affordable service to our customers, and our commitment to corporate sustainability,” said Thomas P. Meissner, Jr., Unitil’s Chairman and Chief Executive Officer. “In addition to strong year-to-date results, we are pleased to have recently issued our third annual Sustainability Report, highlighting the Company’s key initiatives, opportunities, and metrics related to environmental, social, and governance matters.” Unitil’s 2021 Sustainability Report may be accessed at Unitil.com.

Unitil’s Gas GAAP Gross Margin was $11.3 million and $67.7 million in the three and nine months ended September 30, 2021, respectively, increases of $0.8 million and $6.7 million compared to the same periods in 2020. The increase in the three month period was driven by higher rates and customer growth of $1.4 million, partially offset by higher depreciation and amortization expense of $0.6 million. The increase in the nine month period was driven by higher rates, customer growth and the favorable effect of colder winter weather of $8.9 million, partially offset by higher depreciation and amortization expense of $2.2 million.

Gas Adjusted Gross Margin (a non-GAAP measure¹) was $19.4 million and $92.2 million in the

¹  The accompanying section titled “Supplemental Information; Non-GAAP Financial Measures” more fully describes the non-GAAP measures used in this press release and includes a reconciliation of the non-GAAP measures to what the Company’s management believes are the most comparable GAAP measures.

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

Unitil.com

Page 2 of 8

three and nine months ended September 30, 2021, respectively, increases of $1.4 million and $8.9 million compared to the same periods in 2020. The increase in the three month period was driven by higher rates and customer growth of $1.4 million. The increase over the nine month period was driven by higher rates and customer growth of $7.5 million and $1.4 million due to the favorable effect of colder winter weather.

Gas therm sales increased 5.0% and 4.3% in the three and nine month periods ended September 30, 2021, respectively, compared to the same periods in 2020. The increase in gas therm sales reflects colder winter weather in the first quarter of 2021 compared to the same period in 2020, and customer growth. Based on weather data collected in the Company’s gas service areas, on average there were 2.1% more Effective Degree Days (EDD) in the first nine months of 2021 compared to the same period in 2020, although 6.4% fewer EDD compared to normal. The Company estimates weather-normalized gas therm sales, excluding decoupled sales, increased 2.9% in the first nine months of 2021 compared to the same period in 2020. As of September 30, 2021, the number of gas customers increased by 592 over the previous year.

Electric GAAP Gross Margin was $18.9 million and $54.0 million in the three and nine months ended September 30, 2021, respectively, increases of $0.4 million and $1.8 million compared to the same periods in 2020. The increase in the three month period was driven by higher rates and customer growth of $1.3 million, partially offset by the effect of milder summer weather of $0.4 million and higher depreciation and amortization expense of $0.5 million. The increase in the nine month period was driven by higher rates and customer growth of $3.4 million, partially offset by higher depreciation and amortization expense of $1.6 million.

Electric Adjusted Gross Margin (a non-GAAP measure¹) was $25.4 million and $73.4 million in the three and nine months ended September 30, 2021, respectively, increases of $0.9 million and $3.4 million compared with the same periods in 2020. The increase in the three month period was driven by higher rates and customer growth of $1.3 million, partially offset by $0.4 million from the effect of milder summer weather. The increase over the nine month period was driven by higher rates and customer growth of $3.4 million.

Total electric kilowatt-hour (kWh) sales increased 0.2% and 2.0%, respectively in the three and nine month periods ended September 30, 2021 compared to the same periods in 2020. Sales to Residential customers decreased 3.5% and increased 0.4%, respectively, in the three and nine

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

Unitil.com

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month periods ended September 30, 2021 compared to the same periods in 2020. Sales to C&I customers increased 3.3% and 3.2%, respectively, in the three and nine month periods ended September 30, 2021 compared to the same periods in 2020. The changes in sales to Residential customers reflects customer growth and colder winter weather, offset by the effects of milder summer weather and lower Residential electric sales as the economy continues to reopen. The increase in sales to C&I customers reflects customer growth and increased usage due to improving economic conditions. Based on weather data collected in the Company’s electric service areas, on average there were 5.4% fewer Cooling Degree Days in the first nine months of 2021 compared to the same period in 2020. As of September 30, 2021, the number of electric customers increased by 652 over the previous year.

Operation and Maintenance expenses increased $0.6 million and $2.6 million in three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020. The increase in the three month period reflects higher labor costs of $0.8 million, higher utility operating costs of $0.2 million, and lower professional fees of $0.4 million. The increase in the nine month period reflects higher utility operating costs of $1.6 million, higher labor costs of $1.2 million, and lower professional fees of $0.2 million.

Depreciation and Amortization expense increased $1.1 million and $3.8 million in the three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020. These increases primarily reflect additional depreciation associated with higher levels of utility plant in service and higher amortization.

Taxes Other Than Income Taxes increased $0.8 million and $0.6 million for the three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020. The increase in the three month period reflects higher payroll taxes and higher local property taxes on higher utility plant in service. The increase in the nine month period reflects higher local property taxes on higher utility plant in service and slightly higher payroll taxes.

Interest Expense, Net increased $0.9 million and $1.8 million, respectively, in the three and nine months ended September 30, 2021, compared to the same periods in 2020, reflecting higher interest on long-term debt, partially offset by lower rates on lower levels of short-term debt.

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

Unitil.com

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Other Expense (Income), Net decreased $0.1 million and $0.6 million, respectively for the three and nine months ended September 30, 2021 compared to the same periods in 2020, reflecting lower retirement benefit and other costs.

Federal and State Income Taxes increased $1.1 million for the nine months ended September 30, 2021, respectively, compared to the same period in 2020, reflecting higher pre-tax earnings in the current period.

At its January 2021, April 2021, July 2021 and October 2021 meetings, the Unitil Corporation Board of Directors declared quarterly dividends on the Company’s common stock of $0.38 per share. These quarterly dividends result in a current effective annualized dividend rate of $1.52 per share, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock.

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

The Company will hold a quarterly conference call to discuss third quarter 2021 results on Tuesday, November 2, 2021, at 10:00 a.m. Eastern Time. This call is being webcast. This call, financial and other statistical information contained in the Company’s presentation on this call, and information required by Regulation G regarding non-GAAP financial measures can be accessed in the Investor Relations section of Unitil’s website, Unitil.com.

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

Unitil.com

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About Unitil Corporation

Unitil Corporation provides energy for life by safely and reliably delivering natural gas and electricity in New England. We are committed to the communities we serve and to developing people, business practices, and technologies that lead to the delivery of dependable, more efficient energy. Unitil Corporation is a public utility holding company with operations in Maine, New Hampshire and Massachusetts. Together, Unitil’s operating utilities serve approximately 107,100 electric customers and 85,600 natural gas customers. Other subsidiaries include Usource, Unitil’s non-regulated business segment, which the Company divested in the first quarter or 2019. For more information about our people, technologies, and community involvement please visit Unitil.com.

Forward-Looking Statements

This press release may contain forward-looking statements. All statements, other than statements of historical fact, included in this press release are forward-looking statements. Forward-looking statements include declarations regarding Unitil’s beliefs and current expectations. These forward-looking statements are subject to the inherent risks and uncertainties in predicting future results and conditions that could cause the actual results to differ materially from those projected in these forward-looking statements. Some, but not all, of the risks and uncertainties include the following: the COVID-19 pandemic, which could adversely impact the Company’s business, including by disrupting the Company’s employees’ and contractors’ ability to provide ongoing services to the Company, by reducing customer demand for electricity or natural gas, or by reducing the supply of electricity or natural gas; Unitil’s regulatory environment (including regulations relating to climate change, greenhouse gas emissions and other environmental matters); fluctuations in the supply of, the demand for, and the prices of, energy commodities and transmission and transportation capacity and Unitil’s ability to recover energy commodity costs in its rates; customers’ preferred energy sources; severe storms and Unitil’s ability to recover storm costs in its rates; general economic conditions; variations in weather; long-term global climate change; unforeseen or changing circumstances, which could adversely affect the reduction of company-wide direct greenhouse gas emissions; Unitil’s ability to retain its existing customers and attract new customers; increased competition; and other risks detailed in Unitil’s filings with the Securities and Exchange Commission. These forward looking statements speak only as of the date they are made. Unitil undertakes no obligation, and does not intend, to update these forward-looking statements.

For more information please contact:

Todd Diggins – Investor Relations	Alec O’Meara – Media Relations
Phone: 603-773-6504	Phone: 603-773-6404
Email: diggins@unitil.com	Email: omeara@unitil.com

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

Unitil.com

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Supplemental Information; Non-GAAP Financial Measures

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

In the following tables the Company has reconciled Gas and Electric Adjusted Gross Margin to GAAP Gross Margin, which we believe to be the most comparable GAAP measure. GAAP Gross Margin is calculated as Revenue less Cost of Sales, and Depreciation and Amortization. The Company calculates Gas and Electric 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 gas and electric sales in the period.

Three Months Ended September 30, 2021 ($ millions)
	Gas			Electric			Non-Regulated and Other			Total
Total Operating Revenue	$	32.6		$	65.5		$	—		$	98.1
Less: Cost of Sales		(13.2	)		(40.1	)		—			(53.3	)
Less: Depreciation and Amortization		(8.1	)		(6.5	)		(0.2	)		(14.8	)
GAAP Gross Margin		11.3			18.9			(0.2	)		30.0
Depreciation and Amortization		8.1			6.5			0.2			14.8
Adjusted Gross Margin	$	19.4		$	25.4		$	—		$	44.8

Three Months Ended September 30, 2020 ($ millions)
	Gas			Electric			Non-Regulated and Other			Total
Total Operating Revenue	$	27.5		$	59.9		$	—		$	87.4
Less: Cost of Sales		(9.5	)		(35.4	)		—			(44.9	)
Less: Depreciation and Amortization		(7.5	)		(6.0	)		(0.2	)		(13.7	)
GAAP Gross Margin		10.5			18.5			(0.2	)		28.8
Depreciation and Amortization		7.5			6.0			0.2			13.7
Adjusted Gross Margin	$	18.0		$	24.5		$	—		$	42.5

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

Unitil.com

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Nine Months Ended September 30, 2021 ($ millions)
	Gas			Electric			Non-Regulated and Other			Total
Total Operating Revenue	$	151.3		$	182.2		$	—		$	333.5
Less: Cost of Sales		(59.1	)		(108.8	)		—			(167.9	)
Less: Depreciation and Amortization		(24.5	)		(19.4	)		(0.6	)		(44.5	)
GAAP Gross Margin		67.7			54.0			(0.6	)		121.1
Depreciation and Amortization		24.5			19.4			0.6			44.5
Adjusted Gross Margin	$	92.2		$	73.4		$	—		$	165.6

Nine Months Ended September 30, 2020 ($ millions)
	Gas			Electric			Non-Regulated and Other			Total
Total Operating Revenue	$	131.4		$	170.3		$	—		$	301.7
Less: Cost of Sales		(48.1	)		(100.3	)		—			(148.4	)
Less: Depreciation and Amortization		(22.3	)		(17.8	)		(0.6	)		(40.7	)
GAAP Gross Margin		61.0			52.2			(0.6	)		112.6
Depreciation and Amortization		22.3			17.8			0.6			40.7
Adjusted Gross Margin	$	83.3		$	70.0		$	—		$	153.3

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

Unitil.com

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Selected financial data for 2021 and 2020 is presented in the following table:

Unitil Corporation – Condensed Consolidated Financial Data

(Millions, except Per Share data)(Unaudited)

	Three Months Ended Sept. 30,								Nine Months Ended Sept. 30,
	2021			2020		Change			2021		2020		Change
Gas Therm Sales:
Residential		2.6			2.7		(3.7	%)		34.3		34.2		0.3	%
Commercial/Industrial		24.7			23.3		6.0	%		132.7		125.9		5.4	%
Total Gas Therm Sales		27.3			26.0		5.0	%		167.0		160.1		4.3	%
Electric kWh Sales:
Residential		199.7			207.0		(3.5	%)		541.4		539.4		0.4	%
Commercial/Industrial		258.7			250.4		3.3	%		714.6		692.4		3.2	%
Total Electric kWh Sales		458.4			457.4		0.2	%		1,256.0		1,231.8		2.0	%
Gas Revenues	$	32.6		$	27.5	$	5.1		$	151.3	$	131.4	$	19.9
Cost of Gas Sales		13.2			9.5		3.7			59.1		48.1		11.0
Gas Adjusted Gross Margin (a non-GAAP measure1):		19.4			18.0		1.4			92.2		83.3		8.9
Electric Revenues		65.5			59.9		5.6			182.2		170.3		11.9
Cost of Electric Sales		40.1			35.4		4.7			108.8		100.3		8.5
Electric Adjusted Gross Margin (a non-GAAP measure1):		25.4			24.5		0.9			73.4		70.0		3.4
Total Adjusted Gross Margin (a non-GAAP measure1):		44.8			42.5		2.3			165.6		153.3		12.3
Operation & Maintenance Expenses		16.7			16.1		0.6			51.2		48.6		2.6
Depreciation & Amortization		14.8			13.7		1.1			44.5		40.7		3.8
Taxes Other Than Income Taxes		6.1			5.3		0.8			18.5		17.9		0.6
Other Expense (Income), Net		1.0			1.1		(0.1	)		3.4		4.0		(0.6	)
Interest Expense, Net		6.5			5.6		0.9			19.5		17.7		1.8
Income (Loss) Before Income Taxes		(0.3	)		0.7		(1.0	)		28.5		24.4		4.1
Provision (Benefit) for Income Taxes		(0.3	)		0.4		(0.7	)		6.9		5.8		1.1
Net Income	$	—		$	0.3	$	(0.3	)	$	21.6	$	18.6	$	3.0
Earnings Per Share	$	—		$	0.02	$	(0.02	)	$	1.42	$	1.25	$	0.17

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

Unitil.com

XML

Cover Page - shares	9 Months Ended
	Sep. 30, 2021	Oct. 29, 2021
Document Information [Line Items]
Entity Interactive Data Current	Yes
Document Type	10-Q
Document Quarterly Report	true
Document Transition Report	false
Amendment Flag	false
Document Period End Date	Sep. 30, 2021
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q3
Entity Registrant Name	UNITIL CORPORATION
Entity Central Index Key	0000755001
Entity File Number	1-8858
Entity Tax Identification Number	02-0381573
Entity Incorporation, State or Country Code	NH
Current Fiscal Year End Date	--12-31
Entity Shell Company	false
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Current Reporting Status	Yes
Entity Emerging Growth Company	false
Entity Address, Address Line One	6 Liberty Lane West
Entity Address, City or Town	Hampton
Entity Address, Postal Zip Code	03842-1720
Entity Address, State or Province	NH
City Area Code	603
Local Phone Number	772-0775
Trading Symbol	UTL
Security Exchange Name	NYSE
Entity Common Stock, Shares Outstanding		15,973,019
Title of 12(b) Security	Common Stock

XML

CONSOLIDATED STATEMENTS OF EARNINGS - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Operating Revenues
Total Operating Revenues	$ 98.1	$ 87.4	$ 333.5	$ 301.7
Operating Expenses
Operation and Maintenance	16.7	16.1	51.2	48.6
Depreciation and Amortization	14.8	13.7	44.5	40.7
Taxes Other Than Income Taxes	6.1	5.3	18.5	17.9
Total Operating Expenses	90.9	80.0	282.1	255.6
Operating Income	7.2	7.4	51.4	46.1
Interest Expense, Net	6.5	5.6	19.5	17.7
Other Expense (Income), Net	1.0	1.1	3.4	4.0
Income (Loss) Before Income Taxes	(0.3)	0.7	28.5	24.4
Provision (Benefit) for Income Taxes	(0.3)	0.4	6.9	5.8
Net Income	$ 0.0	$ 0.3	$ 21.6	$ 18.6
Net Income Per Common Share (Basic and Diluted)	$ 0	$ 0.02	$ 1.42	$ 1.25
Weighted Average Common Shares Outstanding – (Basic and Diluted)	15.5	14.9	15.2	14.9
Gas
Operating Revenues
Total Operating Revenues	$ 32.6	$ 27.5	$ 151.3	$ 131.4
Operating Expenses
Total Operating Expenses	13.2	9.5	59.1	48.1
Electric
Operating Revenues
Total Operating Revenues	65.5	59.9	182.2	170.3
Operating Expenses
Total Operating Expenses	$ 40.1	$ 35.4	$ 108.8	$ 100.3

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020
Current Assets:
Cash and Cash Equivalents	$ 8.8	$ 6.0	$ 8.2
Accounts Receivable, Net	46.3	62.0	48.6
Accrued Revenue	38.6	50.9	39.1
Exchange Gas Receivable	10.5	4.9	6.5
Gas Inventory	0.9	0.6	0.6
Materials and Supplies	8.6	8.5	8.5
Prepayments and Other	7.3	6.4	5.8
Total Current Assets	121.0	139.3	117.3
Utility Plant:
Gas	932.8	920.2	876.8
Electric	581.0	575.9	545.9
Common	64.8	64.1	63.3
Construction Work in Progress	84.8	34.8	101.0
Utility Plant	1,663.4	1,595.0	1,587.0
Less: Accumulated Depreciation	426.1	401.8	401.7
Net Utility Plant	1,237.3	1,193.2	1,185.3
Other Noncurrent Assets:
Regulatory Assets	132.4	127.4	104.4
Operating Lease Right of Use Assets	5.1	5.2	5.6
Other Assets	13.2	12.8	11.3
Total Other Noncurrent Assets	150.7	145.4	121.3
TOTAL ASSETS	1,509.0	1,477.9	1,423.9
Current Liabilities:
Accounts Payable	29.5	33.2	25.1
Short-Term Debt	30.5	54.7	17.3
Long-Term Debt, Current Portion	10.1	8.5	6.3
Regulatory Liabilities	13.1	5.5	10.6
Energy Supply Obligations	16.1	10.4	12.1
Interest Payable	6.7	5.0	7.2
Environmental Obligations	0.7	0.3	0.3
Other Current Liabilities	19.9	18.5	19.3
Total Current Liabilities	126.6	136.1	98.2
Noncurrent Liabilities:
Retirement Benefit Obligations	166.2	162.3	145.0
Deferred Income Taxes, net	115.7	109.0	109.4
Cost of Removal Obligations	108.2	105.2	107.1
Regulatory Liabilities	42.9	44.3	44.7
Environmental Obligations	1.7	1.8	1.9
Other Noncurrent Liabilities	6.8	6.9	7.8
Total Noncurrent Liabilities	441.5	429.5	415.9
Capitalization:
Long-Term Debt, Less Current Portion	501.3	523.1	529.0
Stockholders' Equity:
Common Equity (Authorized: 25,000,000 and Outstanding: 15,971,962, 15,005,881 and 15,012,310 Shares)	331.6	285.3	284.8
Retained Earnings	107.8	103.7	95.8
Total Common Stock Equity	439.4	389.0	380.6
Preferred Stock	0.2	0.2	0.2
Total Stockholders' Equity	439.6	389.2	380.8
Total Capitalization	940.9	912.3	909.8
Commitments and Contingencies (Notes 6 & 7)
TOTAL LIABILITIES AND CAPITALIZATION	$ 1,509.0	$ 1,477.9	$ 1,423.9

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020
Statement of Financial Position [Abstract]
Common Stock Authorized	25,000,000	25,000,000	25,000,000
Common Equity Outstanding	15,971,962	15,012,310	15,005,881

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
Operating Activities:
Net Income	$ 21.6	$ 18.6
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	44.5	40.7
Deferred Tax Provision	5.5	3.0
Changes in Working Capital Items:
Accounts Receivable	15.7	6.5
Accrued Revenue	12.3	10.9
Exchange Gas Receivable	(5.6)	(0.4)
Regulatory Liabilities	7.6	3.2
Accounts Payable	(3.7)	(12.5)
Other Changes in Working Capital Items	2.7	0.9
Deferred Regulatory and Other Charges	(8.0)	5.3
Other, net	3.3	(1.3)
Cash Provided by Operating Activities	95.9	74.9
Investing Activities:
Property, Plant and Equipment Additions	(81.5)	(93.6)
Cash (Used in) Investing Activities	(81.5)	(93.6)
Financing Activities:
Repayment of Short-Term Debt, net	(24.2)	(41.3)
Repayment of Long-Term Debt	(20.3)	(15.9)
Issuance of Long-Term Debt		95.0
Long-Term Debt Issuance Costs		(0.5)
Net Increase in Exchange Gas Financing	5.2	0.5
Decrease in Capital Lease Obligations	(0.1)
Dividends Paid	(17.5)	(16.9)
Proceeds from Issuance of Common Stock	45.3	0.8
Cash (Used in) Provided by Financing Activities	(11.6)	21.7
Net Increase in Cash and Cash Equivalents	2.8	3.0
Cash and Cash Equivalents at Beginning of Period	6.0	5.2
Cash and Cash Equivalents at End of Period	8.8	8.2
Supplemental Cash Flow Information:
Interest Paid	17.9	15.3
Income Taxes Paid	1.4	0.8
Payments on Capital Leases	0.2	0.2
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	4.2	0.6
Right-of-Use Assets Obtained in Exchange for Lease Obligations	$ 0.9	$ 1.6

XML

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY - USD ($) $ in Millions	Total	Common Equity	Retained Earnings
Beginning Balance at Dec. 31, 2019	$ 376.6	$ 282.5	$ 94.1
Net Income	18.6		18.6
Dividends on Common Shares	(16.9)		(16.9)
Stock Compensation Plans	1.5	1.5
Issuance of Common Shares	0.8	0.8
Ending Balance at Sep. 30, 2020	380.6	284.8	95.8
Beginning Balance at Jun. 30, 2020	385.5	284.4	101.1
Net Income	0.3		0.3
Dividends on Common Shares	(5.6)		(5.6)
Stock Compensation Plans	0.1	0.1
Issuance of Common Shares	0.3	0.3
Ending Balance at Sep. 30, 2020	380.6	284.8	95.8
Beginning Balance at Dec. 31, 2020	389.0	285.3	103.7
Net Income	21.6		21.6
Dividends on Common Shares	(17.5)		(17.5)
Stock Compensation Plans	1.0	1.0
Issuance of Common Shares	45.3	45.3
Ending Balance at Sep. 30, 2021	439.4	331.6	107.8
Beginning Balance at Jun. 30, 2021	400.6	286.8	113.8
Net Income	0.0
Dividends on Common Shares	(6.0)		(6.0)
Stock Compensation Plans	0.1	0.1
Issuance of Common Shares	44.7	44.7
Ending Balance at Sep. 30, 2021	$ 439.4	$ 331.6	$ 107.8

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CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Parenthetical) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Equity [Abstract]
Dividends per Common Share	$ 0.38	$ 0.375	$ 1.14	$ 1.125
Common stock, shares issued	925,493	6,650	936,512	16,849

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2021

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations - Unitil Corporation (Unitil or the Company) is a public utility holding company 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. The following companies are wholly-owned subsidiaries of Unitil: Unitil Energy Systems, Inc. (Unitil Energy), Fitchburg Gas and Electric Light Company (Fitchburg), Northern Utilities, Inc. (Northern Utilities), Granite State Gas Transmission, Inc. (Granite State), Unitil Power Corp. (Unitil Power), Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) and its non-regulated business unit Unitil Resources, Inc. (Unitil Resources).

The Company’s earnings are seasonal and are 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 in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire; Fitchburg, which operates in Massachusetts; and Northern Utilities, which operates in New Hampshire and Maine (collectively referred to as the “distribution utilities”).

Granite State is an interstate gas transmission pipeline company, operating 86 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 the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.

A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, on May 1, 2003 Unitil Power ceased being the wholesale supplier of Unitil Energy and divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers. In the period since, Unitil Power continued to flow revenues and expenses from remaining contracts to Unitil Energy under the Amended Unitil System Agreement. The last of those contracts expired October 31, 2020, and the Company no longer has material revenues or expenses associated with them.

Unitil also has three other wholly-owned subsidiaries: Unitil Service, Unitil Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary.

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 all of 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 nine months ended September 30, 2021 are not necessarily indicative of results to be expected for the year ending December 31, 2021. For further information, please 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, 2020, as filed with the Securities and Exchange Commission (SEC) on February 2, 2021, for a description of the Company’s Basis of Presentation.

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

Revenue is recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of 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 September 30, 2021
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	7.9		$	35.0		$	42.9
C&I		14.4			26.8			41.2
Other		0.8			3.2			4.0
Total Billed and Unbilled Revenue		23.1			65.0			88.1
Rate Adjustment Mechanism Revenue		9.5			0.5			10.0
Total Gas and Electric Operating Revenues	$	32.6		$	65.5		$	98.1
	Three Months Ended September 30, 2020
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	7.0		$	35.3		$	42.3
C&I		11.6			24.1			35.7
Other		1.4			1.4			2.8
Total Billed and Unbilled Revenue		20.0			60.8			80.8
Rate Adjustment Mechanism Revenue		7.5			(0.9	)		6.6
Total Gas and Electric Operating Revenues	$	27.5		$	59.9		$	87.4
	Nine Months Ended September 30, 2021
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	60.5		$	104.0		$	164.5
C&I		86.2			78.2			164.4
Other		7.6			6.9			14.5
Total Billed and Unbilled Revenue		154.3			189.1			343.4
Rate Adjustment Mechanism Revenue		(3.0	)		(6.9	)		(9.9	)
Total Gas and Electric Operating Revenues	$	151.3		$	182.2		$	333.5
	Nine Months Ended September 30, 2020
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	52.4		$	99.9		$	152.3
C&I		72.9			68.7			141.6
Other		5.6			4.9			10.5
Total Billed and Unbilled Revenue		130.9			173.5			304.4
Rate Adjustment Mechanism Revenue		0.5			(3.2	)		(2.7	)
Total Gas and Electric Operating Revenues	$	131.4		$	170.3		$	301.7

Fitchburg is subject to revenue decoupling. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or gas sales. The difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recorded 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 that the Company files with the MDPU.

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 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 include 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 September 30, 2021, September 30, 2020 and December 31, 2020, the Unitil subsidiaries had deposited $5.7 million, $4.7 million and $2.4 million, respectively to satisfy their ISO-NE obligations.

Financial Instruments - In June 2016, the Financial Accounting Standards Board issued ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326)”, which provides a new model for recognizing credit losses on financial instruments based on an estimate of current expected credit losses. Under the new guidance, immediate recognition of all credit losses expected over the life of a financial instrument is required. The Company adopted this standard on the accounting for credit losses on its financial instruments, including accounts receivable, on January 1, 2020, and it did not have a material effect on the financial statements.

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

The Allowance for Doubtful Accounts as of September 30, 2021, September 30, 2020 and December 31, 2020, was as follows:

($ millions)
	September 30,				December 31,
	2021		2020		2020
Allowance for Doubtful Accounts	$	4.3	$	1.6	$	3.3

Accounts Receivable, Net includes $4.2 million, $1.5 million, and $3.1 million of the Allowance for Doubtful Accounts at September 30, 2021, September 30, 2020 and December 31, 2020, respectively. Unbilled Revenues, net (a component of Accrued Revenue, shown in the table below) includes $0.1 million, $0.1 million and $0.2 million of the Allowance for Doubtful Accounts at September 30, 2021, September 30, 2020 and December 31, 2020, 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 September 30, 2021, September 30, 2020 and December 31, 2020.

	September 30,				December 31,
Accrued Revenue ($ millions)	2021		2020		2020
Regulatory Assets – Current	$	30.6	$	31.7	$	37.3
Unbilled Revenues		8.0		7.4		13.6
Total Accrued Revenue	$	38.6	$	39.1	$	50.9

Exchange Gas Receivable - Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers natural gas back to the Company during the months of November through March. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of September 30, 2021, September 30, 2020 and December 31, 2020.

	September 30,				December 31,
Exchange Gas Receivable ($ millions)	2021		2020		2020
Northern Utilities	$	9.7	$	6.0	$	4.4
Fitchburg		0.8		0.5		0.5
Total Exchange Gas Receivable	$	10.5	$	6.5	$	4.9

Gas Inventory - The Company uses the weighted average cost methodology to value natural gas inventory. The following table shows the components of Gas Inventory as of September 30, 2021, September 30, 2020 and December 31, 2020.

	September 30,				December 31,
Gas Inventory ($ millions)	2021		2020		2020
Natural Gas	$	0.4	$	0.2	$	0.2
Propane		0.4		0.3		0.3
Liquefied Natural Gas & Other		0.1		0.1		0.1
Total Gas Inventory	$	0.9	$	0.6	$	0.6

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 September 30, 2021, September 30, 2020 and December 31, 2020, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $108.2 million, $107.1 million, and $105.2 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).

Regulatory Accounting - The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the Massachusetts Department of Public Utilities (MDPU), Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC) and Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the FASB Codification. The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission. The electric and gas divisions of Fitchburg are authorized to recover through rates past due amounts associated with hardship accounts that are protected from shut-off. As of September 30, 2021, September 30, 2020 and December 31, 2020, the Company has recorded $9.5 million, $7.1 million and $6.8 million, respectively, of hardship accounts in Regulatory Assets. These amounts are included in “Other Deferred Charges” in the table below. The Company currently receives recovery in rates or expects to receive recovery of these hardship accounts in future rate cases.

	September 30,				December 31,
Regulatory Assets consist of the following ($ millions)	2021		2020		2020
Retirement Benefits	$	107.0	$	81.0	$	103.7
Energy Supply & Other Rate Adjustment Mechanisms		27.3		28.9		34.1
Deferred Storm Charges		3.4		4.4		4.1
Environmental		4.8		6.1		5.2
Income Taxes		2.8		3.6		3.4
Other Deferred Charges		17.7		12.1		14.2
Total Regulatory Assets	$	163.0	$	136.1	$	164.7
Less: Current Portion of Regulatory Assets(1)		30.6		31.7		37.3
Regulatory Assets – noncurrent	$	132.4	$	104.4	$	127.4

(1) Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets.

	September 30,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2021		2020		2020
Income Taxes (Note 8)	$	44.6	$	45.8	$	45.5
Rate Adjustment Mechanisms		11.3		9.2		4.1
Other		0.1		0.3		0.2
Total Regulatory Liabilities	$	56.0	$	55.3	$	49.8
Less: Current Portion of Regulatory Liabilities		13.1		10.6		5.5
Regulatory Liabilities - noncurrent	$	42.9	$	44.7	$	44.3

Generally, the Company receives a return on investment on its regulatory assets for which a cash outflow has been made. Regulatory Assets at September 30, 2021 include $8.5 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 accounting rules for regulated operations, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

Derivatives - The Company’s regulated energy subsidiaries enter into energy supply contracts to serve their electric and gas customers. The Company follows a procedure for determining whether each contract qualifies as a derivative instrument under the guidance provided by the FASB Codification on Derivatives and Hedging. For each contract, the Company reviews and documents the key terms of the contract. Based on those terms and any additional relevant components of the contract, the Company 

determines and documents whether the contract qualifies as a derivative instrument as defined in the FASB Codification. The Company has determined that its energy supply contracts either do not qualify as a derivative instrument under the guidance set forth in the FASB Codification, have been elected as 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). Until these contingencies are satisfied, these contracts will not qualify for derivative accounting. The Company believes that the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg.

Investments in Marketable Securities - The Company has a trust through which it invests in a money market fund. These investments are intended to satisfy obligations under the Company’s Supplemental Executive Retirement Plan (SERP) (See further discussion of the SERP in Note 9.)

At September 30, 2021, September 30, 2020 and December 31, 2020, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $5.6 million, $5.7 million and $5.7 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.

	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2021		2020		2020
Money Market Fund	$	5.6	$	5.7	$	5.7
Total Marketable Securities	$	5.6	$	5.7	$	5.7

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

At September 30, 2021, September 30, 2020 and December 31, 2020, 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 $0.5 million, $0.5 million and $0.5 million, respectively, as shown in the following table. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other Expense, Net.

	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2021		2020		2020
Equity Funds	$	0.1	$	0.2	$	0.2
Money Market Funds		0.4		0.3		0.3
Total Marketable Securities	$	0.5	$	0.5	$	0.5

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

	September 30,				December 31,
Energy Supply Obligations ($ millions)	2021		2020		2020
Exchange Gas Obligation	$	9.7	$	6.0	$	4.4
Renewable Energy Portfolio Standards		6.4		5.8		5.7
Power Supply Contract Divestitures		—		0.3		0.3
Total Energy Supply Obligations	$	16.1	$	12.1	$	10.4

Exchange Gas Obligation - Northern Utilities enters into gas exchange agreements under which Northern Utilities releases certain gas pipeline and storage assets, resells the gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the gas heating season at the same price at which it 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 in Accrued Revenue with a corresponding liability in Energy Supply Obligations on the Company’s Consolidated Balance Sheets.

Fitchburg has entered into long-term renewable contracts for the purchase of clean energy and/or RECs pursuant to Massachusetts legislation, specifically, An Act Relative to Green Communities (Green Communities Act, 2008), An Act Relative to Competitively Priced Electricity in the Commonwealth (2012) and An Act to Promote Energy Diversity (Energy Diversity Act, 2016). The generating facilities associated with eight of these contracts have been constructed and are now operating. Two additional contracts are scheduled to become commercial in 2021. In 2020, three of the long-term contracts were terminated due to an inability to meet critical milestones. In 2018, the Company filed two long-term contracts with the MDPU, one for offshore wind generation and another for imported hydroelectric power and associated transmission. Those contracts were approved in 2019. In 2019, the Company participated in an additional statewide procurement for offshore wind generation and the resulting contracts were filed with the MDPU during the first quarter of 2020. An Order approving the contracts was issued by the MDPU in November 2020. On November 25, 2020 the Office of the Attorney General filed a Motion for Reconsideration of the MDPU’s order regarding remuneration, which was denied. The MDPU order is now final. In compliance with An Act to Promote a Clean Energy Future (2018), in late 2020 in coordination with the other electric utilities in Massachusetts, the Company began efforts on the next long-term renewable procurement which will seek up to an additional 1,600 megawatts (MW) of offshore wind generation. Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

Power Supply Contract Divestitures - Unitil Energy’s and Fitchburg’s customers are entitled to purchase their electric or gas supplies from third-party suppliers. In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil

Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs. As of September 30, 2021, Fitchburg has fully recovered its power supply-related stranded costs and Unitil Energy has less than $0.1 million remaining to recover. The obligations related to these divestitures are recorded in Energy Supply Obligations on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue.

Subsequent Events - The Company evaluates all events or transactions through the date of the related filing. During the period subsequent to the balance sheet date and through the date of this filing, the Company did not have any material subsequent events that would result in adjustment to or disclosure in its Consolidated Financial Statements.

XML

DIVIDENDS DECLARED PER SHARE

9 Months Ended

Sep. 30, 2021

DIVIDENDS DECLARED PER SHARE [Abstract]

DIVIDENDS DECLARED PER SHARE

NOTE 2 – DIVIDENDS DECLARED PER SHARE

Declaration  Date	Date Paid (Payable)	Shareholder of Record Date	Dividend Amount
10/27/21	11/29/21	11/15/21	$ 0.380
07/28/21	08/27/21	08/13/21	$ 0.380
04/28/21	05/28/21	05/14/21	$ 0.380
01/27/21	02/26/21	02/12/21	$ 0.380
10/28/20	11/30/20	11/16/20	$ 0.375
07/29/20	08/28/20	08/14/20	$ 0.375
04/29/20	05/29/20	05/15/20	$ 0.375
01/29/20	02/28/20	02/14/20	$ 0.375

XML

SEGMENT INFORMATION

9 Months Ended

Sep. 30, 2021

Segment Information

NOTE 3 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three and nine months ended September 30, 2021 and September 30, 2020:

	Gas			Electric			Non- Regulated		Other			Total
Three Months Ended Sept. 30, 2021 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	23.1		$	65.0		$	—	$	—		$	88.1
Rate Adjustment Mechanism Revenue		9.5			0.5			—		—			10.0
Other Operating Revenue – Non-Regulated		—			—			—		—			—
Total Operating Revenues	$	32.6		$	65.5		$	—	$	—		$	98.1
Segment Profit (Loss)		(4.1	)		4.4			—		(0.3	)		—
Capital Expenditures		28.5			10.1			—		0.4			39.0
Three Months Ended Sept. 30, 2020 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	20.0		$	60.8		$	—	$	—		$	80.8
Rate Adjustment Mechanism Revenue		7.5			(0.9	)		—		—			6.6
Other Operating Revenue – Non-Regulated		—			—			—		—			—
Total Operating Revenues	$	27.5		$	59.9		$	—	$	—		$	87.4
Segment Profit (Loss)		(3.6	)		4.4			—		(0.5	)		0.3
Capital Expenditures		27.4			16.0			—		1.4			44.8
Nine Months Ended Sept. 30, 2021 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	154.3		$	189.1		$	—	$	—		$	343.4
Rate Adjustment Mechanism Revenue		(3.0	)		(6.9	)		—		—			(9.9	)
Other Operating Revenue – Non-Regulated		—			—			—		—			—
Total Operating Revenues	$	151.3		$	182.2		$	—	$	—		$	333.5
Segment Profit (Loss)		12.1			10.7			0.1		(1.3	)		21.6
Capital Expenditures		51.7			28.8			—		1.0			81.5
Segment Assets		906.2			583.6			—		19.2			1,509.0
Nine Months Ended Sept. 30, 2020 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	130.9		$	173.5		$	—	$	—		$	304.4
Rate Adjustment Mechanism Revenue		0.5			(3.2	)		—		—			(2.7	)
Other Operating Revenue – Non-Regulated		—			—			—		—			—
Total Operating Revenues	$	131.4		$	170.3		$	—	$	—		$	301.7
Segment Profit		8.6			10.1			—		(0.1	)		18.6
Capital Expenditures		50.0			39.9			—		3.7			93.6
Segment Assets		845.0			556.3			—		22.6			1,423.9

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DEBT AND FINANCING ARRANGEMENTS

9 Months Ended

Sep. 30, 2021

Debt And Financing Arrangements

NOTE 4 –DEBT AND FINANCING ARRANGEMENTS

Details on long-term debt at September 30, 2021, September 30, 2020 and December 31, 2020 are shown below:

($ millions)	September 30,				December 31,
	2021		2020		2020
Unitil Corporation:
6.33% Senior Notes, Due May 1, 2022	$	—	$	20.0	$	15.0
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
Unitil Energy First Mortgage Bonds:
8.49% Senior Secured Notes, Due October 14, 2024		3.0		4.5		3.0
6.96% Senior Secured Notes, Due September 1, 2028		14.0		16.0		16.0
8.00% Senior Secured Notes, Due May 1, 2031		15.0		15.0		15.0
6.32% Senior Secured Notes, Due September 15, 2036		15.0		15.0		15.0
3.58% Senior Secured Notes, Due September 15, 2040		27.5		27.5		27.5
4.18% Senior Secured Notes, Due November 30, 2048		30.0		30.0		30.0
Fitchburg:
6.75% Senior Notes, Due November 30, 2023		—		3.8		1.9
6.79% Senior Notes, Due October 15, 2025		10.0		10.0		10.0
3.52% Senior Notes, Due November 1, 2027		10.0		10.0		10.0
7.37% Senior Notes, Due January 15, 2029		9.6		10.8		10.8
5.90% Senior Notes, Due December 15, 2030		15.0		15.0		15.0
7.98% Senior Notes, Due June 1, 2031		14.0		14.0		14.0
3.78% Senior Notes, Due September 15, 2040		27.5		27.5		27.5
4.32% Senior Notes, Due November 1, 2047		15.0		15.0		15.0
Northern Utilities:
3.52% Senior Notes, Due November 1, 2027		20.0		20.0		20.0
7.72% Senior Notes, Due December 3, 2038		50.0		50.0		50.0
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
Unitil Realty Corp.:
2.64% Senior Secured Notes, Due December 18, 2030		4.5		—		4.7
Total Long-Term Debt		515.1		539.1		535.4
Less: Unamortized Debt Issuance Costs		3.7		3.8		3.8
Total Long-Term Debt, net of Unamortized Debt Issuance Costs		511.4		535.3		531.6
Less: Current Portion		10.1		6.3		8.5
Total Long-term Debt, Less Current Portion	$	501.3	$	529.0	$	523.1

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

($ millions)	September 30,				December 31,
	2021		2020		2020
Estimated Fair Value of Long-Term Debt	$	598.2	$	631.7	$	633.1

On July 25, 2018, the Company entered into a Second Amended and Restated Credit Agreement and related documents (collectively, the Credit Facility) with a syndicate of lenders, which amended and restated in its entirety the Company’s prior credit facility. The Credit Facility extends to
July 25, 2023, subject to two one-year extensions under certain circumstances, and has a borrowing limit of $120 million, which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides the Company with the ability to elect that borrowings under the Credit Facility bear interest under several options, including at a daily fluctuating rate of interest per annum equal to one-month London Interbank Offered Rate plus 1.125%. The Company may increase the borrowing limit under the Credit Facility by up to $50 million under certain circumstances.

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $170.7 million for the nine months ended September 30, 2021. Total gross repayments were $194.9 million for the nine months ended September 30, 2021. The following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of September 30 2021, September 30, 2020 and December 31, 2020:

	Revolving Credit Facility ($ millions)
	September 30,				December 31,
	2021		2020		2020
Limit	$	120.0	$	120.0	$	120.0
Short-Term Borrowings Outstanding		30.5		17.3		54.7
Letter of Credit Outstanding		—		0.1		0.1
Available	$	89.5	$	102.6	$	65.2

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, the Company’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on the Company’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility apply until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At September 30, 2021, September 30, 2020 and December 31, 2020, the Company was in compliance with the covenants contained in the Credit Facility in effect on those dates.

The average interest rates on all short-term borrowings and intercompany money pool transactions were 1.2% and 1.3% for the three months ended September 30, 2021 and September 30, 2020, respectively. The average interest rates on all short-term borrowings and intercompany money pool transactions were 1.2% and 1.8% for the nine months ended September 30, 2021 and September 30, 2020, respectively. The average interest rate on all short-term borrowings for the twelve months ended December 31, 2020 was 1.7%.

On December 18, 2020, Unitil Realty Corp. entered into a loan agreement in the amount of $4.7 million at 2.64%, with a maturity date of December 18, 2030. Less than $0.1 million of costs associated with this loan have been recorded as a reduction to the proceeds. Unitil Realty Corp. used the net proceeds from this loan for general corporate purposes.

On September 15, 2020, Northern Utilities issued $40 million of Notes due 2040 at 3.78%. Fitchburg issued $27.5 million of Notes due 2040 at 3.78%. Unitil Energy issued $27.5 million of Bonds due 2040 at 3.58%. Northern Utilities, Fitchburg and Unitil Energy used the net proceeds from these offerings to repay short-term debt and for general corporate purposes. Approximately $0.5 million of costs associated with these issuances have been recorded as a reduction to Long-Term Debt on the Consolidated Balance Sheets.

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

Northern Utilities enters into asset management agreements under which Northern Utilities releases certain gas pipeline and storage assets, resells to an asset manager and subsequently repurchases the gas over the course of the gas heating season at the same price at which it sold the gas to the asset manager. There was $9.7 million, $6.0 million and $5.4 million of gas obligations at September 30, 2021, September 30, 2020 and December 31, 2020, respectively, related to these asset management agreements. The amount of gas released in September 2021 and payable in October 2021 is $0.1 million and is recorded in Accounts Payable at September 30, 2021. The amount of gas released in September 2020 and payable in October 2020 was less than $0.1 million and was recorded in Accounts Payable at September 30, 2020. The amount of gas released in December 2020 and payable in January 2021 was $1.0 million and was recorded in Accounts Payable at December 31, 2020.

Guarantees

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 September 30, 2021, there were approximately $0.7 million of guarantees outstanding with a duration less than one year.

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 September 30, 2021 and 2020 amounted to $0.5 million and $0.5 million, respectively. Total rental expense under operating leases charged to operations for the nine months ended September 30, 2021 and 2020 amounted to $1.4 million and $1.4 million, respectively.

	September 30,				December 31,
Lease Obligations ($ millions)	2021		2020		2020
Operating Lease Obligations:
Other Current Liabilities (current portion)	$	1.6	$	1.6	$	1.5
Other Noncurrent Liabilities (long-term portion)		3.5		4.0		3.7
Total Operating Lease Obligations	$	5.1	$	5.6	$	5.2
Capital Lease Obligations:
Other Current Liabilities (current portion)	$	0.2	$	0.2	$	0.2
Other Noncurrent Liabilities (long-term portion)		0.2		0.3		0.2
Total Capital Lease Obligations	$	0.4	$	0.5	$	0.4
Total Lease Obligations	$	5.5	$	6.1	$	5.6

Cash paid for amounts included in the measurement of operating lease obligations for the nine months ended September 30, 2021 and September 30, 2020 was $1.4 million and $1.4 million and was included in Cash Provided by Operating Activities on the Consolidated Statements of Cash Flows.

Assets under capital leases amounted to approximately $0.7 million, $1.1 million and $1.0 million as of September 30, 2021, September 30, 2020 and December 31, 2020, respectively, less accumulated amortization of $0.3 million, $0.6 million and $0.5 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 September 30, 2021. The payments for operating leases consist of $1.6 million of current operating lease obligations, which are included in Other Current Liabilities and $3.5 million of noncurrent operating lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of September 30, 2021. The payments for capital leases consist of $0.2 million of current capital lease obligations, which are included in Other Current Liabilities and $0.2 million of noncurrent capital lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of September 30, 2021.

Lease Payments ($000’s) Year Ending December 31,	Operating Leases		Capital Leases
Rest of 2021	$	479	$	39
2022		1,695		150
2023		1,399		107
2024		1,069		52
2025		503		20
2026-2030		320		—
Total Payments		5,465		368
Less: Interest		365		15
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$	5,100	$	353

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 September 30, 2021, the weighted average remaining lease term is 3.7 years and the weighted average operating discount rate used to determine the operating lease obligations was 4.0%. As of September 30, 2020, the weighted average remaining lease term was 4.0 years and the weighted average operating discount rate used to determine the operating lease obligations was 4.4%.

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

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COMMON STOCK AND PREFERRED STOCK

9 Months Ended

Sep. 30, 2021

COMMON STOCK AND PREFERRED STOCK

NOTE 5 – COMMON STOCK AND PREFERRED STOCK

Common Stock

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

The Company had 15,971,962, 15,005,881 and 15,012,310 shares of common stock outstanding at September 30, 2021, September 30, 2020 and December 31, 2020, respectively.

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

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

Dividend Reinvestment and Stock Purchase Plan - During the first nine months of 2021, the Company sold 16,512 shares of its common stock, at an average price of $48.52 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $801,200. 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 awards of restricted shares (Restricted Shares), or of restricted stock units (Restricted Stock Units). The Compensation Committee has the authority to determine the sizes of awards; determine the terms and conditions of awards in a manner consistent with the Stock Plan; construe and interpret the Stock Plan and any agreement or instrument entered into under the Stock Plan as they apply to participants; establish, amend, or waive rules and regulations for the Stock Plan’s administration as they apply to participants; and, subject to the provisions of the Stock Plan, amend the terms and conditions of any outstanding award to the extent such terms and conditions are within the discretion of the Compensation Committee as provided for in the Stock Plan. On April 19, 2012, the Company’s shareholders approved an amendment to the Stock Plan to, among other things, increase the maximum number of shares of common stock available for awards to plan participants.

The maximum number of shares available for awards to participants under the Stock Plan is 677,500. The maximum number of shares that may be awarded in any one calendar year to any one participant is 20,000. In the event of any change 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.

Restricted Shares

Outstanding awards of Restricted Shares fully vest over a period of four years at a rate of 25% each year. During the vesting period, dividends on 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. For purposes of compensation expense, Restricted Shares vest immediately upon a participant becoming eligible for retirement, as defined in the Stock Plan. Prior to the end of the vesting period, the restricted shares are subject to forfeiture if the participant ceases to be employed by the Company other than due to the participant’s death.

On January 26, 2021, 23,140 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of approximately $0.9 million. There were 57,408 and 59,813 non-vested shares under the Stock Plan as of September 30, 2021 and 2020, respectively. The weighted average grant date fair value of these shares was $49.61 and $54.41, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $1.4 million and $2.1 million for the nine months ended September 30, 2021 and 2020, respectively. At September 30, 2021, there was approximately $0.7 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.7 years. During the nine months ended September 30, 2021 there were zero restricted shares forfeited and zero restricted shares cancelled under the Stock Plan.

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 portion of Restricted Stock Units activity during the nine months ended September 30, 2021 in conjunction with the Stock Plan is presented in the following table:

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REGULATORY MATTERS

9 Months Ended

Sep. 30, 2021

REGULATORY MATTERS

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, 2020 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 2, 2021.

Tax Cuts and Jobs Act of 2017

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (TCJA) was signed into law. Among other things, the TCJA substantially reduced the corporate income tax rate to 21%, effective January 1, 2018. Each state public utility commission, with jurisdiction over the areas that are served by Unitil’s electric and gas subsidiary companies, issued orders directing how the tax law changes were to be reflected in rates. Unitil has complied with these orders and has made the required changes to its rates as directed by the commissions. The FERC issued a Notice of Proposed Rulemaking that would allow it to determine which pipelines under the Natural Gas Act may be collecting unjust and unreasonable rates in light of the corporate tax reduction. This matter was resolved for Granite State in its May 2, 2018 uncontested rate settlement filing, which accounted for the effect of the TCJA.

On November 21, 2019, the FERC issued Order No. 864, a final rule on Public Utility Transmission Rate Changes to Address Accumulated Deferred Income Taxes. The new rule requires public utilities with formula transmission rates to revise their formula rates to include a transparent methodology to address the TCJA and future tax law changes on customer rates by accounting for “excess” or “deficient” Accumulated Deferred Income Taxes (ADIT). FERC also required transmission providers with stated rates to account for TCJA’s effect on ADIT in their next rate case. The Company is complying with the new rule and there is no material effect on its financial position, operating results, or cash flows.

Rate Case Activity

Northern Utilities - Base Rates - Maine - On March 26, 2020, the MPUC approved an increase to base revenue of $3.6 million, a 3.6% increase over the Company’s test year operating revenues, effective April 1, 2020. The order approved a Return on Equity of 9.48%, and a hypothetical capital structure of 50% equity and 50% debt. As part of the order and increase in base revenue, the MPUC provided for recovery of some, but not all, of the Company’s implementation costs associated with its customer information system pending the completion of an investigation, including a third-party audit. On March 9, 2021, the MPUC opened a new docket to investigate the amount of customer information system costs that will be allowed in rates and released the third-party audit report. The audit report findings included highlighting the Company’s effective implementation efforts while also suggesting potential excess costs of approximately $5.0 million out of the total cost of $36.8 million. The total cost for the customer information system is allocated across all of Unitil’s distribution utility subsidiary companies. The Company disagrees with many of the characterizations of findings contained in the audit report, as well as many of the report’s opinions and conclusions concerning those findings. On June 30, 2021, the Company filed testimony and exhibits with the MPUC rebutting the assertions made in the audit. The Company continues to believe that the customer information system costs were prudently incurred and continues to pursue recovery of the customer information system costs in rates. The Company believes that the ultimate outcome of the investigation will not have a material effect on its financial position, operating results or cash flows.

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 $1.1 million for 2020 eligible facilities, was approved by the MPUC effective May 1, 2021.

Northern Utilities - Base Rates - New Hampshire - On August 2, 2021, Northern Utilities filed a base rate case with the NHPUC, requesting a permanent increase in total annual revenues of $7.8 million, which represents an increase of 8.1% over total annual revenue at present rates. The multi-year rate filing includes a revenue decoupling mechanism and an Arrearage Management Program for financial hardship customers. Northern Utilities also requested implementation of temporary rates for service rendered on and after October 1, 2021. On September 30, 2021, the NHPUC approved a settlement providing for a temporary rate increase of $2.6 million, effective October 1, 2021. 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.

Unitil Energy - Base Rates - On April 2, 2021, Unitil Energy filed a base rate case with the NHPUC, requesting a permanent increase in total annual revenues of $12.0 million, which represents an increase of 4.4% above present rates. Unitil Energy also requested implementation of temporary rates for service rendered on and after June 1, 2021, and until a final order on permanent rates is issued. The filing includes (1) a proposed multi-year rate plan, (2) a revenue decoupling mechanism, (3) a Grid Modernization plan that includes a group of foundational grid modernization projects, (4) a suite of proposed time of use (TOU) rates including rates for electric vehicles (EV), (5) an EV infrastructure development program which includes rebates for residential customers for the installation of smart charging equipment and a public “make-ready” program for general service customers under which the Company will install the infrastructure required to connect an EV charger, (6) a Marketing, Communications, and Education Plan to engage with customers about the TOU rates and EV program offerings, (7) resiliency programs to further the Company’s commitment to reliability, (8) an Arrearage Management Program for financial hardship customers, and (9) other rate design and tariff changes. On April 24, 2020, the Governor of New Hampshire issued an executive order that extended the NHPUC’s authority to suspend rate schedules by six months, from 12 to 18 months, to conduct its investigation of a utility company’s request to increase rates. On April 6, 2021, the NHPUC determined that the extension applies to this proceeding, but stated it will endeavor to set final rates as expeditiously as possible. On May 27, 2021, the NHPUC approved a settlement agreement providing for a temporary rate increase of $4.5 million in annual electric distribution revenues, effective June 1, 2021. 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.

Fitchburg - Base Rates - Electric - Fitchburg’s base rates are decoupled in order to mitigate economic, weather and energy efficiency affect to the Company’s revenues and subject to an annual revenue decoupling adjustment mechanism, which includes a cap on the amount that rates may be increased in any year. In addition, Fitchburg has an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions. On November 1, 2018, Fitchburg filed its cumulative revenue requirement of $0.9 million associated with the Company’s 2015-2017 capital expenditures. On December 22, 2020, final approval of the filing was issued. On October 29, 2019, Fitchburg filed its cumulative revenue requirement of $1.1 million associated with the Company’s 2015-2018 capital expenditures. On December 22, 2020, final approval of the filing was issued. On November 2, 2020, Fitchburg filed its cumulative revenue requirement of $1.4 million associated with its 2019 capital expenditures. On June 15, 2021, final approval of the filing was issued, effective January 1, 2021.

On April 17, 2020, the MDPU approved a settlement agreement entered into by the Company and the Massachusetts Office of the Attorney General providing for a distribution increase of $1.1 million, effective November 1, 2020. The Company’s subsequent Compliance Filing reflected an adjusted distribution increase of $0.9 million, a decrease of $0.2 million from the original settlement amount. On May 21, 2020, the MDPU approved the Company’s Compliance Filing. The agreement provides for a Return on Equity of 9.7% and a capital structure reflecting 52.45% equity and 47.55% long-term debt. Under the agreement, the Company will not increase or redesign base distribution rates to become effective prior to November 1, 2023, though the Company may seek cost recovery for certain exogenous events that meet a revenue threshold of $0.1 million. The agreement also provides for the implementation of a major storm reserve fund, whereby the Company may recover the costs of restoration for qualifying storm events. In addition, the agreement provides for the extension of the annual capital cost recovery mechanism, modified to allow the recovery of property tax on the cumulative net capital expenditures.

Fitchburg - Base Rates - Gas - Pursuant to its revenue decoupling adjustment clause tariff, as approved in its last base rate case, the Company is allowed to modify, on a semi-annual basis, its base distribution rates to an established revenue per customer target in order to mitigate economic, weather and energy efficiency affect to the Company’s revenues. The MDPU consistently has found the Company’s filings are in accord with its approved tariffs, applicable law and precedent, and that they result in just and reasonable rates.

On February 28, 2020, the MDPU approved a settlement agreement between the Company and the Massachusetts Office of the Attorney General. The agreement provides for an annual distribution revenue increase of $4.6 million to be phased in over two years: (1) an increase of $3.7 million, which became effective on March 1, 2020; and (2) an increase of $0.9 million, which became effective on March 1, 2021. Under the agreement, the Company will not increase or redesign base distribution rates to become effective prior to March 1, 2023, though the Company may seek cost recovery for certain exogenous events that meet a revenue effect threshold of $40,000. The agreement provides for a Return on Equity of 9.7% and a capital structure reflecting 52.45% equity and 47.55% long-term debt.

Fitchburg - Gas System Enhancement Program - Pursuant to statute and MDPU order, Fitchburg has an approved Gas System Enhancement Plan tariff through which it may recover certain gas infrastructure replacement and safety related investment costs, subject to an annual cap. Under the plan, the Company is required to make two annual filings with the MDPU: a forward-looking filing for the subsequent construction year, to be filed on or before October 31; and a filing, submitted on or before May 1, of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably and prudently incurred. Fitchburg’s most recent forward-looking filing, filed on October 30, 2020, requested recovery of approximately $2.2 million, and received final approval on April 29, 2021, effective May 1, 2021. The Company considers these to be routine regulatory proceedings, and there are no material issues outstanding.

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

On August 24, 2021, the FERC accepted Granite State’s first limited Section 4 rate adjustment pursuant to the Settlement Agreement, for an annual revenue increase of $0.1 million, effective September 1, 2021.

Other Matters

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. The GMP is subject to review and approval by the MDPU and remains pending.

Fitchburg - Grid Modernization Cost Recovery Factor - On April 15, 2021, Fitchburg filed its Grid Modernization Factor (GMF) rate adjustment and reconciliation filing pursuant to the Company’s proposed GMF Tariff, for recovery of the costs incurred as a result of implementing the Company’s 2018-2021 GMP, previously approved by the MDPU on February 7, 2019. The proposed GMF was approved on May 27, 2021, effective June 1, 2021, 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, have engaged an independent consultant to conduct a study and prepare a report (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 is to include an examination of the potential pathways identified in the 2050 Decarbonization Roadmap developed by the MA Executive Office of Energy and Environmental Affairs, in consultation with the Massachusetts Department of Environmental Protection and the Massachusetts Department of Energy Resources. On or before March 1, 2022, each LDC is required to submit a proposal to the MDPU that includes the LDCs’ recommendations and plans for helping the Commonwealth achieve its 2050 climate goals, supported by the Report. Prior to filing the Report and the LDCs’ proposals, the LDCs are directed to engage in a stakeholder process to solicit feedback and advice on both the Report and the proposals. Fitchburg is actively involved in the LDCs’ joint effort to respond to the MDPU’s directives.

Financial Effects of COVID-19 Pandemic - The NHPUC and the MDPU have opened proceedings to consider the revenue and cost effects on the regulated gas and electric utilities within their respective jurisdictions of the requirement to continue the availability of gas, electric and water service to customers during the COVID-19 pandemic. Among the effects under investigation are the revenue effects associated with service disconnection moratoriums, the waiver of fees and expanded customer payments arrangements; the increased cost of customer accounts that cannot be collected, including the cost of bad debt reserves and increased working capital costs; and increased operating and maintenance costs incurred for employees to work safely and protect the public. Fitchburg, Unitil Energy and Northern Utilities are active participants in these proceedings, and are in full compliance with all regulatory orders governing service shut-off moratoriums and other customer service protection measures. These matters remain pending. On December 31, 2020, in docket DPU 20-58, the MDPU issued an order which, among other provisions, allows the utility companies to defer for future recovery bad debt expense in excess of a baseline. On July 7, 2021, the NHPUC issued an order which declined to authorize New Hampshire’s rate-regulated utilities’ establishment of a regulatory asset for incremental bad debt or waived late payment fees related to the COVID-19 pandemic. The NHPUC stated that these costs will be addressed in each utility’s next rate case. On September 7, 2021, the NHPUC clarified its July 7 Order, determining that it has not foreclosed rate-regulated utilities from utilizing accounting mechanisms to defer costs in order to seek recovery in a future rate proceeding, and that Unitil Energy’s and Northern Utilities’ respective pending rate cases are the appropriate venue to address incremental bad debt and/or waived late payment fees resulting from the COVID-19 public health emergency orders and directives.

Northern Utilities / Granite State - Firm Capacity Contract - Northern Utilities relies on the transport of gas supply over its affiliate Granite State pipeline to serve its customers in the Maine and New Hampshire service territories. 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 30, 2021, Northern Utilities submitted an annual informational report requesting approval on a one-year extension for the period of November 1, 2021 through October 31, 2022. The MPUC approved the request on June 29, 2021.

Reconciliation Filings - Fitchburg, Unitil Energy and Northern Utilities each have a number of regulatory reconciling accounts that require annual or semi-annual filings with the MDPU, NHPUC and MPUC, respectively, to reconcile costs and revenues, 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 the actual wholesale energy costs for electric power and gas incurred by each of the three companies. Fitchburg, Unitil Energy and Northern Utilities have been, and remain in full compliance with all directives and orders regarding these filings. The Company considers these to be routine regulatory proceedings, and there are no material issues outstanding.

Fitchburg - Massachusetts RFPs - Pursuant to a comprehensive energy law enacted in 2016, “An Act to Promote Energy Diversity,” (the Act) under Section 83C, the Massachusetts electric distribution companies (EDCs), including Fitchburg, are required to jointly solicit proposals for long-term contracts for at least 400 MW) of offshore wind energy generation by June 30, 2017, as part of a total of 1,600 MW of offshore wind the EDCs are directed to procure by June 30, 2027. Under Section 83D of the Act, the EDCs are required to jointly seek proposals for cost-effective clean energy (hydroelectric, solar and land-based wind) long-term contracts via one or more staggered solicitations for a total of 9,450,000 megawatt-hours (MWh) by December 31, 2022. Unitil’s pro rata share of these contracts is approximately one percent. The EDCs issued the RFP for Section 83D Long-Term Contracts for Qualified Clean Energy Projects in March 2017, and after selection of final projects and negotiation, final contracts for 9,554,940 MWh of Qualified Clean Energy and associated Environmental Attributes from hydroelectric generation were filed in July 2018 for approval by the MDPU. On June 25, 2019, the MDPU approved the power purchase agreements, 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 costs to customers. The MDPU also determined that the EDCs’ request for remuneration equal to 2.75% of the contract payments is reasonable and in the public interest and approved the EDCs’ proposal to amend their respective tariffs to include the recovery of costs associated with the contracts. The Massachusetts Supreme Judicial Court upheld the MDPU’s approval in an Order dated September 3, 2020. The Company believes the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg, once certain conditions and contingencies are met.

The EDCs issued the RFP pursuant to Section 83C for Long-Term Contracts for Offshore Wind Energy Generation in June 2017. The EDCs selected an 800 MW project submitted by Vineyard Wind in May 2018, contracts were signed in July 2018 and on July 23, 2018, the EDCs, including Fitchburg, filed two long-term contracts, each for 400 MW of offshore wind energy generation with the MDPU for approval. On April 12, 2019, the MDPU approved the offshore wind energy generation power purchase agreements, 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 costs to customers. The MDPU also determined that the EDCs’ request for remuneration equal to 2.75% of the contract payments is reasonable and in the public interest and approved the EDCs’ proposal to amend their respective tariffs to include the recovery of costs associated with the contracts. The Company believes the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg, once certain conditions and contingencies are met.

was made on February 10, 2020. On November 5, 2020, the MDPU approved the Offshore Wind Energy Generation power purchase agreements. The MDPU also determined that the EDCs’ request for remuneration equal to 2.75% is reasonable and in the public interest. On November 25, 2020 the Office of the Attorney General filed a Motion for Reconsideration of the MDPU’s order regarding remuneration, which was denied. The MDPU order is now final. The Company believes the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg, once certain conditions and contingencies are met.

In accordance with the requirement of Chapter 227 of the Acts of 2018, An Act to Advance Clean Energy, signed August 9, 2018, Massachusetts Department of Energy Resources (MDOER) prepared a report on the necessity, benefits and costs of requiring the EDCs to competitively conduct offshore wind generation RFPs for up to an additional 1,600 MW. The MDOER filed its report with the Legislature in May, 2019, recommending that, “the EDCs should proceed with additional offshore wind solicitations for up to 1,600 MW of offshore wind in 2022 and 2024 and only enter into contracts if found to be cost-effective.” On March 10, 2021, Fitchburg, along with the other MA EDCs, filed a petition with the MDPU for approval of a proposed timetable and method of solicitation and execution of long-term contracts for up to an additional 1,600 MW of off shore wind generation. On May 5, 2021, the DPU approved the proposed timetable and method for the solicitation, and the RFP was issued on May 7, 2021. Responsive proposals were received on September 16, 2021, and project selection is scheduled for December 17, 2021.

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’ Regional Network Service and Local Network Service formula rates. On April 14, 2017, the U.S. Court of Appeals for the D.C. Circuit (the Court) issued an opinion vacating a decision of the FERC with respect to the ROE, and remanded it for further proceedings. The FERC had found that the Transmission Owners existing ROE was unlawful, and set a new ROE. The Court found that the 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. Separately, on March 15, 2018, the Transmission Owners filed a petition for review with the Court of certain orders of the FERC setting for hearing other complaints challenging the allowed Return on Equity component of the formula rates. 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. In response to the FERC order in EL 14-12, the New England Transmission Owners (NETOs) filed a motion to reopen the record, which has been granted. This matter remains pending.

The FERC Section 206 proceeding concerning the justness and reasonableness of ISO-New England, Inc. Participating Transmission Owners’ Regional Network Service and Local Network Service formula rates and to develop formula rate protocols for these rates has been resolved. On August 17, 2018 a joint settlement agreement among a number of the parties was filed with the FERC. FERC rejected the settlement agreement on May 22, 2019 and remanded the proceeding to the Chief Administrative Law Judge to resume hearing procedures. On May 24, 2019 the judge appointed a Dispute Resolution Facilitator to aid parties in settlement negotiations. The procedural schedule was suspended September 24, 2019 in order to allow participants to focus on settlement negotiations. On October 24, 2019, the NETO’s filed an unopposed motion to suspend the procedural schedule and waiver of answer period indicating that the NETO’s, Municipal Pool Transmission Facility Owners and the Commission Trial Staff have reached agreement in principle on the terms of a settlement to resolve all open issues in the proceeding. On June 15, 2020 a settlement was filed. The FERC approved the settlement agreement on December 28, 2020. Under the terms of the settlement agreement, the negotiated formula rates will take effect on January 1, 2022. Fitchburg and Unitil Energy are Participating Transmission Owners, although Unitil Energy does not own transmission plant. To the extent that these proceedings result in any changes to the rates being charged, a retroactive reconciliation may be required. 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.

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ENVIRONMENTAL MATTERS

9 Months Ended

Sep. 30, 2021

ENVIRONMENTAL MATTERS

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, 2020 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 2, 2021.

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 September 30, 2021, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, the Company cannot assure that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs. Based on its current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, the Company does not believe that these environmental costs will have a material adverse effect on the Company’s consolidated financial position or results of operations.

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

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

In July 2019, the NH DES requested that Northern Utilities review modeled expectations for groundwater contaminants against observed data at the Rochester site. In June 2020, the NH DES coupled the submittal of the review to a proposed extension of the gas distribution system by Northern Utilities. Northern Utilities anticipates submittal of the review by November 2021. In anticipation of the NH DES approval of the work plan, the Company has accrued $0.8 million for estimated costs to complete the remediation at the Rochester site, which is included in Environmental Obligations.

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

Fitchburg’s Manufactured Gas Plant Site - Fitchburg has worked with the Massachusetts Department of Environmental Protection (Mass DEP) to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring continues. In April 2020, Fitchburg received notification from the Massachusetts Department of Transportation (Mass DOT) that a portion of the site may be incorporated into the proposed Twin City Rail Trail with an anticipated completion in 2023. Depending upon the final agreement between Fitchburg and Mass DOT, additional minor costs are expected prior to completion.

In August 2021, the Mass DEP issued a Notice of Non-compliance to FGE following a November 2020 audit of the September 2015 Response Action Outcome on the MGP site. Mass DEP directed Fitchburg to further define the extent of MGP site contaminants in the sediment and riverbank of an abutting watercourse, which should be completed by June 2022.

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

Unitil Energy - Kensington Distribution Operations Center - Unitil Energy conducted a Phase I and II environmental site assessment (ESA) in the second quarter of 2021. The ESA results identified soil and groundwater contaminants in excess of state regulatory standards. In September 2021, the NH DES directed Unitil Energy to conduct a supplemental site investigation and identify whether there is a need to conduct further investigation or remedial actions, which should be completed by June 2022.

The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the nine months ended September 30, 2021 and 2020.

Environmental Obligations ($ millions)
	September 30,
	2021		2020
Total Balance at Beginning of Period	$	2.1	$	2.7
Additions		0.6		0.1
Less: Payments / Reductions		0.3		0.6
Total Balance at End of Period		2.4		2.2
Less: Current Portion		0.7		0.3
Noncurrent Balance at End of Period	$	1.7	$	1.9

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INCOME TAXES

9 Months Ended

Sep. 30, 2021

Income Tax Disclosure [Abstract]

Income Taxes

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:

	Nine Months Ended September 30
	2021			2020
Statutory Federal Income Tax Rate		21	%		21	%
Income Tax Effects of:
State Income Taxes, net		6			6
Utility Plant Differences		(3	)		(5	)
Other, net		—			1
Effective Income Tax Rate		24	%		23	%

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 September 30, 2021 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, 2018, December 31, 2019, and December 31, 2020.

In March 2020, the Coronavirus Aid, Relief and Economic Security (CARES) Act was signed into law. The CARES Act included several tax changes as part of its economic package. These changes principally related to expanded Net Operating Loss carryback periods, increases to interest deductibility limitations, and accelerated Alternative Minimum Tax refunds. The Company has evaluated these items and determined that the items do not have a material effect on the Company’s financial statements as of December 31, 2020. Additionally, the CARES Act enacted the Employee Retention Credit (ERC) to incentivize companies to retain employees. The ERC is a 50% credit on employee wages for employees that are retained and cannot perform their job duties at 100% capacity as a result of coronavirus pandemic restrictions.

In December 2020, the Consolidated Appropriations Act, 2021 (CAA) was signed into law. The CAA included additional funding through tax credits as part of its economic package for 2021. These changes include the temporary removal of deduction limitations on business meals through December 2022 and additional funding for the ERC with expanded benefits extended through June 30, 2021. The expanded ERC is a 70% credit on employee wages for employees that are retained and cannot perform their job duties at 100% capacity as a result of coronavirus pandemic restrictions.

In March 2021, the American Rescue Plan Act of 2021 (ARPA) was signed into law. The ARPA included certain provisions that provide economic relief for the ongoing COVID-19 pandemic, such as extending the ERC through December 31, 2021, and other future governmental revenue producing provisions, such as expanding the scope for deduction limitations on executive compensation in future years.

The Company has evaluated each of the CARES, CAA and ARPA provisions and determined that they do not have a material effect on the Company’s financial statements as of September 30, 2021. The Company has recorded a reduction in payroll taxes related to the ERC for $0.6 million in the third quarter of 2020 and $0.4 million in the nine months ended September 30, 2021. These were recorded as a reduction to payroll tax expense which is recorded in Taxes Other Than Income Taxes in the Consolidated Statements of Earnings.

Income tax filings for the year ended December 31, 2020 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, 2020 which were filed with the IRS in October 2021, the Company generated federal Net Operating Loss Carryforward (NOLC) assets of $5.4 million principally due to tax repairs expensing and tax depreciation. In addition, at September 30, 2021, the Company had $0.3 million of cumulative state tax credit carryforwards to offset against future income taxes payable. If unused, the Company’s state tax credit carryforwards will begin to expire in 2023.

In December 2017, the Tax Cuts and Jobs Act (TCJA), which included a reduction to 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) at the new 21% tax rate at which the ADIT will be reversed in future periods. The Company recorded a net Regulatory Liability in the amount of $48.9 million at December 31, 2017 as a result of the ADIT revaluation. The Company expects to flow through to customers $47.1 million of excess ADIT in utility base rates. Approximately $1.8 million of excess ADIT was created through reconciling mechanisms at December 31, 2017, which had not been previously collected from customers through utility rates. The Company reconciled these excess ADIT amounts through the specific reconciliation mechanisms in each of those individual reconciling mechanisms which were reviewed by state regulators. In addition to the $48.9 million of net excess ADIT, as of December 31, 2018, there was $2.0 million of remaining excess ADIT created by the recognition of NOLC, and related to the implementation of the new federal tax rate of the TCJA, which had not been previously included in utility rates. The Company recognized the benefit of this excess ADIT in accordance with the regulatory treatment of excess ADIT for each jurisdiction. In 2019, the Company recognized $1.7 million of this amount and the remaining $0.3 million was recognized in 2020.

Based on communications received by the Company from its state regulators in rate cases and other regulatory proceedings in the first quarter of 2018 and, as prescribed in the TCJA, recent FERC guidance and IRS normalization rules, the benefit of these protected excess ADIT amounts will be subject to flow back to customers in future utility rates according to the Average Rate Assumption Method (ARAM). ARAM reconciles excess ADIT at the reversal rate of the underlying book/tax temporary timing differences. 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. Subject to regulatory approval, the Company expects to flow back to customers a net $47.1 million of protected excess ADIT created as a result of the lowering of the statutory tax rate by the TCJA over periods estimated to be fifteen to twenty years. As of September 30, 2021, the Company flowed back $2.7 million to customers in its Massachusetts, Maine, and federal jurisdictions. New Hampshire liabilities will begin to flow back once rate proceedings have finalized in that jurisdiction.

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RETIREMENT BENEFIT OBLIGATIONS

9 Months Ended

Sep. 30, 2021

Retirement Benefits [Abstract]

Retirement Benefit Plans

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 10 to the Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2020 as filed with the SEC on February 2, 2021 for additional information regarding these plans.

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

Used to Determine Plan Costs	2021			2020
Discount Rate		2.50	%		3.25	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		7.50	%		7.40	%
Health Care Cost Trend Rate Assumed for Next Year		6.60	%		7.00	%
Ultimate Health Care Cost Trend Rate		4.50	%		4.50	%
Year that Ultimate Health Care Cost Trend Rate is reached		2029			2029

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

	Pension Plan						PBOP Plan						SERP
Three Months Ended September 30,	2021			2020			2021			2020			2021			2020
Service Cost	$	868		$	829		$	759		$	673		$	89		$	70
Interest Cost		1,250			1,445			685			782			114			137
Expected Return on Plan Assets		(2,422	)		(2,254	)		(627	)		(515	)		—			—
Prior Service Cost Amortization		76			80			302			301			14			15
Actuarial Loss Amortization		2,021			1,618			260			187			372			259
Sub-total		1,793			1,718			1,379			1,428			589			481
Amounts Capitalized and Deferred		(944	)		(861	)		(904	)		(860	)		(178	)		(144	)
Net Periodic Benefit Cost Recognized	$	849		$	857		$	475		$	568		$	411		$	337

 

	Pension Plan						PBOP Plan						SERP
Nine Months Ended September 30,		2021			2020			2021			2020			2021			2020
Service Cost	$	2,604		$	2,491		$	2,275		$	2,023		$	266		$	212
Interest Cost		3,752			4,332			2,055			2,341			343			412
Expected Return on Plan Assets		(7,268	)		(6,764	)		(1,881	)		(1,547	)		—			—
Prior Service Cost Amortization		226			240			906			907			42			43
Actuarial Loss Amortization		6,065			4,854			784			559			1,117			777
Sub-total		5,379			5,153			4,139			4,283			1,768			1,444
Amounts Capitalized and Deferred		(2,544	)		(2,298	)		(2,358	)		(2,087	)		(534	)		(434	)
Net Periodic Benefit Cost Recognized	$	2,835		$	2,855		$	1,781		$	2,196		$	1,234		$	1,010

Employer Contributions

As of September 30, 2021, the Company had made $4.1 million and $2.8 million of contributions to its Pension Plan and PBOP Plan, respectively, in 2021. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2021 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 September 30, 2021, the Company had made $0.5 million of benefit payments under the SERP Plan in 2021. The Company presently anticipates making an additional $0.1 million of benefit payments under the SERP Plan in 2021.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2021

Accounting Policies [Abstract]

Nature of Operations

Nature of Operations - 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. The following companies are wholly-owned subsidiaries of Unitil: Unitil Energy Systems, Inc. (Unitil Energy), Fitchburg Gas and Electric Light Company (Fitchburg), Northern Utilities, Inc. (Northern Utilities), Granite State Gas Transmission, Inc. (Granite State), Unitil Power Corp. (Unitil Power), Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) and its non-regulated business unit Unitil Resources, Inc. (Unitil Resources).

The Company’s earnings are seasonal and are 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 in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire; Fitchburg, which operates in Massachusetts; and Northern Utilities, which operates in New Hampshire and Maine (collectively referred to as the “distribution utilities”).

Granite State is an interstate gas transmission pipeline company, operating 86 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 the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.

A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, on May 1, 2003 Unitil Power ceased being the wholesale supplier of Unitil Energy and divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers. In the period since, Unitil Power continued to flow revenues and expenses from remaining contracts to Unitil Energy under the Amended Unitil System Agreement. The last of those contracts expired October 31, 2020, and the Company no longer has material revenues or expenses associated with them.

Unitil also has three other wholly-owned subsidiaries: Unitil Service, Unitil Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary.

Basis of Presentation

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 all of 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 nine months ended September 30, 2021 are not necessarily indicative of results to be expected for the year ending December 31, 2021. For further information, please 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, 2020, as filed with the Securities and Exchange Commission (SEC) on February 2, 2021, for a description of the Company’s Basis of Presentation.

Utility Revenue Recognition

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

Revenue is recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of 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.

	Three Months Ended September 30, 2021
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	7.9		$	35.0		$	42.9
C&I		14.4			26.8			41.2
Other		0.8			3.2			4.0
Total Billed and Unbilled Revenue		23.1			65.0			88.1
Rate Adjustment Mechanism Revenue		9.5			0.5			10.0
Total Gas and Electric Operating Revenues	$	32.6		$	65.5		$	98.1
	Three Months Ended September 30, 2020
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	7.0		$	35.3		$	42.3
C&I		11.6			24.1			35.7
Other		1.4			1.4			2.8
Total Billed and Unbilled Revenue		20.0			60.8			80.8
Rate Adjustment Mechanism Revenue		7.5			(0.9	)		6.6
Total Gas and Electric Operating Revenues	$	27.5		$	59.9		$	87.4
	Nine Months Ended September 30, 2021
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	60.5		$	104.0		$	164.5
C&I		86.2			78.2			164.4
Other		7.6			6.9			14.5
Total Billed and Unbilled Revenue		154.3			189.1			343.4
Rate Adjustment Mechanism Revenue		(3.0	)		(6.9	)		(9.9	)
Total Gas and Electric Operating Revenues	$	151.3		$	182.2		$	333.5
	Nine Months Ended September 30, 2020
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	52.4		$	99.9		$	152.3
C&I		72.9			68.7			141.6
Other		5.6			4.9			10.5
Total Billed and Unbilled Revenue		130.9			173.5			304.4
Rate Adjustment Mechanism Revenue		0.5			(3.2	)		(2.7	)
Total Gas and Electric Operating Revenues	$	131.4		$	170.3		$	301.7

Fitchburg is subject to revenue decoupling. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or gas sales. The difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recorded 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 that the Company files with the MDPU.

Income Taxes

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 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 - Cash and Cash Equivalents include 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 September 30, 2021, September 30, 2020 and December 31, 2020, the Unitil subsidiaries had deposited $5.7 million, $4.7 million and $2.4 million, respectively to satisfy their ISO-NE obligations.

Financial Instruments

Financial Instruments - In June 2016, the Financial Accounting Standards Board issued ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326)”, which provides a new model for recognizing credit losses on financial instruments based on an estimate of current expected credit losses. Under the new guidance, immediate recognition of all credit losses expected over the life of a financial instrument is required. The Company adopted this standard on the accounting for credit losses on its financial instruments, including accounts receivable, on January 1, 2020, and it did not have a material effect on the financial statements.

Allowance for Doubtful Accounts

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

The Allowance for Doubtful Accounts as of September 30, 2021, September 30, 2020 and December 31, 2020, was as follows:

($ millions)
	September 30,				December 31,
	2021		2020		2020
Allowance for Doubtful Accounts	$	4.3	$	1.6	$	3.3

Accounts Receivable, Net includes $4.2 million, $1.5 million, and $3.1 million of the Allowance for Doubtful Accounts at September 30, 2021, September 30, 2020 and December 31, 2020, respectively. Unbilled Revenues, net (a component of Accrued Revenue, shown in the table below) includes $0.1 million, $0.1 million and $0.2 million of the Allowance for Doubtful Accounts at September 30, 2021, September 30, 2020 and December 31, 2020, respectively.

Accrued Revenue

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 September 30, 2021, September 30, 2020 and December 31, 2020.

	September 30,				December 31,
Accrued Revenue ($ millions)	2021		2020		2020
Regulatory Assets – Current	$	30.6	$	31.7	$	37.3
Unbilled Revenues		8.0		7.4		13.6
Total Accrued Revenue	$	38.6	$	39.1	$	50.9

Exchange Gas Receivable

Exchange Gas Receivable - Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers natural gas back to the Company during the months of November through March. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of September 30, 2021, September 30, 2020 and December 31, 2020.

	September 30,				December 31,
Exchange Gas Receivable ($ millions)	2021		2020		2020
Northern Utilities	$	9.7	$	6.0	$	4.4
Fitchburg		0.8		0.5		0.5
Total Exchange Gas Receivable	$	10.5	$	6.5	$	4.9

Gas Inventory

Gas Inventory - The Company uses the weighted average cost methodology to value natural gas inventory. The following table shows the components of Gas Inventory as of September 30, 2021, September 30, 2020 and December 31, 2020.

	September 30,				December 31,
Gas Inventory ($ millions)	2021		2020		2020
Natural Gas	$	0.4	$	0.2	$	0.2
Propane		0.4		0.3		0.3
Liquefied Natural Gas & Other		0.1		0.1		0.1
Total Gas Inventory	$	0.9	$	0.6	$	0.6

Utility Plant

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 September 30, 2021, September 30, 2020 and December 31, 2020, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $108.2 million, $107.1 million, and $105.2 million, respectively.

Leases

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

Regulatory Accounting

Regulatory Accounting - The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the Massachusetts Department of Public Utilities (MDPU), Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC) and Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the FASB Codification. The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission. The electric and gas divisions of Fitchburg are authorized to recover through rates past due amounts associated with hardship accounts that are protected from shut-off. As of September 30, 2021, September 30, 2020 and December 31, 2020, the Company has recorded $9.5 million, $7.1 million and $6.8 million, respectively, of hardship accounts in Regulatory Assets. These amounts are included in “Other Deferred Charges” in the table below. The Company currently receives recovery in rates or expects to receive recovery of these hardship accounts in future rate cases.

	September 30,				December 31,
Regulatory Assets consist of the following ($ millions)	2021		2020		2020
Retirement Benefits	$	107.0	$	81.0	$	103.7
Energy Supply & Other Rate Adjustment Mechanisms		27.3		28.9		34.1
Deferred Storm Charges		3.4		4.4		4.1
Environmental		4.8		6.1		5.2
Income Taxes		2.8		3.6		3.4
Other Deferred Charges		17.7		12.1		14.2
Total Regulatory Assets	$	163.0	$	136.1	$	164.7
Less: Current Portion of Regulatory Assets(1)		30.6		31.7		37.3
Regulatory Assets – noncurrent	$	132.4	$	104.4	$	127.4

(1) Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets.

	September 30,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2021		2020		2020
Income Taxes (Note 8)	$	44.6	$	45.8	$	45.5
Rate Adjustment Mechanisms		11.3		9.2		4.1
Other		0.1		0.3		0.2
Total Regulatory Liabilities	$	56.0	$	55.3	$	49.8
Less: Current Portion of Regulatory Liabilities		13.1		10.6		5.5
Regulatory Liabilities - noncurrent	$	42.9	$	44.7	$	44.3

Generally, the Company receives a return on investment on its regulatory assets for which a cash outflow has been made. Regulatory Assets at September 30, 2021 include $8.5 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 accounting rules for regulated operations, 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

Derivatives - The Company’s regulated energy subsidiaries enter into energy supply contracts to serve their electric and gas customers. The Company follows a procedure for determining whether each contract qualifies as a derivative instrument under the guidance provided by the FASB Codification on Derivatives and Hedging. For each contract, the Company reviews and documents the key terms of the contract. Based on those terms and any additional relevant components of the contract, the Company 

determines and documents whether the contract qualifies as a derivative instrument as defined in the FASB Codification. The Company has determined that its energy supply contracts either do not qualify as a derivative instrument under the guidance set forth in the FASB Codification, have been elected as 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). Until these contingencies are satisfied, these contracts will not qualify for derivative accounting. The Company believes that the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg.

Investments in Marketable Securities

Investments in Marketable Securities - The Company has a trust through which it invests in a money market fund. These investments are intended to satisfy obligations under the Company’s Supplemental Executive Retirement Plan (SERP) (See further discussion of the SERP in Note 9.)

At September 30, 2021, September 30, 2020 and December 31, 2020, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $5.6 million, $5.7 million and $5.7 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.

	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2021		2020		2020
Money Market Fund	$	5.6	$	5.7	$	5.7
Total Marketable Securities	$	5.6	$	5.7	$	5.7

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

At September 30, 2021, September 30, 2020 and December 31, 2020, 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 $0.5 million, $0.5 million and $0.5 million, respectively, as shown in the following table. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other Expense, Net.

	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2021		2020		2020
Equity Funds	$	0.1	$	0.2	$	0.2
Money Market Funds		0.4		0.3		0.3
Total Marketable Securities	$	0.5	$	0.5	$	0.5

Energy Supply Obligations

	September 30,				December 31,
Energy Supply Obligations ($ millions)	2021		2020		2020
Exchange Gas Obligation	$	9.7	$	6.0	$	4.4
Renewable Energy Portfolio Standards		6.4		5.8		5.7
Power Supply Contract Divestitures		—		0.3		0.3
Total Energy Supply Obligations	$	16.1	$	12.1	$	10.4

Exchange Gas Obligation - Northern Utilities enters into gas exchange agreements under which Northern Utilities releases certain gas pipeline and storage assets, resells the gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the gas heating season at the same price at which it 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 in Accrued Revenue with a corresponding liability in Energy Supply Obligations on the Company’s Consolidated Balance Sheets.

Fitchburg has entered into long-term renewable contracts for the purchase of clean energy and/or RECs pursuant to Massachusetts legislation, specifically, An Act Relative to Green Communities (Green Communities Act, 2008), An Act Relative to Competitively Priced Electricity in the Commonwealth (2012) and An Act to Promote Energy Diversity (Energy Diversity Act, 2016). The generating facilities associated with eight of these contracts have been constructed and are now operating. Two additional contracts are scheduled to become commercial in 2021. In 2020, three of the long-term contracts were terminated due to an inability to meet critical milestones. In 2018, the Company filed two long-term contracts with the MDPU, one for offshore wind generation and another for imported hydroelectric power and associated transmission. Those contracts were approved in 2019. In 2019, the Company participated in an additional statewide procurement for offshore wind generation and the resulting contracts were filed with the MDPU during the first quarter of 2020. An Order approving the contracts was issued by the MDPU in November 2020. On November 25, 2020 the Office of the Attorney General filed a Motion for Reconsideration of the MDPU’s order regarding remuneration, which was denied. The MDPU order is now final. In compliance with An Act to Promote a Clean Energy Future (2018), in late 2020 in coordination with the other electric utilities in Massachusetts, the Company began efforts on the next long-term renewable procurement which will seek up to an additional 1,600 megawatts (MW) of offshore wind generation. Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

Power Supply Contract Divestitures - Unitil Energy’s and Fitchburg’s customers are entitled to purchase their electric or gas supplies from third-party suppliers. In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil

Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs. As of September 30, 2021, Fitchburg has fully recovered its power supply-related stranded costs and Unitil Energy has less than $0.1 million remaining to recover. The obligations related to these divestitures are recorded in Energy Supply Obligations on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue.

Subsequent Events

Subsequent Events - The Company evaluates all events or transactions through the date of the related filing. During the period subsequent to the balance sheet date and through the date of this filing, the Company did not have any material subsequent events that would result in adjustment to or disclosure in its Consolidated Financial Statements.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

9 Months Ended

Sep. 30, 2021

Components of Gas and Electric Operating Revenue

	Three Months Ended September 30, 2021
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	7.9		$	35.0		$	42.9
C&I		14.4			26.8			41.2
Other		0.8			3.2			4.0
Total Billed and Unbilled Revenue		23.1			65.0			88.1
Rate Adjustment Mechanism Revenue		9.5			0.5			10.0
Total Gas and Electric Operating Revenues	$	32.6		$	65.5		$	98.1
	Three Months Ended September 30, 2020
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	7.0		$	35.3		$	42.3
C&I		11.6			24.1			35.7
Other		1.4			1.4			2.8
Total Billed and Unbilled Revenue		20.0			60.8			80.8
Rate Adjustment Mechanism Revenue		7.5			(0.9	)		6.6
Total Gas and Electric Operating Revenues	$	27.5		$	59.9		$	87.4
	Nine Months Ended September 30, 2021
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	60.5		$	104.0		$	164.5
C&I		86.2			78.2			164.4
Other		7.6			6.9			14.5
Total Billed and Unbilled Revenue		154.3			189.1			343.4
Rate Adjustment Mechanism Revenue		(3.0	)		(6.9	)		(9.9	)
Total Gas and Electric Operating Revenues	$	151.3		$	182.2		$	333.5
	Nine Months Ended September 30, 2020
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	52.4		$	99.9		$	152.3
C&I		72.9			68.7			141.6
Other		5.6			4.9			10.5
Total Billed and Unbilled Revenue		130.9			173.5			304.4
Rate Adjustment Mechanism Revenue		0.5			(3.2	)		(2.7	)
Total Gas and Electric Operating Revenues	$	131.4		$	170.3		$	301.7

Allowance for Doubtful Accounts Included in Accounts Receivable Net

($ millions)
	September 30,				December 31,
	2021		2020		2020
Allowance for Doubtful Accounts	$	4.3	$	1.6	$	3.3

Components of Accrued Revenue

The following table shows the components of Accrued Revenue as of September 30, 2021, September 30, 2020 and December 31, 2020.

	September 30,				December 31,
Accrued Revenue ($ millions)	2021		2020		2020
Regulatory Assets – Current	$	30.6	$	31.7	$	37.3
Unbilled Revenues		8.0		7.4		13.6
Total Accrued Revenue	$	38.6	$	39.1	$	50.9

Components of Exchange Gas Receivable

	September 30,				December 31,
Exchange Gas Receivable ($ millions)	2021		2020		2020
Northern Utilities	$	9.7	$	6.0	$	4.4
Fitchburg		0.8		0.5		0.5
Total Exchange Gas Receivable	$	10.5	$	6.5	$	4.9

Components of Gas Inventory

	September 30,				December 31,
Gas Inventory ($ millions)	2021		2020		2020
Natural Gas	$	0.4	$	0.2	$	0.2
Propane		0.4		0.3		0.3
Liquefied Natural Gas & Other		0.1		0.1		0.1
Total Gas Inventory	$	0.9	$	0.6	$	0.6

Regulatory Assets

	September 30,				December 31,
Regulatory Assets consist of the following ($ millions)	2021		2020		2020
Retirement Benefits	$	107.0	$	81.0	$	103.7
Energy Supply & Other Rate Adjustment Mechanisms		27.3		28.9		34.1
Deferred Storm Charges		3.4		4.4		4.1
Environmental		4.8		6.1		5.2
Income Taxes		2.8		3.6		3.4
Other Deferred Charges		17.7		12.1		14.2
Total Regulatory Assets	$	163.0	$	136.1	$	164.7
Less: Current Portion of Regulatory Assets(1)		30.6		31.7		37.3
Regulatory Assets – noncurrent	$	132.4	$	104.4	$	127.4

(1) Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets.

Regulatory Liabilities

	September 30,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2021		2020		2020
Income Taxes (Note 8)	$	44.6	$	45.8	$	45.5
Rate Adjustment Mechanisms		11.3		9.2		4.1
Other		0.1		0.3		0.2
Total Regulatory Liabilities	$	56.0	$	55.3	$	49.8
Less: Current Portion of Regulatory Liabilities		13.1		10.6		5.5
Regulatory Liabilities - noncurrent	$	42.9	$	44.7	$	44.3

Fair Value of Marketable Securities

Changes in the fair value of these investments are recorded in Other Expense, Net.

	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2021		2020		2020
Money Market Fund	$	5.6	$	5.7	$	5.7
Total Marketable Securities	$	5.6	$	5.7	$	5.7

Components of Energy Supply Obligations

	September 30,				December 31,
Energy Supply Obligations ($ millions)	2021		2020		2020
Exchange Gas Obligation	$	9.7	$	6.0	$	4.4
Renewable Energy Portfolio Standards		6.4		5.8		5.7
Power Supply Contract Divestitures		—		0.3		0.3
Total Energy Supply Obligations	$	16.1	$	12.1	$	10.4

Deferred Compensation Plan [Member]

Fair Value of Marketable Securities

Changes in the fair value of these investments are recorded in Other Expense, Net.

	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2021		2020		2020
Equity Funds	$	0.1	$	0.2	$	0.2
Money Market Funds		0.4		0.3		0.3
Total Marketable Securities	$	0.5	$	0.5	$	0.5

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DIVIDENDS DECLARED PER SHARE (Tables)

9 Months Ended

Sep. 30, 2021

DIVIDENDS DECLARED PER SHARE [Abstract]

Schedule of Dividends Declared

Declaration  Date	Date Paid (Payable)	Shareholder of Record Date	Dividend Amount
10/27/21	11/29/21	11/15/21	$ 0.380
07/28/21	08/27/21	08/13/21	$ 0.380
04/28/21	05/28/21	05/14/21	$ 0.380
01/27/21	02/26/21	02/12/21	$ 0.380
10/28/20	11/30/20	11/16/20	$ 0.375
07/29/20	08/28/20	08/14/20	$ 0.375
04/29/20	05/29/20	05/15/20	$ 0.375
01/29/20	02/28/20	02/14/20	$ 0.375

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SEGMENT INFORMATION (Tables)

9 Months Ended

Sep. 30, 2021

Significant Segment Financial Data

The following table provides significant segment financial data for the three and nine months ended September 30, 2021 and September 30, 2020:

	Gas			Electric			Non- Regulated		Other			Total
Three Months Ended Sept. 30, 2021 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	23.1		$	65.0		$	—	$	—		$	88.1
Rate Adjustment Mechanism Revenue		9.5			0.5			—		—			10.0
Other Operating Revenue – Non-Regulated		—			—			—		—			—
Total Operating Revenues	$	32.6		$	65.5		$	—	$	—		$	98.1
Segment Profit (Loss)		(4.1	)		4.4			—		(0.3	)		—
Capital Expenditures		28.5			10.1			—		0.4			39.0
Three Months Ended Sept. 30, 2020 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	20.0		$	60.8		$	—	$	—		$	80.8
Rate Adjustment Mechanism Revenue		7.5			(0.9	)		—		—			6.6
Other Operating Revenue – Non-Regulated		—			—			—		—			—
Total Operating Revenues	$	27.5		$	59.9		$	—	$	—		$	87.4
Segment Profit (Loss)		(3.6	)		4.4			—		(0.5	)		0.3
Capital Expenditures		27.4			16.0			—		1.4			44.8
Nine Months Ended Sept. 30, 2021 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	154.3		$	189.1		$	—	$	—		$	343.4
Rate Adjustment Mechanism Revenue		(3.0	)		(6.9	)		—		—			(9.9	)
Other Operating Revenue – Non-Regulated		—			—			—		—			—
Total Operating Revenues	$	151.3		$	182.2		$	—	$	—		$	333.5
Segment Profit (Loss)		12.1			10.7			0.1		(1.3	)		21.6
Capital Expenditures		51.7			28.8			—		1.0			81.5
Segment Assets		906.2			583.6			—		19.2			1,509.0
Nine Months Ended Sept. 30, 2020 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	130.9		$	173.5		$	—	$	—		$	304.4
Rate Adjustment Mechanism Revenue		0.5			(3.2	)		—		—			(2.7	)
Other Operating Revenue – Non-Regulated		—			—			—		—			—
Total Operating Revenues	$	131.4		$	170.3		$	—	$	—		$	301.7
Segment Profit		8.6			10.1			—		(0.1	)		18.6
Capital Expenditures		50.0			39.9			—		3.7			93.6
Segment Assets		845.0			556.3			—		22.6			1,423.9

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DEBT AND FINANCING ARRANGEMENTS (Tables)

9 Months Ended

Sep. 30, 2021

Details on Long Term Debt

Details on long-term debt at September 30, 2021, September 30, 2020 and December 31, 2020 are shown below:

($ millions)	September 30,				December 31,
	2021		2020		2020
Unitil Corporation:
6.33% Senior Notes, Due May 1, 2022	$	—	$	20.0	$	15.0
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
Unitil Energy First Mortgage Bonds:
8.49% Senior Secured Notes, Due October 14, 2024		3.0		4.5		3.0
6.96% Senior Secured Notes, Due September 1, 2028		14.0		16.0		16.0
8.00% Senior Secured Notes, Due May 1, 2031		15.0		15.0		15.0
6.32% Senior Secured Notes, Due September 15, 2036		15.0		15.0		15.0
3.58% Senior Secured Notes, Due September 15, 2040		27.5		27.5		27.5
4.18% Senior Secured Notes, Due November 30, 2048		30.0		30.0		30.0
Fitchburg:
6.75% Senior Notes, Due November 30, 2023		—		3.8		1.9
6.79% Senior Notes, Due October 15, 2025		10.0		10.0		10.0
3.52% Senior Notes, Due November 1, 2027		10.0		10.0		10.0
7.37% Senior Notes, Due January 15, 2029		9.6		10.8		10.8
5.90% Senior Notes, Due December 15, 2030		15.0		15.0		15.0
7.98% Senior Notes, Due June 1, 2031		14.0		14.0		14.0
3.78% Senior Notes, Due September 15, 2040		27.5		27.5		27.5
4.32% Senior Notes, Due November 1, 2047		15.0		15.0		15.0
Northern Utilities:
3.52% Senior Notes, Due November 1, 2027		20.0		20.0		20.0
7.72% Senior Notes, Due December 3, 2038		50.0		50.0		50.0
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
Unitil Realty Corp.:
2.64% Senior Secured Notes, Due December 18, 2030		4.5		—		4.7
Total Long-Term Debt		515.1		539.1		535.4
Less: Unamortized Debt Issuance Costs		3.7		3.8		3.8
Total Long-Term Debt, net of Unamortized Debt Issuance Costs		511.4		535.3		531.6
Less: Current Portion		10.1		6.3		8.5
Total Long-term Debt, Less Current Portion	$	501.3	$	529.0	$	523.1

Fair Value of Long Term Debt

($ millions)	September 30,				December 31,
	2021		2020		2020
Estimated Fair Value of Long-Term Debt	$	598.2	$	631.7	$	633.1

Borrowing Limits Amounts Outstanding and Amounts Available under Credit Facility

The following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of September 30 2021, September 30, 2020 and December 31, 2020:

	Revolving Credit Facility ($ millions)
	September 30,				December 31,
	2021		2020		2020
Limit	$	120.0	$	120.0	$	120.0
Short-Term Borrowings Outstanding		30.5		17.3		54.7
Letter of Credit Outstanding		—		0.1		0.1
Available	$	89.5	$	102.6	$	65.2

Classification of the Company Lease Obligations

	September 30,				December 31,
Lease Obligations ($ millions)	2021		2020		2020
Operating Lease Obligations:
Other Current Liabilities (current portion)	$	1.6	$	1.6	$	1.5
Other Noncurrent Liabilities (long-term portion)		3.5		4.0		3.7
Total Operating Lease Obligations	$	5.1	$	5.6	$	5.2
Capital Lease Obligations:
Other Current Liabilities (current portion)	$	0.2	$	0.2	$	0.2
Other Noncurrent Liabilities (long-term portion)		0.2		0.3		0.2
Total Capital Lease Obligations	$	0.4	$	0.5	$	0.4
Total Lease Obligations	$	5.5	$	6.1	$	5.6

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

The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of September 30, 2021. The payments for operating leases consist of $1.6 million of current operating lease obligations, which are included in Other Current Liabilities and $3.5 million of noncurrent operating lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of September 30, 2021. The payments for capital leases consist of $0.2 million of current capital lease obligations, which are included in Other Current Liabilities and $0.2 million of noncurrent capital lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of September 30, 2021.

Lease Payments ($000’s) Year Ending December 31,	Operating Leases		Capital Leases
Rest of 2021	$	479	$	39
2022		1,695		150
2023		1,399		107
2024		1,069		52
2025		503		20
2026-2030		320		—
Total Payments		5,465		368
Less: Interest		365		15
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$	5,100	$	353

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COMMON STOCK AND PREFERRED STOCK (Tables)

9 Months Ended

Sep. 30, 2021

Table Text Block Supplement [Abstract]

Restricted Stock Units Issued

The equity portion of Restricted Stock Units activity during the nine months ended September 30, 2021 in conjunction with the Stock Plan is presented in the following table:

Restricted Stock Units (Equity Portion)

	Units		Weighted Average Stock Price
Restricted Stock Units as of December 31, 2020		43,192	$	41.34
Restricted Stock Units Granted		—		—
Dividend Equivalents Earned		1,032	$	48.10
Restricted Stock Units Settled		—		—
Restricted Stock Units as of September 30, 2021		44,224	$	41.49

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ENVIRONMENTAL MATTERS (Tables)

9 Months Ended

Sep. 30, 2021

Environmental Obligations Recognized by Company

The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the nine months ended September 30, 2021 and 2020.

Environmental Obligations ($ millions)
	September 30,
	2021		2020
Total Balance at Beginning of Period	$	2.1	$	2.7
Additions		0.6		0.1
Less: Payments / Reductions		0.3		0.6
Total Balance at End of Period		2.4		2.2
Less: Current Portion		0.7		0.3
Noncurrent Balance at End of Period	$	1.7	$	1.9

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INCOME TAXES (Tables)

9 Months Ended

Sep. 30, 2021

Income Tax Disclosure [Abstract]

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

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

	Nine Months Ended September 30
	2021			2020
Statutory Federal Income Tax Rate		21	%		21	%
Income Tax Effects of:
State Income Taxes, net		6			6
Utility Plant Differences		(3	)		(5	)
Other, net		—			1
Effective Income Tax Rate		24	%		23	%

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RETIREMENT BENEFIT OBLIGATIONS (Tables)

9 Months Ended

Sep. 30, 2021

Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations

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	2021			2020
Discount Rate		2.50	%		3.25	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		7.50	%		7.40	%
Health Care Cost Trend Rate Assumed for Next Year		6.60	%		7.00	%
Ultimate Health Care Cost Trend Rate		4.50	%		4.50	%
Year that Ultimate Health Care Cost Trend Rate is reached		2029			2029

Components of Retirement Plan Costs

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

	Pension Plan						PBOP Plan						SERP
Three Months Ended September 30,	2021			2020			2021			2020			2021			2020
Service Cost	$	868		$	829		$	759		$	673		$	89		$	70
Interest Cost		1,250			1,445			685			782			114			137
Expected Return on Plan Assets		(2,422	)		(2,254	)		(627	)		(515	)		—			—
Prior Service Cost Amortization		76			80			302			301			14			15
Actuarial Loss Amortization		2,021			1,618			260			187			372			259
Sub-total		1,793			1,718			1,379			1,428			589			481
Amounts Capitalized and Deferred		(944	)		(861	)		(904	)		(860	)		(178	)		(144	)
Net Periodic Benefit Cost Recognized	$	849		$	857		$	475		$	568		$	411		$	337

 

	Pension Plan						PBOP Plan						SERP
Nine Months Ended September 30,		2021			2020			2021			2020			2021			2020
Service Cost	$	2,604		$	2,491		$	2,275		$	2,023		$	266		$	212
Interest Cost		3,752			4,332			2,055			2,341			343			412
Expected Return on Plan Assets		(7,268	)		(6,764	)		(1,881	)		(1,547	)		—			—
Prior Service Cost Amortization		226			240			906			907			42			43
Actuarial Loss Amortization		6,065			4,854			784			559			1,117			777
Sub-total		5,379			5,153			4,139			4,283			1,768			1,444
Amounts Capitalized and Deferred		(2,544	)		(2,298	)		(2,358	)		(2,087	)		(534	)		(434	)
Net Periodic Benefit Cost Recognized	$	2,835		$	2,855		$	1,781		$	2,196		$	1,234		$	1,010

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Summary of Significant Accounting Policies - Additional Information (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2021 USD ($) Subsidiary mi	Dec. 31, 2020 USD ($)	Sep. 30, 2020 USD ($)
Significant Accounting Policies [Line Items]
Length Of Pipeline | mi	86
Cost of removal obligation	$ 108.2	$ 105.2	$ 107.1
Investments in trading securities	5.6	5.7	5.7
Allowance for doubtful accounts	4.3	3.3	1.6
Regulatory assets	163.0	164.7	136.1
Other Deferred Charges
Significant Accounting Policies [Line Items]
Regulatory assets	17.7	14.2	12.1
Unbilled Revenues [member]
Significant Accounting Policies [Line Items]
Allowance for doubtful accounts	0.1	0.2	0.1
Accounts Receivable [member]
Significant Accounting Policies [Line Items]
Allowance for doubtful accounts	$ 4.2	3.1	1.5
Utilities
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Entity | Subsidiary	3
Unitil Service; Unitil Realty; and Unitil Resources
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Entity | Subsidiary	3
Power Supply Contract Divestitures	$ 0.1
Fitchburg Gas and Electric Light Company | Other Deferred Charges | Electric And Gas Division
Significant Accounting Policies [Line Items]
Hardship accounts in regulatory assets	9.5	6.8	7.1
Environmental and Rate Case Costs and Other Expenditures | Recovered over the next seven years
Significant Accounting Policies [Line Items]
Regulatory assets	8.5
ISO-NE Obligations
Significant Accounting Policies [Line Items]
Cash Deposits	$ 5.7	2.4	4.7
Maximum
Significant Accounting Policies [Line Items]
Lease term	12 months
Deferred Compensation Plan [Member]
Significant Accounting Policies [Line Items]
Investments in trading securities	$ 0.5	$ 0.5	$ 0.5

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Components of Gas and Electric Operating Revenue (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ 98.1	$ 87.4	$ 333.5	$ 301.7
Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	88.1	80.8	343.4	304.4
Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	10.0	6.6	(9.9)	(2.7)
Gas Segment
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	32.6	27.5	151.3	131.4
Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	23.1	20.0	154.3	130.9
Gas Segment | Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	9.5	7.5	(3.0)	0.5
Electric
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	65.5	59.9	182.2	170.3
Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	65.0	60.8	189.1	173.5
Electric | Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	0.5	(0.9)	(6.9)	(3.2)
Residential
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	42.9	42.3	164.5	152.3
Residential | Gas Segment
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	7.9	7.0	60.5	52.4
Residential | Electric
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	35.0	35.3	104.0	99.9
Commercial & Industrial
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	41.2	35.7	164.4	141.6
Commercial & Industrial | Gas Segment
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	14.4	11.6	86.2	72.9
Commercial & Industrial | Electric
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	26.8	24.1	78.2	68.7
Other
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	4.0	2.8	14.5	10.5
Other | Gas Segment
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	0.8	1.4	7.6	5.6
Other | Electric
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ 3.2	$ 1.4	$ 6.9	$ 4.9

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Allowance for Doubtful Accounts Included in Accounts Receivable Net (Detail) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020
Allowance for Doubtful Accounts Included in Accounts Receivable Net Detail [Abstract]
Allowance for Doubtful Accounts	$ 4.3	$ 3.3	$ 1.6

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Components of Accrued Revenue (Detail) - USD ($) $ in Millions		Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020
Deferred Revenue Arrangement [Line Items]
Regulatory Assets – Current	[1]	$ 30.6	$ 37.3	$ 31.7
Total Accrued Revenue		38.6	50.9	39.1
Unbilled Revenues
Deferred Revenue Arrangement [Line Items]
Regulatory Assets – Current		8.0	13.6	7.4
Regulatory Assets
Deferred Revenue Arrangement [Line Items]
Regulatory Assets – Current		$ 30.6	$ 37.3	$ 31.7

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

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Components of Exchange Gas Receivable (Detail) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020
Receivables [Line Items]
Total Exchange Gas Receivable	$ 10.5	$ 4.9	$ 6.5
Northern Utilities Inc
Receivables [Line Items]
Total Exchange Gas Receivable	9.7	4.4	6.0
Fitchburg
Receivables [Line Items]
Total Exchange Gas Receivable	$ 0.8	$ 0.5	$ 0.5

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Components of Gas Inventory (Detail) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.9	$ 0.6	$ 0.6
Liquefied Natural Gas & Other
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.1	0.1	0.1
Natural Gas
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.4	0.2	0.2
Propane
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.4	$ 0.3	$ 0.3

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Regulatory Assets (Detail) - USD ($) $ in Millions		Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020
Regulatory Assets [Line Items]
Regulatory Assets		$ 163.0	$ 164.7	$ 136.1
Less: Current Portion of Regulatory Assets	[1]	30.6	37.3	31.7
Regulatory Assets – noncurrent		132.4	127.4	104.4
Environmental Matters
Regulatory Assets [Line Items]
Regulatory Assets		4.8	5.2	6.1
Other Deferred Charges
Regulatory Assets [Line Items]
Regulatory Assets		17.7	14.2	12.1
Retirement Benefits
Regulatory Assets [Line Items]
Regulatory Assets		107.0	103.7	81.0
Deferred Storm Charges
Regulatory Assets [Line Items]
Regulatory Assets		3.4	4.1	4.4
Income Taxes
Regulatory Assets [Line Items]
Regulatory Assets		2.8	3.4	3.6
Energy Supply & Other Rate Adjustment Mechanisms
Regulatory Assets [Line Items]
Regulatory Assets		$ 27.3	$ 34.1	$ 28.9

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

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Regulatory Liabilities (Detail) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 56.0	$ 49.8	$ 55.3
Less: Current Portion of Regulatory Liabilities	13.1	5.5	10.6
Regulatory Liabilities – noncurrent	42.9	44.3	44.7
Income Taxes
Regulatory Liabilities [Line Items]
Regulatory Liabilities	44.6	45.5	45.8	$ 48.9
Rate Adjustment Mechanisms
Regulatory Liabilities [Line Items]
Regulatory Liabilities	11.3	4.1	9.2
Other
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 0.1	$ 0.2	$ 0.3

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Fair Value of Marketable Securities (Detail) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	$ 5.6	$ 5.7	$ 5.7
Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	0.5	0.5	0.5
Fair Value, Inputs, Level 1
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	5.6	5.7	5.7
Fair Value, Inputs, Level 1 | Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	0.5	0.5	0.5
Fair Value, Inputs, Level 1 | Equity Funds | Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	0.1	0.2	0.2
Fair Value, Inputs, Level 1 | Money Market Funds
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	5.6	5.7	5.7
Fair Value, Inputs, Level 1 | Money Market Funds | Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	$ 0.4	$ 0.3	$ 0.3

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Components of Energy Supply Obligations (Detail) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 16.1	$ 10.4	$ 12.1
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	9.7	4.4	6.0
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	6.4	5.7	5.8
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 0.0	$ 0.3	$ 0.3

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Dividends Declared Per Share (Detail) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Dividends Payable [Line Items]
Dividend Amount	$ 0.38	$ 0.375	$ 1.14	$ 1.125
Group One
Dividends Payable [Line Items]
Declaration Date			Oct. 27, 2021
Date Paid (Payable)			Nov. 29, 2021
Shareholder of Record Date			Nov. 15, 2021
Dividend Amount			$ 0.380
Group Two
Dividends Payable [Line Items]
Declaration Date			Jul. 28, 2021
Date Paid (Payable)			Aug. 27, 2021
Shareholder of Record Date			Aug. 13, 2021
Dividend Amount			$ 0.380
Group Three
Dividends Payable [Line Items]
Declaration Date			Apr. 28, 2021
Date Paid (Payable)			May 28, 2021
Shareholder of Record Date			May 14, 2021
Dividend Amount			$ 0.380
Group Four
Dividends Payable [Line Items]
Declaration Date			Jan. 27, 2021
Date Paid (Payable)			Feb. 26, 2021
Shareholder of Record Date			Feb. 12, 2021
Dividend Amount			$ 0.380
Group Five
Dividends Payable [Line Items]
Declaration Date			Oct. 28, 2020
Date Paid (Payable)			Nov. 30, 2020
Shareholder of Record Date			Nov. 16, 2020
Dividend Amount			$ 0.375
Group Six
Dividends Payable [Line Items]
Declaration Date			Jul. 29, 2020
Date Paid (Payable)			Aug. 28, 2020
Shareholder of Record Date			Aug. 14, 2020
Dividend Amount			$ 0.375
Group Seven
Dividends Payable [Line Items]
Declaration Date			Apr. 29, 2020
Date Paid (Payable)			May 29, 2020
Shareholder of Record Date			May 15, 2020
Dividend Amount			$ 0.375
Group Eight
Dividends Payable [Line Items]
Declaration Date			Jan. 29, 2020
Date Paid (Payable)			Feb. 28, 2020
Shareholder of Record Date			Feb. 14, 2020
Dividend Amount			$ 0.375

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Significant Segment Financial Data (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	$ 98.1	$ 87.4	$ 333.5	$ 301.7
Segment Profit (Loss)	0.0	0.3	21.6	18.6
Capital Expenditures	39.0	44.8	81.5	93.6
Segment Assets	1,509.0	1,423.9	1,509.0	1,423.9	$ 1,477.9
Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	88.1	80.8	343.4	304.4
Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	10.0	6.6	(9.9)	(2.7)
Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	32.6	27.5	151.3	131.4
Segment Profit (Loss)	(4.1)	(3.6)	12.1	8.6
Capital Expenditures	28.5	27.4	51.7	50.0
Segment Assets	906.2	845.0	906.2	845.0
Gas Segment | Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	23.1	20.0	154.3	130.9
Gas Segment | Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	9.5	7.5	(3.0)	0.5
Gas Segment | Other Operating Revenue Non-Regulated
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	0.0	0.0	0.0	0.0
Electric
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	65.5	59.9	182.2	170.3
Segment Profit (Loss)	4.4	4.4	10.7	10.1
Capital Expenditures	10.1	16.0	28.8	39.9
Segment Assets	583.6	556.3	583.6	556.3
Electric | Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	65.0	60.8	189.1	173.5
Electric | Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	0.5	(0.9)	(6.9)	(3.2)
Electric | Other Operating Revenue Non-Regulated
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	0.0	0.0	0.0	0.0
All Other Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Segment Profit (Loss)	(0.3)	(0.5)	(1.3)	(0.1)
Capital Expenditures	0.4	1.4	1.0	3.7
Segment Assets	$ 19.2	$ 22.6	19.2	$ 22.6
Non- Regulated Operation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Segment Profit (Loss)			$ 0.1

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Details on Long Term Debt (Detail) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020
Debt Instrument [Line Items]
Total Long-Term Debt	$ 515.1	$ 535.4	$ 539.1
Less: Unamortized Debt Issuance Costs	3.7	3.8	3.8
Long-Term Debt	511.4	531.6	535.3
Less: Current Portion	10.1	8.5	6.3
Total Long-Term Debt, Less Current Portion	501.3	523.1	529.0
6.33% Senior Notes, Due May 1, 2022
Debt Instrument [Line Items]
Total Long-Term Debt	0.0	15.0	20.0
3.70% Senior Notes, Due August 1, 2026
Debt Instrument [Line Items]
Total Long-Term Debt	30.0	30.0	30.0
3.43% Senior Notes, Due December 18, 2029
Debt Instrument [Line Items]
Total Long-Term Debt	30.0	30.0	30.0
Unitil Energy Systems Inc | First Mortgage Bonds 8.49% Senior Secured Notes, Due October 14, 2024
Debt Instrument [Line Items]
Total Long-Term Debt	3.0	3.0	4.5
Unitil Energy Systems Inc | First Mortgage Bonds 6.96% Senior Secured Notes, Due September 1, 2028
Debt Instrument [Line Items]
Total Long-Term Debt	14.0	16.0	16.0
Unitil Energy Systems Inc | First Mortgage Bonds 8.00% Senior Secured Notes, Due May 1, 2031
Debt Instrument [Line Items]
Total Long-Term Debt	15.0	15.0	15.0
Unitil Energy Systems Inc | First Mortgage Bonds 6.32% Senior Secured Notes, Due September 15, 2036
Debt Instrument [Line Items]
Total Long-Term Debt	15.0	15.0	15.0
Unitil Energy Systems Inc | First Mortgage Bonds 4.18% Senior Secured Notes Due November 30, 2048
Debt Instrument [Line Items]
Total Long-Term Debt	30.0	30.0	30.0
Unitil Energy Systems Inc | Senior Notes Three Point Five Eight Percent Due September Fifteen Twenty Fourty [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	27.5	27.5	27.5
Fitchburg Gas and Electric Light Company | 6.75% Senior Notes, Due November 30, 2023
Debt Instrument [Line Items]
Total Long-Term Debt		1.9	3.8
Fitchburg Gas and Electric Light Company | 6.79% Senior Notes, Due October 15, 2025
Debt Instrument [Line Items]
Total Long-Term Debt	10.0	10.0	10.0
Fitchburg Gas and Electric Light Company | 3.52% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt	10.0	10.0	10.0
Fitchburg Gas and Electric Light Company | 7.37% Notes, Due January 15, 2029
Debt Instrument [Line Items]
Total Long-Term Debt	9.6	10.8	10.8
Fitchburg Gas and Electric Light Company | 5.90% Notes, Due December 15, 2030
Debt Instrument [Line Items]
Total Long-Term Debt	15.0	15.0	15.0
Fitchburg Gas and Electric Light Company | 7.98% Notes, Due June 1, 2031
Debt Instrument [Line Items]
Total Long-Term Debt	14.0	14.0	14.0
Fitchburg Gas and Electric Light Company | 4.32% Senior Notes, Due November 1, 2047
Debt Instrument [Line Items]
Total Long-Term Debt	15.0	15.0	15.0
Fitchburg Gas and Electric Light Company | Senior Notes Three Point Seven Eight Percent Due September Fifteen Twenty Fourty [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	27.5	27.5	27.5
Northern Utilities Inc | 3.52% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt	20.0	20.0	20.0
Northern Utilities Inc | 4.32% Senior Notes, Due November 1, 2047
Debt Instrument [Line Items]
Total Long-Term Debt	30.0	30.0	30.0
Northern Utilities Inc | 7.72% Senior Notes, Due December 3, 2038
Debt Instrument [Line Items]
Total Long-Term Debt	50.0	50.0	50.0
Northern Utilities Inc | 4.42% Senior Notes, Due October 15, 2044
Debt Instrument [Line Items]
Total Long-Term Debt	50.0	50.0	50.0
Northern Utilities Inc | 4.04% Senior Notes, Due September 12, 2049
Debt Instrument [Line Items]
Total Long-Term Debt	40.0	40.0	40.0
Northern Utilities Inc | Senior Notes Three Point Seven Eight Percent Due September Fifteen Twenty Fourty [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	40.0	40.0	40.0
Granite State Gas Transmission Inc | 3.72% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt	15.0	15.0	$ 15.0
Unitil Realty Corp [Member] | Senior Notes Two Point Six Four Percent Due December Eighteen Twenty Thirty [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	$ 4.5	$ 4.7

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Details on Long Term Debt (Parenthetical) (Detail)	9 Months Ended		12 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
6.33% Senior Notes, Due May 1, 2022
Debt Instrument [Line Items]
Stated interest rate	6.33%	6.33%	6.33%
Debt instrument due date	May 01, 2022	May 01, 2022	May 01, 2022
3.70% Senior Notes, Due August 1, 2026
Debt Instrument [Line Items]
Stated interest rate	3.70%	3.70%	3.70%
Debt instrument due date	Aug. 01, 2026	Aug. 01, 2026	Aug. 01, 2026
3.43% Senior Notes, Due December 18, 2029
Debt Instrument [Line Items]
Stated interest rate	3.43%	3.43%	3.43%
Debt instrument due date	Dec. 18, 2029	Dec. 18, 2029	Dec. 18, 2029
First Mortgage Bonds 8.49% Senior Secured Notes, Due October 14, 2024
Debt Instrument [Line Items]
Stated interest rate	8.49%	8.49%	8.49%
Debt instrument due date	Oct. 14, 2024	Oct. 14, 2024	Oct. 14, 2024
First Mortgage Bonds 6.96% Senior Secured Notes, Due September 1, 2028
Debt Instrument [Line Items]
Stated interest rate	6.96%	6.96%	6.96%
Debt instrument due date	Sep. 01, 2028	Sep. 01, 2028	Sep. 01, 2028
First Mortgage Bonds 8.00% Senior Secured Notes, Due May 1, 2031
Debt Instrument [Line Items]
Stated interest rate	8.00%	8.00%	8.00%
Debt instrument due date	May 01, 2031	May 01, 2031	May 01, 2031
First Mortgage Bonds 6.32% Senior Secured Notes, Due September 15, 2036
Debt Instrument [Line Items]
Stated interest rate	6.32%	6.32%	6.32%
Debt instrument due date	Sep. 15, 2036	Sep. 15, 2036	Sep. 15, 2036
First Mortgage Bonds 4.18% Senior Secured Notes Due November 30, 2048
Debt Instrument [Line Items]
Stated interest rate	4.18%	4.18%	4.18%
Debt instrument due date	Nov. 30, 2048	Nov. 30, 2048	Nov. 30, 2048
6.75% Senior Notes, Due November 30, 2023
Debt Instrument [Line Items]
Stated interest rate	6.75%	6.75%	6.75%
Debt instrument due date	Nov. 30, 2023	Nov. 30, 2023	Nov. 30, 2023
6.79% Senior Notes, Due October 15, 2025
Debt Instrument [Line Items]
Stated interest rate	6.79%	6.79%	6.79%
Debt instrument due date	Oct. 15, 2025	Oct. 15, 2025	Oct. 15, 2025
3.52% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Stated interest rate	3.52%	3.52%	3.52%
Debt instrument due date	Nov. 01, 2027	Nov. 01, 2027	Nov. 01, 2027
7.37% Notes, Due January 15, 2029
Debt Instrument [Line Items]
Stated interest rate	7.37%	7.37%	7.37%
Debt instrument due date	Jan. 15, 2029	Jan. 15, 2029	Jan. 15, 2029
5.90% Notes, Due December 15, 2030
Debt Instrument [Line Items]
Stated interest rate	5.90%	5.90%	5.90%
Debt instrument due date	Dec. 15, 2030	Dec. 15, 2030	Dec. 15, 2030
7.98% Notes, Due June 1, 2031
Debt Instrument [Line Items]
Stated interest rate	7.98%	7.98%	7.98%
Debt instrument due date	Jun. 01, 2031	Jun. 01, 2031	Jun. 01, 2031
4.32% Senior Notes, Due November 1, 2047
Debt Instrument [Line Items]
Stated interest rate	4.32%	4.32%	4.32%
Debt instrument due date	Nov. 01, 2047	Nov. 01, 2047	Nov. 01, 2047
7.72% Senior Notes, Due December 3, 2038
Debt Instrument [Line Items]
Stated interest rate	7.72%	7.72%	7.72%
Debt instrument due date	Dec. 03, 2038	Dec. 03, 2038	Dec. 03, 2038
4.42% Senior Notes, Due October 15, 2044
Debt Instrument [Line Items]
Stated interest rate	4.42%	4.42%	4.42%
Debt instrument due date	Oct. 15, 2044	Oct. 15, 2044	Oct. 15, 2044
4.04% Senior Notes, Due September 12, 2049
Debt Instrument [Line Items]
Stated interest rate	4.04%	4.04%	4.04%
Debt instrument due date	Sep. 12, 2049	Sep. 12, 2049	Sep. 12, 2049
3.72% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Stated interest rate	3.72%	3.72%	3.72%
Debt instrument due date	Nov. 01, 2027	Nov. 01, 2027	Nov. 01, 2027
First Mortgage Bonds Three Point Fifty Eight Percent Senior Secured Notes Due September Fifteen Twenty Forty [Member]
Debt Instrument [Line Items]
Stated interest rate	3.58%	3.58%	3.58%
Debt instrument due date	Sep. 15, 2040	Sep. 15, 2040	Sep. 15, 2040
Senior Notes Three Point Seventy Eight Percent Due September Fifteen Twenty Forty [Member]
Debt Instrument [Line Items]
Stated interest rate	3.78%	3.78%	3.78%
Debt instrument due date	Sep. 15, 2040	Sep. 15, 2040	Sep. 15, 2040
Senior Notes Two Point Six Four Percent Due December Eighteen Twenty Thirty [Member]
Debt Instrument [Line Items]
Stated interest rate	2.64%	2.64%	2.64%
Debt instrument due date	Dec. 18, 2030	Dec. 18, 2030	Dec. 18, 2030

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Estimated Fair Value of Long Term Debt (Detail) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020
Fair Value, Inputs, Level 2
Debt Instrument [Line Items]
Estimated Fair Value of Long-Term Debt	$ 598.2	$ 633.1	$ 631.7

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Debt and Financing Arrangements - Additional Information (Detail) - USD ($)			1 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended
	Dec. 18, 2020	Sep. 15, 2020	Jul. 25, 2018	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Line of Credit Facility [Line Items]
Issuance of long-term debt		$ 500,000
Weighted average interest rate on short term borrowings				1.20%	1.30%	1.20%	1.80%	1.70%
Capital lease obligation, current				$ 200,000		$ 200,000
Capital lease obligation, noncurrent				200,000		200,000
Accounts Payable				29,500,000	$ 25,100,000	29,500,000	$ 25,100,000	$ 33,200,000
Total rental expense under operating leases				500,000	500,000	1,400,000	1,400,000
Net Utility Plant				1,237,300,000	$ 1,185,300,000	1,237,300,000	1,185,300,000	1,193,200,000
Guarantee outstanding				700,000		700,000
Operating lease obligations						1,400,000	$ 1,400,000
Other current operating lease obligation				1,600,000		1,600,000
Other noncurrent operating lease obligation				$ 3,500,000		$ 3,500,000
Operating lease, weighted average remaining lease term				3 years 8 months 12 days	4 years	3 years 8 months 12 days	4 years
Operating lease, weighted average discount rate percentage				4.00%	4.40%	4.00%	4.40%
Long-term Debt, Gross				$ 515,100,000	$ 539,100,000	$ 515,100,000	$ 539,100,000	535,400,000
Payments of Debt Issuance Costs							500,000
Guarantee Term Period						1 year
Assets under Capital Leases [Member]
Line of Credit Facility [Line Items]
Net Utility Plant				700,000	1,100,000	$ 700,000	1,100,000	1,000,000.0
Net Utility Plant, accumulated amortization				$ 300,000	600,000	$ 300,000	600,000	500,000
Northern Utilities Inc
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization				65.00%		65.00%
Natural gas storage inventory				$ 9,700,000	6,000,000.0	$ 9,700,000	6,000,000.0	5,400,000
Accounts Payable				100,000	100,000	100,000	100,000	1,000,000.0
Unitil Reality Corp [Member]
Line of Credit Facility [Line Items]
Long-term debt, stated interest rate	2.64%
Long-term debt, maturity date	Dec. 18, 2020
Long-term Debt, Gross	$ 4,700,000
Payments of Debt Issuance Costs	$ 100,000
Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility				$ 120,000,000.0	$ 120,000,000.0	120,000,000.0	$ 120,000,000.0	$ 120,000,000.0
Proceeds from lines of credit						170,700,000
Repayments of lines of credit						$ 194,900,000
Credit Facility | Second Amended Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility			$ 120,000,000
Sublimit for the issuance of standby letters of credit			$ 25,000,000
Revolving credit facility termination date			Jul. 25, 2023
Increase in borrowing limit			$ 50,000,000
Credit Facility | Second Amended Credit Facility | London Interbank Offered Rate
Line of Credit Facility [Line Items]
Credit facility, daily fluctuating rate of interest			1.125%
Credit Facility | Revolving Credit Facility
Line of Credit Facility [Line Items]
Percentage of capitalization						The affirmative and negative covenants under the Credit Facility apply until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At September 30, 2021, September 30, 2020 and December 31, 2020, the Company was in compliance with the covenants contained in the Credit Facility in effect on those dates.
Three Point Five Eight Percentage Mortage BondsDue September Tweleve twenty Fourty [Member] | Unitil Energy
Line of Credit Facility [Line Items]
Long-term debt, maturity date		Sep. 15, 2040
Three Point Five Eight Percentage Mortage BondsDue September Tweleve twenty Fourty [Member] | Unitil Energy Systems Inc [Member]
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount		$ 27,500,000
Long-term debt, stated interest rate		3.58%
3.78% Senior Notes, Due September 15, 2040 | Northern Utilities Inc
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount		$ 40,000,000
Long-term debt, stated interest rate		3.78%
Long-term debt, maturity date		Sep. 15, 2040
3.78% Senior Notes, Due September 15, 2040 | Fitchburg Gas and Electric Light Company
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount		$ 27,500,000
Long-term debt, stated interest rate		3.78%
Long-term debt, maturity date		Sep. 15, 2040

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Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility (Detail) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020
Debt Instrument [Line Items]
Short-Term Borrowings Outstanding	$ 30.5	$ 54.7	$ 17.3
Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility, limit	120.0	120.0	120.0
Short-Term Borrowings Outstanding	30.5	54.7	17.3
Letter of Credit Outstanding		0.1	0.1
Available revolving credit facility	$ 89.5	$ 65.2	$ 102.6

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Debt and Financing Arrangements - Classification of the Company Lease Obligations (Detail) - USD ($) $ in Thousands	Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020
Operating Lease Obligations:
Other Current Liabilities (current portion)	$ 1,600
Other Noncurrent Liabilities (long-term portion)	3,500
Capital Lease Obligations:
Other Current Liabilities (current portion)	200
Other Noncurrent Liabilities (long-term portion)	200
Lease Obligations [Member]
Operating Lease Obligations:
Other Current Liabilities (current portion)	1,600	$ 1,500	$ 1,600
Other Noncurrent Liabilities (long-term portion)	3,500	3,700	4,000
Total Operating Lease Obligations	5,100	5,200	5,600
Capital Lease Obligations:
Other Current Liabilities (current portion)	200	200	200
Other Noncurrent Liabilities (long-term portion)	200	200	300
Total Capital Lease Obligations	353	400	500
Total Lease Obligations	$ 5,500	$ 5,600	$ 6,100

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Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases (Detail) - Lease Obligations [Member] - USD ($) $ in Thousands	Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020
Operating leases
Rest of 2021	$ 479
2022	1,695
2023	1,399
2024	1,069
2025	503
2026-2030	320
Total Payments	5,465
Less: Interest	365
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	5,100	$ 5,200	$ 5,600
Capital lease
Rest of 2021	39
2022	150
2023	107
2024	52
2025	20
2026-2030	0
Total Payments	368
Less: Interest	15
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$ 353	$ 400	$ 500

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Common Stock And Preferred Stock - Additional Information (Detail) - USD ($)			3 Months Ended		9 Months Ended		12 Months Ended
	Aug. 06, 2021	Jan. 26, 2021	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Class of Stock [Line Items]
Common stock, shares outstanding			15,971,962	15,005,881	15,971,962	15,005,881	15,012,310
Common stock, shares issued			925,493	6,650	936,512	16,849
Proceeds from Issuance of Common Stock					$ 45,300,000	$ 800,000
Restricted Stock Units Granted					$ 49.61	$ 54.41
Share based compensation expense					$ 1,400,000	$ 2,100,000
Percentage of fully-vested restricted stock units that directors will receive in common shares when settled					70.00%
Fair value of liabilities associated with fully vested RSUs that will be settled in cash			$ 800,000	$ 600,000	$ 800,000	600,000	$ 800,000
Percentage of fully-vested restricted stock units that directors will receive in cash when settled					30.00%
Preferred Stock			200,000	200,000	$ 200,000	200,000	$ 200,000
Maximum
Class of Stock [Line Items]
Dividend declared			$ 100,000	$ 100,000	$ 100,000	$ 100,000
Restricted Stock
Class of Stock [Line Items]
Restricted stock vesting period					4 years
Restricted stock non-vested			57,408	59,813	57,408	59,813
Unrecognized share based compensation			$ 700,000		$ 700,000
Share compensation recognition period					2 years 8 months 12 days
Restricted Stock Units Granted		23,140
Aggregate Market Value		$ 900,000
Forfeitures under the stock plan					0
Cancellations under the stock plan					0
Restricted Stock | Maximum
Class of Stock [Line Items]
Restricted stock available for awards			677,500		677,500
Restricted stock that may be awarded in any one calendar year to any one participant			20,000		20,000
Restricted Stock | Vesting Annually
Class of Stock [Line Items]
Restricted stock vesting percentage annually					25.00%
Restricted Stock Units (RSUs)
Class of Stock [Line Items]
Restricted Stock Units Granted					0
Restricted stock units outstanding				39,057		39,057
Weighted-Average Stock Price				$ 41.54		$ 41.54
Series 6 | Unitil Energy Systems Inc
Class of Stock [Line Items]
Preferred stock, outstanding			1,861	1,887	1,861	1,887	1,887
Preferred Stock			$ 200,000	$ 200,000	$ 200,000	$ 200,000	$ 200,000
Dividend rate					6.00%	6.00%	6.00%
Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Proceeds from Issuance of Common Stock					$ 801,200
Dividend and Distribution Reinvestment and Share Purchase Plan | Average
Class of Stock [Line Items]
Common stock price per share				$ 48.52		$ 48.52
Dividend and Distribution Reinvestment and Share Purchase Plan | Common Stock
Class of Stock [Line Items]
Common stock, shares issued					16,512
Over-Allotment Option [Member]
Class of Stock [Line Items]
Number of shares granted over-allotment option to purchase additional shares	30 days
Sale of Stock, Number of Shares Issued in Transaction	120,000
Proceeds from Issuance of Private Placement	$ 5,900,000
Common Stock Offering [Member]
Class of Stock [Line Items]
Common stock, shares issued	800,000
Common stock price per share	$ 50.80
Proceeds from Issuance Initial Public Offering	$ 38,600,000

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Restricted Stock Units Issued (Detail) - Restricted Stock Units (RSUs)	9 Months Ended
	Sep. 30, 2021 $ / shares shares
Restricted Stock Units
Beginning Restricted Stock Units | shares	43,192
Restricted Stock Units Granted | shares	0
Dividend Equivalents Earned | shares	1,032
Restricted Stock Units Settled | shares	0
Ending Restricted Stock Units | shares	44,224
Weighted-Average Stock Price
Beginning Restricted Stock Units | $ / shares	$ 41.34
Restricted Stock Units Granted | $ / shares	0
Dividend Equivalents Earned | $ / shares	48.10
Restricted Stock Units Settled | $ / shares	0
Ending Restricted Stock Units | $ / shares	$ 41.49

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Regulatory Matters - Additional Information (Detail)																1 Months Ended	9 Months Ended		12 Months Ended
	Oct. 01, 2021 USD ($)	Aug. 24, 2021 USD ($)	Aug. 02, 2021 USD ($)	May 27, 2021 USD ($)	May 01, 2021 USD ($)	Apr. 02, 2021 USD ($)	Mar. 09, 2021 USD ($)	Mar. 01, 2021 USD ($)	Nov. 30, 2020 USD ($)	Nov. 02, 2020 USD ($)	Mar. 26, 2020 USD ($)	Feb. 28, 2020 USD ($)	Jan. 31, 2020 USD ($)	Oct. 29, 2019 USD ($)	Nov. 01, 2018 USD ($)	Mar. 31, 2020 USD ($)	Sep. 30, 2021 USD ($)	Sep. 30, 2020	Dec. 31, 2020	Dec. 31, 2017	Jun. 30, 2027 MW	Dec. 31, 2022 MW	Mar. 10, 2021 MW	Nov. 05, 2020	May 31, 2019 MW	Aug. 09, 2018 MW	Jul. 31, 2018 MW	Jun. 30, 2017 MW
Regulatory Assets [Line Items]
Corporate income tax rate																	21.00%	21.00%
Approved annual increase in rates											$ 3,600,000	$ 4,600,000				$ 3,700,000
Increase in annual base rate											3.60%
Requested annual increase in rates					$ 1,100,000
Tax Year 2018
Regulatory Assets [Line Items]
Corporate income tax rate																	21.00%		21.00%	21.00%
Other Restructuring
Regulatory Assets [Line Items]
Cost recovery period, years																	2 years
Offshore Wind Energy
Regulatory Assets [Line Items]
Power generation facility | MW																					1,600
Northern Utilities Inc
Regulatory Assets [Line Items]
Approved annual increase in rates				$ 4,500,000		$ 12,000,000.0
Increase in annual base rate						4.40%
Northern Utilities Inc | ME
Regulatory Assets [Line Items]
Percentage of approved return on equity											9.48%
Percentage of approved return on equity, reflecting on equity											50.00%
Percentage of approved return on equity, reflecting on debt											50.00%
Customer information system potential excess costs							$ 5,000,000.0
Customer information system costs							$ 36,800,000
Northern Utilities Inc | New Hampshire
Regulatory Assets [Line Items]
Requested annual increase in rates			$ 7,800,000
Requested annual increase in rates Percent			8.10%
Northern Utilities Inc | New Hampshire | Subsequent Event [Member]
Regulatory Assets [Line Items]
Approved annual increase in rates	$ 2,600,000
Fitchburg Gas and Electric Light Company
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue										$ 1,400,000
Percentage of approved return on equity													9.70%
Percentage of approved return on equity, reflecting on equity													52.45%
Percentage of approved return on equity, reflecting on debt													47.55%
Requested annual increase in rates														$ 1,100,000	$ 900,000
Revenue impact threshold													$ 100,000
Fitchburg Gas and Electric Light Company | Offshore Wind Energy
Regulatory Assets [Line Items]
Power generation facility | MW																											400
Remuneration Percentage																								2.75%				2.75%
Fitchburg Gas and Electric Light Company | Offshore Wind Energy | First Solicitation [Member]
Regulatory Assets [Line Items]
Power generation facility | MW																										1,600
Fitchburg Gas and Electric Light Company | Offshore Wind Energy | Second Solicitation [Member]
Regulatory Assets [Line Items]
Power generation facility | MW																							1,600		1,600		800
Fitchburg Gas and Electric Light Company | Offshore Wind Energy | Second Rate Step Adjustments
Regulatory Assets [Line Items]
Power generation facility | MW																											800
Fitchburg Gas and Electric Light Company | Qualified Clean Energy
Regulatory Assets [Line Items]
Power generation capacity | MW																											9,554,940
Fitchburg Gas and Electric Light Company | Minimum [Member] | Offshore Wind Energy
Regulatory Assets [Line Items]
Power generation facility | MW																												400
Fitchburg Gas and Electric Light Company | Scenario Forecast
Regulatory Assets [Line Items]
Power generation capacity | MW																						9,450,000
Fitchburg Gas Company
Regulatory Assets [Line Items]
Percentage of approved return on equity												9.70%
Percentage of approved return on equity, reflecting on equity												52.45%
Percentage of approved return on equity, reflecting on debt												47.55%
Regulatory assets approved increase in revenue due to be recovered					$ 2,200,000
Approved annual increase in rates								$ 900,000					$ 1,100,000
Approved annual increase in rates																	$ 900,000
Apporved annual decrease in rates																	200,000
Revenue impact threshold												$ 40,000
Granite State
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue		$ 100,000							$ 1,300,000
Spending cap																	$ 14,600,000

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Environmental Matters - Additional Information (Detail) - Environmental Restoration Costs $ in Millions	9 Months Ended
	Sep. 30, 2021 USD ($)
Site Contingency [Line Items]
Estimated Costs Accrued For Remediation	$ 0.8
Maine
Site Contingency [Line Items]
Amortization period for environmental costs	5 years
New Hampshire
Site Contingency [Line Items]
Amortization period for environmental costs	7 years

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Company's Liability for Environmental Obligations (Detail) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	$ 2.1	$ 2.7
Additions	0.6	0.1
Less: Payments / Reductions	0.3	0.6
Total Balance at End of Period	2.4	2.2
Less: Current Portion	0.7	0.3	$ 0.3
Noncurrent Balance at End of Period	$ 1.7	$ 1.9	$ 1.8

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Differences Between Provisions for Income Taxes and Provisions Calculated at Statutory Federal Tax Rate (Detail)	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
Income Tax Examination [Line Items]
Statutory Federal Income Tax Rate	21.00%	21.00%
State Income Taxes, net	6.00%	6.00%
Utility Plant Differences	(3.00%)	(5.00%)
Other, net	0.00%	1.00%
Effective Income Tax Rate	24.00%	23.00%

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Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	9 Months Ended		12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Taxes [Line Items]
Corporate federal income tax			21.00%	21.00%
Regulatory Liability	$ 49.8	$ 55.3	$ 56.0	$ 55.3	$ 49.8
Regulatory liability, expected flow back to customers					47.1			$ 48.9
Regulatory liability, expected pass back to ratepayers			$ 0.3		0.3	$ 1.7		1.8
Net Operating Loss Carryforwards Utilized For Income Taxes					5.4
Percentage of employment retention credit			50.00%
Employment retention duties capacity			100.00%
Employment tax expense		0.6	$ 0.4
Consolidated Appropriations Act 2021 [Member]
Income Taxes [Line Items]
Percentage of employment retention credit	70.00%
Employment retention duties capacity	100.00%
Minimum
Income Taxes [Line Items]
Average Rate Assumption Method estimated flow back period			15 years
Maximum
Income Taxes [Line Items]
Average Rate Assumption Method estimated flow back period			20 years
Income Tax Related Liabilities
Income Taxes [Line Items]
Regulatory Liability	$ 45.5	$ 45.8	$ 44.6	$ 45.8	$ 45.5			$ 48.9
Gas Ratepayers | Massachusetts And Maine [Member]
Income Taxes [Line Items]
Regulatory liability, expected flow back to customers			$ 2.7
Net Operating Loss Carryforward Assets
Income Taxes [Line Items]
Regulatory liability, expected pass back to ratepayers							$ 2.0
Tax Year 2018
Income Taxes [Line Items]
Corporate federal income tax			21.00%		21.00%			21.00%

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Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail) - Benefit Plan Costs	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	2.50%	3.25%
Rate of Compensation Increase	3.00%	3.00%
Expected Long-term rate of return on plan assets	7.50%	7.40%
Health Care Cost Trend Rate Assumed for Next Year	6.60%	7.00%
Ultimate Health Care Cost Trend Rate	4.50%	4.50%
Year that Ultimate Health Care Cost Trend Rate is reached	2029	2029

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Components of Retirement Plan Costs (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 868	$ 829	$ 2,604	$ 2,491
Interest Cost	1,250	1,445	3,752	4,332
Expected Return on Plan Assets	(2,422)	(2,254)	(7,268)	(6,764)
Prior Service Cost Amortization	76	80	226	240
Actuarial Loss Amortization	2,021	1,618	6,065	4,854
Sub-total	1,793	1,718	5,379	5,153
Amounts Capitalized and Deferred	(944)	(861)	(2,544)	(2,298)
Net Periodic Benefit Cost Recognized	849	857	2,835	2,855
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	759	673	2,275	2,023
Interest Cost	685	782	2,055	2,341
Expected Return on Plan Assets	(627)	(515)	(1,881)	(1,547)
Prior Service Cost Amortization	302	301	906	907
Actuarial Loss Amortization	260	187	784	559
Sub-total	1,379	1,428	4,139	4,283
Amounts Capitalized and Deferred	(904)	(860)	(2,358)	(2,087)
Net Periodic Benefit Cost Recognized	475	568	1,781	2,196
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	89	70	266	212
Interest Cost	114	137	343	412
Prior Service Cost Amortization	14	15	42	43
Actuarial Loss Amortization	372	259	1,117	777
Sub-total	589	481	1,768	1,444
Amounts Capitalized and Deferred	(178)	(144)	(534)	(434)
Net Periodic Benefit Cost Recognized	$ 411	$ 337	$ 1,234	$ 1,010

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Retirement Benefit Obligations - Additional Information (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2021 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Company's contributions	$ 4.1
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Company's contributions	2.8
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Benefit payments under SERP Plan	0.5
Expected additional benefit payments for the remainder of 2020	$ 0.1