10-Q

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM

10-Q

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

For the quarterly period ended

June 30, 2021

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

For the transition period from

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.

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 July 30, 2021
Common Stock, no par value		15,047,468 Shares

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;

•

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:

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.

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 $1,209.8 million at June 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 with regard to certain bookkeeping, accounting and reporting requirements. Unitil’s utility operations related to wholesale and interstate energy business activities are also regulated by the FERC. Unitil’s distribution utilities are subject to regulation by the applicable state public utility commissions, with regard to their rates, issuance of securities and other accounting and operational matters: Unitil Energy is subject to regulation by the New Hampshire Public Utilities Commission (NHPUC); Fitchburg is subject to regulation by the Massachusetts Department of Public Utilities (MDPU); 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 the targeted revenue decoupling amounts is recognized as an increase or a decrease in Accrued Revenue which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases and other authorized adjustments that the Company files with the MDPU. The Company estimates that revenue decoupling currently applies to approximately 27% and 11% of Unitil’s total annual electric and gas sales volumes, respectively.

RESULTS OF OPERATIONS

The following section of MD&A compares the results of operations for each of the two fiscal periods ended June 30, 2021 and June 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. In addition, approximately 27% and 11% of the Company’s total annual electric and gas sales volumes, respectively, are currently decoupled and changes in sales to existing customers do not affect GAAP gross margin and adjusted gross margin.

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 revenue, is a meaningful measure to inform investors of the Company’s profitability from gas and electric sales in the period.


Three Months Ended June 30, 2021 ($ millions)
	Gas			Electric			Non- Regulated and Other			Total
Total Operating Revenue	$	40.0		$	56.6		$	—		$	96.6
Less: Cost of Sales		(15.0	)		(32.3	)		—			(47.3	)
Less: Depreciation and Amortization		(8.2	)		(6.4	)		(0.2	)		(14.8	)

GAAP Gross Margin		16.8			17.9			(0.2	)		34.5
Depreciation and Amortization		8.2			6.4			0.2			14.8

Adjusted Gross Margin	$	25.0		$	24.3		$	—		$	49.3


Three Months Ended June 30, 2020 ($ millions)
	Gas			Electric			Non- Regulated and Other			Total
Total Operating Revenue	$	33.7		$	50.2		$	—		$	83.9
Less: Cost of Sales		(10.8	)		(27.8	)		—			(38.6	)
Less: Depreciation and Amortization		(7.4	)		(5.9	)		(0.2	)		(13.5	)

GAAP Gross Margin		15.5			16.5			(0.2	)		31.8
Depreciation and Amortization		7.4			5.9			0.2			13.5

Adjusted Gross Margin	$	22.9		$	22.4		$	—		$	45.3


Six Months Ended June 30, 2021 ($ millions)
	Gas			Electric			Non- Regulated and Other			Total
Total Operating Revenue	$	118.7		$	116.7		$	—		$	235.4
Less: Cost of Sales		(45.9	)		(68.7	)		—			(114.6	)
Less: Depreciation and Amortization		(16.4	)		(12.9	)		(0.4	)		(29.7	)

GAAP Gross Margin		56.4			35.1			(0.4	)		91.1
Depreciation and Amortization		16.4			12.9			0.4			29.7

Adjusted Gross Margin	$	72.8		$	48.0		$	—		$	120.8


Six Months Ended June 30, 2020 ($ millions)
	Gas			Electric			Non- Regulated and Other			Total
Total Operating Revenue	$	103.9		$	110.4		$	—		$	214.3
Less: Cost of Sales		(38.6	)		(64.9	)		—			(103.5	)
Less: Depreciation and Amortization		(14.8	)		(11.8	)		(0.4	)		(27.0	)

GAAP Gross Margin		50.5			33.7			(0.4	)		83.8
Depreciation and Amortization		14.8			11.8			0.4			27.0

Adjusted Gross Margin	$	65.3		$	45.5		$	—		$	110.8

Gas GAAP Gross Margin was $16.8 million and $56.4 million in the three and six months ended June 30, 2021, respectively, increases of $1.3 million and $5.9 million, respectively, compared to the same periods in 2020. The increase in the three month period was driven by higher rates of $1.8 million, $0.3 million from the net favorable effect of customer growth and warmer weather, and higher depreciation and amortization of $0.8 million. The increase in the six month period was driven by higher rates of $5.1 million and $2.4 million from the net favorable effect of customer growth, colder winter weather and warmer spring weather, partially offset by higher depreciation and amortization of $1.6 million.

Electric GAAP Gross Margin was $17.9 million and $35.1 million in the three and six months ended June 30, 2021, respectively, increases of $1.4 million and $1.4 million, respectively, compared to the same periods in 2020. The increase in the three month period was driven by higher rates of $1.0 million and $0.9 million from the favorable effects of customer growth and warmer early summer weather, partially offset by higher depreciation and amortization of $0.5 million. The increase in the six month period was driven by higher rates of $1.0 million and $1.5 million from the favorable effects of customer growth, colder winter weather and warmer early summer weather, partially offset by higher depreciation and amortization of $1.1 million.

Earnings Overview

The Company’s Net Income was $2.7 million, or $0.18 in Earnings Per Share (EPS), for the second quarter of 2021, a decrease of $0.4 million in Net Income, or $0.03 per share, compared to the second quarter of 2020. For the second quarter of 2021, higher Gas and Electric Adjusted Margins (a

non-GAAP

measure) were more than offset by higher operating expenses compared to the same period in 2020.

For the six months ended June 30, 2021, the Company reported Net Income of $21.6 million, or $1.44 per share, an increase of $3.3 million, or $0.21 per share, compared to the same six month period in 2020. The Company’s earnings in the first six months of 2021 reflect higher Gas and Electric Adjusted Margins (a

non-GAAP

measure), partially offset by higher operating expenses.

Gas Adjusted Gross Margin (a

non-GAAP

measure) was $25.0 million and $72.8 million in the three and six months ended June 30, 2021, respectively, increases of $2.1 million and $7.5 million, respectively, compared to the same periods in 2020. The increase in the three month period was driven by higher rates of $1.8 million and $0.3 million from the net favorable effect of customer growth and warmer weather on gas sales. The increase over the six month period was driven by higher rates of $5.1 million and $2.4 million from the net favorable effect of customer growth, colder winter weather and warmer spring weather.

Gas therm sales increased 0.2% and 4.2% in the three and six month periods ended June 30, 2021, respectively, compared to the same periods in 2020. The increase in gas therm sales in the Company’s service areas 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 six 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 2.4% in the first six months of 2021 compared to the same period in 2020. As of June 30, 2021, the number of gas customers served increased by 1,200 over the previous year.

Electric Adjusted Gross Margin (a

non-GAAP

measure) was $24.3 million and $48.0 million in the three and six months ended June 30, 2021, respectively, increases of $1.9 million and $2.5 million, respectively, compared with the same periods in 2020. The increase in the three month period was driven by higher rates of $1.0 million and $0.9 million from the favorable effects of customer growth and warmer early summer weather. The increase over the six month period was driven by higher rates of $1.0 million and $1.5 million from the favorable effects of customer growth, colder winter weather and warmer early summer weather.

Total electric kilowatt-hour (kWh) sales increased 5.7% and 3.0%, respectively in the three and six month periods ended June 30, 2021 compared to the same periods in 2020. Sales to Residential customers decreased 2.5% and increased 2.8%, respectively, in the three and six month periods ended June 30, 2021 compared to the same periods in 2020. Sales to Commercial and Industrial (C&I) customers increased 11.9% and 3.1%, respectively, in the three and six month periods ended June 30, 2021 compared to the same periods in 2020. The changes in sales to Residential customers reflects customer growth, the positive effects of colder winter weather, warmer early summer weather, and lower Residential electric sales as the economy continues to fully and safely 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 36.1% more Cooling Degree Days (CDD) in the first six months of 2021 compared to the same period in 2020. As of June 30, 2021, the number of electric customers served has increased by 876 over the previous year.

Operation and Maintenance (O&M) expenses increased $2.9 million and $2.0 million in three and six months ended June 30, 2021, respectively, compared to the same periods in 2020. The increase in the three month period reflects higher labor costs of $1.2 million, higher utility operating costs of $1.1 million, and higher professional fees of $0.6 million. The increase in the six month period reflects higher utility operating costs of $1.4 million, higher labor costs of $0.4 million, and higher professional fees of $0.2 million.

Depreciation and Amortization expense increased $1.3 million and $2.7 million in the three and six months ended June 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.

Taxes Other Than Income Taxes increased $0.1 million, or 1.6%, for the three months ended June 30, 2021 compared to the same period in 2020, reflecting higher local property taxes on higher utility plant in service. For the six months ended June 30, 2021, Taxes Other Than Income Taxes decreased $0.2 million, or 1.6%, compared to the same period in 2020, reflecting lower payroll taxes, partially offset by higher local property taxes on higher utility plant in service.

Interest Expense, Net increased $0.4 million and $0.9 million, respectively, in the three and six months ended June 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 $0.3 million and $0.5 million, respectively for the three and six months ended June 30, 2021 compared to the same periods in 2020, reflecting lower retirement benefit and other costs.

Federal and State Income Taxes increased $1.8 million for the six months ended June 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 and July 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 0.2% and 4.2% in the three and six month periods ended June 30, 2021, respectively, compared to the same periods in 2020. In the second quarter of 2021, sales to Residential customers decreased 13.8% and sales to C&I customers increased 4.0%, compared to the same period in 2020. For the six months ended June 30, 2021, sales to Residential and C&I customers increased 0.6% and 5.3%, respectively, compared to the same period in 2020. The increase in gas therm sales in the Company’s service areas 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 six 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 2.4% in the first six months of 2021 compared to the same period in 2020. As of June 30, 2021, the number of gas customers served increased by 1,200 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 six months ended June 30, 2021 and 2020, by major customer class:


Therm Sales (millions)
	Three Months Ended June 30,										Six Months Ended June 30,
	2021		2020		Change			% Change			2021		2020		Change		% Change
Residential		8.1		9.4		(1.3	)		(13.8	%)		31.7		31.5		0.2		0.6	%
Commercial / Industrial		36.4		35.0		1.4			4.0	%		108.0		102.6		5.4		5.3	%

Total		44.5		44.4		0.1			0.2	%		139.7		134.1		5.6		4.2	%

Gas Operating Revenues and Adjusted Gross Margin -

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


Gas Operating Revenues and Gas Adjusted Gross Margin ($ millions)
	Three Months Ended June 30,									Six Months Ended June 30,
	2021		2020		$ Change		% Change			2021		2020		$ Change		% Change
Gas Operating Revenue:
Residential	$	16.0	$	14.2	$	1.8		12.7	%	$	49.4	$	43.7	$	5.7		13.0	%
Commercial / Industrial		24.0		19.5		4.5		23.1	%		69.3		60.2		9.1		15.1	%

Total Gas Operating Revenue	$	40.0	$	33.7	$	6.3		18.7	%	$	118.7	$	103.9	$	14.8		14.2	%

Cost of Gas Sales	$	15.0	$	10.8	$	4.2		38.9	%	$	45.9	$	38.6	$	7.3		18.9	%

Gas Adjusted Gross Margin	$	25.0	$	22.9	$	2.1		9.2	%	$	72.8	$	65.3	$	7.5		11.5	%

Gas Adjusted Gross Margin (a

non-GAAP

The increases in Total Gas Operating Revenue of $6.3 million and $14.8 million in the three and six months ended June 30, 2021, respectively, compared to the same periods in 2020, reflect higher cost 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 5.7% and 3.0%, respectively in the three and six month periods ended June 30, 2021 compared to the same periods in 2020. Sales to Residential customers decreased 2.5% and increased 2.8%, respectively, in the three and six month periods ended June 30, 2021 compared to the same periods in 2020. Sales to C&I customers increased 11.9% and 3.1%, respectively, in the three and six month periods ended June 30, 2021 compared to the same periods in 2020. The changes in sales to Residential customers reflects customer growth, the positive effects of colder winter weather, warmer early summer weather, and lower Residential electric sales as the economy continues to fully and safely 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 36.1% more CDD in the first six months of 2021 compared to the same period in 2020. As of June 30, 2021, the number of electric customers served has increased by 876 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.

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


kWh Sales (millions)
	Three Months Ended June 30,										Six Months Ended June 30,
	2021		2020		Change			% Change			2021		2020		Change		% Change
Residential		149.5		153.3		(3.8	)		(2.5	%)		341.7		332.4		9.3		2.8	%
Commercial / Industrial		224.0		200.1		23.9			11.9	%		455.9		442.0		13.9		3.1	%

Total		373.5		353.4		20.1			5.7	%		797.6		774.4		23.2		3.0	%

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 six month periods ended June 30, 2021 and 2020:


Electric Operating Revenues and Electric Adjusted Gross Margin ($ millions)

	Three Months Ended June 30,									Six Months Ended June 30,
	2021		2020		$ Change		% Change			2021		2020		$ Change		% Change
Electric Operating Revenue:
Residential	$	31.5	$	30.4	$	1.1		3.6	%	$	67.7	$	66.3	$	1.4		2.1	%
Commercial / Industrial		25.1		19.8		5.3		26.8	%		49.0		44.1		4.9		11.1	%

Total Electric Operating Revenue	$	56.6	$	50.2	$	6.4		12.7	%	$	116.7	$	110.4	$	6.3		5.7	%

Cost of Electric Sales	$	32.3	$	27.8	$	4.5		16.2	%	$	68.7	$	64.9	$	3.8		5.9	%

Electric Adjusted Gross Margin	$	24.3	$	22.4	$	1.9		8.5	%	$	48.0	$	45.5	$	2.5		5.5	%

Electric Adjusted Gross Margin (a

non-GAAP

The increases in Total Electric Operating Revenue of $6.4 million and $6.3 million in the three and six months ended June 30, 2021, respectively, compared to the same periods in 2020 reflect higher cost 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 of natural gas purchased and manufactured to supply the Company’s total gas supply requirements and spending on energy efficiency programs. Cost of Gas Sales increased $4.2 million, or 38.9%, and $7.3 million, or 18.9%, in the three and six months ended June 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 efficiency programs. Cost of Electric Sales increased $4.5 million, or 16.2%, and $3.8 million, or 5.9% in the three and six months ended June 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 $2.9 million, or 19.9%, and $2.0 million, or 6.2%, in three and six months ended June 30, 2021, respectively, compared to the same periods in 2020. The increase in the three month period reflects higher labor costs of $1.2 million, higher utility operating costs of $1.1 million, and higher professional fees of $0.6 million. The increase in the six month period reflects higher utility operating costs of $1.4 million, higher labor costs of $0.4 million, and higher professional fees of $0.2 million.

Depreciation and Amortization -

Depreciation and Amortization expense increased $1.3 million, or 9.6%, and $2.7 million, or 10.0%, in the three and six months ended June 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.

Taxes Other Than Income Taxes

Other Expense (Income), Net -

Other Expense (Income), Net decreased $0.3 million, or 21.4%, and $0.5 million, or 17.2%, respectively for the three and six months ended June 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 June 30, 2021 was on par with the same period in 2020 and increased $1.8 million for the six months ended June 30, 2021, 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.


Interest Expense, Net ($ millions)	Three Months Ended June 30,									Six Months Ended June 30,
	2021			2020			Change			2021			2020			Change
Interest Expense
Long-term Debt	$	6.5		$	5.9		$	0.6		$	13.2		$	12.0		$	1.2
Short-term Debt		0.1			0.3			(0.2	)		0.3			0.6			(0.3	)
Regulatory Liabilities		0.1			0.1			—			0.2			0.2			—

Subtotal Interest Expense		6.7			6.3			0.4			13.7			12.8			0.9

Interest (Income)
Regulatory Assets		(0.1	)		(0.2	)		0.1			(0.4	)		(0.4	)		—
AFUDC (1) and Other		(0.3	)		(0.2	)		(0.1	)		(0.3	)		(0.3	)		—

Subtotal Interest (Income)		(0.4	)		(0.4	)		—			(0.7	)		(0.7	)		—

Total Interest Expense, Net	$	6.3		$	5.9		$	0.4		$	13.0		$	12.1		$	0.9

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

Interest Expense, Net increased $0.4 million, or 6.8%, and $0.9 million, or 7.4%, respectively, in the three and six months ended June 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.

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.

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 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 June 30, 2021, June 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

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 $102.8 million for the six months ended June 30, 2021. Total gross repayments were $127.8 million for the six months ended June 30, 2021. The following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of June 30, 2021, June 30, 2020 and December 31, 2020:


	Revolving Credit Facility ($ millions)
	June 30,				December 31,
	2021		2020		2020
Limit	$	120.0	$	120.0	$	120.0
Short-Term Borrowings Outstanding		29.7		74.9		54.7
Letter of Credit Outstanding		—		0.1		0.1

Available	$	90.3	$	45.0	$	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 June 30, 2021, June 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.

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 June 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 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. There was $4.9 million, $3.9 million and $5.4 million of gas storage inventory at June 30, 2021, June 30, 2020 and December 31, 2020, respectively, related to these asset management agreements. The amount of gas inventory released in June 2021 and payable in July 2021 is $0.1 million and is recorded in Accounts Payable at June 30, 2021. The amount of gas inventory released in June 2020 and payable in July 2020 was less than $0.1 million and was recorded in Accounts Payable at June 30, 2020. The amount of gas inventory 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 June 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 estimates, assumptions and judgment, the financial position of the Company could be materially affected and the results of operations of the Company could be materially different than reported. As of June 30, 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 June 30, 2021, the Company and its subsidiaries had 510 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 June 30, 2021, a total of 166 employees of certain of the Company’s subsidiaries were represented by labor unions. The following table details by subsidiary the employees covered by a collective bargaining agreement (CBA) as of June 30, 2021:


	Employees Covered		CBA Expiration
Fitchburg		44		05/31/2022
Northern Utilities NH Division		36		06/07/2025
Northern Utilities ME Division		37		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 or decrease interest expense in future periods. For example, if the average amount of short-term debt outstanding was $25 million for the period of one year, a change in interest rates of 1% would result in a change in annual interest expense of approximately $250,000. The average interest rates on the Company’s short-term borrowings and intercompany money pool transactions for the three months ended June 30, 2021 and June 30, 2020 were 1.2% and 1.5%, respectively. The average interest rates on the Company’s short-term borrowings for the six months ended June 30, 2021 and June 30, 2020 were 1.3% and 2.0%, respectively. The average interest rate on the Company’s short-term borrowings for the twelve months ended December 31, 2020 was 1.7%.

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS (Cont.)

(Millions, except number of shares) (UNAUDITED)


	June 30,				December 31,
	2021		2020		2020
LIABILITIES AND CAPITALIZATION:
Current Liabilities:
Accounts Payable	$	32.6	$	24.7	$	33.2
Short-Term Debt		29.7		74.9		54.7
Long-Term Debt, Current Portion		19.0		6.3		8.5
Regulatory Liabilities		17.1		12.6		5.5
Energy Supply Obligations		9.9		8.4		10.4
Interest Payable		4.9		4.2		5.0
Environmental Obligations		0.4		0.3		0.3
Other Current Liabilities		19.7		17.9		18.5

Total Current Liabilities		133.3		149.3		136.1

Noncurrent Liabilities:
Retirement Benefit Obligations		165.1		147.5		162.3
Deferred Income Taxes, net		115.4		109.0		109.0
Cost of Removal Obligations		105.1		102.6		105.2
Regulatory Liabilities		43.2		44.8		44.3
Environmental Obligations		1.7		1.9		1.8
Other Noncurrent Liabilities		7.2		7.3		6.9

Total Noncurrent Liabilities		437.7		413.1		429.5

Capitalization:
Long-Term Debt, Less Current Portion		505.3		436.4		523.1
Stockholders’ Equity:
Common Equity (Authorized: 25,000,000 and Outstanding: 15,046,469, 14,996,231 and 15,012,310 Shares)		286.8		284.4		285.3
Retained Earnings		113.8		101.1		103.7

Total Common Stock Equity		400.6		385.5		389.0
Preferred Stock		0.2		0.2		0.2

Total Stockholders’ Equity		400.8		385.7		389.2

Total Capitalization		906.1		822.1		912.3

Commitments and Contingencies (Notes 6 & 7)
TOTAL LIABILITIES AND CAPITALIZATION	$	1,477.1	$	1,384.5	$	1,477.9

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions) (UNAUDITED)


	Six Months Ended June 30,
	2021			2020
Operating Activities:
Net Income	$	21.6		$	18.3
Adjustments to Reconcile Net Income to Cas h
Provided by Operating Activities:
Depreciation and Amortization		29.7			27.0
Deferred Tax Provision		6.2			4.8
Changes in Working Capital Items:
Accounts Receivable		11.7			6.8
Accrued Revenue		16.3			15.1
Exchange Gas Receivable		(0.3	)		1.9
Regulatory Liabilities		11.6			5.2
Accounts Payable		(0.6	)		(12.9	)
Other Changes in Working Capital Items		(3.3	)		(8.0	)
Deferred Regulatory and Other Charges		(9.4	)		(0.8	)
Other, net		0.9			0.9

Cash Provided by Operating Activities		84.4			58.3

Investing Activities:
Property, Plant and Equipment Additions		(42.5	)		(48.8	)

Cash (Used in) Investing Activities		(42.5	)		(48.8	)

Financing Activities:
(Repayment of) Proceeds from Short-Term Debt, net		(25.0	)		16.3
Repayment of Long-Term Debt		(7.3	)		(14.4	)
Net Increase (Decrease) in Exchange Gas Financing		0.4			(1.6	)
Dividends Paid		(11.5	)		(11.3	)
Proceeds from Issuance of Common Stock		0.5			0.5

Cash (Used in) Financing Activities		(42.9	)		(10.5	)

Net Decrease in Cash and Cash Equivalents		(1.0	)		(1.0	)
Cash and Cash Equivalents at Beginning of Period		6.0			5.2

Cash and Cash Equivalents at End of Period	$	5.0		$	4.2

Supplemental Cash Flow Information:
Interest Paid	$	13.2		$	12.6
Income Taxes Paid	$	1.0		$	0.6
Payments on Capital Leases	$	0.1		$	0.2
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$	3.9		$	0.9
Right-of-Use Assets Obtained in Exchange for Lease Obligations	$	0.4		$	0.5

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

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 six months ended June 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.

Table of Contents

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.

Table of Contents

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


	Three Months Ended June 30, 2021
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	14.9		$	30.8		$	45.7
C&I		21.8			25.5			47.3
Other		1.3			2.0			3.3

Total Billed and Unbilled Revenue		38.0			58.3			96.3
Rate Adjustment Mechanism Revenue		2.0			(1.7	)		0.3

Total Gas and Electric Operating Revenues	$	40.0		$	56.6		$	96.6



	Three Months Ended June 30, 2020
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	14.3		$	30.2		$	44.5
C&I		19.0			20.5			39.5
Other		1.2			1.5			2.7

Total Billed and Unbilled Revenue		34.5			52.2			86.7
Rate Adjustment Mechanism Revenue		(0.8	)		(2.0	)		(2.8	)

Total Gas and Electric Operating Revenues	$	33.7		$	50.2		$	83.9



	Six Months Ended June 30, 2021
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	52.6		$	68.9		$	121.5
C&I		71.9			51.4			123.3
Other		6.7			3.8			10.5

Total Billed and Unbilled Revenue		131.2			124.1			255.3
Rate Adjustment Mechanism Revenue		(12.5	)		(7.4	)		(19.9	)

Total Gas and Electric Operating Revenues	$	118.7		$	116.7		$	235.4



	Six Months Ended June 30, 2020
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	45.4		$	64.6		$	110.0
C&I		61.3			44.7			106.0
Other		4.2			3.5			7.7

Total Billed and Unbilled Revenue		110.9			112.8			223.7
Rate Adjustment Mechanism Revenue		(7.0	)		(2.4	)		(9.4	)

Total Gas and Electric Operating Revenues	$	103.9		$	110.4		$	214.3

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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 June 30, 2021, June 30, 2020 and December 31, 2020, the Unitil subsidiaries had deposited $1.5 million, $1.4 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 statement

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 factors such as the extent and duration of any shut off 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 their energy commodity portion of bad debts through rate mechanisms. Also, the electric and gas divisions of Fitchburg are authorized to recover through rates past due amounts associated with protected hardship accounts. Evaluating the adequacy of the allowance for doubtful accounts requires judgment about the assumptions used in the analysis. The Company’s experience has been that the assumptions used in evaluating the adequacy of the allowance for doubtful accounts have proven to be reasonably accurate.

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


($ millions)
	June 30,				December 31,
	2021		2020		2020
Allowance for Doubtful Accounts	$	4.6	$	1.4	$	3.3

Accounts Receivable, Net includes $4.5 million, $1.3 million, and $3.1 million of the Allowance for Doubtful Accounts at June 30, 2021, June 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 June 30, 2021, June 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 June 30, 2021, June 30, 2020 and December 31, 2020.


	June 30,				December 31,
Accrued Revenue ($ millions)	2021		2020		2020
Regulatory Assets – Current	$	25.0	$	26.8	$	37.3
Unbilled Revenues		9.6		8.1		13.6

Total Accrued Revenue	$	34.6	$	34.9	$	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 June 30, 2021, June 30, 2020 and December 31, 2020.


	June 30,				December 31,
Exchange Gas Receivable ($ millions)	2021		2020		2020
Northern Utilities	$	4.8	$	3.9	$	4.4
Fitchburg		0.4		0.3		0.5

Total Exchange Gas Receivable	$	5.2	$	4.2	$	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 June 30, 2021, June 30, 2020 and December 31, 2020.


	June 30,				December 31,
Gas Inventory ($ millions)	2021		2020		2020
Natural Gas	$	0.2	$	0.1	$	0.2
Propane		0.3		0.3		0.3
Liquefied Natural Gas & Other		0.1		0.1		0.1

Total Gas Inventory	$	0.6	$	0.5	$	0.6

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Utility Plant -

The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At June 30, 2021, June 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 $105.1 million, $102.6 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 June 30, 2021, June 30, 2020 and December 31, 2020, the Company has recorded $9.8 million, $7.3 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.


	June 30,				December 31,
Regulatory Assets consist of the following ($ millions)	2021		2020		2020
Retirement Benefits	$	105.7	$	80.8	$	103.7
Energy Supply & Other Rate Adjustment Mechanisms		21.5		23.8		34.1
Deferred Storm Charges		3.4		4.9		4.1
Environmental		4.7		6.2		5.2
Income Taxes		3.0		3.8		3.4
Other Deferred Charges		17.8		12.2		14.2

Total Regulatory Assets	$	156.1	$	131.7	$	164.7
Less: Current Portion of Regulatory Assets (1)		25.0		26.8		37.3

Regulatory Assets – noncurrent	$	131.1	$	104.9	$	127.4

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

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Generally, the Company receives a return on investment on its regulatory assets for which a cash outflow has been made. Regulatory Assets at June 30, 2021 include $8.3 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 variety of equity and fixed income mutual funds. These funds are intended to satisfy obligations under the Company’s SERP Plan (See further discussion of the SERP Plan in Note 9.)

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At June 30, 2021, June 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 $5.5 million, $5.6 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.


	June 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2021		2020		2020
Money Market Funds	$	5.5	$	5.6	$	5.7

Total Marketable Securities	$	5.5	$	5.6	$	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 June 30, 2021, June 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 $0.7 million, $0.4 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.


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

Total Marketable Securities	$	0.7	$	0.4	$	0.5


	June 30,				December 31,
Energy Supply Obligations ($ millions)	2021		2020		2020
Current:
Exchange Gas Obligation	$	4.8	$	3.9	$	4.4
Renewable Energy Portfolio Standards		5.0		4.2		5.7
Power Supply Contract Divestitures		0.1		0.3		0.3

Total Energy Supply Obligations - Current		9.9		8.4		10.4
Noncurrent:
Power Supply Contract Divestitures		—		0.1		—

Total Energy Supply Obligations	$	9.9	$	8.5	$	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 seven of these contracts have been constructed and are now operating. 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

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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 March 31, 2021, Fitchburg has fully recovered its power supply-related stranded costs and Unitil Energy has $0.2 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
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 six months ended June 30, 2021 and Jun

30, 2020:


	Gas			Electric			Non- Regulated		Other			Total
Three Months Ended June 30, 2021 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	38.0		$	58.3		$	—	$	—		$	96.3
Rate Adjustment Mechanism Revenue		2.0			(1.7	)		—		—			0.3
Other Operating Revenue – Non-Regulated		—			—			—		—			—

Total Operating Revenues	$	40.0		$	56.6		$	—	$	—		$	96.6

Segment Profit (Loss)		(0.2	)		3.4			0.1		(0.6	)		2.7
Capital Expenditures		18.9			9.2			—		0.3			28.4

Three Months Ended June 30, 2020 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	34.5		$	52.2		$	—	$	—		$	86.7
Rate Adjustment Mechanism Revenue		(0.8	)		(2.0	)		—		—			(2.8	)
Other Operating Revenue – Non-Regulated		—			—			—		—			—

Total Operating Revenues	$	33.7		$	50.2		$	—	$	—		$	83.9

Segment Profit (Loss)		(0.1	)		3.1			—		0.1			3.1
Capital Expenditures		16.8			14.0			—		1.2			32.0

Six Months Ended June 30, 2021 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	131.2		$	124.1		$	—	$	—		$	255.3
Rate Adjustment Mechanism Revenue		(12.5	)		(7.4	)		—		—			(19.9	)
Other Operating Revenue – Non-Regulated		—			—			—		—			—

Total Operating Revenues	$	118.7		$	116.7		$	—	$	—		$	235.4

Segment Profit (Loss)		16.2			6.3			0.1		(1.0	)		21.6
Capital Expenditures		23.2			18.7			—		0.6			42.5
Segment Assets		878.3			577.3			—		21.5			1,477.1

Six Months Ended June 30, 2020 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	110.9		$	112.8		$	—	$	—		$	223.7
Rate Adjustment Mechanism Revenue		(7.0	)		(2.4	)		—		—			(9.4	)
Other Operating Revenue – Non-Regulated		—			—			—		—			—

Total Operating Revenues	$	103.9		$	110.4		$	—	$	—		$	214.3

Segment Profit		12.2			5.7			—		0.4			18.3
Capital Expenditures		22.6			23.9			—		2.3			48.8
Segment Assets		821.1			543.8			—		19.6			1,384.5

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NOTE 4 – DEBT AND FINANCING ARRANGEMENTS

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


($ millions)	June 30,				December 31,
	2021		2020		2020
Unitil Corporation:
6.33% Senior Notes, Due May 1, 2022	$	9.0	$	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		16.0		18.0		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
4.18% Senior Secured Notes, Due November 30, 2048		30.0		30.0		30.0
Fitchburg:
6.75% Senior Notes, Due November 30, 2023		1.9		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
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
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		4.6		—		4.7

Total Long-Term Debt		528.1		446.1		535.4
Less: Unamortized Debt Issuance Costs		3.8		3.4		3.8

Total Long-Term Debt, net of Unamortized Debt Issuance Costs		524.3		442.7		531.6
Less: Current Portion		19.0		6.3		8.5

Total Long-term Debt, Less Current Portion	$	505.3	$	436.4	$	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)	June 30,				December 31,
	2021		2020		2020
Estimated Fair Value of Long-Term Debt	$	597.8	$	516.6	$	633.1

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.


	Revolving Credit Facility ($ millions)
	June 30,				December 31,
	2021		2020		2020
Limit	$	120.0	$	120.0	$	120.0
Short-Term Borrowings Outstanding		29.7		74.9		54.7
Letter of Credit Outstanding		—		0.1		0.1

Available	$	90.3	$	45.0	$	65.2

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The average interest rates on all short-term borrowings and intercompany money pool transactions were 1.2% and 1.5% for the three months ended June 30, 2021 and June 30, 2020, respectively. The average interest rates on all short-term borrowings and intercompany money pool transactions were 1.3% and 2.0% for the six months ended June 30, 2021 and June 30, 2020, respectively. The average interest rate on all short-term borrowings for the twelve months ended December 31, 2020 was 1.7%.

million of costs associated with these issuances have been recorded as a reduction to Long-Term Debt on the Consolidated Balance Sheets.

Guarantees

Leases

Unitil’s subsidiaries lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements.

Total rental expense under operating leases charged to operations for the three months ended June 30, 2021 and 2020 amounted to $0.5 million and $0.4 million, respectively. Total rental expense under operating leases charged to operations for the six months ended June 30, 2021 and 2020 amounted to $1.0

million and $0.8 million, respectively.

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


	June 30,				December 31,
Lease Obligations ($ millions)	2021		2020		2020
Operating Lease Obligations:
Other Current Liabilities (current portion)	$	1.5	$	1.3	$	1.5
Other Noncurrent Liabilities (long-term portion)		3.4		3.2		3.7

Total Operating Lease Obligations	$	4.9	$	4.5	$	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	$	5.3	$	5.0	$	5.6

Cash paid for amounts included in the measurement of operating lease obligations for the six months ended June 30, 2021 and June 30, 2020 was $1.0 million and $0.8 million and was included in Cash Provided by Operating Activities on the Consolidated Statements of Cash Flows.

Assets under capital leases amounted to approximately $0.9 million, $1.2 million and $1.0 million as of June 30, 2021, June 30, 2020 and December 31, 2020, respectively, less accumulated amortization of $0.5 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 June 30, 2021. The payments for operating leases consist of $1.5 million of current operating lease obligations, which are included in Other Current Liabilities and $3.4 million of noncurrent operating lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of June 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 June 30, 2021.


Lease Payments ($000’s) Year Ending December 31,	Operating Leases		Capital Leases
Rest of 2021	$	915	$	89
2022		1,589		150
2023		1,293		107
2024		964		52
2025		397		19
2026-2030		148		—

Total Payments		5,306		417

Less: Interest		367		18

Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$	4,939	$	399

Operating lease obligations are based on the net present value of the remaining lease payments over the remaining lease term. In determining the present value of lease payments, the Company used the interest rate stated in each lease agreement. As of June 30, 2021, the weighted average remaining lease term is 3.6 years and the weighted average operating discount rate used to determine the operating lease obligations was 4.2%. As of June 30, 2020, the weighted average remaining lease term was 3.8 years and the weighted average operating discount rate used to determine the operating lease obligations was 4.9%.

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 15,046,469, 14,996,231 and 15,012,310 shares of common stock outstanding at June 30, 2021, June 30, 2020 and December 31, 2020, respectively.

Dividend Reinvestment and Stock Purchase Plan -

During the first six months of 2021, the Company sold 11,019 shares of its common stock, at an average price of $47.90 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $527,800. 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 62,566 and 56,813

non-vested

shares under the Stock Plan as of June 30, 2021 and 2020, respectively. The weighted average grant date fair value of these shares was $49.44 and $54.88, respectively. The compensation expense associated with the

issuance

of shares under the Stock Plan is being recognized

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over the vesting period and was $1.3 million and $1.9 million for the six months ended June 30, 2021 and 2020, respectively. At June 30, 2021, there was approximately $0.8 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.9 years. During the six months ended June 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 six months ended June 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		694	$	47.50
Restricted Stock Units Settled		—		—

Restricted Stock Units as of June 30, 2021		43 886	$	41.43

There were 38,710 Restricted Stock Units outstanding as of June 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 June 30, 2021, June 30, 2020 and December 31, 2020 is $1.0 million, $0.7 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 1,887 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of June 30, 2021, June 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 six month periods ended June 30, 2021 and June 30, 2020, respectively.

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 intends to vigorously pursue full 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 May 2, 2018, the NHPUC approved a settlement agreement providing for a net annual revenue increase of $3.2 million, incorporating the effect of the TCJA, and an initial step increase to recover post-test year capital investments. The Company’s second annual revenue step increase of approximately $1.4

million to recover eligible capital investments in 2018 was approved by the NHPUC effective May 1, 2019. According to the terms of the settlement agreement, Northern Utilities’ next distribution base rate case shall be based on a historical test year no earlier than the twelve months ending December 31, 2020. 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. Northern Utilities also requested implementation of temporary rates for service rendered on and after October 1, 2021, and until a final order on permanent rates is issued. The requested temporary rates, if approved at the requested levels, could result in an increase in annual revenues of up to $3.2 million, or a 3.6% increase 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.

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.

Fitchburg - Base Rates - Electric -

Fitchburg’s base rates are decoupled, and subject to an annual revenue decoupling adjustment mechanism, which includes a cap on the amount that rates may be increased in any year. On December 28, 2020, the MDPU approved a decoupling revenue adjustment increase of $1.3 million, effective January 1, 2021. 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 (GSEP) tariff through which it may recover certain gas infrastructure replacement and safety related investment costs, subject to an annual cap. Under the plan, the Company is required to make two annual filings with the MDPU: a forward-looking filing for the subsequent construction year, to be filed on or before October 31; and a filing, submitted on or before May 1, of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably and prudently incurred. 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 outstandin

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 July 29, 2021, Granite State filed a limited Section 4 rate adjustment for an annual revenue increase of $0.1 million, effective September 1, 2021. This filing remains pending before the FERC.

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 - Independent Statewide Examination of the Safety of the Commonwealth’s Gas Distribution System -

The MDPU engaged a third-party evaluator to conduct an independent statewide examination of the safety of the gas distribution system to complement the investigation of the National Transportation Safety Board focused on the gas incident on September 13, 2018 in the Merrimack Valley and its potential causes. The evaluator examined: (1) the physical integrity and safety of the gas distribution system; and (2) the operation and maintenance policies and practices of the gas companies and municipal gas companies, with respect to the Commonwealth’s gas distribution system, including recommendations for improvements. The evaluator issued its final report on January 31, 2020, which contained a number of observations and recommendations for the improvement of gas distribution safety. On February 28, 2020, the Company filed a response and plan to implement the Unitil-specific recommendations, as well as general safety improvements.

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 LDC’s 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 LDC’s 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. In 2020, the NHPUC staff supported rate-regulated utilities’ deferral through a regulatory asset for incremental bad debt expense. However, 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.

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.

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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

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wholesale market and to credit or charge the difference between the contract costs and the

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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, 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 are due 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.

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 June 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. Although the review was completed in June 2021, work on the extension is now anticipated before the start of the 2021 heating season. 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.

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 Systems 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. The Company has recorded a liability in Other Current Liabilities on the Consolidated Balance Sheets as of June 30, 2021 for expected remediation actions and will continue to assess any new information or future developments that could require a reassessment of the potential exposure for required environmental remediatio

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

Environmental Obligations


	($ millions)
	Fitchburg				Northern Utilities				Total
	Six months ended June 30,
	2021		2020		2021		2020		2021		2020

Total Balance at Beginning of Period	$	0.1	$	—	$	2.0	$	2.7	$	2.1	$	2.7
Additions		—		—		0.1		—		0.1		—
Less: Payments / Reductions		—		—		0.1		0.5		0.1		0.5

Total Balance at End of Period		0.1		—		2.0		2.2		2.1		2.2

Less: Current Portion		0.1		—		0.3		0.3		0.4		0.3

Noncurrent Balance at End of Period	$	—	$	—	$	1.7	$	1.9	$	1.7	$	1.9

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:


	Six Months Ended June 30,
	2021			2020

Statutory Federal Income Tax Rate		21	%		21	%
Income Tax Effects of:
State Income Taxes, net		6			6
Utility Plant Differences		(2	)		(4	)
Other, net		—			—

Effective Income Tax Rate		25	%		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 June 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, 2017, December 31, 2018, and December 31, 2019.

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 (NOL) carryback periods, increases to interest deductibility limitations, and accelerated Alternative Minimum Tax (AMT) 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 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 Employment Retention Credit (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 June 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 six months ended June 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, 2019 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, 2019 which were filed with the IRS in October 2020, the Company utilized federal NOLC assets of $8.2 million. As of December 31, 2020, the Company had recognized the utilization of the remaining federal NOLC assets of $2.7 million to offset against current taxes payable. The Company received $0.9 million of Alternative Minimum Tax (AMT) credits in 2019 and will receive $0.9 million of AMT credits in 2021 as provided for in the CARES Act. In addition, at December 31, 2020, 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 Net Operating Loss Carryforward assets (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 June 30, 2021, the Company flowed back $2.5 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 Supplemental Executive Retirement Plan (SERP Plan) 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 Plan
Three Months Ended June 30,	2021			2020			2021			2020			2021			2020
Service Cost	$	868		$	831		$	758		$	675		$	88		$	71
Interest Cost		1,251			1,443			685			779			115			138
Expected Return on Plan Assets		(2,423	)		(2,255	)		(627	)		(516	)		—			—
Prior Service Cost Amortization		75			80			302			303			14			14
Actuarial Loss Amortization		2,022			1,618			262			186			373			259

Sub-total		1,793			1,717			1,380			1,427			590			482
Amounts Capitalized and Deferred		(887	)		(807	)		(791	)		(695	)		(178	)		(152	)

Net Periodic Benefit Cost Recognized	$	906		$	910		$	589		$	732		$	412		$	330




	Pension Plan						PBOP Plan						SERP Plan
Six Months Ended June 30,	2021			2020			2021			2020			2021			2020
Service Cost	$	1,736		$	1,662		$	1,516		$	1,350		$	177		$	142
Interest Cost		2,502			2,887			1,370			1,559			229			275
Expected Return on Plan Assets		(4,846	)		(4,510	)		(1,254	)		(1,032	)		—			—
Prior Service Cost Amortization		150			160			604			606			28			28
Actuarial Loss Amortization		4,044			3,236			524			372			745			518

Sub-total		3,586			3,435			2,760			2,855			1,179			963
Amounts Capitalized and Deferred		(1,600	)		(1,437	)		(1,454	)		(1,227	)		(356	)		(290	)

Net Periodic Benefit Cost Recognized	$	1,986		$	1,998		$	1,306		$	1,628		$	823		$	673

Employer Contributions

As of June 30, 2021, the Company had made $2.7 million and $1.6 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 June 30, 2021, the Company had made $0.3 million of benefit payments under the SERP Plan in 2021. The Company presently anticipates making an additional $0.3 million of benefit payments under the SERP Plan in 202

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 June 30, 2021. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of June 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 June 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 June 30, 2021.


	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
4/1/21 – 4/30/21		—		—		—	$	808
5/1/21 – 5/31/21		—		—		—	$	350,500
6/1/21 – 6/30/21		—		—		—	$	350,500

Total		—		—		—

Item 5. Other Information

On August 3, 2021, the Company issued a press release announcing its results of operations for the three and six month periods ended June 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
10.1	Employment Agreement between Unitil Corporation and Thomas P. Meissner, Jr.	Exhibit 10.1 to Form 8-K dated April 28, 2021 (SEC 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 August 3, 2021 Announcing Earnings For the Quarter Ended June 30, 2021.	Filed herewith

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


						UNITIL CORPORATION
						(Registrant)

Date: August 3, 2021						/s/ Robert B. Hevert
						Robert B. Hevert
						Chief Financial Officer


		Page No.
Cautionary Statement			3

Part I. Financial Information

Item 1.	Financial Statements - Unaudited

	Consolidated Statements of Earnings - Three and Six Months Ended June 30, 2021 and 2020		19

	Consolidated Balance Sheets, June 30, 2021, June 30, 2020 and December 31, 2020		20-21

	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2021 and 2020		22

	Consolidated Statements of Changes in Common Stock Equity – Three and Six Months Ended June 30, 2021 and 2020		23-24

	Notes to Consolidated Financial Statements		25-52

Item 2.	Management’s Discussion and Analysis (MD&A) of Financial Condition and Results of Operations		4-18

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		52

Item 4.	Controls and Procedures		52

Part II. Other Information

Item 1.	Legal Proceedings		53

Item 1A.	Risk Factors		53

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		53

Item 3.	Defaults Upon Senior Securities		Inapplicable

Item 4.	Mine Safety Disclosures		Inapplicable

Item 5.	Other Information		54

Item 6.	Exhibits		54-55

Signatures			56


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Operating Revenues
Gas	$	40.0	$	33.7	$	118.7	$	103.9
Electric		56.6		50.2		116.7		110.4

Total Operating Revenues		96.6		83.9		235.4		214.3

Operating Expenses
Cost of Gas Sales		15.0		10.8		45.9		38.6
Cost of Electric Sales		32.3		27.8		68.7		64.9
Operation and Maintenance		17.5		14.6		34.5		32.5
Depreciation and Amortization		14.8		13.5		29.7		27.0
Taxes Other Than Income Taxes		6.2		6.1		12.4		12.6

Total Operating Expenses		85.8		72.8		191.2		175.6

Operating Income		10.8		11.1		44.2		38.7
Interest Expense, Net		6.3		5.9		13.0		12.1
Other Expense (Income), Net		1.1		1.4		2.4		2.9

Income Before Income Taxes		3.4		3.8		28.8		23.7
Provision for Income Taxes		0.7		0.7		7.2		5.4

Net Income	$	2.7	$	3.1	$	21.6	$	18.3

Net Income Per Common Share (Basic and Diluted)	$	0.18	$	0.21	$	1.44	$	1.23
Weighted Average Common Shares Outstanding – (Basic and Diluted)		15.0		14.9		15.0		14.9


	Common Equity		Retained Earnings			Total
Three Months Ended June 30, 2021
Balance at April 1, 2021	$	286.3	$	116.8		$	403.1
Net Income				2.7			2.7
Dividends on Common Shares ($0.38 per share)				(5.7	)		(5.7	)
Stock Compensation Plans		0.2					0.2
Issuance of 4,840 Common Shares		0.3					0.3

Balance at June 30, 2021	$	286.8	$	113.8		$	400.6


Three Months Ended June 30, 2020
Balance at April 1, 2020	$	284.0	$	103.7		$	387.7
Net Income				3.1			3.1
Dividends on Common Shares ($0.375 per share)				(5.7	)		(5.7	)
Stock Compensation Plans		0.2					0.2
Issuance of 5,555 Common Shares		0.2					0.2

Balance at June 30, 2020	$	284.4	$	101.1		$	385.5


	June 30,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2021		2020		2020
Income Taxes (Note 8)	$	44.8	$	45.9	$	45.5
Rate Adjustment Mechanisms		15.3		11.2		4.1
Other		0.2		0.3		0.2

Total Regulatory Liabilities	$	60.3	$	57.4	$	49.8
Less: Current Portion of Regulatory Liabilities		17.1		12.6		5.5

Regulatory Liabilities – n oncurrent	$	43.2	$	44.8	$	44.3