10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2019

or

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

For the transition period from________to _________

Commission File Number 1-8858

UNITIL CORPORATION

(Exact name of registrant as specified in its charter)

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

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

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

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

Title of each class	Trading Symbol	Name of each exchange of which registered
Common Stock	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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).    Yes  ☒    No  ☐

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

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
(Do not check if a smaller reporting company)		Emerging growth company	☐

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

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

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

Class	Outstanding at October 21, 2019
Common Stock, No par value	14,926,205 Shares

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended September 30, 2019

Table of Contents

		Page No.
Part I. Financial Information
Item 1.	Financial Statements - Unaudited
	Consolidated Statements of Earnings - Three and Nine Months Ended September 30, 2019 and 2018		19
	Consolidated Balance Sheets, September 30, 2019, September 30, 2018 and December 31, 2018		20-21
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2019 and 2018		22
	Consolidated Statements of Changes in Common Stock Equity - Three and Nine Months Ended September 30, 2019 and 2018		23-24
	Notes to Consolidated Financial Statements		25-51
Item 2.	Management’s Discussion and Analysis (MD&A) of Financial Condition and Results of Operations		3-18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		51
Item 4.	Controls and Procedures		51
Part II. Other Information
Item 1.	Legal Proceedings		51
Item 1A.	Risk Factors		52
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		52
Item 3.	Defaults Upon Senior Securities		Inapplicable
Item 4.	Mine Safety Disclosures		Inapplicable
Item 5.	Other Information		52
Item 6.	Exhibits		53
Signatures			55

Cautionary Statement

This report and the documents incorporated by reference into this report contain statements that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact, included or incorporated by reference into this report, including, without limitation, statements regarding the financial position, business strategy and other plans and objectives for the Company’s future operations, are forward-looking statements.

These statements include declarations regarding the Company’s beliefs and current expectations. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue,” or the negative of such terms or other comparable terminology. These forward-looking statements are subject to inherent risks and uncertainties in predicting future results and conditions that could cause the actual results to differ materially from those projected in these forward-looking statements. Some, but not all, of the risks and uncertainties include those described in Item 1A (Risk Factors) and the following:

• the Company’s regulatory environment (including regulations relating to climate change, greenhouse gas emissions and other environmental matters), which could affect the rates the Company is able to charge, the Company’s authorized rate of return and the Company’s ability to recover costs in its rates;

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

• customers’ preferred energy sources;

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

• the potential for disruption to the Company’s operations due to cyber-attacks, computer viruses, human errors, acts of war or terrorism or other reasons;

• the Company’s stranded electric generation and generation-related supply costs and the Company’s ability to recover stranded 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 counterparties’ 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 natural gas distribution services;

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

• catastrophic events;

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• 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. 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 impact 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 natural gas throughout its service areas in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of three wholly-owned distribution utilities:

i) Unitil Energy Systems, Inc. (Unitil Energy), which provides electric service in the southeastern seacoast and state capital regions of New Hampshire, including the capital city of Concord, New Hampshire;

ii) Fitchburg Gas and Electric Light Company (Fitchburg), which provides both electric and natural gas service in the greater Fitchburg area of north central Massachusetts; and

iii) Northern Utilities, Inc. (Northern Utilities), which provides natural gas service in southeastern New Hampshire and portions of southern and central Maine, including the city of Portland, which is the largest city in northern New England.

Unitil Energy, Fitchburg and Northern Utilities are collectively referred to as the “distribution utilities.” Together, the distribution utilities serve approximately 105,600 electric customers and 82,700 natural gas customers in their service territory.

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

Unitil had an investment in Net Utility Plant of $1,083.9 million at September 30, 2019. Unitil’s total operating revenue includes revenue to recover the approved cost of purchased electricity and natural gas in rates on a fully reconciling basis. As a result of this reconciling rate structure, the Company’s earnings are not directly affected by changes in the cost of purchased electricity and natural 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. Usource, Inc. and Usource L.L.C. (collectively, Usource), which the Company divested of in the first quarter of 2019, were wholly-owned subsidiaries of Unitil Resources. Usource provided brokering and advisory services to large commercial and industrial customers in the northeastern United States. See additional discussion of the divestiture of Usource in “Divestiture of Non-Regulated Business Subsidiary” in Note 1 to the Consolidated Financial Statements.

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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 natural gas transmission pipeline, is subject to regulation by the FERC with regard to its rates and operations. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations and financial position.

Unitil’s distribution utilities deliver electricity and/or natural gas to all customers in their service territory, at rates established under cost of service regulation. Under this regulatory structure, Unitil’s distribution utilities recover the cost of providing distribution service to their customers based on a historical test year, and earn a return on their capital investment in utility assets. In addition, the Company’s distribution utilities and its natural gas transmission pipeline company may also recover certain base rate costs, including capital project spending and enhanced reliability and vegetation management programs, through annual step adjustments and cost tracker rate mechanisms.

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 natural 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 applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.

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 percent, 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 opened a rulemaking proceeding on this matter which has been addressed in a rate settlement filing by Granite State. More recently, on November 15, 2018, the FERC issued a Notice of Proposed Rulemaking and a Policy Statement to address the TCJA’s effects on the Accumulated Deferred Income Taxes (ADIT) on transmission rates. Under the proposed rules all public utilities with transmission formula rates, including Fitchburg, would be required to: (1) include mechanisms

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to deduct any excess ADIT from or add any deficient ADIT to their rate bases; (2) include mechanisms in those rates that would raise or lower their income tax allowances by any amortized excess or deficient ADIT; and (3) incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT. The Company believes that these matters are substantially resolved and will not have a material impact on its financial position, operating results, or cash flows.

Rate Case Activity

Northern Utilities – Base Rates – Maine – On June 28, 2019, Northern Utilities filed a petition with the MPUC seeking an increase to annual base operating revenues of $7.0 million. If approved as filed, the requested increase will result in a 7 percent increase over the Company’s test-year operating revenues. The intended rate effective date is April 1, 2020. In addition, Northern Utilities is requesting approval to implement a multi-year alternative rate mechanism (“Capital Investment Recovery Adjustment” or “CIRA”) that will allow for future changes to the Company’s distribution rates and mitigate the need to file a general rate case. The CIRA is designed to recover the costs of replacing, relocating and abandoning existing facilities and other operational and safety-related system improvements. The first annual adjustment is proposed for November 1, 2020, to recover the Company’s 2019 investment cost of eligible facilities and improvements. This matter remains pending.

Northern Utilities – Targeted Infrastructure Replacement Adjustment (TIRA) – Maine – The settlement in Northern Utilities’ Maine division’s 2013 rate case allowed 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’ last 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. On May 7, 2018, the MPUC approved the Company’s request to increase its annual base rates by 2.4%, or $1.1 million, effective May 1, 2018, to recover the revenue requirements for 2017 eligible facilities. On April 17, 2019, the MPUC approved the Company’s request to increase its annual base rates by 2.1%, or $1.0 million, effective May 1, 2019, to recover the revenue requirements for 2018 eligible facilities.

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 step increase of approximately $1.4 million of annual revenue was approved by the NHPUC, effective May 1, 2019, to recover eligible capital investments in 2018. According to the terms of the settlement agreement, Northern Utilities’ next distribution base rate case shall be based on an historic test year of no earlier than twelve months ending December 31, 2020.

Unitil Energy – Base Rates – On April 20, 2017 the NHPUC issued its final order providing for a permanent increase of $4.1 million, effective May 1, 2017, followed by two annual rate step adjustments to recover the revenue requirements associated with certain capital expenditures. On April 30, 2018, the NHPUC approved Unitil Energy’s first step increase, effective May 1, 2018. On April 22, 2019, the NHPUC approved Unitil Energy’s second and final step adjustment, providing for a revenue increase of approximately $340,000, effective May 1, 2019.

Fitchburg – Base Rates – Electric – Fitchburg’s base rates are decoupled, and subject to an annual revenue decoupling adjustment mechanism, which includes a cap on the amount that rates may be increased in any year. In addition, Fitchburg has an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions. On April 3, 2019, the DPU approved Fitchburg’s cumulative revenue requirement associated with the Company’s 2015 and 2016 capital expenditures, an increase of $0.4 million. The increase was effective January 1, 2018. On November 1, 2018, Fitchburg filed its cumulative revenue requirement of $0.9 million associated with the Company’s 2015, 2016 and 2017 capital expenditures. On December 27, 2018, the filing was approved, effective January 1, 2019, subject to further investigation and reconciliation. Final approval of the 2018 filing

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remains pending. On September 5, 2019, Fitchburg’s electric division filed with the MDPU a letter of intent to file for a general increase in base rates. Under MDPU precedent, a utility company is required to provide no less than a 30 day advance notice of its intent to file for a base rate increase. At this time, Fitchburg anticipates that the filing will be made during the fourth quarter 2019.

Fitchburg – Base Rates – Gas – Pursuant to the Company’s 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 impacts to the Company’s revenues. The MDPU has consistently found that 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 September 5, 2019, Fitchburg’s gas division filed with the MDPU a letter of intent to file for a general increase in base rates. Under MDPU precedent, a utility company is required to provide no less than a 30 day advance notice of its intent to file for a base rate increase. At this time, Fitchburg anticipates that the filing will be made during the fourth quarter 2019.

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 (the “GSEP Filing”); and a filing, submitted on or before May 1, of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably and prudently incurred (the “GREC Filing”). The Company considers these to be routine regulatory proceedings and there are no material issues outstanding.

In an Order issued on April 30, 2019, the MDPU approved Fitchburg’s 2018 GSEP Filing and increased the annual cap on recovery. Because the amount approved for recovery, $1.6 million, still exceeded the annual cap, the Order resulted in a revenue increase of $1.0 million that went into effect on May 1, 2019, subject to reconciliation. The amount that exceeded the cap, $0.6 million, has been deferred to be recovered in a later proceeding. On May 1, 2019, the Company made its 2019 GREC Filing, seeking a waiver of the annual cap and a revenue increase of $1.0 million. This matter remains pending.

Granite State – Base Rates – On May 2, 2018, Granite State filed an uncontested rate settlement with FERC which provided for no change in rates, and accounted for the effects of a capital step adjustment offset by the effect of the TCJA. The settlement was approved by FERC on June 27, 2018, and complies with the FERC Notice of Proposed Rulemaking concerning the justness and reasonableness of rates in light of the corporate income tax reductions under the TCJA.

RESULTS OF OPERATIONS

The following section of MD&A compares the results of operations for each of the two fiscal periods ended September 30, 2019 and September 30, 2018 and should be read in conjunction with the accompanying unaudited Consolidated Financial Statements and the accompanying Notes to unaudited Consolidated Financial Statements included in Part I, Item 1 of this report, which are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).

The Company’s results of operations reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the heating season as a result of higher sales of natural gas due to cold weather. Accordingly, the results of operations are historically most favorable in the first and fourth quarters. Fluctuations in seasonal weather conditions may have a significant effect on the result of operations. Sales of electricity are generally less sensitive to weather than natural gas sales, but may also be affected by the weather conditions in both the winter and summer seasons. Also, as a result of recent rate cases, the Company’s natural gas sales margins are derived from a higher percentage of fixed billing components, including customer charges. Therefore, natural gas revenues and margin will be less affected by the seasonal nature of the natural gas business. In addition, as discussed above, approximately 27% and 11% of the Company’s total annual electric and natural gas sales volumes, respectively, are decoupled and changes in sales to existing customers do not affect sales margin.

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Earnings Overview

The Company’s Net Income was $2.3 million, or $0.15 in Earnings Per Share (EPS), for the third quarter of 2019, a decrease of $0.5 million, or $0.04 in EPS, compared to the third quarter of 2018. For the nine months ended September 30, 2019, the Company reported Net Income of $32.8 million, or $2.20 in EPS, an increase of $10.8 million, or $0.71 in EPS, compared to the same nine month period in 2018. In the first quarter of 2019, the Company recognized a one-time net gain of $9.8 million, or $0.66 in EPS, on the Company’s divestiture of its non-regulated business subsidiary, Usource. In addition, the Company’s earnings in the first nine months 2019 were driven by higher natural gas and electric sales margins. Earnings for the Company’s utility operations were Net Income of $23.0 million, or $1.54 in EPS, for the first nine months of 2019, an increase of $1.0 million in Net Income, or $0.05 in EPS, compared to the first nine months of 2018.

Natural gas sales margins were $18.7 million and $85.5 million in the three and nine months ended September 30, 2019, respectively, increases of $1.1 million and $5.1 million, respectively, compared to the same periods in 2018. Gas sales margins in the third quarter of 2019 were positively affected by higher natural gas distribution rates of $0.8 million and by $0.3 million from higher therm sales, reflecting customer growth and increased average consumption by Commercial and Industrial (C&I) and Residential customers.

Gas sales margins in the first nine months of 2019 were positively affected by higher natural gas distribution rates of $4.6 million and by $1.7 million from higher therm sales, reflecting customer growth and increased average consumption by C&I and Residential customers. The positive effect of the higher rates and customer growth was partially offset by the absence in the current period of a $1.2 million non-recurring adjustment recognized in the second quarter of 2018 to increase gas revenue in connection with a then ongoing base rate case for the Company’s New Hampshire natural gas utility.

Natural gas therm sales increased 4.2% and 2.5% in the three and nine month periods ended September 30, 2019, respectively, compared to the same periods in 2018. The increase in gas therm sales in the Company’s service areas was driven by customer growth and increased average consumption by C&I and Residential customers. The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were up 5.5% in the first nine months of 2019 compared to the same period in 2018. As of September 30, 2019, the number of total natural gas customers served has increased by 1,468 over the last year.

Electric sales margins were $25.1 million and $70.6 million in the three and nine months ended September 30, 2019, respectively, a decrease of $0.8 million and an increase of $0.1 million, respectively, compared to the same periods in 2018. The decrease in electric sales margins in the third quarter were due to lower kWh sales, reflecting milder summer weather in 2019 and overall lower average usage, including reduced usage by some industrial customers for production purposes, partially offset by positive customer growth. Electric sales margins in the first nine months of 2019 were positively affected by higher electric distribution rates of $1.4 million, partially offset by a decrease of $1.3 million from lower kWh sales, for the reasons noted above.

Total electric kilowatt-hour (kWh) sales decreased 5.3% and 5.2%, respectively in the three and nine month periods ended September 30, 2019 compared to the same periods in 2018. For the third quarter, the decrease reflects milder summer weather in 2019 compared to 2018. Based on weather data collected in the Company’s electric service areas, there were 19% fewer Cooling Degree Days in the third quarter of 2019 compared to the same period in 2018. The decreases in the three and nine month periods also reflect overall lower average usage due to both energy efficiency purposes and aforementioned reduced usage by some industrial customers, but were partially offset by overall customer growth. As of September 30, 2019, the number of total electric customers served has increased by 554 over the last year.

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Operation and Maintenance (O&M) expenses decreased $0.9 million and $1.6 million in three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. Excluding a non-recurring adjustment to increase O&M expenses by $1.2 million in the second quarter of 2018 in connection with a then ongoing base rate case for the Company’s New Hampshire natural gas utility; O&M expenses decreased $0.4 million in the nine months ended September 30, 2019 compared to the same period in 2018. The decrease in the three month period reflects lower labor and other costs of $0.8 million, resulting from the divestiture of the Company’s non-regulated business subsidiary, Usource. In addition, in the three month period, the decrease in O&M expenses reflects lower professional fees of $0.4 million, partially offset by higher compensation and benefit costs of $0.3 million. The decrease in the nine month period reflects lower labor and other costs of $1.7 million, resulting from the divestiture of the Company’s non-regulated business subsidiary, Usource. O&M expenses in the nine month period also reflect higher compensation and benefit costs of $0.9 million, higher utility operating costs of $0.3 million and higher professional fees of $0.1 million.

Depreciation and Amortization expense increased $0.4 million and $1.6 million in the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. These increases reflect increased depreciation on higher levels of utility plant in service, partially offset by lower amortization.

Taxes Other Than Income Taxes in the three months ended September 30, 2019 was essentially unchanged compared to the same period in 2018, reflecting higher local property tax rates on higher levels of utility plant in service, offset by property tax abatements. Taxes Other Than Income Taxes increased $0.5 million in the nine months ended September 30, 2019 compared to the same period in 2018. The increase in the nine month period reflects higher local property tax rates on higher levels of utility plant in service, partially offset by property tax abatements.

Interest Expense, Net decreased $0.2 million in the three months ended September 30, 2019, compared to the same period in 2018, reflecting lower interest on short-term borrowings and higher interest income on AFUDC. For the nine months ended September 30, 2019, Interest Expense, Net was essentially unchanged compared to the same period in 2018, reflecting lower interest on long-term debt and higher interest income on AFUDC, offset by interest on higher levels of short-term borrowings.

Other Expense (Income), Net decreased by $0.1 million for the three months ended September 30, 2019 compared to the same period in 2018. Other Expense (Income), Net changed from an expense of $4.1 million in the first nine months of 2018 to income of $9.8 million in the first nine months of 2019, a net change of $13.9 million. This change primarily reflects a pre-tax gain of $13.4 million on the Company’s divestiture of Usource, discussed above, and lower retirement benefit costs in the current period. The Usource divestiture generated a capital gain to the Company and a $3.6 million provision is included in the Company’s income tax expense for the nine months ended September 30, 2019.

Federal and State Income Taxes increased by $0.5 million and $5.2 million for the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. The increase in the nine month period reflects income taxes associated with the Company’s divestiture of its non-regulated business subsidiary, Usource, discussed above.

At its January 2019, April 2019, July 2019 and October 2019 meetings, the Unitil Corporation Board of Directors declared quarterly dividends on the Company’s common stock of $0.37 per share. These quarterly dividends result in a current effective annualized dividend rate of $1.48 per share, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock.

A more detailed discussion of the Company’s results of operations for the three and nine months ended September 30, 2019 is presented below.

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Gas Sales, Revenues and Margin

Therm Sales – Unitil’s total therm sales of natural gas increased 4.2% and 2.5% in the three and nine month periods ended September 30, 2019, respectively, compared to the same periods in 2018. In the third quarter of 2019, sales to Residential and C&I customers increased 4.0% and 4.2%, respectively, compared to the same period in 2018. For the nine months ended September 30, 2019, sales to Residential and C&I customers increased 0.8% and 2.9%, respectively, compared to the same period in 2018. The increase in gas therm sales in the Company’s service areas was driven by customer growth and increased average consumption by C&I and Residential customers. The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were up 5.5% in the first nine months of 2019 compared to the same period in 2018. As of September 30, 2019, the number of total natural gas customers served has increased by 1,468 over the last year. As previously discussed, sales margins derived from decoupled unit sales (representing approximately 11% of total annual therm sales volume) are not sensitive to changes in gas therm sales.

The following table details total firm therm sales for the three and nine months ended September 30, 2019 and 2018, by major customer class:

Therm Sales (millions)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2019		2018		Change		% Change			2019		2018		Change		% Change
Residential		2.6		2.5		0.1		4.0	%		36.2		35.9		0.3		0.8	%
Commercial / Industrial		24.9		23.9		1.0		4.2	%		136.2		132.3		3.9		2.9	%
Total		27.5		26.4		1.1		4.2	%		172.4		168.2		4.2		2.5	%

Gas Operating Revenues and Sales Margin – The following table details total Gas Operating Revenues and Sales Margin for the three and nine months ended September 30, 2019 and 2018:

Gas Operating Revenues and Sales Margin (millions)
	Three Months Ended September 30,										Nine Months Ended September 30,
	2019		2018		$ Change			% Change			2019		2018		$ Change			% Change
Gas Operating Revenue:
Residential	$	8.9	$	9.2	$	(0.3	)		(3.3	%)	$	57.8	$	58.9	$	(1.1	)		(1.9	%)
Commercial / Industrial		16.0		16.5		(0.5	)		(3.0	%)		86.1		88.5		(2.4	)		(2.7	%)
Total Gas Operating Revenue	$	24.9	$	25.7	$	(0.8	)		(3.1	%)	$	143.9	$	147.4	$	(3.5	)		(2.4	%)
Cost of Gas Sales	$	6.2	$	8.1	$	(1.9	)		(23.5	%)	$	58.4	$	67.0	$	(8.6	)		(12.8	%)
Gas Sales Margin	$	18.7	$	17.6	$	1.1			6.2	%	$	85.5	$	80.4	$	5.1			6.3	%

The Company analyzes operating results using Gas Sales Margin, a non-GAAP measure. Gas Sales Margin is calculated as Total Gas Operating Revenue (See “Utility Revenue Recognition” in Note 1 to the accompanying Consolidated Financial Statements) less Cost of Gas Sales. The Company believes Gas Sales Margin is an important measure to analyze profitability because the approved cost of sales are tracked and reconciled costs that are passed through directly to the customer, resulting in an equal and offsetting amount reflected in Total Gas Operating Revenue. Sales margin can be reconciled to Operating Income, a GAAP measure, by including Operation and Maintenance, Depreciation and Amortization and Taxes Other Than Income Taxes for each segment in the analysis.

9

Natural gas sales margins were $18.7 million and $85.5 million in the three and nine months ended September 30, 2019, respectively, increases of $1.1 million and $5.1 million, respectively, compared to the same periods in 2018. Gas sales margins in the third quarter of 2019 were positively affected by higher natural gas distribution rates of $0.8 million and by $0.3 million from higher therm sales, reflecting customer growth and increased average consumption by C&I and Residential customers.

Gas sales margins in the first nine months of 2019 were positively affected by higher natural gas distribution rates of $4.6 million and by $1.7 million from higher therm sales, reflecting customer growth and increased average consumption by C&I and Residential customers. The positive effect of the higher rates and customer growth was partially offset by the absence in the current period of a $1.2 million non-recurring adjustment recognized in the second quarter of 2018 to increase gas revenue in connection with a then ongoing base rate case for the Company’s New Hampshire natural gas utility.

The decreases in Total Gas Operating Revenues of $0.8 million and $3.5 million in the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2019, reflect lower cost of gas sales, which are tracked and reconciled costs that are passed through directly to customers, and for the nine month period, the non-recurring adjustment recognized in the second quarter of 2019, discussed above, partially offset by higher natural gas sales volumes.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales – Unitil’s total electric kWh sales decreased 5.3% and 5.2%, respectively in the three and nine month periods ended September 30, 2019 compared to the same periods in 2018. Sales to Residential customers decreased 7.2% and 5.6%, respectively, in the three and nine month periods ended September 30, 2019 compared to the same periods in 2018. Sales to C&I customers decreased 4.0% and 4.9%, respectively, in the three and nine month periods ended September 30, 2019 compared to the same periods in 2018. For the third quarter, the decrease reflects milder summer weather in 2019 compared to 2018. Based on weather data collected in the Company’s electric service areas, there were 19% fewer Cooling Degree Days in the third quarter of 2019 compared to the same period in 2018. The decreases in the three and nine month periods also reflect overall lower average usage due to both energy efficiency purposes and aforementioned reduced usage by some industrial customers, but were partially offset by overall customer growth. As of September 30, 2019, the number of total electric customers served has increased by 554 over the last year. As previously discussed, sales margins derived from decoupled unit sales (representing approximately 27% of total annual kWh sales volume) are not sensitive to changes in electric kWh sales.

The following table details total kWh sales for the three and nine months ended September 30, 2019 and 2018 by major customer class:

kWh Sales (millions)
	Three Months Ended September 30,										Nine Months Ended September 30,
	2019		2018		Change			% Change			2019		2018		Change			% Change
Residential		180.9		195.0		(14.1	)		(7.2	%)		498.3		527.8		(29.5	)		(5.6	%)
Commercial / Industrial		257.7		268.3		(10.6	)		(4.0	%)		718.5		755.9		(37.4	)		(4.9	%)
Total		438.6		463.3		(24.7	)		(5.3	%)		1,216.8		1,283.7		(66.9	)		(5.2	%)

10

Electric Operating Revenues and Sales Margin – The following table details total Electric Operating Revenues and Sales Margin for the three and nine month periods ended September 30, 2019 and 2018:

Electric Operating Revenues and Sales Margin (millions)
	Three Months Ended September 30,										Nine Months Ended September 30,
	2019		2018		$ Change			% Change			2019		2018		$ Change		% Change
Electric Operating Revenue:
Residential	$	34.4	$	35.5	$	(1.1	)		(3.1	%)	$	101.9	$	95.7	$	6.2		6.5	%
Commercial / Industrial		26.0		25.9		0.1			0.4	%		75.1		71.9		3.2		4.5	%
Total Electric Operating Revenue	$	60.4	$	61.4	$	(1.0	)		(1.6	%)	$	177.0	$	167.6	$	9.4		5.6	%
Cost of Electric Sales	$	35.3	$	35.5	$	(0.2	)		(0.6	%)	$	106.4	$	97.1	$	9.3		9.6	%
Electric Sales Margin	$	25.1	$	25.9	$	(0.8	)		(3.1	%)	$	70.6	$	70.5	$	0.1		0.1	%

The Company analyzes operating results using Electric Sales Margin, a non-GAAP measure. Electric Sales Margin is calculated as Total Electric Operating Revenues (See “Utility Revenue Recognition” in Note 1 to the accompanying Consolidated Financial Statements) less Cost of Electric Sales. The Company believes Electric Sales Margin is an important measure to analyze profitability because the approved cost of sales are tracked and reconciled costs that are passed through directly to the customer resulting in an equal and offsetting amount reflected in Total Electric Operating Revenues. Sales margin can be reconciled to Operating Income, a GAAP measure, by including Operation and Maintenance, Depreciation and Amortization and Taxes Other Than Income Taxes for each segment in the analysis.

Electric sales margins were $25.1 million and $70.6 million in the three and nine months ended September 30, 2019, respectively, a decrease of $0.8 million and an increase of $0.1 million, respectively, compared to the same periods in 2018. The decrease in electric sales margins in the third quarter were due to lower kWh sales, reflecting milder summer weather in 2019 and overall lower average usage, including reduced usage by some industrial customers for production purposes, partially offset by positive customer growth. Electric sales margins in the first nine months of 2019 were positively affected by higher electric distribution rates of $1.4 million, partially offset by a decrease of $1.3 million from lower kWh sales, for the reasons noted above.

Total Electric Operating Revenues decreased $1.0 million in the three months ended September 30, 2019, respectively, compared to the same period in 2018 reflecting lower sales of electricity, partially offset by lower cost of electric sales, which are tracked and reconciled to costs that are passed through directly to customers. Total Electric Operating Revenues increased $9.4 million in the nine months ended September 30, 2019, respectively, compared to the same period in 2018 reflecting higher cost of electric sales, partially offset by lower sales of electricity.

11

Operating Revenue – Other

The following table details total Other Revenue for the three and nine months ended September 30, 2019 and 2018:

Other Revenue (000’s)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2019		2018		$ Change			% Change		2019		2018		$ Change			% Change
Other	$	—	$	1.1	$	(1.1	)		N/M	$	0.9	$	3.5	$	(2.6	)		(74.3	%)
Total Other Revenue	$	—	$	1.1	$	(1.1	)		N/M	$	0.9	$	3.5	$	(2.6	)		(74.3	%)

Total Other Operating Revenue (See “Other Operating Revenue – Non-regulated” in Note 1 to the accompanying Consolidated Financial Statements), which is comprised of revenues from the Company’s non-regulated energy brokering business, Usource, decreased $1.1 million and $2.6 million, respectively, in the three and nine months ended September 30, 2019, compared to the same periods in 2018, reflecting the Company’s divestiture of Usource in the first quarter of 2019 (See “Divestiture of Non-Regulated Business Subsidiary” in Note 1 to the accompanying Consolidated Financial Statements).

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 decreased $1.9 million, or 23.5%, and $8.6 million, or 12.8%, in the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. These decreases reflect lower wholesale natural gas prices, partially offset by higher sales of natural gas. The Company reconciles and recovers the approved Cost of Gas Sales in its rates at cost on a pass-through basis and therefore changes in approved expenses do not affect earnings.

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 decreased $0.2 million, or 0.6%, and increased $9.3 million, or 9.6%, in the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. The decrease in the three month period reflects lower sales of electricity, partially offset by higher wholesale electricity prices and a decrease in the amount of electricity purchased by customers directly from third-party suppliers. The increase in the nine month period reflects higher wholesale electricity prices and a decrease in the amount of electricity purchased by customers directly from third-party suppliers, partially offset by lower sales of electricity. The Company reconciles and recovers the approved Cost of Electric Sales in its rates at cost on a pass-through basis and therefore changes in approved expenses do not affect earnings.

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 decreased $0.9 million, or 5.5%, and $1.6 million, or 3.1%, in three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. Excluding a non-recurring adjustment to increase O&M expenses by $1.2 million in the second quarter of 2018 in connection with a then ongoing base rate case for the Company’s New Hampshire natural gas utility; O&M expenses decreased $0.4 million in the nine months ended September 30, 2019 compared to the same period in 2018. The decrease in the three month period reflects lower labor and other costs of $0.8 million, resulting from the divestiture of the Company’s non-regulated business subsidiary, Usource. In addition, in the three month period, the decrease in O&M expenses reflects lower professional fees of $0.4 million, partially offset by higher compensation and benefit costs of $0.3 million. The decrease in the nine month period reflects lower labor and other costs of $1.7 million, resulting from the divestiture of the Company’s non-regulated business subsidiary, Usource. O&M expenses in the nine month period also reflect higher compensation and benefit costs of $0.9 million, higher utility operating costs of $0.3 million and higher professional fees of $0.1 million.

12

Depreciation and Amortization – Depreciation and Amortization expense increased $0.4 million, or 3.2%, and $1.6 million, or 4.3%, in the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. These increases reflect increased depreciation on higher levels of utility plant in service, partially offset by lower amortization.

Taxes Other Than Income Taxes – Taxes Other Than Income Taxes in the three months ended September 30, 2019 was essentially unchanged compared to the same period in 2018, reflecting higher local property tax rates on higher levels of utility plant in service, offset by property tax abatements. Taxes Other Than Income Taxes increased $0.5 million, or 3.0%, in the nine months ended September 30, 2019 compared to the same period in 2018. The increase in the nine month period reflects higher local property tax rates on higher levels of utility plant in service, partially offset by property tax abatements.

Other Expense (Income), Net – Other Expense (Income), Net decreased by $0.1 million for the three months ended September 30, 2019 compared to the same period in 2018. Other Expense (Income), Net changed from an expense of $4.1 million in the first nine months of 2018 to income of $9.8 million in the first nine months of 2019, a net change of $13.9 million. This change primarily reflects a pre-tax gain of $13.4 million on the Company’s divestiture of Usource, discussed above, and lower retirement benefit costs in the current period. The Usource divestiture generated a capital gain to the Company and a $3.6 million provision is included in the Company’s income tax expense for the nine months ended September 30, 2019.

Provision for Income Taxes – Federal and State Income Taxes increased by $0.5 million and $5.2 million for the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. The increase in the nine month period reflects income taxes associated with the Company’s divestiture of its non-regulated business subsidiary, Usource, discussed above.

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 balance of costs. In accordance with the distribution utilities’ rate tariffs, interest is accrued on these balances and will produce either interest income or interest expense. Consistent with regulatory precedent, interest income is recorded on an under-collection of costs which creates a regulatory asset to be recovered in future periods when rates are reset. Interest expense is recorded on an over-collection of costs, which creates a regulatory liability to be refunded in future periods when rates are reset.

13

Interest Expense, Net (Millions)	Three Months Ended September 30,									Nine Months Ended September 30,
	2019			2018			Change			2019			2018			Change
Interest Expense
Long-term Debt	$	5.7		$	5.7		$	—		$	17.0		$	17.3		$	(0.3	)
Short-term Debt		0.6			0.7			(0.1	)		2.4			1.6			0.8
Regulatory Liabilities		0.2			0.2			—			0.5			0.5			—
Subtotal Interest Expense		6.5			6.6			(0.1	)		19.9			19.4			0.5
Interest (Income)
Regulatory Assets		(0.2	)		(0.2	)		—			(0.6	)		(0.6	)		—
AFUDC(1) and Other		(0.5	)		(0.4	)		(0.1	)		(1.4	)		(0.9	)		(0.5	)
Subtotal Interest (Income)		(0.7	)		(0.6	)		(0.1	)		(2.0	)		(1.5	)		(0.5	)
Total Interest Expense, Net	$	5.8		$	6.0		$	(0.2	)	$	17.9		$	17.9		$	—

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

Interest Expense, Net decreased $0.2 million in the three months ended September 30, 2019, compared to the same period in 2018, reflecting lower interest on short-term borrowings and higher interest income on AFUDC. For the nine months ended September 30, 2019, Interest Expense, Net was essentially unchanged compared to the same period in 2018, reflecting lower interest on long-term debt and higher interest income on AFUDC, offset by interest on higher levels of short-term borrowings.

Capital Requirements

Sources of Capital

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

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 below). At September 30, 2019, September 30, 2018 and December 31, 2018, the Company and all of its subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

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

14

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $187.1 million for the nine months ended September 30, 2019. Total gross repayments were $220.7 million for the nine months ended September 30, 2019. The following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of September 30, 2019, September 30, 2018 and December 31, 2018:

	Revolving Credit Facility ($ millions)
	September 30,				December 31,
	2019		2018		2018
Limit	$	120.0	$	120.0	$	120.0
Short-Term Borrowings Outstanding		49.2		69.1		82.8
Letter of Credit Outstanding		0.1		—		—
Available	$	70.7	$	50.9	$	37.2

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 shall apply until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At September 30, 2019, September 30, 2018 and December 31, 2018, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date. (See also “Credit Arrangements” in Note 4.)

The Company believes the future operating cash flows of the Company, along with its existing borrowing availability and access to financial markets for the issuance of new long-term debt, will be sufficient to meet any working capital and future operating requirements, and capital investment forecast opportunities.

As discussed previously, the Company divested of its non-regulated subsidiary business, Usource, in the first quarter of 2019. The Company used the net proceeds of $9.8 million from this divestiture for general corporate purposes.

On September 12, 2019, Northern Utilities issued $40 million of Notes due 2049 at 4.04%. Northern Utilities used the net proceeds from this offering to repay short-term debt and for general corporate purposes. Approximately $0.2 million of costs associated with these issuances have been netted against Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.

On November 30, 2018 Unitil Energy issued $30 million of First Mortgage Bonds due November 30, 2048 at 4.18%. Unitil Energy used the net proceeds from this offering to repay short-term debt and for general corporate purposes. Approximately $0.5 million of costs associated with these issuances have been netted against long-term debt for presentation purposes on the Consolidated Balance Sheets.

15

In April 2014, Unitil Service Corp. entered into a financing arrangement, structured as a capital lease obligation, for various information systems and technology equipment. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. This capital lease was paid in full in the second quarter of 2019.

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

The continued availability of various methods of financing, as well as the choice of a specific form of security for such financing, will depend on many factors, including, but not limited to: security market conditions; general economic climate; regulatory approvals; the ability to meet covenant issuance restrictions; the level of earnings, cash flows and financial position; and the competitive pricing offered by financing sources.

The Company provides limited guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of September 30, 2019, there were approximately $4.3 million of guarantees outstanding.

Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There was $8.1 million, $9.6 million and $8.4 million of natural gas storage inventory at September 30, 2019, September 30, 2018 and December 31, 2018, respectively, related to these asset management agreements. The amount of natural gas inventory released in September 2019 and payable in October 2019 is $0.1 million and is recorded in Accounts Payable at September 30, 2019. The amount of natural gas inventory released in September 2018 and payable in October 2018 was $0.1 million and was recorded in Accounts Payable at September 30, 2018. The amount of natural gas inventory released in December 2018 and payable in January 2019 was $0.9 million and was recorded in Accounts Payable at December 31, 2018.

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 also lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements. Additionally, as of September 30, 2019, there were approximately $4.3 million of guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities outstanding. See Note 4 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

Critical Accounting Policies

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 impact 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. For a complete discussion of the Company’s significant accounting policies, refer to the Note 1 to the Consolidated Financial Statements in the Company’s Annual Report on Form 10-K, as filed with the Securities and Exchange Commission on January 31, 2019.

16

LABOR RELATIONS

As of September 30, 2019, the Company and its subsidiaries had 503 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of September 30, 2019, a total of 162 employees of certain of the Company’s subsidiaries were represented by labor unions. The following table details by subsidiary the employees covered by a collective bargaining agreement (CBA) as of September 30, 2019:

	Employees Covered		CBA Expiration
Fitchburg		44		05/31/2022
Northern Utilities NH Division		37		06/05/2020
Northern Utilities ME Division		36		03/31/2021
Granite State		4		03/31/2021
Unitil Energy		36		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

As discussed above, Unitil meets its external financing needs by issuing short-term and long-term debt. The majority of debt outstanding represents long-term notes bearing fixed rates of interest. Changes in market interest rates do not affect interest expense resulting from these outstanding long-term debt securities. However, the Company periodically repays its short-term debt borrowings through the issuance of new long-term debt securities. Changes in market interest rates may affect the interest rate and corresponding interest expense on any new issuances of long-term debt securities. In addition, short-term debt borrowings bear a variable rate of interest. As a result, changes in short-term interest rates will increase or decrease interest expense in future periods. For example, if the average amount of short-term debt outstanding was $25 million for the period of one year, a change in interest rates of 1% would result in a change in annual interest expense of approximately $250,000. The average interest rates on the Company’s short-term borrowings and intercompany money pool transactions for the three months ended September 30, 2019 and September 30, 2018 were 3.4% and 3.3%, respectively. The average interest rates on the Company’s short-term borrowings for the nine months ended September 30, 2019 and September 30, 2018 were 3.6% and 3.2%, respectively. The average interest rate on the Company’s short-term borrowings for the twelve months ended December 31, 2018 was 3.3%.

COMMODITY PRICE RISK

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

17

Regulatory Matters

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

ENVIRONMENTAL MATTERS

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

18

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF EARNINGS

(Millions except per share data)

(UNAUDITED)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019			2018
Operating Revenues
Gas	$	24.9	$	25.7	$	143.9		$	147.4
Electric		60.4		61.4		177.0			167.6
Other		—		1.1		0.9			3.5
Total Operating Revenues		85.3		88.2		321.8			318.5
Operating Expenses
Cost of Gas Sales		6.2		8.1		58.4			67.0
Cost of Electric Sales		35.3		35.5		106.4			97.1
Operation and Maintenance		15.5		16.4		49.9			51.5
Depreciation and Amortization		12.8		12.4		39.0			37.4
Taxes Other Than Income Taxes		5.5		5.5		17.0			16.5
Total Operating Expenses		75.3		77.9		270.7			269.5
Operating Income		10.0		10.3		51.1			49.0
Interest Expense, Net		5.8		6.0		17.9			17.9
Other Expense (Income), Net		1.0		1.1		(9.8	)		4.1
Income Before Income Taxes		3.2		3.2		43.0			27.0
Provision for Income Taxes		0.9		0.4		10.2			5.0
Net Income	$	2.3	$	2.8	$	32.8		$	22.0
Net Income Per Common Share (Basic and Diluted)	$	0.15	$	0.19	$	2.20		$	1.49
Weighted Average Common Shares Outstanding – (Basic and Diluted)		14.9		14.8		14.9			14.8

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

19

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Millions)

(UNAUDITED)

	September 30,				December 31,
	2019		2018		2018
ASSETS:
Current Assets:
Cash and Cash Equivalents	$	7.3	$	6.3	$	7.8
Accounts Receivable, Net		39.4		52.3		66.8
Accrued Revenue		35.3		36.0		54.7
Exchange Gas Receivable		8.6		10.1		8.1
Refundable Taxes		2.9		—		0.5
Gas Inventory		0.8		0.9		0.8
Materials and Supplies		7.7		7.2		7.0
Prepayments and Other		5.4		7.8		6.5
Total Current Assets		107.4		120.6		152.2
Utility Plant:
Gas		783.2		712.7		760.6
Electric		514.8		485.6		500.1
Common		61.6		82.1		83.1
Construction Work in Progress		72.9		68.4		25.5
Utility Plant		1,432.5		1,348.8		1,369.3
Less: Accumulated Depreciation		348.6		326.5		332.5
Net Utility Plant		1,083.9		1,022.3		1,036.8
Other Noncurrent Assets:
Regulatory Assets		98.7		111.6		99.0
Operating Lease Right of Use Assets		4.2		—		—
Other Assets		15.5		10.0		10.3
Total Other Noncurrent Assets		118.4		121.6		109.3
TOTAL ASSETS	$	1,309.7	$	1,264.5	$	1,298.3

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

20

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS (Cont.)

(Millions, except number of shares)

(UNAUDITED)

	September 30,				December 31,
	2019		2018		2018
LIABILITIES AND CAPITALIZATION:
Current Liabilities:
Accounts Payable	$	22.9	$	27.4	$	42.6
Short-Term Debt		49.2		69.1		82.8
Long-Term Debt, Current Portion		19.5		31.8		18.4
Regulatory Liabilities		14.4		12.2		11.5
Energy Supply Obligations		12.5		15.0		13.4
Interest Payable		7.1		7.0		4.3
Other Current Liabilities		18.8		18.0		19.5
Total Current Liabilities		144.4		180.5		192.5
Noncurrent Liabilities:
Retirement Benefit Obligations		120.8		142.4		121.5
Deferred Income Taxes, net		108.3		86.4		97.8
Cost of Removal Obligations		98.4		91.2		90.7
Regulatory Liabilities		46.7		47.9		47.0
Other Noncurrent Liabilities		10.2		10.0		10.1
Total Noncurrent Liabilities		384.4		377.9		367.1
Capitalization:
Long-Term Debt, Less Current Portion		410.9		361.1		387.4
Stockholders’ Equity:
Common Equity (Authorized: 25,000,000 and Outstanding: 14,925,898, 14,872,011 and 14,876,955 Shares)		281.7		278.3		279.1
Retained Earnings		88.1		66.5		72.0
Total Common Stock Equity		369.8		344.8		351.1
Preferred Stock		0.2		0.2		0.2
Total Stockholders’ Equity		370.0		345.0		351.3
Total Capitalization		780.9		706.1		738.7
Commitments and Contingencies (Notes 6 & 7)
TOTAL LIABILITIES AND CAPITALIZATION	$	1,309.7	$	1,264.5	$	1,298.3

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

21

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions)

(UNAUDITED)

	Nine Months Ended September 30,
	2019			2018
Operating Activities:
Net Income	$	32.8		$	22.0
Adjustments to Reconcile Net Income to Cash
Provided by Operating Activities:
Depreciation and Amortization		39.0			37.4
Deferred Tax Provision		9.3			4.6
Gain on Divestiture, Net (See Note 1)		(13.4	)		—
Changes in Working Capital Items:
Accounts Receivable		27.4			15.1
Accrued Revenue		19.4			17.3
Exchange Gas Receivable		(0.5	)		(4.3	)
Regulatory Liabilities		2.9			3.0
Accounts Payable		(19.7	)		(14.1	)
Other Changes in Working Capital Items		(2.4	)		3.7
Deferred Regulatory and Other Charges		(4.7	)		(5.7	)
Other, net		2.1			(9.0	)
Cash Provided by Operating Activities		92.2			70.0
Investing Activities:
Property, Plant and Equipment Additions		(76.7	)		(76.3	)
Proceeds from Divestiture, Net (See Note 1)		13.4			—
Cash (Used in) Investing Activities		(63.3	)		(76.3	)
Financing Activities:
(Repayment of) Proceeds from Short-Term Debt, net		(33.6	)		30.8
Repayment of Long-Term Debt		(15.2	)		(13.5	)
Issuance of Long-Term Debt		39.8			—
Decrease in Capital Lease Obligations		(5.1	)		(2.3	)
Net Increase in Exchange Gas Financing		0.5			4.1
Dividends Paid		(16.7	)		(16.3	)
Proceeds from Issuance of Common Stock, net		0.9			0.9
Cash (Used in) Provided by Financing Activities		(29.4	)		3.7
Net Decrease in Cash and Cash Equivalents		(0.5	)		(2.6	)
Cash and Cash Equivalents at Beginning of Period		7.8			8.9
Cash and Cash Equivalents at End of Period	$	7.3		$	6.3
Supplemental Cash Flow Information:
Interest Paid	$	15.6		$	15.6
Income Taxes Paid	$	0.9		$	0.4
Payments on Capital Leases	$	5.4		$	2.3
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$	0.8		$	1.2
Right-of-Use Assets Obtained in Exchange for Lease Obligations	$	4.2		$	—

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

22

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

(Millions, except per share data and number of shares)

(UNAUDITED)

	Common Equity		Retained Earnings			Total
Three Months Ended September 30, 2019
Balance at July 1, 2019	$	281.3	$	91.5		$	372.8
Net Income				2.3			2.3
Dividends on Common Shares ($0.370 per share)				(5.7	)		(5.7	)
Stock Compensation Plans		0.1					0.1
Issuance of 4,727 Common Shares		0.3					0.3
Balance at September 30, 2019	$	281.7	$	88.1		$	369.8
Three Months Ended September 30, 2018
Balance at July 1, 2018	$	277.9	$	69.1		$	347.0
Net Income				2.8			2.8
Dividends on Common Shares ($0.365 per share)				(5.4	)		(5.4	)
Stock Compensation Plans		0.1					0.1
Issuance of 5,423 Common Shares		0.3					0.3
Balance at September 30, 2018	$	278.3	$	66.5		$	344.8

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

23

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

(Millions, except per share data and number of shares)

(UNAUDITED)

	Common Equity		Retained Earnings			Total
Nine Months Ended September 30, 2019
Balance at January 1, 2019	$	279.1	$	72.0		$	351.1
Net Income				32.8			32.8
Dividends on Common Shares ($1.11 per share)				(16.7	)		(16.7	)
Stock Compensation Plans		1.7					1.7
Issuance of 15,793 Common Shares		0.9					0.9
Balance at September 30, 2019	$	281.7	$	88.1		$	369.8
Nine Months Ended September 30, 2018
Balance at January 1, 2018	$	275.8	$	60.8		$	336.6
Net Income				22.0			22.0
Dividends on Common Shares ($1.095 per share)				(16.3	)		(16.3	)
Stock Compensation Plans		1.5					1.5
Issuance of 19,700 Common Shares		1.0					1.0
Balance at September 30, 2018	$	278.3	$	66.5		$	344.8

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

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 1 – Summary of Significant Accounting Policies

Nature of Operations – Unitil Corporation (Unitil or the Company) is a public utility holding company. Unitil and its subsidiaries are subject to regulation as a holding company system by the Federal Energy Regulatory Commission (FERC) under the Energy Policy Act of 2005. The following companies are wholly-owned subsidiaries of Unitil: Unitil Energy Systems, Inc. (Unitil Energy), Fitchburg Gas and Electric Light Company (Fitchburg), Northern Utilities, Inc. (Northern Utilities), 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). Usource Inc. and Usource L.L.C., which the Company sold in the first quarter of 2019, were wholly-owned subsidiaries of Unitil Resources.

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

Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capital regions of New Hampshire and the greater Fitchburg area of north central Massachusetts, and the local distribution of natural gas in southeastern New Hampshire, portions of southern and central Maine 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 a natural gas transportation pipeline, 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 natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.

A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of Unitil Energy on May 1, 2003 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.

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. Usource, Inc. and Usource L.L.C. (collectively, Usource), which the Company divested of in the first quarter of 2019, were wholly-owned subsidiaries of Unitil Resources. Usource provided brokering and advisory services to large commercial and industrial customers in the northeastern United States. See additional discussion of the divestiture of Usource below.

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 and are of a normal and recurring nature. The results of operations for the three and nine months ended September 30, 2019 are not necessarily indicative of results to be expected for the year ending December 31, 2019. 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, 2018, as filed with the Securities and Exchange Commission (SEC) on January 31, 2019, for a description of the Company’s Basis of Presentation.

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Divestiture of Non-Regulated Business Subsidiary – On March 1, 2019, the Company divested of its non-regulated energy brokering and advisory business subsidiary, Usource. The Company recognized an after-tax net gain of approximately $9.8 million on this divestiture in the first quarter of 2019. The pre-tax net gain of approximately $13.4 million on this divestiture is included in Other Income (Expense), Net on the Consolidated Statements of Earnings for the nine months ended September 30, 2019, while the income taxes associated with this transaction of $3.6 million are included in the Provision For Income Taxes.

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.

Billed and unbilled revenue is recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenues are calculated. These unbilled revenues are calculated each month based on estimated customer usage by class and applicable customer rates 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 ASU 2014-09. Revenue recognized in connection with rate adjustment mechanisms is consistent with the definition of alternative revenue programs in Accounting Standards Codification (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. ASU 2014-09 requires the Company to disclose separately the amount of revenues from contracts with customers and alternative revenue program revenues.

26

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

 

	Three Months Ended September 30, 2019
Gas and Electric Operating Revenues ($ millions):	Gas			Electric		Total
Billed and Unbilled Revenue:
Residential	$	6.9		$	31.3	$	38.2
C&I		12.5			24.5		37.0
Other		1.1			1.5		2.6
Total Billed and Unbilled Revenue		20.5			57.3		77.8
Rate Adjustment Mechanism Revenue		4.4			3.1		7.5
Total Gas and Electric Operating Revenues	$	24.9		$	60.4	$	85.3
	Three Months Ended September 30, 2018
Gas and Electric Operating Revenues ($ millions):	Gas			Electric		Total
Billed and Unbilled Revenue:
Residential	$	6.6		$	33.6	$	40.2
C&I		11.9			25.3		37.2
Other		1.1			2.0		3.1
Total Billed and Unbilled Revenue		19.6			60.9		80.5
Rate Adjustment Mechanism Revenue		6.1			0.5		6.6
Total Gas and Electric Operating Revenues	$	25.7		$	61.4	$	87.1
	Nine Months Ended September 30, 2019
Gas and Electric Operating Revenues ($ millions):	Gas			Electric		Total
Billed and Unbilled Revenue:
Residential	$	61.4		$	94.8	$	156.2
C&I		89.5			72.2		161.7
Other		9.1			5.8		14.9
Total Billed and Unbilled Revenue		160.0			172.8		332.8
Rate Adjustment Mechanism Revenue		(16.1	)		4.2		(11.9	)
Total Gas and Electric Operating Revenues	$	143.9		$	177.0	$	320.9

27

	Nine Months Ended September 30, 2018
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	58.3		$	95.6		$	153.9
C&I		84.7			74.1			158.8
Other		8.1			6.5			14.6
Total Billed and Unbilled Revenue		151.1			176.2			327.3
Rate Adjustment Mechanism Revenue		(3.7	)		(8.6	)		(12.3	)
Total Gas and Electric Operating Revenues	$	147.4		$	167.6		$	315.0

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 natural 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 Massachusetts Department of Public Utilities (MDPU). The Company estimates that revenue decoupling applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.

Other Operating Revenue – Non-regulated – Other Operating Revenue – Non-regulated – Other Operating Revenue consists solely of revenue from Usource, Unitil’s non-regulated subsidiary, which, as discussed previously, the Company divested of on March 1, 2019. Usource conducted its business activities as a broker of competitive energy services. Usource did not take title to the electric and gas commodities which were the subject of the brokerage contracts. The Company recorded energy brokering revenues based upon the amount of electricity and gas delivered to customers through the end of the accounting period. Usource partnered with certain entities to facilitate these brokerage services and paid these entities a fee under revenue sharing agreements.

Income Taxes – The Company is subject to Federal and State income taxes as well as various other business taxes. This process involves estimating the Company’s current tax liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included in the Company’s Consolidated Balance Sheets. The Company accounts for income tax assets, liabilities and expenses in accordance with the Financial Accounting Standards Board (FASB) Codification guidance on Income Taxes. The Company classifies penalty and interest expense related to income tax liabilities as income tax expense and interest expense, respectively, in the Consolidated Statements of Earnings.

Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s current and 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. 

28

Cash and Cash Equivalents – Cash and Cash Equivalents include all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. As of September 30, 2019, September 30, 2018 and December 31, 2018, the Unitil subsidiaries had deposited $3.5 million, $3.2 million and $3.5 million, respectively to satisfy their ISO-NE obligations.

Allowance for Doubtful Accounts – The Company recognizes a provision for doubtful accounts each month based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables is performed which takes into account an assumption about the cash recovery of delinquent receivables. The analysis 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 hardship accounts that are protected from shut-off. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including the level of customers enrolling in payment plans with the Company. It has been the Company’s experience that the assumptions it has used in evaluating the adequacy of the Allowance for Doubtful Accounts have proven to be reasonably accurate.

The Allowance for Doubtful Accounts as of September 30, 2019, September 30, 2018 and December 31, 2018, which is included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, was as follows:

($ millions)
	September 30,				December 31,
	2019		2018		2018
Allowance for Doubtful Accounts	$	1.0	$	1.2	$	1.3

Accrued Revenue – Accrued Revenue includes the current portion of Regulatory Assets and unbilled revenues. The following table shows the components of Accrued Revenue as of September 30, 2019, September 30, 2018 and December 31, 2018. 

	September 30,				December 31,
Accrued Revenue ($ millions)	2019		2018		2018
Regulatory Assets – Current	$	24.9	$	26.4	$	41.3
Unbilled Revenues		10.4		9.6		13.4
Total Accrued Revenue	$	35.3	$	36.0	$	54.7

Exchange Gas Receivable – Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers natural gas back to the Company during the months of November through March. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of September 30, 2019, September 30, 2018 and December 31, 2018.

29

	September 30,				December 31,
Exchange Gas Receivable ($ millions)	2019		2018		2018
Northern Utilities	$	8.0	$	9.5	$	7.5
Fitchburg		0.6		0.6		0.6
Total Exchange Gas Receivable	$	8.6	$	10.1	$	8.1

Gas Inventory – The Company uses the weighted average cost methodology ​​​​​​​to value natural gas inventory. The following table shows the components of Gas Inventory as of September 30, 2019, September 30, 2018 and December 31, 2018.

	September 30,				December 31,
Gas Inventory ($ millions)	2019		2018		2018
Natural Gas	$	0.4	$	0.4	$	0.3
Propane		0.3		0.4		0.4
Liquefied Natural Gas & Other		0.1		0.1		0.1
Total Gas Inventory	$	0.8	$	0.9	$	0.8

Utility Plant – The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At September 30, 2019, September 30, 2018 and December 31, 2018, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $98.4 million, $91.2 million, and $90.7 million, respectively.

Leases – On January 1, 2019, the Company adopted ASU No. 2016-02, “Leases (Topic 842)”. The new standard requires lessees to record assets and liabilities on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allows the Company to carryforward the historical lease classification. The Company also elected the practical expedient related to land easements, allowing the Company to carry forward its current accounting treatment for land easements on existing agreements. The Company made an accounting policy election to keep leases with an initial term of 12 months or less off of the balance sheet. The Company recognizes those lease payments in the Consolidated Statements of Earnings on a straight-line basis over the lease term. The adoption of the standard resulted in recognition of approximately $4.2 million of lease assets and lease liabilities as of January 1, 2019 on the Company’s Consolidated Balance Sheets. The Company’s adoption of the standard did not have a material effect on its Consolidated Statements of Earnings and Consolidated Statements of Cash Flows. See additional discussion below in the “Leases” section of Note 4 to the Consolidated Financial Statements.

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

30

(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.

	September 30,				December 31,
Regulatory Assets consist of the following ($ millions)	2019		2018		2018
Retirement Benefits	$	74.0	$	88.0	$	72.0
Energy Supply & Other Rate Adjustment Mechanisms		20.6		24.8		38.4
Deferred Storm Charges		5.0		6.3		6.3
Environmental		8.0		8.9		7.9
Income Taxes		4.3		5.9		5.7
Other		11.7		4.1		10.0
Total Regulatory Assets		123.6		138.0		140.3
Less: Current Portion of Regulatory Assets(1)		24.9		26.4		41.3
Regulatory Assets – noncurrent	$	98.7	$	111.6	$	99.0

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

	September 30,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2019		2018		2018
Income Taxes (Note 8)	$	47.6	$	47.9	$	47.0
Energy Supply & Other Rate Adjustment Mechanisms		13.5		12.2		11.5
Total Regulatory Liabilities		61.1		60.1		58.5
Less: Current Portion of Regulatory Liabilities		14.4		12.2		11.5
Regulatory Liabilities—noncurrent	$	46.7	$	47.9	$	47.0

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. As of September 30, 2019 there are $5.8 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years which regulators have authorized recovery of, but without a return. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

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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 none of its energy supply contracts currently qualify as a derivative instrument under the guidance set forth in the FASB Codification.

As discussed below in the “Fitchburg – Massachusetts RFP’s” section of Note 6 (Regulatory Matters), Fitchburg has entered into power purchase agreements for which contingencies exist. 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 impact on the contractual obligations and regulatory assets of Fitchburg, once they qualify for derivative accounting.

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.)

At September 30, 2019, September 30, 2018 and December 31, 2018, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $5.9 million, $5.3 million and $4.8 million, respectively, as shown in the table below. 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 (Income), Net.

	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2019		2018		2018
Equity Funds	$	—	$	3.0	$	—
Fixed Income Funds		—		2.3		—
Money Market Funds		5.9		—		4.8
Total Marketable Securities	$	5.9	$	5.3	$	4.8

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

At September 30, 2019, September 30, 2018 and December 31, 2018, 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 $0.1 million, $0 and $0, respectively, as shown in the table below. 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.​​​​​​​

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	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2019		2018		2018
Equity Funds	$	—	$	—	$	—
Money Market Funds		0.1		—		—
Total Marketable Securities	$	0.1	$	—	$	—

Energy Supply Obligations – The following ​​​​​​​discussion and table summarize the nature and amounts of the items recorded on the Company’s Consolidated Balance Sheets. The current portion of these obligations is recorded as Energy Supply Obligations and the noncurrent portion is included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets.

	September 30,				December 31,
Energy Supply Obligations ($ millions)	2019		2018		2018
Current:
Exchange Gas Obligation	$	8.0	$	9.5	$	7.5
Renewable Energy Portfolio Standards		4.2		5.2		5.6
Power Supply Contract Divestitures		0.3		0.3		0.3
Total Energy Supply Obligations – Current		12.5		15.0		13.4
Noncurrent:
Power Supply Contract Divestitures		0.4		0.7		0.6
Total Energy Supply Obligations	$	12.9	$	15.7	$	14.0

Exchange Gas Obligation – Northern Utilities enters into gas exchange agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. The gas inventory related to these agreements is recorded in Exchange Gas Receivable on the Company’s Consolidated Balance Sheets while the corresponding obligations are recorded in Energy Supply Obligations.

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 is recorded in Accrued Revenue with a corresponding liability in Energy Supply Obligations on the Company’s Consolidated Balance Sheets.

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Fitchburg has entered into long-term renewable contracts for the purchase of clean energy and/or renewable energy certificates (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 four of these contracts have been constructed and are now operating. Since 2017, the Company has participated in two major statewide procurements which resulted in contracts for imported hydroelectric power and associated transmission and for offshore wind generation. The contracts were approved by the MDPU in the second quarter of 2019.

Additional long-term clean energy contracts are expected in compliance with the Energy Diversity Act and An Act to Promote a Clean Energy Future (2018). 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 – As a result of the restructuring of the utility industry in New Hampshire and Massachusetts, Unitil Energy’s and Fitchburg’s customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs. 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 (current portion) and Regulatory Assets (long-term portion).

Recently Issued Pronouncements – In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842)”. The new standard requires lessees to record assets and liabilities on the balance sheet for all leases with terms longer than 12 months. The Company adopted the standard as of January 1, 2019. See “Leases” above in Note 1.

Other than the pronouncement discussed above, there are no recently issued pronouncements that the Company has not already adopted or that have a material impact on the Company.

Subsequent Events – The Company has evaluated all events or transactions through the date of this filing. During this period the Company did not have any material subsequent events that would result in adjustment to or disclosure in its unaudited consolidated financial statements.

Note 2 – Dividends Declared Per Share

Declaration Date	Date Paid (Payable)	Shareholder of Record Date	Dividend Amount
10/23/19	11/27/19	11/13/19	$ 0.370
07/24/19	08/29/19	08/15/19	$ 0.370
04/24/19	05/29/19	05/15/19	$ 0.370
01/30/19	02/28/19	02/14/19	$ 0.370
10/24/18	11/29/18	11/15/18	$ 0.365
07/25/18	08/29/18	08/15/18	$ 0.365
04/25/18	05/29/18	05/15/18	$ 0.365
01/30/18	02/28/18	02/14/18	$ 0.365

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note 3 – Segment Information

The following table provides significant segment financial data for the three and nine months ended September 30, 2019 and September 30, 2018 and as of December 31, 2018 (millions):

	Gas			Electric		Non- Regulated		Other		Total
Three Months Ended September 30, 2019
Revenues:
Billed and Unbilled Revenue	$	20.5		$	57.3	$	—	$	—	$	77.8
Rate Adjustment Mechanism Revenue		4.4			3.1		—		—		7.5
Other Operating Revenue – Non-Regulated		—			—		—		—		—
Total Operating Revenues	$	24.9		$	60.4	$	—	$	—	$	85.3
Segment Profit		(3.9	)		4.4		—		1.8		2.3
Capital Expenditures		26.9			9.2		—		1.9		38.0
Three Months Ended September 30, 2018
Revenues:
Billed and Unbilled Revenue	$	19.6		$	60.9	$	—	$	—	$	80.5
Rate Adjustment Mechanism Revenue		6.1			0.5		—		—		6.6
Other Operating Revenue – Non-Regulated		—			—		1.1		—		1.1
Total Operating Revenues	$	25.7		$	61.4	$	1.1	$	—	$	88.2
Segment Profit (Loss)		(3.2	)		4.5		0.3		1.2		2.8
Capital Expenditures		30.9			7.2		—		1.0		39.1

Nine Months Ended September 30, 2019
Revenues:
Billed and Unbilled Revenue	$	160.0		$	172.8		$	—	$	—	$	332.8
Rate Adjustment Mechanism Revenue		(16.1	)		4.2			—		—		(11.9	)
Other Operating Revenue – Non-Regulated		—			—			0.9		—		0.9
Total Operating Revenues	$	143.9		$	177.0		$	0.9	$	—	$	321.8
Segment Profit		10.1			9.7			10.2		2.8		32.8
Capital Expenditures		48.3			24.1			—		4.3		76.7
Segment Assets		780.7			507.6			0.3		21.1		1,309.7
Nine Months Ended September 30, 2018
Revenues:
Billed and Unbilled Revenue	$	151.1		$	176.2		$	—	$	—	$	327.3
Rate Adjustment Mechanism Revenue		(3.7	)		(8.6	)		—		—		(12.3	)
Other Operating Revenue – Non-Regulated		—			—			3.5		—		3.5
Total Operating Revenues	$	147.4		$	167.6		$	3.5	$	—	$	318.5
Segment Profit		9.1			10.2			0.9		1.8		22.0
Capital Expenditures		53.1			20.8			—		2.4		76.3
Segment Assets		730.0			485.7			6.6		42.2		1,264.5

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Note 4 – Debt AND FINANCING ARRANGEMENTS

Details on long-term debt at September 30, 2019, September 30, 2018 and December 31, 2018 are shown below:

($ millions)	September 30,				December 31,
	2019		2018		2018
Unitil Corporation:
6.33% Senior Notes, Due May 1, 2022	$	20.0	$	20.0	$	20.0
3.70% Senior Notes, Due August 1, 2026		30.0		30.0		30.0
Unitil Energy First Mortgage Bonds:
5.24% Senior Secured Notes, Due March 2, 2020		5.0		10.0		10.0
8.49% Senior Secured Notes, Due October 14, 2024		6.0		7.5		6.0
6.96% Senior Secured Notes, Due September 1, 2028		18.0		20.0		20.0
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
4.18% Senior Secured Notes, Due November 30, 2048		30.0		—		30.0
Fitchburg:
6.75% Senior Notes, Due November 30, 2023		5.7		7.6		5.7
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		12.0		12.0		12.0
5.90% Senior Notes, Due December 15, 2030		15.0		15.0		15.0
7.98% Senior Notes, Due June 1, 2031		14.0		14.0		14.0
4.32% Senior Notes, Due November 1, 2047		15.0		15.0		15.0
Northern Utilities:
6.95% Senior Notes, Due December 3, 2018		—		10.0		—
5.29% Senior Notes, Due March 2, 2020		8.2		16.6		16.6
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
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		—		—
Granite State:
7.15% Senior Notes, Due December 15, 2018		—		3.3		—
3.72% Senior Notes, Due November 1, 2027		15.0		15.0		15.0
Total Long-Term Debt		433.9		396.0		409.3
Less: Unamortized Debt Issuance Costs		3.5		3.1		3.5
Total Long-Term Debt, net of Unamortized Debt Issuance Costs		430.4		392.9		405.8
Less: Current Portion(1)		19.5		31.8		18.4
Total Long-term Debt, Less Current Portion	$	410.9	$	361.1	$	387.4

(1) The Current Portion of Long-Term Debt ​​​​​​​includes sinking ​​​​​​​fund payments.

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

($ millions)	September 30,				December 31,
	2019		2018		2018
Estimated Fair Value of Long-Term Debt	$	495.1	$	418.7	$	422.0

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

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $187.1 million for the nine months ended September 30, 2019. Total gross repayments were $220.7 million for the nine months ended September 30, 2019. The following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of September 30 2019, September 30, 2018 and December 31, 2018:

	Revolving Credit Facility ($ millions)
	September 30,				December 31,
	2019		2018		2018
Limit	$	120.0	$	120.0	$	120.0
Short-Term Borrowings Outstanding		49.2		69.1		82.8
Letter of Credit Outstanding		0.1		—		—
Available	$	70.7	$	50.9	$	37.2

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 shall apply until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At September 30, 2019, September 30, 2018 and December 31, 2018, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.

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The Company believes the future operating cash flows of the Company, along with its existing borrowing availability and access to financial markets for the issuance of new long-term debt, will be sufficient to meet any working capital and future operating requirements, and capital investment forecast opportunities.

The average interest rates on all short-term borrowings and intercompany money pool transactions were 3.4% and 3.3% for the three months ended September 30, 2019 and September 30, 2018, respectively. The average interest rates on all short-term borrowings and intercompany money pool transactions were 3.6% and 3.2% for the nine months ended September 30, 2019 and September 30, 2018, respectively. The average interest rate on all short-term borrowings for the twelve months ended December 31, 2018 was 3.3%.

As discussed previously, the Company divested of its non-regulated subsidiary business, Usource, in the first quarter of 2019. The Company used the net proceeds of $9.8 million from this divestiture for general corporate purposes.

On September 12, 2019, Northern Utilities issued $40 million of Notes due 2049 at 4.04%. Northern Utilities used the net proceeds from this offering to repay short-term debt and for general corporate purposes. Approximately $0.2 million of costs associated with these issuances have been netted against Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.

On November 30, 2018 Unitil Energy issued $30 million of First Mortgage Bonds due November 30, 2048 at 4.18%. Unitil Energy used the net proceeds from this offering to repay short-term debt and for general corporate purposes. Approximately $0.5 million of costs associated with these issuances have been netted against long-term debt for presentation purposes on the Consolidated Balance Sheets.

In April 2014, Unitil Service Corp. entered into a financing arrangement, structured as a capital lease obligation, for various information systems and technology equipment. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. This capital lease was paid off in the second quarter of 2019.

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

Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There was $8.1 million, $9.6 million and $8.4 million of natural gas storage inventory at September 30, 2019, September 30, 2018 and December 31, 2018, respectively, related to these asset management agreements. The amount of natural gas inventory released in September 2019 and payable in October 2019 is $0.1 million and is recorded in Accounts Payable at September 30, 2019. The amount of natural gas inventory released in September 2018 and payable in October 2018 was $0.1 million and was recorded in Accounts Payable at September 30, 2018. The amount of natural gas inventory released in December 2018 and payable in January 2019 was $0.9 million and was recorded in Accounts Payable at December 31, 2018.

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Guarantees

The Company provides limited guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of September 30, 2019, there were approximately $4.3 million of guarantees outstanding.

Leases

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

Total rental expense under operating leases charged to operations for the three months ended September 30, 2019 and 2018 amounted to $0.4 million and $0.4 million, respectively. Total rental expense under operating leases charged to operations for the nine months ended September 30, 2019 and 2018 amounted to $1.1 million and $1.4 million, respectively.

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

	September 30,				December 31,
Lease Obligations ($ millions)	2019		2018		2018
Operating Lease Obligations:
Other Current Liabilities (current portion)	$	1.2	$	—	$	—
Other Noncurrent Liabilities (long-term portion)		3.0		—		—
Total Operating Lease Obligations		4.2		—		—
Capital Lease Obligations:
Other Current Liabilities (current portion)		0.3		3.1		3.1
Other Noncurrent Liabilities (long-term portion)		0.3		3.4		2.7
Total Capital Lease Obligations		0.6		6.5		5.8
Total Lease Obligations	$	4.8	$	6.5	$	5.8

Cash paid for amounts included in the measurement of operating lease obligations for the nine months ended September 30, 2019 was $1.1 million and was included in Cash Provided by Operating Activities on the Consolidated Statements of Cash Flows.

Assets under capital leases amounted to approximately $1.3 million, $15.0 million and $15.0 million as of September 30, 2019, September 30, 2018 and December 31, 2018, respectively, less accumulated amortization of $0.6 million, $2.1 million and $1.7 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheets.

The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of September 30, 2019. The payments for capital leases consist of $0.3​​​​​​​​​​​​​​ million of current capital lease obligations, which are included in Other​​​​​​​ Current Liabilities and $0.3 million of noncurrent capital lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of September 30, 2019.

The payments for operating leases consist of $1.2 million of current operating lease obligations, which are included in Other Current Liabilities and $3.0 million of noncurrent operating lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of September 30, 2019.

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Lease Payments ($000’s) Year Ending December 31,	Operating Leases		Capital Leases
Rest of 2019	$	356	$	80
2020		1,338		262
2021		1,168		161
2022		887		97
2023		587		55
2024-2028		400		—
Total Payments		4,736		655
Less: Interest		507		35
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$	4,229	$	620

Operating lease obligations are based on the net present value of the remaining lease payments over the remaining lease term. In determining the present value of lease payments, the Company used the interest rate stated in each lease agreement. As of September 30, 2019, the weighted average remaining lease term is 4.0 years and the weighted average operating discount rate used to determine the operating lease obligations was 5.3%.

Disclosures Related to Periods Prior to the Adoption of ASU NO. 2016-02 – Leases (See Note 1).

The payment amounts in the following table, which are as of December 31, 2018, would not differ substantially from the payment amounts as of September 30, 2018.

Lease Payments ($000’s) Year Ending December 31,	Operating Leases		Capital Leases
2019	$	1,372	$	3,069
2020		1,138		2,535
2021		969		93
2022		689		32
2023		390		14
2024-2028		120		—
Total Payments	$	4,678	$	5,743

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 14,872,011, 14,876,955 and 14,925,898 shares of common stock outstanding at September 30, 2018, December 31, 2018 and September 30, 2019, respectively.

Dividend Reinvestment and Stock Purchase Plan – During the first nine months of 2019, the Company sold 15,793 shares of its common stock, at an average price of $56.29 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $889,000. The DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock.

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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 29, 2019, 33,150 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of approximately $1.6 million. There were 50,917 and 49,581 non-vested shares under the Stock Plan as of September 30, 2019 and 2018, respectively. The weighted average grant date fair value of these shares was $46.41 and $41.96, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $2.2 million and $2.1 million for the nine months ended September 30, 2019 and 2018, respectively. At September 30, 2019, there was approximately $0.8 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.7 years. There were no forfeitures and no cancellations under the Stock Plan during the nine months ended September 30, 2019.

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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. Restricted Stock Units earn dividend equivalents and will generally be settled by payment to each Director as soon as practicable following the Director’s separation from service to the Company. The Restricted Stock Units will be paid such that the Director will receive (i) 70% of the shares of the Company’s common stock underlying the restricted stock units and (ii) cash in an amount equal to the fair market value of 30% of the shares of the Company’s common stock underlying the Restricted Stock Units. The equity portion of Restricted Stock Units activity during the nine months ended September 30, 2019 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, 2018		61,789	$	38.25
Restricted Stock Units Granted		—		—
Dividend Equivalents Earned		1,210	$	57.08
Restricted Stock Units Settled		—		—
Restricted Stock Units as of September 30, 2019		62,999	$	38.61

There were 53,454 Restricted Stock Units outstanding as of September 30, 2018 with a weighted average stock price of $36.47. On October 1, 2019, there were 9,918 fully-vested Restricted Stock Units issued to members of the Company’s Board of Directors. Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of September 30, 2019, September 30, 2018 and December 31, 2018 is $1.7 million, $1.2 million and $1.3 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 was $0.2 million, or 1,887 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of September 30, 2019.  There was $0.2 million, or 1,893 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of September 30, 2018 and December 31, 2018. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the three and nine month periods ended September 30, 2019 and September 30, 2018, 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, 2018 as filed with the Securities and Exchange Commission on january 31, 2019.

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 percent, 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 opened a rulemaking proceeding on this matter which has been addressed in a rate settlement filing by Granite State. More recently, on November 15, 2018, the FERC issued a Notice of Proposed Rulemaking and a Policy Statement to address the TCJA’s effects on the Accumulated Deferred Income Taxes (ADIT) on transmission rates. Under the proposed rules all public utilities with transmission formula rates, including Fitchburg, would be required to: (1) include mechanisms to deduct any excess ADIT from or add any deficient ADIT to their rate bases; (2) include mechanisms in those rates that would raise or lower their income tax allowances by any amortized excess or deficient ADIT; and (3) incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT. The Company believes that these matters are substantially resolved and will not have a material impact on its financial position, operating results, or cash flows.

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Rate Case Activity

Northern Utilities – Base Rates – Maine – On June 28, 2019, Northern Utilities filed a petition with the MPUC seeking an increase to annual base operating revenues of $7.0 million. If approved as filed, the requested increase will result in a 7 percent increase over the Company’s test-year operating revenues. The intended rate effective date is April 1, 2020. In addition, Northern Utilities is requesting approval to implement a multi-year alternative rate mechanism (“Capital Investment Recovery Adjustment” or “CIRA”) that will allow for future changes to the Company’s distribution rates and mitigate the need to file a general rate case. The CIRA is designed to recover the costs of replacing, relocating and abandoning existing facilities and other operational and safety-related system improvements. The first annual adjustment is proposed for November 1, 2020, to recover the Company’s 2019 investment cost of eligible facilities and improvements. This matter remains pending.

Northern Utilities – Targeted Infrastructure Replacement Adjustment (TIRA) – Maine – The settlement in Northern Utilities’ Maine division’s 2013 rate case allowed 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’ last 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. On May 7, 2018, the MPUC approved the Company’s request to increase its annual base rates by 2.4%, or $1.1 million, effective May 1, 2018, to recover the revenue requirements for 2017 eligible facilities. On April 17, 2019, the MPUC approved the Company’s request to increase its annual base rates by 2.1%, or $1.0 million, effective May 1, 2019, to recover the revenue requirements for 2018 eligible facilities.

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 step increase of approximately $1.4 million of annual revenue was approved by the NHPUC, effective May 1, 2019, to recover eligible capital investments in 2018. According to the terms of the settlement agreement, Northern Utilities’ next distribution base rate case shall be based on an historic test year of no earlier than twelve months ending December 31, 2020.

Unitil Energy – Base Rates – On April 20, 2017 the NHPUC issued its final order providing for a permanent increase of $4.1 million, effective May 1, 2017, followed by two annual rate step adjustments to recover the revenue requirements associated with certain capital expenditures. On April 30, 2018, the NHPUC approved Unitil Energy’s first step increase, effective May 1, 2018. On April 22, 2019, the NHPUC approved Unitil Energy’s second and final step adjustment, providing for a revenue increase of approximately $340,000, effective May 1, 2019.

Fitchburg – Base Rates – Electric – Fitchburg’s base rates are decoupled, and subject to an annual revenue decoupling adjustment mechanism, which includes a cap on the amount that rates may be increased in any year. In addition, Fitchburg has an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions. On April 3, 2019, the DPU approved Fitchburg’s cumulative revenue requirement associated with the Company’s 2015 and 2016 capital expenditures, an increase of $0.4 million. The increase was effective January 1, 2018. On November 1, 2018, Fitchburg filed its cumulative revenue requirement of $0.9 million associated with the Company’s 2015, 2016 and 2017 capital expenditures. On December 27, 2018, the filing was approved, effective January 1, 2019, subject to further investigation and reconciliation. Final approval of the 2018 filing remains pending. On September 5, 2019, Fitchburg’s electric division filed with the MDPU a letter of intent to file for a general increase in base rates. Under MDPU precedent, a utility company is required to provide no less than a 30 day advance notice of its intent to file for a base rate increase. At this time, Fitchburg anticipates that the filing will be made during the fourth quarter 2019.

Fitchburg – Base Rates – Gas – Pursuant to the Company’s 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 impacts to the Company’s revenues. The MDPU has consistently found that the Company’s filings are in accord with its approved tariffs, applicable law and precedent, and that

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they result in just and reasonable rates. On September 5, 2019, Fitchburg’s gas division filed with the MDPU a letter of intent to file for a general increase in base rates. Under MDPU precedent, a utility company is required to provide no less than a 30 day advance notice of its intent to file for a base rate increase. At this time, Fitchburg anticipates that the filing will be made during the fourth quarter 2019.

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 (the “GSEP Filing”); and a filing, submitted on or before May 1, of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably and prudently incurred (the “GREC Filing”). The Company considers these to be routine regulatory proceedings and there are no material issues outstanding.

In an Order issued on April 30, 2019, the MDPU approved Fitchburg’s 2018 GSEP Filing and increased the annual cap on recovery. Because the amount approved for recovery, $1.6 million, still exceeded the annual cap, the Order resulted in a revenue increase of $1.0 million that went into effect on May 1, 2019, subject to reconciliation. The amount that exceeded the cap, $0.6  million, has been deferred to be recovered in a later proceeding. On May 1, 2019, the Company made its 2019 GREC Filing, seeking a waiver of the annual cap and a revenue increase of $1.0  million. This matter remains pending.

Granite State – Base Rates – On May 2, 2018, Granite State filed an uncontested rate settlement with FERC which provided for no change in rates, and accounted for the effects of a capital step adjustment offset by the effect of the TCJA. The settlement was approved by FERC on June 27, 2018, and complies with the FERC Notice of Proposed Rulemaking concerning the justness and reasonableness of rates in light of the corporate income tax reductions under the TCJA.

Other Matters

Fitchburg – Independent Statewide Examination of the Safety of the Commonwealth’s Gas Distribution System – The MDPU has 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 which focuses on the gas incident on September 13, 2018 in the Merrimack Valley and its potential causes. The evaluator will examine the following areas: (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 a Phase 1 summary report including preliminary recommendations for the MDPU’s consideration on May 13, 2019. The investigation is on-going and the evaluator will produce a final report at the end of the process. The Company believes that this examination will not result in a material impact on its financial position, operating results or cash flows.

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, as 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 as well as the 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 July 11, 2019, the MPUC approved Northern Utilities’ request to extend its contract for firm transmission on its affiliate Granite State pipeline for another year, extending the current contract for the period of November 1, 2019 through October 31, 2020. The next request to the MPUC for approval to extend the transmission contract will be filed in July 2020. In New Hampshire, pursuant to statute, Northern Utilities advises the NHPUC of its annual contract renewal with Granite State, though it is not required to seek approval of the renewal.

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

Fitchburg – Massachusetts RFPs – Pursuant to a comprehensive energy law enacted in 2016, “An Act to Promote Energy Diversity,” 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’s 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 (hydro, solar and land-based wind) long-term contracts via one or more staggered solicitations for a total of 9,450,000 megawatt-hours by December 31, 2022. Unitil’s pro rata share of each of these contracts is approximately one percent. The EDCs issued the RFP for Section 83D Long-Term Contracts for Qualified Clean Energy Projects in March 2017, and after selection of final projects and negotiation, final contracts for 9,554,940 MWh of Qualified Clean Energy and associated Environmental Attributes from hydroelectric generation were filed in July 2018 for approval by the MDPU. On June 25, 2019, the MDPU approved the power purchase agreements, including the EDCs’ proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market costs to customers. The MDPU also determined that the EDCs’ request for remuneration equal to 2.75 percent is reasonable and in the public interest. Also, the MDPU approved the EDCs’ proposal to amend their respective tariffs to include the recovery of costs associated with the contracts. The Company believes that the power purchase obligations under these long-term contracts will have a material impact on the contractual obligations and regulatory assets 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. Final selection of projects was made 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 400MW of offshore wind energy generation with 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 percent is reasonable and in the public interest. Also, the MDPU approved the EDCs’ proposal to amend their respective tariffs to include the recovery of costs associated with the contracts. The Company believes that the power purchase obligations under these long-term contracts will have a material impact on the contractual obligations and regulatory assets of Fitchburg.

The EDCs issued an RFP pursuant to Section 83C for Long-Term Contracts for Offshore Wind Energy Generation on May 23, 2019. This is the second solicitation pursuant to Section 83C and with the Department’s approval of the Vineyard Wind contracts for 800 MW of offshore wind energy generation as a result of the first solicitation, the remaining obligation under 83C is to procure an additional 800 MW of offshore wind energy generation. The EDCs intend to purchase at least 400 MW of the remaining 800 MW obligation under this RFP. Proposals were received on August 23, 2019, and selection is to occur on November 8, 2019, contracts are to be executed by December 13, 2019, and filed with the Department on January 10, 2020.

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Northern Utilities Gas Supply Cost Investigation – The MPUC has opened an investigation into the gas supply and procurement activities of Maine local distribution companies. Northern Utilities is the first company to have its procurement practices examined, and the Company is cooperating with a consultant engaged by the MPUC to conduct this ongoing investigation. The Company believes that this investigation will not result in a material impact on its financial position, operating results or cash flows.

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 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 had 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.

Also pending at FERC is a 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. 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. The initial decision has been rescheduled to be issued on November 2, 2020. 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 that these proceedings will have a material adverse impact on the Company’s financial condition or results of operations.

Legal Proceedings

The Company is involved in legal and administrative proceedings and claims of various types, 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 impact 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, 2018 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 31, 2019.

The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company is in material compliance with applicable environmental and safety laws and regulations and, as of September 30, 2019, 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 the Company’s 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.

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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 Rochester. The results of the review, along with any recommendations, will be submitted to the NH DES in January 2020. The Company has accrued $0.7 million for estimated costs to complete the remediation at the Rochester site, which is included in the Environmental Obligations table below.

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 below 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 to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring will continue and it is possible that future activities may be required.

The Environmental Obligations table below shows the amounts accrued for Fitchburg related to estimated and periodic, regulatory review costs for the completed permanent remediation of the Sawyer Passway site. A corresponding Regulatory Asset was recorded to reflect that the recovery of these environmental remediation costs is probable through the regulatory process. The amounts recorded do not assume any amounts are recoverable from insurance companies or other third parties. 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.

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The following table sets forth a summary of changes in the Company’s liability for the current and long-term portions of the Company’s environmental obligations, which are included in Other Current Liabilities and Other Noncurrent Liabilities, respectively, on the Company’s ​​​​​​​Consolidated Balance Sheets as of September 30, 2019 and 2018.

Environmental Obligations

	($ millions)
	Fitchburg				Northern Utilities				Total
	Nine months ended September 30,
	2019		2018		2019		2018		2019		2018
Total Balance at Beginning of Period	$	—	$	0.1	$	2.0	$	2.0	$	2.0	$	2.1
Additions		—		—		1.0		0.6		1.0		0.6
Less: Payments / Reductions		—		0.1		0.2		0.5		0.2		0.6
Total Balance at End of Period		—		—		2.8		2.1		2.8		2.1
Less: Current Portion		—		—		0.6		0.6		0.6		0.6
Noncurrent Balance at End of Period	$	—	$	—	$	2.2	$	1.5	$	2.2	$	1.5

Note 8: INCOME TAXES 

In June 2019 the Company received notice that the Internal Revenue Service (IRS) completed​​​​​​​ all fieldwork for the tax years December 31, 2015 and December 31, 2016 income tax audit and closed the audit with no adjustment. Income tax filings for the year ended December 31, 2018 have been filed with the IRS, Massachusetts Department of Revenue, the Maine Revenue Service, and the New Hampshire Department of Revenue Administration. The Company evaluated its tax positions at September 30, 2019 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, de-recognition, settlement and 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, 2016; December 31, 2017; and December 31, 2018.

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 GAAP Accounting Standard 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 MDPU issued a multi-utility Order D.P.U. 18-15-E (the “Order”) on December 21, 2018. The Order clarified the categories of Excess ADIT for Massachusetts ratemaking: 1) Excess protected ADIT directly related to utility plant fixed assets (rate base), 2) other non-plant excess ADIT amounts (unprotected), and 3) excess ADIT created through reconciling mechanisms. In the Order, all Massachusetts utilities were ordered to begin flow back of protected and unprotected excess ADIT on February 1, 2019 and to reconcile excess ADIT amounts previously collected from ratepayers through reconciliation mechanisms in the next filing of each of those individual reconciling mechanisms. Fitchburg was ordered to begin flowing back to customers excess ADIT of $10.1 million and $10.4 million to electric and gas ratepayers, respectively, over approximately fifteen years. Fitchburg filed its compliance filing under D.P.U.18-15-E on January 4, 2019 for rates effective February 1, 2019. The MDPU approved this filing on January 16, 2019. The filing will be updated and the balances of excess ADIT will be reconciled annually.

On November 15, 2018 the FERC issued two pronouncements regarding the accounting for income taxes due to the TCJA; 1) Notice of Proposed Rulemaking Docket No. RM 19-5-000 and 2) Policy Statement PL 19-2-000 providing specific guidance on the flow back of excess ADIT created by the implementation of the TCJA. Final rules are expected to be issued in the second quarter of 2019. According to the FERC guidance; the amount of the reduction to ADIT that was previously collected from customers but is no longer payable to the IRS is excess ADIT and should be flowed back to ratepayers under general ratemaking principles.

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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, the recent FERC guidance noted above 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.

In addition to the protected excess $47.1 million ADIT amounts the Company expects to flow through to customers in utility rates, as noted above, there is approximately $1.8 million of excess ADIT created through reconciling mechanisms at December 31, 2017, related to the implementation of the new federal tax rate of the TCJA, which had not been previously collected from customers through utility rates. The Company will reconcile these excess ADIT amounts through the specific reconciliation mechanisms in the next filing of each of those individual reconciling mechanisms which will be subject to the review of state regulators.

In addition to the $48.9 million of net excess ADIT noted above; there was $5.8 million of excess ADIT at December 31, 2017, created by the recognition of Net Operating Loss Carryforward assets (NOLC), discussed below, 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 is recognizing the benefit of this excess ADIT in accordance with the regulatory treatment of excess ADIT for each of jurisdiction. In 2018 the Company recognized $2.4 million of this tax benefit provision due to the turning of book/tax temporary differences associated with this excess ADIT. The Company has recognized $1.4 million in the first nine months of 2019. Of the remaining amount, the Company expects to recognize $0.4 million in the fourth quarter of 2019 and $1.6 million in 2020, in accordance with regulatory guidance as discussed above.

In the fourth quarter of 2018 the Company was ordered in D.P.U. 18-15-E to begin the flowback of excess ADIT to ratepayers starting February 1, 2019. The Company complied with the Order and subsequently started flowing back excess ADIT to its Massachusetts ratepayers. The Company has not yet received regulatory orders in all of its jurisdictions regarding the flow-back of excess deferred taxes. The Company’s regulators are expected to issue additional ratemaking guidance in future periods​​​​​​​ that will determine the final disposition of the re-measurement of regulatory deferred tax balances. At this time, the Company has applied a reasonable interpretation of the TCJA and a reasonable estimate of the regulatory resolution. Future clarification of TCJA matters with the Company’s regulators may change the amounts estimated.

Under the Company’s Tax Sharing Agreement (the “Agreement”) which was approved upon the formation of Unitil as a PUHC; 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 filed its tax returns for the year ended December 31, 2018 with the Internal Revenue Service in September 2019 and utilized federal NOLC assets of $5.7 million principally due to pension cost deductions, tax repair deductions, tax depreciation and research and development deductions. As of September 30, 2019, the Company had recorded cumulative federal and state NOLC assets of $11.9 million, on its filed tax returns to offset against taxes payable in future periods. If unused, the Company’s NOLC carryforward assets will begin to expire in 2029. In addition, at December 31, 2018, the Company had $3.1 million of cumulative alternative minimum tax credits, general business tax credit and other state tax credit carryforwards to offset future income taxes payable.

49

In assessing the near-term use of NOLCs and tax credits, the Company evaluates the expected level of future taxable income, available tax planning strategies, reversals of existing taxable temporary differences and taxable income available in carryback years. Based on all available evidence, both positive and negative, and the weight of that evidence to the extent such evidence can be objectively verified, the Company expects to utilize all of its NOLCs by December 31, 2020 prior to their expiration in 2029.

The Company bills its customers for sales tax in Massachusetts and Maine. These taxes are remitted to the appropriate departments of revenue in each state and are excluded from revenues on the Company’s unaudited Consolidated Statements of Earnings.

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, 2018 as filed with the SEC on January 31, 2019 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	2019			2018
Discount Rate		4.25	%		3.60	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		7.75	%		7.75	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		7.50	%
Ultimate Health Care Cost Trend Rate		4.50	%		4.50	%
Year that Ultimate Health Care Cost Trend Rate is reached		2024			2024

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

	Pension Plan						PBOP Plan						SERP Plan
Three Months Ended September 30,	2019			2018			2019			2018			2019			2018
Service Cost	$	776		$	848		$	576		$	733		$	62		$	122
Interest Cost		1,621			1,469			857			852			142			101
Expected Return on Plan Assets		(2,119	)		(1,946	)		(412	)		(409	)		—			—
Prior Service Cost Amortization		80			81			304			327			14			47
Actuarial Loss Amortization		1,081			1,447			56			346			157			121
Sub-total		1,439			1,899			1,381			1,849			375			391
Amounts Capitalized and Deferred		(650	)		(962	)		(650	)		(930	)		(107	)		(113	)
Net Periodic Benefit Cost Recognized	$	789		$	937		$	731		$	919		$	268		$	278

50

	Pension Plan						PBOP Plan						SERP Plan
Nine Months Ended September 30,	2019			2018			2019			2018			2019			2018
Service Cost	$	2,328		$	2,544		$	1,728		$	2,199		$	185		$	366
Interest Cost		4,863			4,407			2,569			2,554			426			303
Expected Return on Plan Assets		(6,356	)		(5,838	)		(1,234	)		(1,227	)		—			—
Prior Service Cost Amortization		240			243			910			981			42			141
Actuarial Loss Amortization		3,243			4,341			170			1,038			471			365
Sub-total		4,318			5,697			4,143			5,545			1,124			1,175
Amounts Capitalized and Deferred		(1,659	)		(2,590	)		(1,730	)		(2,557	)		(322	)		(339	)
Net Periodic Benefit Cost Recognized	$	2,659		$	3,107		$	2,413		$	2,988		$	802		$	836

Employer Contributions

As of September 30, 2019, the Company had made $6.9 million and $2.8 million of contributions to its Pension and PBOP Plans, respectively, in 2019. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2019 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension and PBOP Plan costs.

As of September 30, 2019, the Company had made $0.4 million of benefit​​​​​​​ payments under the SERP Plan in 2019. The Company presently anticipates making an additional $0.2 million of benefit payments under the SERP Plan in 2019.

Item 3.     Quantitative and Qualitative Disclosures About Market Risk

Reference is made to the “Interest Rate Risk” and “Market Risk” sections of Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (above).

Item 4.     Controls and Procedures

Management of the Company, under the supervision and with the participation of the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, carried out an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as of September 30, 2019. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of September 30, 2019 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 impact on the Company’s financial position.

51

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, 2018 as filed with the SEC on January 31, 2019.

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

Recent Sales of Unregistered Securities

There were no sales of unregistered equity securities by the Company during the fiscal quarter ended September 30, 2019.

Issuer Purchases of Equity Securities

Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted and announced by the Company on May 1, 2019, 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 $195,000 in value of shares have been purchased or, if sooner, on May 1, 2020.

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

The following table shows information regarding repurchases by the Company of shares of its common stock pursuant to the trading plan for each month in the quarter ended September 30, 2019.

	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
7/1/19 – 7/31/19		—		—		—	$	195,000
8/1/19 – 8/31/19		—		—		—	$	195,000
9/1/19 – 9/30/19		—		—		—	$	195,000
Total		—		—		—

Item 5.     Other Information

On October 24, 2019, the Company issued a press release announcing its results of operations for the three and nine month periods ended September 30, 2019. The press release is furnished with this Quarterly Report on Form 10-Q as Exhibit 99.1.

52

Item 6.     Exhibits

(a) Exhibits

Exhibit No.		Description of Exhibit	Reference(1)
	4.1	Note Purchase Agreement dated September 12, 2019 by and among Northern Utilities, Inc. and the several purchasers named therein.		Exhibit 4.1 to  Form 8-K dated September 12, 2019 (SEC File No. 1-8858	)
	4.2(2)	4.04% Senior Note, Series 2019, due September 12, 2049, issued by Northern Utilities, Inc. to Pacific Life Insurance Company.		Exhibit 4.2 to Form 8-K dated September 12, 2019 (SEC File No. 1-8858)
	11	Computation in Support of Earnings Per Weighted 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 October 24, 2019 Announcing Earnings For the Quarter Ended September 30, 2019.		Filed herewith
	101.INS	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	XBRL Taxonomy Extension Schema Document.		Filed herewith
	101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.		Filed herewith
	101.DEF	XBRL Taxonomy Extension Definition Linkbase Document		Filed herewith

53

101.LAB	XBRL Taxonomy Extension Label Linkbase Document.	Filed herewith
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.	Filed herewith
104	Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101).	Filed herewith

(1)    The exhibits referred to in this column by specific designations and dates have heretofore been filed with the Securities and Exchange Commission under such designations and are hereby incorporated by reference.

(2)    This Note is substantially identical in all material respects to other Notes that are otherwise required to be filed as exhibits, except as to the registered payee of such Note, the identifying number of such Note, and the principal amount of such Note. In accordance with instruction no. 2 to Item 601 of Regulation S-K, the registrant has filed a copy of only one of such Notes, with a schedule identifying the other Notes omitted and setting forth the material details in which such Notes differ from the Note that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any Note so omitted.

54

SIGNATURES

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

	UNITIL CORPORATION
	(Registrant)
Date: October 24, 2019	/s/ Christine L. Vaughan
	Christine L. Vaughan
	Chief Financial Officer
Date: October 24, 2019	/s/ Laurence M. Brock
	Laurence M. Brock
	Chief Accounting Officer

55

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

COMPUTATION OF EARNINGS PER WEIGHTED AVERAGE COMMON SHARE OUTSTANDING

(Millions except common shares and per share data)

(UNAUDITED)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Net Income	$	2.3	$	2.8	$	32.8	$	22.0
Weighted Average Number of Common Shares Outstanding – Basic (000’s)		14,898		14,829		14,889		14,818
Dilutive Effect of Stock Options and Restricted Stock (000’s)		8		5		6		5
Weighted Average Number of Common Shares Outstanding – Diluted (000’s)		14,906		14,834		14,895		14,823
Earnings Per Share – Basic and Diluted	$	0.15	$	0.19	$	2.20	$	1.49

56

EX-11

EXHIBIT 11

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

COMPUTATION OF EARNINGS PER WEIGHTED AVERAGE COMMON SHARE OUTSTANDING

(Millions except common shares and per share data)

(UNAUDITED)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Net Income	$	2.3	$	2.8	$	32.8	$	22.0
Weighted Average Number of Common Shares Outstanding – Basic (000’s)		14,898		14,829		14,889		14,818
Dilutive Effect of Stock Options and Restricted Stock (000’s)		8		5		6		5
Weighted Average Number of Common Shares Outstanding – Diluted (000’s)		14,906		14,834		14,895		14,823
Earnings Per Share – Basic and Diluted	$	0.15	$	0.19	$	2.20	$	1.49

EX-31.1

Exhibit 31.1

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

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

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

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

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

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

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

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

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

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

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

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

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

Date: October 24, 2019

/s/ Thomas P. Meissner, Jr.

Thomas P. Meissner, Jr.

Chief Executive Officer and President

EX-31.2

Exhibit 31.2

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

I, Christine L. Vaughan, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: October 24, 2019

/s/ Christine L. Vaughan

Christine L. Vaughan

Chief Financial Officer

EX-31.3

Exhibit 31.3

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

I, Laurence M. Brock, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: October 24, 2019

/s/ Laurence M. Brock

Laurence M. Brock

Chief Accounting Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Unitil Corporation (the “Company”) on Form 10-Q for the period ending September 30, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned Thomas P. Meissner, Jr., Chief Executive Officer and President, Christine L. Vaughan, Chief Financial Officer and Laurence M. Brock, Chief Accounting Officer, certifies, to the best knowledge and belief of the signatory, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Signature	Capacity	Date
/s/ Thomas P. Meissner, Jr.
Thomas P. Meissner, Jr.	Chief Executive Officer and President	October 24, 2019
/s/ Christine L. Vaughan
Christine L. Vaughan	Chief Financial Officer	October 24, 2019
/s/ Laurence M. Brock
Laurence M. Brock	Chief Accounting Officer	October 24, 2019

EX-99.1

Exhibit 99.1

Page 1 of 6

FOR RELEASE

UNITIL REPORTS THIRD QUARTER EARNINGS

HAMPTON, N.H., OCTOBER 24, 2019 — Unitil Corporation (NYSE: UTL) (www.unitil.com) today announced Net Income of $2.3 million, or $0.15 in Earnings Per Share (EPS), for the third quarter of 2019, a decrease of $0.5 million, or $0.04 in EPS, compared to the third quarter of 2018. For the nine months ended September 30, 2019, the Company reported Net Income of $32.8 million, or $2.20 in EPS, an increase of $10.8 million, or $0.71 in EPS, compared to the same nine month period in 2018. In the first quarter of 2019, the Company recognized a one-time net gain of $9.8 million, or $0.66 in EPS, on the Company’s divestiture of its non-regulated business subsidiary, Usource. In addition, the Company’s earnings in the first nine months 2019 were driven by higher natural gas and electric sales margins as well as customer growth. Earnings for the Company’s utility operations were Net Income of $23.0 million, or $1.54 in EPS, for the first nine months of 2019, an increase of $1.0 million in Net Income, or $0.05 in EPS, compared to the first nine months of 2018.

“Our third quarter results reflect milder summer weather in 2019 but we continue to see solid customer growth,” said Thomas P. Meissner, Jr., Unitil’s Chairman and Chief Executive Officer. “We are positioned well to continue this growth for the foreseeable future.”

Natural gas sales margins were $18.7 million and $85.5 million in the three and nine months ended September 30, 2019, respectively, increases of $1.1 million and $5.1 million, respectively, compared to the same periods in 2018. Gas sales margins in the third quarter of 2019 were positively affected by higher natural gas distribution rates of $0.8 million and by $0.3 million from higher therm sales, reflecting customer growth and increased average consumption by Commercial and Industrial (C&I) and Residential customers.

Gas sales margins in the first nine months of 2019 were positively affected by higher natural gas distribution rates of $4.6 million and by $1.7 million from higher therm sales, reflecting customer growth and increased average consumption by C&I and Residential customers. The positive effect of the higher rates and customer growth was partially offset by the absence in the current period of a $1.2 million non-recurring adjustment recognized in the second quarter of 2018 to increase gas revenue in connection with a then ongoing base rate case for the Company’s New Hampshire natural gas utility.

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

www.unitil.com

Page 2 of 6

Natural gas therm sales increased 4.2% and 2.5% in the three and nine month periods ended September 30, 2019, respectively, compared to the same periods in 2018. The increase in gas therm sales in the Company’s service areas was driven by customer growth and increased average consumption by C&I and Residential customers. The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were up 5.5% in the first nine months of 2019 compared to the same period in 2018. As of September 30, 2019, the number of total natural gas customers served has increased by 1,468 over the last year.

Electric sales margins were $25.1 million and $70.6 million in the three and nine months ended September 30, 2019, respectively, a decrease of $0.8 million and an increase of $0.1 million, respectively, compared to the same periods in 2018. The decrease in electric sales margins in the third quarter were due to lower kWh sales, reflecting milder summer weather in 2019 and overall lower average usage, including reduced usage by some industrial customers for production purposes, partially offset by positive customer growth. Electric sales margins in the first nine months of 2019 were positively affected by higher electric distribution rates of $1.4 million, partially offset by a decrease of $1.3 million from lower kWh sales, for the reasons noted above.

Total electric kilowatt-hour (kWh) sales decreased 5.3% and 5.2%, respectively in the three and nine month periods ended September 30, 2019 compared to the same periods in 2018. For the third quarter, the decrease reflects milder summer weather in 2019 compared to 2018. Based on weather data collected in the Company’s electric service areas, there were 19% fewer Cooling Degree Days in the third quarter of 2019 compared to the same period in 2018. The decreases in the three and nine month periods also reflect overall lower average usage due to both energy efficiency purposes and aforementioned reduced usage by some industrial customers, but were partially offset by overall customer growth. As of September 30, 2019, the number of total electric customers served has increased by 554 over the last year.

Operation and Maintenance (O&M) expenses decreased $0.9 million and $1.6 million in three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. Excluding a non-recurring adjustment to increase O&M expenses by $1.2 million in the second quarter of 2018 in connection with a then ongoing base rate case for the Company’s New Hampshire natural gas utility; O&M expenses decreased $0.4 million in the nine months ended

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

www.unitil.com

Page 3 of 6

September 30, 2019 compared to the same period in 2018. The decrease in the three month period reflects lower labor and other costs of $0.8 million, resulting from the divestiture of the Company’s non-regulated business subsidiary, Usource. In addition, in the three month period, the decrease in O&M expenses reflects lower professional fees of $0.4 million, partially offset by higher compensation and benefit costs of $0.3 million. The decrease in the nine month period reflects lower labor and other costs of $1.7 million, resulting from the divestiture of the Company’s non-regulated business subsidiary, Usource. O&M expenses in the nine month period also reflect higher compensation and benefit costs of $0.9 million, higher utility operating costs of $0.3 million and higher professional fees of $0.1 million.

Depreciation and Amortization expense increased $0.4 million and $1.6 million in the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. These increases reflect increased depreciation on higher levels of utility plant in service, partially offset by lower amortization.

Taxes Other Than Income Taxes in the three months ended September 30, 2019 was essentially unchanged compared to the same period in 2018, reflecting higher local property tax rates on higher levels of utility plant in service, offset by property tax abatements. Taxes Other Than Income Taxes increased $0.5 million in the nine months ended September 30, 2019 compared to the same period in 2018. The increase in the nine month period reflects higher local property tax rates on higher levels of utility plant in service, partially offset by property tax abatements.

Interest Expense, Net decreased $0.2 million in the three months ended September 30, 2019, compared to the same period in 2018, reflecting lower interest on short-term borrowings and higher interest income. For the nine months ended September 30, 2019, Interest Expense, Net was essentially unchanged compared to the same period in 2018, reflecting lower interest on long-term debt and higher interest income, offset by interest on higher levels of short-term borrowings.

Other Expense (Income), Net decreased by $0.1 million for the three months ended September 30, 2019 compared to the same period in 2018. Other Expense (Income), Net changed from an expense of $4.1 million in the first nine months of 2018 to income of $9.8 million in the first nine months of 2019, a net change of $13.9 million. This change primarily reflects a pre-tax gain of $13.4 million on the Company’s divestiture of Usource, discussed above, and lower retirement benefit costs in the current period. The Usource divestiture generated a capital gain to the Company and a $3.6 million provision is included in the Company’s income tax expense for the nine months ended September 30, 2019.

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

www.unitil.com

Page 4 of 6

Federal and State Income Taxes increased by $0.5 million and $5.2 million for the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. The increase in the nine month period reflects income taxes associated with the Company’s divestiture of its non-regulated business subsidiary, Usource, discussed above.

At its January 2019, April 2019, July 2019 and October 2019 meetings, the Unitil Corporation Board of Directors declared quarterly dividends on the Company’s common stock of $0.37 per share. These quarterly dividends result in a current effective annualized dividend rate of $1.48 per share, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock.

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

The Company will hold a quarterly conference call to discuss third quarter 2019 results on Thursday, October 24, 2019, at 2:00 p.m. Eastern Time. This call is being webcast and can be accessed in the Investor Relations section of Unitil’s website, www.unitil.com.

About Unitil Corporation

Unitil Corporation provides energy for life by safely and reliably delivering natural gas and electricity in New England. We are committed to the communities we serve and to developing people, business practices, and technologies that lead to the delivery of dependable, more efficient energy. Unitil Corporation is a public utility holding company with operations in Maine, New Hampshire and Massachusetts. Together, Unitil’s operating utilities serve approximately 105,600 electric customers and 82,700 natural gas customers. For more information about our people, technologies, and community involvement please visit www.unitil.com.

Forward-Looking Statements

This press release may contain forward-looking statements. All statements, other than statements of historical fact, included in this press release are forward-looking statements. Forward-looking statements include declarations regarding Unitil’s beliefs and current expectations. These forward-looking statements are subject to the inherent risks and uncertainties in predicting future results and conditions that could cause the actual results to differ materially from those projected in these forward-looking statements. Some, but not all, of the risks and uncertainties include the following: Unitil’s regulatory environment (including regulations relating to climate change, greenhouse gas emissions and other environmental matters); fluctuations in the supply of, the demand for, and the prices of, gas and electric energy

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

www.unitil.com

Page 5 of 6

commodities and transmission and transportation capacity and Unitil’s ability to recover energy supply costs in its rates; customers’ preferred energy sources; severe storms and Unitil’s ability to recover storm costs in its rates; general economic conditions; variations in weather; long-term global climate change; Unitil’s ability to retain its existing customers and attract new customers; increased competition; and other risks detailed in Unitil’s filings with the Securities and Exchange Commission. These forward looking statements speak only as of the date they are made. Unitil undertakes no obligation, and does not intend, to update these forward-looking statements.

For more information please contact:

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

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

www.unitil.com

Page 6 of 6

Selected financial data for 2019 and 2018 is presented in the following table:

Unitil Corporation – Condensed Consolidated Financial Data

(Millions, except Per Share data) (Unaudited)

	Three Months Ended Sept. 30,							Nine Months Ended Sept. 30,
	2019		2018		Change			2019			2018		Change
Gas Therm Sales
Residential		2.6		2.5		4.0	%		36.2			35.9		0.8	%
Commercial/Industrial		24.9		23.9		4.2	%		136.2			132.3		2.9	%
Total Gas Therm Sales		27.5		26.4		4.2	%		172.4			168.2		2.5	%
Electric kWh Sales
Residential		180.9		195.0		(7.2	%)		498.3			527.8		(5.6	%)
Commercial/Industrial		257.7		268.3		(4.0	%)		718.5			755.9		(4.9	%)
Total Electric kWh Sales		438.6		463.3		(5.3	%)		1,216.8			1,283.7		(5.2	%)
Gas Revenues	$	24.9	$	25.7	$	(0.8	)	$	143.9		$	147.4	$	(3.5	)
Cost of Gas Sales		6.2		8.1		(1.9	)		58.4			67.0		(8.6	)
Gas Sales Margin		18.7		17.6		1.1			85.5			80.4		5.1
Electric Revenues		60.4		61.4		(1.0	)		177.0			167.6		9.4
Cost of Electric Sales		35.3		35.5		(0.2	)		106.4			97.1		9.3
Electric Sales Margin		25.1		25.9		(0.8	)		70.6			70.5		0.1
Other Revenues		—		1.1		(1.1	)		0.9			3.5		(2.6	)
Total Sales Margin		43.8		44.6		(0.8	)		157.0			154.4		2.6
Operation & Maintenance Expenses		15.5		16.4		(0.9	)		49.9			51.5		(1.6	)
Depreciation & Amortization		12.8		12.4		0.4			39.0			37.4		1.6
Property & Other Taxes		5.5		5.5		—			17.0			16.5		0.5
Other Expense (Income), Net		1.0		1.1		(0.1	)		(9.8	)		4.1		(13.9	)
Interest Expense, Net		5.8		6.0		(0.2	)		17.9			17.9		—
Income Before Income Taxes		3.2		3.2		—			43.0			27.0		16.0
Income Tax Expense		0.9		0.4		0.5			10.2			5.0		5.2
Net Income	$	2.3	$	2.8	$	(0.5	)	$	32.8		$	22.0	$	10.8
Earnings Per Share	$	0.15	$	0.19	$	(0.04	)	$	2.20		$	1.49	$	0.71

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

www.unitil.com

XML

Regulatory Matters - Additional Information (Detail)		1 Months Ended							6 Months Ended	9 Months Ended
	Nov. 01, 2017 USD ($)	Jun. 28, 2019 USD ($)	May 01, 2019 USD ($)	Feb. 28, 2019 USD ($)	May 07, 2018 USD ($)	May 02, 2018 USD ($)	Dec. 31, 2017	Apr. 20, 2017 USD ($)	Jun. 30, 2017 MW	Sep. 30, 2019	Jun. 30, 2027 MW	Dec. 31, 2022 MWh	Jun. 25, 2019	Apr. 30, 2019 USD ($)	Jul. 31, 2018 MWh	Jul. 31, 2018	Jul. 31, 2018 MW
Regulatory Assets [Line Items]
Annual revenue adjustment			$ 1,400,000
Power generation facility | MW											1,600
Pro rata percentage share of contracts									1
Tax Year 2018
Regulatory Assets [Line Items]
Corporate income tax rate							21.00%			21.00%
Unitil Energy Systems Inc | New Hampshire
Regulatory Assets [Line Items]
Permanent rate increase								$ 4,100,000
Increase (decrease) in annual revenue				$ 340,000
Fitchburg Gas and Electric Light Company
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue	$ 900,000		1,000,000.0
Recovery amount			$ 600,000											$ 1,600,000
Annual revenue adjustment	$ 400,000
Amendment effective date	Nov. 01, 2018
Fitchburg Gas and Electric Light Company | Offshore Wind Energy
Regulatory Assets [Line Items]
Power generation facility | MWh															400
Remuneration Percentage													2.75			2.75
Fitchburg Gas and Electric Light Company | Offshore Wind Energy | First Solicitation [Member]
Regulatory Assets [Line Items]
Power generation facility | MWh															800
Fitchburg Gas and Electric Light Company | Offshore Wind Energy | Second Solicitation [Member]
Regulatory Assets [Line Items]
Power generation facility															800		400
Fitchburg Gas and Electric Light Company | Qualified Clean Energy
Regulatory Assets [Line Items]
Power Generation Capacity | MWh															9,554,940
Fitchburg Gas and Electric Light Company | Minimum [Member] | Offshore Wind Energy
Regulatory Assets [Line Items]
Power generation facility | MW									400
Fitchburg Gas and Electric Light Company | Scenario Forecast
Regulatory Assets [Line Items]
Power Generation Capacity | MWh												9,450,000
Northern Utilities Inc
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue		$ 7,000,000.0				$ 3,200,000
Increase In Annual Base Rate				2.1	2.4
Annual TIRA Adjustment				$ 1,000,000.0	$ 1,100,000
Percentage Of Increase In Test Year Operating Revenue		7.00%
Northern Utilities Inc | Maine
Regulatory Assets [Line Items]
TIRA extended term										8 years

XML

Debt and Financing Arrangements - Classification of the Company Lease Obligations (Detail) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018
Operating Lease Obligations:
Other Current Liabilities (current portion)	$ 1,200
Other Noncurrent Liabilities (long-term portion)	3,000
Total Operating Lease Obligations	4,229
Capital Lease Obligations:
Other Current Liabilities (current portion)	300	$ 3,100	$ 3,100
Other Noncurrent Liabilities (long-term portion)	300	2,700	3,400
Total Capital Lease Obligations	620	5,800	6,500
Total Lease Obligations	$ 4,800	$ 5,800	$ 6,500

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ENVIRONMENTAL MATTERS (Tables)

9 Months Ended

Sep. 30, 2019

Environmental Obligations Recognized by Company

The following table sets forth a summary of changes in the Company’s liability for the current and long-term portions of the Company’s environmental obligations, which are included in Other Current Liabilities and Other Noncurrent Liabilities, respectively, on the Company’s ​​​​​​​Consolidated Balance Sheets as of September 30, 2019 and 2018.

Environmental Obligations

	($ millions)
	Fitchburg				Northern Utilities				Total
	Nine months ended September 30,
	2019		2018		2019		2018		2019		2018
Total Balance at Beginning of Period	$	—	$	0.1	$	2.0	$	2.0	$	2.0	$	2.1
Additions		—		—		1.0		0.6		1.0		0.6
Less: Payments / Reductions		—		0.1		0.2		0.5		0.2		0.6
Total Balance at End of Period		—		—		2.8		2.1		2.8		2.1
Less: Current Portion		—		—		0.6		0.6		0.6		0.6
Noncurrent Balance at End of Period	$	—	$	—	$	2.2	$	1.5	$	2.2	$	1.5

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018
Current Assets:
Cash and Cash Equivalents		$ 7.3	$ 7.8	$ 6.3
Accounts Receivable, Net		39.4	66.8	52.3
Accrued Revenue		35.3	54.7	36.0
Exchange Gas Receivable		8.6	8.1	10.1
Refundable Taxes		2.9	0.5
Gas Inventory		0.8	0.8	0.9
Materials and Supplies		7.7	7.0	7.2
Prepayments and Other		5.4	6.5	7.8
Total Current Assets		107.4	152.2	120.6
Utility Plant:
Gas		783.2	760.6	712.7
Electric		514.8	500.1	485.6
Common		61.6	83.1	82.1
Construction Work in Progress		72.9	25.5	68.4
Utility Plant		1,432.5	1,369.3	1,348.8
Less: Accumulated Depreciation		348.6	332.5	326.5
Net Utility Plant		1,083.9	1,036.8	1,022.3
Other Noncurrent Assets:
Regulatory Assets		98.7	99.0	111.6
Operating Lease Right of Use Assets		4.2
Other Assets		15.5	10.3	10.0
Total Other Noncurrent Assets		118.4	109.3	121.6
TOTAL ASSETS		1,309.7	1,298.3	1,264.5
Current Liabilities:
Accounts Payable		22.9	42.6	27.4
Short-Term Debt		49.2	82.8	69.1
Long-Term Debt, Current Portion	[1]	19.5	18.4	31.8
Regulatory Liabilities		14.4	11.5	12.2
Energy Supply Obligations		12.5	13.4	15.0
Interest Payable		7.1	4.3	7.0
Other Current Liabilities		18.8	19.5	18.0
Total Current Liabilities		144.4	192.5	180.5
Noncurrent Liabilities:
Retirement Benefit Obligations		120.8	121.5	142.4
Deferred Income Taxes, net		108.3	97.8	86.4
Cost of Removal Obligations		98.4	90.7	91.2
Regulatory Liabilities		46.7	47.0	47.9
Other Noncurrent Liabilities		10.2	10.1	10.0
Total Noncurrent Liabilities		384.4	367.1	377.9
Capitalization:
Long-Term Debt, Less Current Portion		410.9	387.4	361.1
Stockholders' Equity:
Common Equity (Authorized: 25,000,000 and Outstanding: 14,925,898, 14,872,011 and 14,876,955 Shares)		281.7	279.1	278.3
Retained Earnings		88.1	72.0	66.5
Total Common Stock Equity		369.8	351.1	344.8
Preferred Stock		0.2	0.2	0.2
Total Stockholders' Equity		370.0	351.3	345.0
Total Capitalization		780.9	738.7	706.1
TOTAL LIABILITIES AND CAPITALIZATION		$ 1,309.7	$ 1,298.3	$ 1,264.5

[1] The Current Portion of Long-Term Debt includes sinking fund payments.

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CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Parenthetical) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Dividends per Common Share	$ 0.370	$ 0.365	$ 1.11	$ 1.095
Common stock, shares issued	4,727	5,423	15,793	19,700

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Allowance for Doubtful Accounts Included in Accounts Receivable Net (Detail) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018
Valuation Allowance [Line Items]
Allowance for Doubtful Accounts	$ 1.0	$ 1.3	$ 1.2

XML

DIVIDENDS DECLARED PER SHARE (Tables)

9 Months Ended

Sep. 30, 2019

DIVIDENDS DECLARED PER SHARE [Abstract]

Schedule of Dividends Declared

Declaration Date	Date Paid (Payable)	Shareholder of Record Date	Dividend Amount
10/23/19	11/27/19	11/13/19	$ 0.370
07/24/19	08/29/19	08/15/19	$ 0.370
04/24/19	05/29/19	05/15/19	$ 0.370
01/30/19	02/28/19	02/14/19	$ 0.370
10/24/18	11/29/18	11/15/18	$ 0.365
07/25/18	08/29/18	08/15/18	$ 0.365
04/25/18	05/29/18	05/15/18	$ 0.365
01/30/18	02/28/18	02/14/18	$ 0.365

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DEBT AND FINANCING ARRANGEMENTS

9 Months Ended

Sep. 30, 2019

DEBT AND FINANCING ARRANGEMENTS

Note 4 – Debt AND FINANCING ARRANGEMENTS

Details on long-term debt at September 30, 2019, September 30, 2018 and December 31, 2018 are shown below:

($ millions)	September 30,				December 31,
	2019		2018		2018
Unitil Corporation:
6.33% Senior Notes, Due May 1, 2022	$	20.0	$	20.0	$	20.0
3.70% Senior Notes, Due August 1, 2026		30.0		30.0		30.0
Unitil Energy First Mortgage Bonds:
5.24% Senior Secured Notes, Due March 2, 2020		5.0		10.0		10.0
8.49% Senior Secured Notes, Due October 14, 2024		6.0		7.5		6.0
6.96% Senior Secured Notes, Due September 1, 2028		18.0		20.0		20.0
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
4.18% Senior Secured Notes, Due November 30, 2048		30.0		—		30.0
Fitchburg:
6.75% Senior Notes, Due November 30, 2023		5.7		7.6		5.7
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		12.0		12.0		12.0
5.90% Senior Notes, Due December 15, 2030		15.0		15.0		15.0
7.98% Senior Notes, Due June 1, 2031		14.0		14.0		14.0
4.32% Senior Notes, Due November 1, 2047		15.0		15.0		15.0
Northern Utilities:
6.95% Senior Notes, Due December 3, 2018		—		10.0		—
5.29% Senior Notes, Due March 2, 2020		8.2		16.6		16.6
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
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		—		—
Granite State:
7.15% Senior Notes, Due December 15, 2018		—		3.3		—
3.72% Senior Notes, Due November 1, 2027		15.0		15.0		15.0
Total Long-Term Debt		433.9		396.0		409.3
Less: Unamortized Debt Issuance Costs		3.5		3.1		3.5
Total Long-Term Debt, net of Unamortized Debt Issuance Costs		430.4		392.9		405.8
Less: Current Portion(1)		19.5		31.8		18.4
Total Long-term Debt, Less Current Portion	$	410.9	$	361.1	$	387.4

(1) The Current Portion of Long-Term Debt ​​​​​​​includes sinking ​​​​​​​fund payments.

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

($ millions)	September 30,				December 31,
	2019		2018		2018
Estimated Fair Value of Long-Term Debt	$	495.1	$	418.7	$	422.0

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

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $187.1 million for the nine months ended September 30, 2019. Total gross repayments were $220.7 million for the nine months ended September 30, 2019. The following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of September 30 2019, September 30, 2018 and December 31, 2018:

	Revolving Credit Facility ($ millions)
	September 30,				December 31,
	2019		2018		2018
Limit	$	120.0	$	120.0	$	120.0
Short-Term Borrowings Outstanding		49.2		69.1		82.8
Letter of Credit Outstanding		0.1		—		—
Available	$	70.7	$	50.9	$	37.2

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 shall apply until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At September 30, 2019, September 30, 2018 and December 31, 2018, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.

The Company believes the future operating cash flows of the Company, along with its existing borrowing availability and access to financial markets for the issuance of new long-term debt, will be sufficient to meet any working capital and future operating requirements, and capital investment forecast opportunities.

The average interest rates on all short-term borrowings and intercompany money pool transactions were 3.4% and 3.3% for the three months ended September 30, 2019 and September 30, 2018, respectively. The average interest rates on all short-term borrowings and intercompany money pool transactions were 3.6% and 3.2% for the nine months ended September 30, 2019 and September 30, 2018, respectively. The average interest rate on all short-term borrowings for the twelve months ended December 31, 2018 was 3.3%.

As discussed previously, the Company divested of its non-regulated subsidiary business, Usource, in the first quarter of 2019. The Company used the net proceeds of $9.8 million from this divestiture for general corporate purposes.

On September 12, 2019, Northern Utilities issued $40 million of Notes due 2049 at 4.04%. Northern Utilities used the net proceeds from this offering to repay short-term debt and for general corporate purposes. Approximately $0.2 million of costs associated with these issuances have been netted against Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.

On November 30, 2018 Unitil Energy issued $30 million of First Mortgage Bonds due November 30, 2048 at 4.18%. Unitil Energy used the net proceeds from this offering to repay short-term debt and for general corporate purposes. Approximately $0.5 million of costs associated with these issuances have been netted against long-term debt for presentation purposes on the Consolidated Balance Sheets.

In April 2014, Unitil Service Corp. entered into a financing arrangement, structured as a capital lease obligation, for various information systems and technology equipment. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. This capital lease was paid off in the second quarter of 2019.

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

Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There was $8.1 million, $9.6 million and $8.4 million of natural gas storage inventory at September 30, 2019, September 30, 2018 and December 31, 2018, respectively, related to these asset management agreements. The amount of natural gas inventory released in September 2019 and payable in October 2019 is $0.1 million and is recorded in Accounts Payable at September 30, 2019. The amount of natural gas inventory released in September 2018 and payable in October 2018 was $0.1 million and was recorded in Accounts Payable at September 30, 2018. The amount of natural gas inventory released in December 2018 and payable in January 2019 was $0.9 million and was recorded in Accounts Payable at December 31, 2018.

Guarantees

The Company provides limited guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of September 30, 2019, there were approximately $4.3 million of guarantees outstanding.

Leases

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

Total rental expense under operating leases charged to operations for the three months ended September 30, 2019 and 2018 amounted to $0.4 million and $0.4 million, respectively. Total rental expense under operating leases charged to operations for the nine months ended September 30, 2019 and 2018 amounted to $1.1 million and $1.4 million, respectively.

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

	September 30,				December 31,
Lease Obligations ($ millions)	2019		2018		2018
Operating Lease Obligations:
Other Current Liabilities (current portion)	$	1.2	$	—	$	—
Other Noncurrent Liabilities (long-term portion)		3.0		—		—
Total Operating Lease Obligations		4.2		—		—
Capital Lease Obligations:
Other Current Liabilities (current portion)		0.3		3.1		3.1
Other Noncurrent Liabilities (long-term portion)		0.3		3.4		2.7
Total Capital Lease Obligations		0.6		6.5		5.8
Total Lease Obligations	$	4.8	$	6.5	$	5.8

Cash paid for amounts included in the measurement of operating lease obligations for the nine months ended September 30, 2019 was $1.1 million and was included in Cash Provided by Operating Activities on the Consolidated Statements of Cash Flows.

Assets under capital leases amounted to approximately $1.3 million, $15.0 million and $15.0 million as of September 30, 2019, September 30, 2018 and December 31, 2018, respectively, less accumulated amortization of $0.6 million, $2.1 million and $1.7 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheets.

The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of September 30, 2019. The payments for capital leases consist of $0.3​​​​​​​​​​​​​​ million of current capital lease obligations, which are included in Other​​​​​​​ Current Liabilities and $0.3 million of noncurrent capital lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of September 30, 2019.

The payments for operating leases consist of $1.2 million of current operating lease obligations, which are included in Other Current Liabilities and $3.0 million of noncurrent operating lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of September 30, 2019.

Lease Payments ($000’s) Year Ending December 31,	Operating Leases		Capital Leases
Rest of 2019	$	356	$	80
2020		1,338		262
2021		1,168		161
2022		887		97
2023		587		55
2024-2028		400		—
Total Payments		4,736		655
Less: Interest		507		35
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$	4,229	$	620

Operating lease obligations are based on the net present value of the remaining lease payments over the remaining lease term. In determining the present value of lease payments, the Company used the interest rate stated in each lease agreement. As of September 30, 2019, the weighted average remaining lease term is 4.0 years and the weighted average operating discount rate used to determine the operating lease obligations was 5.3%.

Disclosures Related to Periods Prior to the Adoption of ASU NO. 2016-02 – Leases (See Note 1).

The payment amounts in the following table, which are as of December 31, 2018, would not differ substantially from the payment amounts as of September 30, 2018.

Lease Payments ($000’s) Year Ending December 31,	Operating Leases		Capital Leases
2019	$	1,372	$	3,069
2020		1,138		2,535
2021		969		93
2022		689		32
2023		390		14
2024-2028		120		—
Total Payments	$	4,678	$	5,743

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INCOME TAXES

9 Months Ended

Sep. 30, 2019

INCOME TAXES

Note 8: INCOME TAXES 

In June 2019 the Company received notice that the Internal Revenue Service (IRS) completed​​​​​​​ all fieldwork for the tax years December 31, 2015 and December 31, 2016 income tax audit and closed the audit with no adjustment. Income tax filings for the year ended December 31, 2018 have been filed with the IRS, Massachusetts Department of Revenue, the Maine Revenue Service, and the New Hampshire Department of Revenue Administration. The Company evaluated its tax positions at September 30, 2019 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, de-recognition, settlement and 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, 2016; December 31, 2017; and December 31, 2018.

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 GAAP Accounting Standard 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 MDPU issued a multi-utility Order D.P.U. 18-15-E (the “Order”) on December 21, 2018. The Order clarified the categories of Excess ADIT for Massachusetts ratemaking: 1) Excess protected ADIT directly related to utility plant fixed assets (rate base), 2) other non-plant excess ADIT amounts (unprotected), and 3) excess ADIT created through reconciling mechanisms. In the Order, all Massachusetts utilities were ordered to begin flow back of protected and unprotected excess ADIT on February 1, 2019 and to reconcile excess ADIT amounts previously collected from ratepayers through reconciliation mechanisms in the next filing of each of those individual reconciling mechanisms. Fitchburg was ordered to begin flowing back to customers excess ADIT of $10.1 million and $10.4 million to electric and gas ratepayers, respectively, over approximately fifteen years. Fitchburg filed its compliance filing under D.P.U.18-15-E on January 4, 2019 for rates effective February 1, 2019. The MDPU approved this filing on January 16, 2019. The filing will be updated and the balances of excess ADIT will be reconciled annually.

On November 15, 2018 the FERC issued two pronouncements regarding the accounting for income taxes due to the TCJA; 1) Notice of Proposed Rulemaking Docket No. RM 19-5-000 and 2) Policy Statement PL 19-2-000 providing specific guidance on the flow back of excess ADIT created by the implementation of the TCJA. Final rules are expected to be issued in the second quarter of 2019. According to the FERC guidance; the amount of the reduction to ADIT that was previously collected from customers but is no longer payable to the IRS is excess ADIT and should be flowed back to ratepayers under general ratemaking principles.

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, the recent FERC guidance noted above 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.

In addition to the protected excess $47.1 million ADIT amounts the Company expects to flow through to customers in utility rates, as noted above, there is approximately $1.8 million of excess ADIT created through reconciling mechanisms at December 31, 2017, related to the implementation of the new federal tax rate of the TCJA, which had not been previously collected from customers through utility rates. The Company will reconcile these excess ADIT amounts through the specific reconciliation mechanisms in the next filing of each of those individual reconciling mechanisms which will be subject to the review of state regulators.

In addition to the $48.9 million of net excess ADIT noted above; there was $5.8 million of excess ADIT at December 31, 2017, created by the recognition of Net Operating Loss Carryforward assets (NOLC), discussed below, 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 is recognizing the benefit of this excess ADIT in accordance with the regulatory treatment of excess ADIT for each of jurisdiction. In 2018 the Company recognized $2.4 million of this tax benefit provision due to the turning of book/tax temporary differences associated with this excess ADIT. The Company has recognized $1.4 million in the first nine months of 2019. Of the remaining amount, the Company expects to recognize $0.4 million in the fourth quarter of 2019 and $1.6 million in 2020, in accordance with regulatory guidance as discussed above.

In the fourth quarter of 2018 the Company was ordered in D.P.U. 18-15-E to begin the flowback of excess ADIT to ratepayers starting February 1, 2019. The Company complied with the Order and subsequently started flowing back excess ADIT to its Massachusetts ratepayers. The Company has not yet received regulatory orders in all of its jurisdictions regarding the flow-back of excess deferred taxes. The Company’s regulators are expected to issue additional ratemaking guidance in future periods​​​​​​​ that will determine the final disposition of the re-measurement of regulatory deferred tax balances. At this time, the Company has applied a reasonable interpretation of the TCJA and a reasonable estimate of the regulatory resolution. Future clarification of TCJA matters with the Company’s regulators may change the amounts estimated.

Under the Company’s Tax Sharing Agreement (the “Agreement”) which was approved upon the formation of Unitil as a PUHC; 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 filed its tax returns for the year ended December 31, 2018 with the Internal Revenue Service in September 2019 and utilized federal NOLC assets of $5.7 million principally due to pension cost deductions, tax repair deductions, tax depreciation and research and development deductions. As of September 30, 2019, the Company had recorded cumulative federal and state NOLC assets of $11.9 million, on its filed tax returns to offset against taxes payable in future periods. If unused, the Company’s NOLC carryforward assets will begin to expire in 2029. In addition, at December 31, 2018, the Company had $3.1 million of cumulative alternative minimum tax credits, general business tax credit and other state tax credit carryforwards to offset future income taxes payable.

In assessing the near-term use of NOLCs and tax credits, the Company evaluates the expected level of future taxable income, available tax planning strategies, reversals of existing taxable temporary differences and taxable income available in carryback years. Based on all available evidence, both positive and negative, and the weight of that evidence to the extent such evidence can be objectively verified, the Company expects to utilize all of its NOLCs by December 31, 2020 prior to their expiration in 2029.

The Company bills its customers for sales tax in Massachusetts and Maine. These taxes are remitted to the appropriate departments of revenue in each state and are excluded from revenues on the Company’s unaudited Consolidated Statements of Earnings.

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Significant Segment Financial Data (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Other Operating Revenue - Non-Regulated		$ 1.1	$ 0.9	$ 3.5
Total Operating Revenues	$ 85.3	88.2	321.8	318.5
Segment Profit (Loss)	2.3	2.8	32.8	22.0
Capital Expenditures	38.0	39.1	76.7	76.3
Segment Assets	1,309.7	1,264.5	1,309.7	1,264.5	$ 1,298.3
Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	77.8	80.5	332.8	327.3
Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	7.5	6.6	(11.9)	(12.3)
Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	24.9	25.7	143.9	147.4
Segment Profit (Loss)	(3.9)	(3.2)	10.1	9.1
Capital Expenditures	26.9	30.9	48.3	53.1
Segment Assets	780.7	730.0	780.7	730.0
Gas Segment | Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	20.5	19.6	160.0	151.1
Gas Segment | Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	4.4	6.1	(16.1)	(3.7)
Electric
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	60.4	61.4	177.0	167.6
Segment Profit (Loss)	4.4	4.5	9.7	10.2
Capital Expenditures	9.2	7.2	24.1	20.8
Segment Assets	507.6	485.7	507.6	485.7
Electric | Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	57.3	60.9	172.8	176.2
Electric | Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Total Operating Revenues	3.1	0.5	4.2	(8.6)
All Other Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Segment Profit (Loss)	1.8	1.2	2.8	1.8
Capital Expenditures	1.9	1.0	4.3	2.4
Segment Assets	21.1	42.2	21.1	42.2
Unregulated Operation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Other Operating Revenue - Non-Regulated		1.1	0.9	3.5
Total Operating Revenues		1.1	0.9	3.5
Segment Profit (Loss)		0.3	10.2	0.9
Segment Assets	$ 0.3	$ 6.6	$ 0.3	$ 6.6

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Regulatory Liabilities (Detail) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 61.1	$ 58.5	$ 60.1
Less: Current Portion of Regulatory Liabilities	14.4	11.5	12.2
Regulatory Liabilities-noncurrent	46.7	47.0	47.9
Energy Supply & Other Rate Adjustment Mechanisms
Regulatory Liabilities [Line Items]
Regulatory Liabilities	13.5	11.5	12.2
Income Tax
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 47.6	$ 47.0	$ 47.9	$ 48.9

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SEGMENT INFORMATION

9 Months Ended

Sep. 30, 2019

SEGMENT INFORMATION

note 3 – Segment Information

The following table provides significant segment financial data for the three and nine months ended September 30, 2019 and September 30, 2018 and as of December 31, 2018 (millions):

	Gas			Electric		Non- Regulated		Other		Total
Three Months Ended September 30, 2019
Revenues:
Billed and Unbilled Revenue	$	20.5		$	57.3	$	—	$	—	$	77.8
Rate Adjustment Mechanism Revenue		4.4			3.1		—		—		7.5
Other Operating Revenue – Non-Regulated		—			—		—		—		—
Total Operating Revenues	$	24.9		$	60.4	$	—	$	—	$	85.3
Segment Profit		(3.9	)		4.4		—		1.8		2.3
Capital Expenditures		26.9			9.2		—		1.9		38.0
Three Months Ended September 30, 2018
Revenues:
Billed and Unbilled Revenue	$	19.6		$	60.9	$	—	$	—	$	80.5
Rate Adjustment Mechanism Revenue		6.1			0.5		—		—		6.6
Other Operating Revenue – Non-Regulated		—			—		1.1		—		1.1
Total Operating Revenues	$	25.7		$	61.4	$	1.1	$	—	$	88.2
Segment Profit (Loss)		(3.2	)		4.5		0.3		1.2		2.8
Capital Expenditures		30.9			7.2		—		1.0		39.1

Nine Months Ended September 30, 2019
Revenues:
Billed and Unbilled Revenue	$	160.0		$	172.8		$	—	$	—	$	332.8
Rate Adjustment Mechanism Revenue		(16.1	)		4.2			—		—		(11.9	)
Other Operating Revenue – Non-Regulated		—			—			0.9		—		0.9
Total Operating Revenues	$	143.9		$	177.0		$	0.9	$	—	$	321.8
Segment Profit		10.1			9.7			10.2		2.8		32.8
Capital Expenditures		48.3			24.1			—		4.3		76.7
Segment Assets		780.7			507.6			0.3		21.1		1,309.7
Nine Months Ended September 30, 2018
Revenues:
Billed and Unbilled Revenue	$	151.1		$	176.2		$	—	$	—	$	327.3
Rate Adjustment Mechanism Revenue		(3.7	)		(8.6	)		—		—		(12.3	)
Other Operating Revenue – Non-Regulated		—			—			3.5		—		3.5
Total Operating Revenues	$	147.4		$	167.6		$	3.5	$	—	$	318.5
Segment Profit		9.1			10.2			0.9		1.8		22.0
Capital Expenditures		53.1			20.8			—		2.4		76.3
Segment Assets		730.0			485.7			6.6		42.2		1,264.5

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ENVIRONMENTAL MATTERS

9 Months Ended

Sep. 30, 2019

ENVIRONMENTAL MATTERS

NOTE 7 – ENVIRONMENTAL MATTERS

UNITIL’S ENVIRONMENTAL MATTERS ARE DESCRIBED IN NOTE 8 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2018 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 31, 2019.

The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company is in material compliance with applicable environmental and safety laws and regulations and, as of September 30, 2019, 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 the Company’s 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 Rochester. The results of the review, along with any recommendations, will be submitted to the NH DES in January 2020. The Company has accrued $0.7 million for estimated costs to complete the remediation at the Rochester site, which is included in the Environmental Obligations table below.

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 below 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 to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring will continue and it is possible that future activities may be required.

The Environmental Obligations table below shows the amounts accrued for Fitchburg related to estimated and periodic, regulatory review costs for the completed permanent remediation of the Sawyer Passway site. A corresponding Regulatory Asset was recorded to reflect that the recovery of these environmental remediation costs is probable through the regulatory process. The amounts recorded do not assume any amounts are recoverable from insurance companies or other third parties. 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.

The following table sets forth a summary of changes in the Company’s liability for the current and long-term portions of the Company’s environmental obligations, which are included in Other Current Liabilities and Other Noncurrent Liabilities, respectively, on the Company’s ​​​​​​​Consolidated Balance Sheets as of September 30, 2019 and 2018.

Environmental Obligations

	($ millions)
	Fitchburg				Northern Utilities				Total
	Nine months ended September 30,
	2019		2018		2019		2018		2019		2018
Total Balance at Beginning of Period	$	—	$	0.1	$	2.0	$	2.0	$	2.0	$	2.1
Additions		—		—		1.0		0.6		1.0		0.6
Less: Payments / Reductions		—		0.1		0.2		0.5		0.2		0.6
Total Balance at End of Period		—		—		2.8		2.1		2.8		2.1
Less: Current Portion		—		—		0.6		0.6		0.6		0.6
Noncurrent Balance at End of Period	$	—	$	—	$	2.2	$	1.5	$	2.2	$	1.5

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

9 Months Ended

Sep. 30, 2019

Components of Gas and Electric Operating Revenue

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

 

	Three Months Ended September 30, 2019
Gas and Electric Operating Revenues ($ millions):	Gas			Electric		Total
Billed and Unbilled Revenue:
Residential	$	6.9		$	31.3	$	38.2
C&I		12.5			24.5		37.0
Other		1.1			1.5		2.6
Total Billed and Unbilled Revenue		20.5			57.3		77.8
Rate Adjustment Mechanism Revenue		4.4			3.1		7.5
Total Gas and Electric Operating Revenues	$	24.9		$	60.4	$	85.3
	Three Months Ended September 30, 2018
Gas and Electric Operating Revenues ($ millions):	Gas			Electric		Total
Billed and Unbilled Revenue:
Residential	$	6.6		$	33.6	$	40.2
C&I		11.9			25.3		37.2
Other		1.1			2.0		3.1
Total Billed and Unbilled Revenue		19.6			60.9		80.5
Rate Adjustment Mechanism Revenue		6.1			0.5		6.6
Total Gas and Electric Operating Revenues	$	25.7		$	61.4	$	87.1
	Nine Months Ended September 30, 2019
Gas and Electric Operating Revenues ($ millions):	Gas			Electric		Total
Billed and Unbilled Revenue:
Residential	$	61.4		$	94.8	$	156.2
C&I		89.5			72.2		161.7
Other		9.1			5.8		14.9
Total Billed and Unbilled Revenue		160.0			172.8		332.8
Rate Adjustment Mechanism Revenue		(16.1	)		4.2		(11.9	)
Total Gas and Electric Operating Revenues	$	143.9		$	177.0	$	320.9

	Nine Months Ended September 30, 2018
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	58.3		$	95.6		$	153.9
C&I		84.7			74.1			158.8
Other		8.1			6.5			14.6
Total Billed and Unbilled Revenue		151.1			176.2			327.3
Rate Adjustment Mechanism Revenue		(3.7	)		(8.6	)		(12.3	)
Total Gas and Electric Operating Revenues	$	147.4		$	167.6		$	315.0

Allowance for Doubtful Accounts Included in Accounts Receivable Net

The Allowance for Doubtful Accounts as of September 30, 2019, September 30, 2018 and December 31, 2018, which is included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, was as follows:

($ millions)
	September 30,				December 31,
	2019		2018		2018
Allowance for Doubtful Accounts	$	1.0	$	1.2	$	1.3

Components of Accrued Revenue

The following table shows the components of Accrued Revenue as of September 30, 2019, September 30, 2018 and December 31, 2018. 

	September 30,				December 31,
Accrued Revenue ($ millions)	2019		2018		2018
Regulatory Assets – Current	$	24.9	$	26.4	$	41.3
Unbilled Revenues		10.4		9.6		13.4
Total Accrued Revenue	$	35.3	$	36.0	$	54.7

Components of Exchange Gas Receivable

The following table shows the components of Exchange Gas Receivable as of September 30, 2019, September 30, 2018 and December 31, 2018.

	September 30,				December 31,
Exchange Gas Receivable ($ millions)	2019		2018		2018
Northern Utilities	$	8.0	$	9.5	$	7.5
Fitchburg		0.6		0.6		0.6
Total Exchange Gas Receivable	$	8.6	$	10.1	$	8.1

Components of Gas Inventory

The following table shows the components of Gas Inventory as of September 30, 2019, September 30, 2018 and December 31, 2018.

	September 30,				December 31,
Gas Inventory ($ millions)	2019		2018		2018
Natural Gas	$	0.4	$	0.4	$	0.3
Propane		0.3		0.4		0.4
Liquefied Natural Gas & Other		0.1		0.1		0.1
Total Gas Inventory	$	0.8	$	0.9	$	0.8

Regulatory Assets

	September 30,				December 31,
Regulatory Assets consist of the following ($ millions)	2019		2018		2018
Retirement Benefits	$	74.0	$	88.0	$	72.0
Energy Supply & Other Rate Adjustment Mechanisms		20.6		24.8		38.4
Deferred Storm Charges		5.0		6.3		6.3
Environmental		8.0		8.9		7.9
Income Taxes		4.3		5.9		5.7
Other		11.7		4.1		10.0
Total Regulatory Assets		123.6		138.0		140.3
Less: Current Portion of Regulatory Assets(1)		24.9		26.4		41.3
Regulatory Assets – noncurrent	$	98.7	$	111.6	$	99.0

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

Regulatory Liabilities

	September 30,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2019		2018		2018
Income Taxes (Note 8)	$	47.6	$	47.9	$	47.0
Energy Supply & Other Rate Adjustment Mechanisms		13.5		12.2		11.5
Total Regulatory Liabilities		61.1		60.1		58.5
Less: Current Portion of Regulatory Liabilities		14.4		12.2		11.5
Regulatory Liabilities—noncurrent	$	46.7	$	47.9	$	47.0

Fair Value of Marketable Securities

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

	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2019		2018		2018
Equity Funds	$	—	$	3.0	$	—
Fixed Income Funds		—		2.3		—
Money Market Funds		5.9		—		4.8
Total Marketable Securities	$	5.9	$	5.3	$	4.8

Components of Energy Supply Obligations

The following ​​​​​​​discussion and table summarize the nature and amounts of the items recorded on the Company’s Consolidated Balance Sheets. The current portion of these obligations is recorded as Energy Supply Obligations and the noncurrent portion is included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets.

	September 30,				December 31,
Energy Supply Obligations ($ millions)	2019		2018		2018
Current:
Exchange Gas Obligation	$	8.0	$	9.5	$	7.5
Renewable Energy Portfolio Standards		4.2		5.2		5.6
Power Supply Contract Divestitures		0.3		0.3		0.3
Total Energy Supply Obligations – Current		12.5		15.0		13.4
Noncurrent:
Power Supply Contract Divestitures		0.4		0.7		0.6
Total Energy Supply Obligations	$	12.9	$	15.7	$	14.0

Deferred Compensation Plan [Member]

Fair Value of Marketable Securities

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

	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2019		2018		2018
Equity Funds	$	—	$	—	$	—
Money Market Funds		0.1		—		—
Total Marketable Securities	$	0.1	$	—	$	—

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Details on Long Term Debt (Detail) - USD ($) $ in Millions		Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018
Debt Instrument [Line Items]
Total Long-Term Debt		$ 433.9	$ 409.3	$ 396.0
Less: Unamortized Debt Issuance Costs		3.5	3.5	3.1
Long-Term Debt		430.4	405.8	392.9
Less: Current Portion	[1]	19.5	18.4	31.8
Total Long-Term Debt, Less Current Portion		410.9	387.4	361.1
Long-Term Debt		430.4	405.8	392.9
6.33% Senior Notes, Due May 1, 2022
Debt Instrument [Line Items]
Total Long-Term Debt		20.0	20.0	20.0
3.70% Senior Notes, Due August 1, 2026
Debt Instrument [Line Items]
Total Long-Term Debt		30.0	30.0	30.0
Unitil Energy Systems Inc | First Mortgage Bonds 5.24% Senior Secured Notes, Due March 2, 2020
Debt Instrument [Line Items]
Total Long-Term Debt		5.0	10.0	10.0
Unitil Energy Systems Inc | First Mortgage Bonds 8.49% Senior Secured Notes, Due October 14, 2024
Debt Instrument [Line Items]
Total Long-Term Debt		6.0	6.0	7.5
Unitil Energy Systems Inc | First Mortgage Bonds 6.96% Senior Secured Notes, Due September 1, 2028
Debt Instrument [Line Items]
Total Long-Term Debt		18.0	20.0	20.0
Unitil Energy Systems Inc | First Mortgage Bonds 8.00% Senior Secured Notes, Due May 1, 2031
Debt Instrument [Line Items]
Total Long-Term Debt		15.0	15.0	15.0
Unitil Energy Systems Inc | First Mortgage Bonds 6.32% Senior Secured Notes, Due September 15, 2036
Debt Instrument [Line Items]
Total Long-Term Debt		15.0	15.0	15.0
Unitil Energy Systems Inc | First Mortgage Bonds 4.18% Senior Secured Notes Due November 30, 2048
Debt Instrument [Line Items]
Total Long-Term Debt		30.0	30.0
Fitchburg Gas and Electric Light Company | 6.75% Senior Notes, Due November 30, 2023
Debt Instrument [Line Items]
Total Long-Term Debt		5.7	5.7	7.6
Fitchburg Gas and Electric Light Company | 6.79% Senior Notes, Due October 15, 2025
Debt Instrument [Line Items]
Total Long-Term Debt		10.0	10.0	10.0
Fitchburg Gas and Electric Light Company | 3.52% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt		10.0	10.0	10.0
Fitchburg Gas and Electric Light Company | 7.37% Notes, Due January 15, 2029
Debt Instrument [Line Items]
Total Long-Term Debt		12.0	12.0	12.0
Fitchburg Gas and Electric Light Company | 5.90% Notes, Due December 15, 2030
Debt Instrument [Line Items]
Total Long-Term Debt		15.0	15.0	15.0
Fitchburg Gas and Electric Light Company | 7.98% Notes, Due June 1, 2031
Debt Instrument [Line Items]
Total Long-Term Debt		14.0	14.0	14.0
Fitchburg Gas and Electric Light Company | 4.32% Senior Notes, Due November 1, 2047
Debt Instrument [Line Items]
Total Long-Term Debt		15.0	15.0	15.0
Northern Utilities Inc | 3.52% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt		20.0	20.0	20.0
Northern Utilities Inc | 4.32% Senior Notes, Due November 1, 2047
Debt Instrument [Line Items]
Total Long-Term Debt		30.0	30.0	30.0
Northern Utilities Inc | 6.95% Senior Notes, Due December 3, 2018
Debt Instrument [Line Items]
Total Long-Term Debt				10.0
Northern Utilities Inc | 5.29% Senior Notes, Due March 2, 2020
Debt Instrument [Line Items]
Total Long-Term Debt		8.2	16.6	16.6
Northern Utilities Inc | 7.72% Senior Notes, Due December 3, 2038
Debt Instrument [Line Items]
Total Long-Term Debt		50.0	50.0	50.0
Northern Utilities Inc | 4.42% Senior Notes, Due October 15, 2044
Debt Instrument [Line Items]
Total Long-Term Debt		50.0	50.0	50.0
Northern Utilities Inc | 4.04% Senior Notes, Due September 12, 2049
Debt Instrument [Line Items]
Total Long-Term Debt		40.0
Granite State Gas Transmission Inc | 7.15% Senior Notes, Due December 15, 2018
Debt Instrument [Line Items]
Total Long-Term Debt				3.3
Granite State Gas Transmission Inc | 3.72% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt		$ 15.0	$ 15.0	$ 15.0

[1] The Current Portion of Long-Term Debt includes sinking fund payments.

XML

Fair Value of Marketable Securities (Detail) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	$ 5.9	$ 4.8	$ 5.3
Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	0.1	0.0	0.0
Fair Value, Inputs, Level 1
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	5.9	4.8	5.3
Fair Value, Inputs, Level 1 | Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	0.1
Fair Value, Inputs, Level 1 | Equity Funds
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities			3.0
Fair Value, Inputs, Level 1 | Fixed Income Funds
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities			$ 2.3
Fair Value, Inputs, Level 1 | Money Market Funds
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	5.9	$ 4.8
Fair Value, Inputs, Level 1 | Money Market Funds | Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	$ 0.1

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Retirement Benefit Obligations - Additional Information (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2019 USD ($)
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Contributions to benefit plan	$ 6.9
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Contributions to benefit plan	2.8
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Benefit payments under SERP Plan	0.4
Expected additional benefit payments for the remainder of 2019	$ 0.2

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Environmental Matters - Additional Information (Detail) - Environmental Restoration Costs $ in Millions	9 Months Ended
	Sep. 30, 2019 USD ($)
Maine
Site Contingency [Line Items]
Amortization period for environmental costs	5 years
New Hampshire
Site Contingency [Line Items]
Amortization period for environmental costs	7 years
Northern Utilities Manufactured Gas Plant Sites
Site Contingency [Line Items]
Estimated Costs Accrued For Remediation	$ 0.7

XML

Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases (Detail) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018
Operating leases
Rest of 2019	$ 356
2019		$ 1,372
2020	1,338	1,138
2021	1,168	969
2022	887	689
2023	587	390
2024-2028	400	120
Total Payments	4,736	4,678
Less: Interest	507
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	4,229
Capital lease
Rest of 2019	80
2019		3,069
2020	262	2,535
2021	161	93
2022	97	32
2023	55	14
Total Payments	655	5,743
Less: Interest	35
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$ 620	$ 5,800	$ 6,500

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COMMON STOCK AND PREFERRED STOCK (Tables)

9 Months Ended

Sep. 30, 2019

Table Text Block Supplement [Abstract]

Restricted Stock Units Issued

The equity portion of Restricted Stock Units activity during the nine months ended September 30, 2019 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, 2018		61,789	$	38.25
Restricted Stock Units Granted		—		—
Dividend Equivalents Earned		1,210	$	57.08
Restricted Stock Units Settled		—		—
Restricted Stock Units as of September 30, 2019		62,999	$	38.61

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CONSOLIDATED STATEMENTS OF EARNINGS - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Operating Revenues
Total Operating Revenues	$ 85.3	$ 88.2	$ 321.8	$ 318.5
Operating Expenses
Operation and Maintenance	15.5	16.4	49.9	51.5
Depreciation and Amortization	12.8	12.4	39.0	37.4
Taxes Other Than Income Taxes	5.5	5.5	17.0	16.5
Total Operating Expenses	75.3	77.9	270.7	269.5
Operating Income	10.0	10.3	51.1	49.0
Interest Expense, Net	5.8	6.0	17.9	17.9
Other Expense (Income), Net	1.0	1.1	(9.8)	4.1
Income Before Income Taxes	3.2	3.2	43.0	27.0
Provision for Income Taxes	0.9	0.4	10.2	5.0
Net Income	$ 2.3	$ 2.8	$ 32.8	$ 22.0
Net Income Per Common Share (Basic and Diluted)	$ 0.15	$ 0.19	$ 2.20	$ 1.49
Weighted Average Common Shares Outstanding – (Basic and Diluted)	14.9	14.8	14.9	14.8
Gas
Operating Revenues
Total Operating Revenues	$ 24.9	$ 25.7	$ 143.9	$ 147.4
Operating Expenses
Total Operating Expenses	6.2	8.1	58.4	67.0
Electric
Operating Revenues
Total Operating Revenues	60.4	61.4	177.0	167.6
Operating Expenses
Total Operating Expenses	$ 35.3	35.5	106.4	97.1
Other
Operating Revenues
Total Operating Revenues		$ 1.1	$ 0.9	$ 3.5

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CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY - USD ($) $ in Millions	Total	Common Equity	Retained Earnings
Beginning Balance at Dec. 31, 2017	$ 336.6	$ 275.8	$ 60.8
Net Income	22.0		22.0
Dividends on Common Shares	(16.3)		(16.3)
Stock Compensation Plans	1.5	1.5
Issuance of Common Shares	1.0	1.0
Ending Balance at Sep. 30, 2018	344.8	278.3	66.5
Beginning Balance at Jun. 30, 2018	347.0	277.9	69.1
Net Income	2.8		2.8
Dividends on Common Shares	(5.4)		(5.4)
Stock Compensation Plans	0.1	0.1
Issuance of Common Shares	0.3	0.3
Ending Balance at Sep. 30, 2018	344.8	278.3	66.5
Beginning Balance at Dec. 31, 2018	351.1	279.1	72.0
Net Income	32.8		32.8
Dividends on Common Shares	(16.7)		(16.7)
Stock Compensation Plans	1.7	1.7
Issuance of Common Shares	0.9	0.9
Ending Balance at Sep. 30, 2019	369.8	281.7	88.1
Beginning Balance at Jun. 30, 2019	372.8	281.3	91.5
Net Income	2.3		2.3
Dividends on Common Shares	(5.7)		(5.7)
Stock Compensation Plans	0.1	0.1
Issuance of Common Shares	0.3	0.3
Ending Balance at Sep. 30, 2019	$ 369.8	$ 281.7	$ 88.1

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Components of Gas and Electric Operating Revenue (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ 85.3	$ 87.1	$ 320.9	$ 315.0
Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	77.8	80.5	332.8	327.3
Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	7.5	6.6	(11.9)	(12.3)
Gas Segment
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	24.9	25.7	143.9	147.4
Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	20.5	19.6	160.0	151.1
Gas Segment | Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	4.4	6.1	(16.1)	(3.7)
Electric
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	60.4	61.4	177.0	167.6
Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	57.3	60.9	172.8	176.2
Electric | Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	3.1	0.5	4.2	(8.6)
Residential | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	38.2	40.2	156.2	153.9
Residential | Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	6.9	6.6	61.4	58.3
Residential | Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	31.3	33.6	94.8	95.6
C&I | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	37.0	37.2	161.7	158.8
C&I | Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	12.5	11.9	89.5	84.7
C&I | Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	24.5	25.3	72.2	74.1
Other | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	2.6	3.1	14.9	14.6
Other | Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	1.1	1.1	9.1	8.1
Other | Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ 1.5	$ 2.0	$ 5.8	$ 6.5

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Dividends Declared Per Share (Detail) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Dividends Payable [Line Items]
Dividend Amount	$ 0.370	$ 0.365	$ 1.11	$ 1.095
Group One
Dividends Payable [Line Items]
Declaration Date			Oct. 23, 2019
Date Paid (Payable)			Nov. 27, 2019
Shareholder of Record Date			Nov. 13, 2019
Dividend Amount			$ 0.370
Group Two
Dividends Payable [Line Items]
Declaration Date			Jul. 24, 2019
Date Paid (Payable)			Aug. 29, 2019
Shareholder of Record Date			Aug. 15, 2019
Dividend Amount			$ 0.370
Group Three
Dividends Payable [Line Items]
Declaration Date			Apr. 24, 2019
Date Paid (Payable)			May 29, 2019
Shareholder of Record Date			May 15, 2019
Dividend Amount			$ 0.370
Group Four
Dividends Payable [Line Items]
Declaration Date			Jan. 30, 2019
Date Paid (Payable)			Feb. 28, 2019
Shareholder of Record Date			Feb. 14, 2019
Dividend Amount			$ 0.370
Group Five
Dividends Payable [Line Items]
Declaration Date			Oct. 24, 2018
Date Paid (Payable)			Nov. 29, 2018
Shareholder of Record Date			Nov. 15, 2018
Dividend Amount			$ 0.365
Group Six
Dividends Payable [Line Items]
Declaration Date			Jul. 25, 2018
Date Paid (Payable)			Aug. 29, 2018
Shareholder of Record Date			Aug. 15, 2018
Dividend Amount			$ 0.365
Group Seven
Dividends Payable [Line Items]
Declaration Date			Apr. 25, 2018
Date Paid (Payable)			May 29, 2018
Shareholder of Record Date			May 15, 2018
Dividend Amount			$ 0.365
Group Eight
Dividends Payable [Line Items]
Declaration Date			Jan. 30, 2018
Date Paid (Payable)			Feb. 28, 2018
Shareholder of Record Date			Feb. 14, 2018
Dividend Amount			$ 0.365

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Regulatory Assets (Detail) - USD ($) $ in Millions		Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018
Regulatory Assets [Line Items]
Regulatory assets		$ 123.6	$ 140.3	$ 138.0
Less: Current Portion of Regulatory Assets	[1]	24.9	41.3	26.4
Regulatory Assets - noncurrent		98.7	99.0	111.6
Environmental Matters
Regulatory Assets [Line Items]
Regulatory assets		8.0	7.9	8.9
Other
Regulatory Assets [Line Items]
Regulatory assets		11.7	10.0	4.1
Retirement Benefits
Regulatory Assets [Line Items]
Regulatory assets		74.0	72.0	88.0
Deferred Storm Charges
Regulatory Assets [Line Items]
Regulatory assets		5.0	6.3	6.3
Income Taxes
Regulatory Assets [Line Items]
Regulatory assets		4.3	5.7	5.9
Energy Supply & Other Rate Adjustment Mechanisms
Regulatory Assets [Line Items]
Regulatory assets		$ 20.6	$ 38.4	$ 24.8

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

XML

Estimated Fair Value of Long Term Debt (Detail) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018
Fair Value, Inputs, Level 2
Debt Instrument [Line Items]
Estimated Fair Value of Long-Term Debt	$ 495.1	$ 422.0	$ 418.7

XML

COMMON STOCK AND PREFERRED STOCK

9 Months Ended

Sep. 30, 2019

COMMON STOCK AND PREFERRED STOCK

Note 5 – Common Stock and preferred stock

Common Stock

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

The Company had 14,872,011, 14,876,955 and 14,925,898 shares of common stock outstanding at September 30, 2018, December 31, 2018 and September 30, 2019, respectively.

Dividend Reinvestment and Stock Purchase Plan – During the first nine months of 2019, the Company sold 15,793 shares of its common stock, at an average price of $56.29 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $889,000. The DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock.

Stock Plan – The Company maintains the Unitil Corporation 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 29, 2019, 33,150 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of approximately $1.6 million. There were 50,917 and 49,581 non-vested shares under the Stock Plan as of September 30, 2019 and 2018, respectively. The weighted average grant date fair value of these shares was $46.41 and $41.96, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $2.2 million and $2.1 million for the nine months ended September 30, 2019 and 2018, respectively. At September 30, 2019, there was approximately $0.8 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.7 years. There were no forfeitures and no cancellations under the Stock Plan during the nine months ended September 30, 2019.

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. Restricted Stock Units earn dividend equivalents and will generally be settled by payment to each Director as soon as practicable following the Director’s separation from service to the Company. The Restricted Stock Units will be paid such that the Director will receive (i) 70% of the shares of the Company’s common stock underlying the restricted stock units and (ii) cash in an amount equal to the fair market value of 30% of the shares of the Company’s common stock underlying the Restricted Stock Units. The equity portion of Restricted Stock Units activity during the nine months ended September 30, 2019 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, 2018		61,789	$	38.25
Restricted Stock Units Granted		—		—
Dividend Equivalents Earned		1,210	$	57.08
Restricted Stock Units Settled		—		—
Restricted Stock Units as of September 30, 2019		62,999	$	38.61

There were 53,454 Restricted Stock Units outstanding as of September 30, 2018 with a weighted average stock price of $36.47. On October 1, 2019, there were 9,918 fully-vested Restricted Stock Units issued to members of the Company’s Board of Directors. Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of September 30, 2019, September 30, 2018 and December 31, 2018 is $1.7 million, $1.2 million and $1.3 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 was $0.2 million, or 1,887 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of September 30, 2019.  There was $0.2 million, or 1,893 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of September 30, 2018 and December 31, 2018. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the three and nine month periods ended September 30, 2019 and September 30, 2018, respectively.

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RETIREMENT BENEFIT OBLIGATIONS

9 Months Ended

Sep. 30, 2019

RETIREMENT BENEFIT OBLIGATIONS

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, 2018 as filed with the SEC on January 31, 2019 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	2019			2018
Discount Rate		4.25	%		3.60	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		7.75	%		7.75	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		7.50	%
Ultimate Health Care Cost Trend Rate		4.50	%		4.50	%
Year that Ultimate Health Care Cost Trend Rate is reached		2024			2024

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

	Pension Plan						PBOP Plan						SERP Plan
Three Months Ended September 30,	2019			2018			2019			2018			2019			2018
Service Cost	$	776		$	848		$	576		$	733		$	62		$	122
Interest Cost		1,621			1,469			857			852			142			101
Expected Return on Plan Assets		(2,119	)		(1,946	)		(412	)		(409	)		—			—
Prior Service Cost Amortization		80			81			304			327			14			47
Actuarial Loss Amortization		1,081			1,447			56			346			157			121
Sub-total		1,439			1,899			1,381			1,849			375			391
Amounts Capitalized and Deferred		(650	)		(962	)		(650	)		(930	)		(107	)		(113	)
Net Periodic Benefit Cost Recognized	$	789		$	937		$	731		$	919		$	268		$	278

	Pension Plan						PBOP Plan						SERP Plan
Nine Months Ended September 30,	2019			2018			2019			2018			2019			2018
Service Cost	$	2,328		$	2,544		$	1,728		$	2,199		$	185		$	366
Interest Cost		4,863			4,407			2,569			2,554			426			303
Expected Return on Plan Assets		(6,356	)		(5,838	)		(1,234	)		(1,227	)		—			—
Prior Service Cost Amortization		240			243			910			981			42			141
Actuarial Loss Amortization		3,243			4,341			170			1,038			471			365
Sub-total		4,318			5,697			4,143			5,545			1,124			1,175
Amounts Capitalized and Deferred		(1,659	)		(2,590	)		(1,730	)		(2,557	)		(322	)		(339	)
Net Periodic Benefit Cost Recognized	$	2,659		$	3,107		$	2,413		$	2,988		$	802		$	836

Employer Contributions

As of September 30, 2019, the Company had made $6.9 million and $2.8 million of contributions to its Pension and PBOP Plans, respectively, in 2019. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2019 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension and PBOP Plan costs.

As of September 30, 2019, the Company had made $0.4 million of benefit​​​​​​​ payments under the SERP Plan in 2019. The Company presently anticipates making an additional $0.2 million of benefit payments under the SERP Plan in 2019.

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Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail) - Benefit Plan Costs	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.25%	3.60%
Rate of Compensation Increase	3.00%	3.00%
Expected Long-term rate of return on plan assets	7.75%	7.75%
Health Care Cost Trend Rate Assumed for Next Year	7.00%	7.50%
Ultimate Health Care Cost Trend Rate	4.50%	4.50%
Year that Ultimate Health Care Cost Trend Rate is reached	2024	2024

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Restricted Stock Units Issued (Detail) - Restricted Stock Units (RSUs) - $ / shares		9 Months Ended
	Oct. 01, 2019	Sep. 30, 2019
Restricted Stock Units
Beginning Restricted Stock Units	62,999	61,789
Restricted Stock Units Granted	9,918	0
Dividend Equivalents Earned		1,210
Restricted Stock Units Settled		0
Ending Restricted Stock Units		62,999
Weighted-Average Stock Price
Beginning Restricted Stock Units	$ 38.61	$ 38.25
Restricted Stock Units Granted		0
Dividend Equivalents Earned		57.08
Restricted Stock Units Settled		0
Ending Restricted Stock Units		$ 38.61

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Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility (Detail) - USD ($)	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018
Debt Instrument [Line Items]
Short-Term Borrowings Outstanding	$ 49,200,000	$ 82,800,000	$ 69,100,000
Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility, limit	120,000,000.0	120,000,000.0	120,000,000.0
Short-Term Borrowings Outstanding	49,200,000	82,800,000	69,100,000
Letters of Credit Outstanding	100,000
Available revolving credit facility	$ 70,700,000	$ 37,200,000	$ 50,900,000

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Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2020	Dec. 31, 2018	Dec. 31, 2017	Sep. 30, 2018
Income Taxes [Line Items]
Regulatory Liability			$ 61.1		$ 58.5		$ 60.1
Regulatory liability, expected flow back to customers			47.1			$ 48.9
Tax provision					$ 2.4
NOL carryforward assets expiration date					2029
Alternative minimum tax credit carryforwards					$ 3.1
Scenario Forecast
Income Taxes [Line Items]
Regulatory liability, expected pass back to ratepayers		$ 0.4		$ 1.6
Reconciling Mechanisms
Income Taxes [Line Items]
Regulatory liability, expected pass back to ratepayers						1.8
Net Operating Loss Carryforward Assets
Income Taxes [Line Items]
Regulatory liability, expected pass back to ratepayers						5.8
Tax Cuts And Jobs Act Of 2017 Change In Tax Rate Regulatory Liability recognized			$ 1.4
Minimum
Income Taxes [Line Items]
Average Rate Assumption Method estimated flow back period			15 years
Maximum
Income Taxes [Line Items]
Average Rate Assumption Method estimated flow back period			20 years
Fitchburg Gas and Electric Light Company
Income Taxes [Line Items]
Average Rate Assumption Method estimated flow back period			15 years
Income Tax Related Liabilities
Income Taxes [Line Items]
Regulatory Liability	$ 48.9		$ 47.6		$ 47.0	$ 48.9	$ 47.9
Electric Ratepayers | Fitchburg Gas and Electric Light Company
Income Taxes [Line Items]
Regulatory liability, expected flow back to customers			10.1
Gas Ratepayers | Fitchburg Gas and Electric Light Company
Income Taxes [Line Items]
Regulatory liability, expected flow back to customers			$ 10.4
Tax Year 2018
Income Taxes [Line Items]
Corporate federal income tax	21.00%		21.00%
Internal Revenue Service [Member] | Tax Year 2018
Income Taxes [Line Items]
Net Operating Loss Carryforwards Utilized For Income Taxes			$ 5.7
Federal, Maine, Massachusetts, and New Hampshire Tax Authorities
Income Taxes [Line Items]
Tax examination description			The Company remains subject to examination by Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2016; December 31, 2017; and December 31, 2018.
Domestic Country And State Jurisdiction [Member]
Income Taxes [Line Items]
Net Operating Loss Carryforwards			$ 11.9

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Components of Accrued Revenue (Detail) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 35.3	$ 54.7	$ 36.0
Unbilled Revenues
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	10.4	13.4	9.6
Regulatory Assets
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 24.9	$ 41.3	$ 26.4

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2019

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Note 1 – Summary of Significant Accounting Policies

Nature of Operations – Unitil Corporation (Unitil or the Company) is a public utility holding company. 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). Usource Inc. and Usource L.L.C., which the Company sold in the first quarter of 2019, were wholly-owned subsidiaries of Unitil Resources.

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

Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capital regions of New Hampshire and the greater Fitchburg area of north central Massachusetts, and the local distribution of natural gas in southeastern New Hampshire, portions of southern and central Maine 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 a natural gas transportation pipeline, 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 natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.

A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of Unitil Energy on May 1, 2003 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.

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. Usource, Inc. and Usource L.L.C. (collectively, Usource), which the Company divested of in the first quarter of 2019, were wholly-owned subsidiaries of Unitil Resources. Usource provided brokering and advisory services to large commercial and industrial customers in the northeastern United States. See additional discussion of the divestiture of Usource below.

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 and are of a normal and recurring nature. The results of operations for the three and nine months ended September 30, 2019 are not necessarily indicative of results to be expected for the year ending December 31, 2019. 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, 2018, as filed with the Securities and Exchange Commission (SEC) on January 31, 2019, for a description of the Company’s Basis of Presentation.

Divestiture of Non-Regulated Business Subsidiary – On March 1, 2019, the Company divested of its non-regulated energy brokering and advisory business subsidiary, Usource. The Company recognized an after-tax net gain of approximately $9.8 million on this divestiture in the first quarter of 2019. The pre-tax net gain of approximately $13.4 million on this divestiture is included in Other Income (Expense), Net on the Consolidated Statements of Earnings for the nine months ended September 30, 2019, while the income taxes associated with this transaction of $3.6 million are included in the Provision For Income Taxes.

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.

Billed and unbilled revenue is recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenues are calculated. These unbilled revenues are calculated each month based on estimated customer usage by class and applicable customer rates 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 ASU 2014-09. Revenue recognized in connection with rate adjustment mechanisms is consistent with the definition of alternative revenue programs in Accounting Standards Codification (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. ASU 2014-09 requires the Company to disclose separately the amount of revenues from contracts with customers and alternative revenue program revenues.

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

	Three Months Ended September 30, 2019
Gas and Electric Operating Revenues ($ millions):	Gas			Electric		Total
Billed and Unbilled Revenue:
Residential	$	6.9		$	31.3	$	38.2
C&I		12.5			24.5		37.0
Other		1.1			1.5		2.6
Total Billed and Unbilled Revenue		20.5			57.3		77.8
Rate Adjustment Mechanism Revenue		4.4			3.1		7.5
Total Gas and Electric Operating Revenues	$	24.9		$	60.4	$	85.3
	Three Months Ended September 30, 2018
Gas and Electric Operating Revenues ($ millions):	Gas			Electric		Total
Billed and Unbilled Revenue:
Residential	$	6.6		$	33.6	$	40.2
C&I		11.9			25.3		37.2
Other		1.1			2.0		3.1
Total Billed and Unbilled Revenue		19.6			60.9		80.5
Rate Adjustment Mechanism Revenue		6.1			0.5		6.6
Total Gas and Electric Operating Revenues	$	25.7		$	61.4	$	87.1
	Nine Months Ended September 30, 2019
Gas and Electric Operating Revenues ($ millions):	Gas			Electric		Total
Billed and Unbilled Revenue:
Residential	$	61.4		$	94.8	$	156.2
C&I		89.5			72.2		161.7
Other		9.1			5.8		14.9
Total Billed and Unbilled Revenue		160.0			172.8		332.8
Rate Adjustment Mechanism Revenue		(16.1	)		4.2		(11.9	)
Total Gas and Electric Operating Revenues	$	143.9		$	177.0	$	320.9

	Nine Months Ended September 30, 2018
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	58.3		$	95.6		$	153.9
C&I		84.7			74.1			158.8
Other		8.1			6.5			14.6
Total Billed and Unbilled Revenue		151.1			176.2			327.3
Rate Adjustment Mechanism Revenue		(3.7	)		(8.6	)		(12.3	)
Total Gas and Electric Operating Revenues	$	147.4		$	167.6		$	315.0

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 natural 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 Massachusetts Department of Public Utilities (MDPU). The Company estimates that revenue decoupling applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.

Other Operating Revenue – Non-regulated – Other Operating Revenue – Non-regulated – Other Operating Revenue consists solely of revenue from Usource, Unitil’s non-regulated subsidiary, which, as discussed previously, the Company divested of on March 1, 2019. Usource conducted its business activities as a broker of competitive energy services. Usource did not take title to the electric and gas commodities which were the subject of the brokerage contracts. The Company recorded energy brokering revenues based upon the amount of electricity and gas delivered to customers through the end of the accounting period. Usource partnered with certain entities to facilitate these brokerage services and paid these entities a fee under revenue sharing agreements.

Income Taxes – The Company is subject to Federal and State income taxes as well as various other business taxes. This process involves estimating the Company’s current tax liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included in the Company’s Consolidated Balance Sheets. The Company accounts for income tax assets, liabilities and expenses in accordance with the Financial Accounting Standards Board (FASB) Codification guidance on Income Taxes. The Company classifies penalty and interest expense related to income tax liabilities as income tax expense and interest expense, respectively, in the Consolidated Statements of Earnings.

Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s current and deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known. 

Cash and Cash Equivalents – Cash and Cash Equivalents include all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. As of September 30, 2019, September 30, 2018 and December 31, 2018, the Unitil subsidiaries had deposited $3.5 million, $3.2 million and $3.5 million, respectively to satisfy their ISO-NE obligations.

Allowance for Doubtful Accounts – The Company recognizes a provision for doubtful accounts each month based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables is performed which takes into account an assumption about the cash recovery of delinquent receivables. The analysis 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 hardship accounts that are protected from shut-off. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including the level of customers enrolling in payment plans with the Company. It has been the Company’s experience that the assumptions it has used in evaluating the adequacy of the Allowance for Doubtful Accounts have proven to be reasonably accurate.

The Allowance for Doubtful Accounts as of September 30, 2019, September 30, 2018 and December 31, 2018, which is included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, was as follows:

($ millions)
	September 30,				December 31,
	2019		2018		2018
Allowance for Doubtful Accounts	$	1.0	$	1.2	$	1.3

Accrued Revenue – Accrued Revenue includes the current portion of Regulatory Assets and unbilled revenues. The following table shows the components of Accrued Revenue as of September 30, 2019, September 30, 2018 and December 31, 2018. 

	September 30,				December 31,
Accrued Revenue ($ millions)	2019		2018		2018
Regulatory Assets – Current	$	24.9	$	26.4	$	41.3
Unbilled Revenues		10.4		9.6		13.4
Total Accrued Revenue	$	35.3	$	36.0	$	54.7

Exchange Gas Receivable – Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers natural gas back to the Company during the months of November through March. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of September 30, 2019, September 30, 2018 and December 31, 2018.

	September 30,				December 31,
Exchange Gas Receivable ($ millions)	2019		2018		2018
Northern Utilities	$	8.0	$	9.5	$	7.5
Fitchburg		0.6		0.6		0.6
Total Exchange Gas Receivable	$	8.6	$	10.1	$	8.1

Gas Inventory – The Company uses the weighted average cost methodology ​​​​​​​to value natural gas inventory. The following table shows the components of Gas Inventory as of September 30, 2019, September 30, 2018 and December 31, 2018.

	September 30,				December 31,
Gas Inventory ($ millions)	2019		2018		2018
Natural Gas	$	0.4	$	0.4	$	0.3
Propane		0.3		0.4		0.4
Liquefied Natural Gas & Other		0.1		0.1		0.1
Total Gas Inventory	$	0.8	$	0.9	$	0.8

Utility Plant – The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At September 30, 2019, September 30, 2018 and December 31, 2018, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $98.4 million, $91.2 million, and $90.7 million, respectively.

Leases – On January 1, 2019, the Company adopted ASU No. 2016-02, “Leases (Topic 842)”. The new standard requires lessees to record assets and liabilities on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allows the Company to carryforward the historical lease classification. The Company also elected the practical expedient related to land easements, allowing the Company to carry forward its current accounting treatment for land easements on existing agreements. The Company made an accounting policy election to keep leases with an initial term of 12 months or less off of the balance sheet. The Company recognizes those lease payments in the Consolidated Statements of Earnings on a straight-line basis over the lease term. The adoption of the standard resulted in recognition of approximately $4.2 million of lease assets and lease liabilities as of January 1, 2019 on the Company’s Consolidated Balance Sheets. The Company’s adoption of the standard did not have a material effect on its Consolidated Statements of Earnings and Consolidated Statements of Cash Flows. See additional discussion below in the “Leases” section of Note 4 to the Consolidated Financial Statements.

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.

	September 30,				December 31,
Regulatory Assets consist of the following ($ millions)	2019		2018		2018
Retirement Benefits	$	74.0	$	88.0	$	72.0
Energy Supply & Other Rate Adjustment Mechanisms		20.6		24.8		38.4
Deferred Storm Charges		5.0		6.3		6.3
Environmental		8.0		8.9		7.9
Income Taxes		4.3		5.9		5.7
Other		11.7		4.1		10.0
Total Regulatory Assets		123.6		138.0		140.3
Less: Current Portion of Regulatory Assets(1)		24.9		26.4		41.3
Regulatory Assets – noncurrent	$	98.7	$	111.6	$	99.0

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

	September 30,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2019		2018		2018
Income Taxes (Note 8)	$	47.6	$	47.9	$	47.0
Energy Supply & Other Rate Adjustment Mechanisms		13.5		12.2		11.5
Total Regulatory Liabilities		61.1		60.1		58.5
Less: Current Portion of Regulatory Liabilities		14.4		12.2		11.5
Regulatory Liabilities—noncurrent	$	46.7	$	47.9	$	47.0

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. As of September 30, 2019 there are $5.8 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years which regulators have authorized recovery of, but without a return. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

Derivatives – The Company’s regulated energy subsidiaries enter into energy supply contracts to serve their electric and gas customers. The Company follows a procedure for determining whether each contract qualifies as a derivative instrument under the guidance provided by the FASB Codification on Derivatives and Hedging. For each contract, the Company reviews and documents the key terms of the contract. Based on those terms and any additional relevant components of the contract, the Company determines and documents whether the contract qualifies as a derivative instrument as defined in the FASB Codification. The Company has determined that none of its energy supply contracts currently qualify as a derivative instrument under the guidance set forth in the FASB Codification.

As discussed below in the “Fitchburg – Massachusetts RFP’s” section of Note 6 (Regulatory Matters), Fitchburg has entered into power purchase agreements for which contingencies exist. 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 impact on the contractual obligations and regulatory assets of Fitchburg, once they qualify for derivative accounting.

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.)

At September 30, 2019, September 30, 2018 and December 31, 2018, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $5.9 million, $5.3 million and $4.8 million, respectively, as shown in the table below. 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 (Income), Net.

	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2019		2018		2018
Equity Funds	$	—	$	3.0	$	—
Fixed Income Funds		—		2.3		—
Money Market Funds		5.9		—		4.8
Total Marketable Securities	$	5.9	$	5.3	$	4.8

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

At September 30, 2019, September 30, 2018 and December 31, 2018, 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 $0.1 million, $0 and $0, respectively, as shown in the table below. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other Expense, Net.​​​​​​​

	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2019		2018		2018
Equity Funds	$	—	$	—	$	—
Money Market Funds		0.1		—		—
Total Marketable Securities	$	0.1	$	—	$	—

Energy Supply Obligations – The following ​​​​​​​discussion and table summarize the nature and amounts of the items recorded on the Company’s Consolidated Balance Sheets. The current portion of these obligations is recorded as Energy Supply Obligations and the noncurrent portion is included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets.

	September 30,				December 31,
Energy Supply Obligations ($ millions)	2019		2018		2018
Current:
Exchange Gas Obligation	$	8.0	$	9.5	$	7.5
Renewable Energy Portfolio Standards		4.2		5.2		5.6
Power Supply Contract Divestitures		0.3		0.3		0.3
Total Energy Supply Obligations – Current		12.5		15.0		13.4
Noncurrent:
Power Supply Contract Divestitures		0.4		0.7		0.6
Total Energy Supply Obligations	$	12.9	$	15.7	$	14.0

Exchange Gas Obligation – Northern Utilities enters into gas exchange agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. The gas inventory related to these agreements is recorded in Exchange Gas Receivable on the Company’s Consolidated Balance Sheets while the corresponding obligations are recorded in Energy Supply Obligations.

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 is 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 renewable energy certificates (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 four of these contracts have been constructed and are now operating. Since 2017, the Company has participated in two major statewide procurements which resulted in contracts for imported hydroelectric power and associated transmission and for offshore wind generation. The contracts were approved by the MDPU in the second quarter of 2019.

Additional long-term clean energy contracts are expected in compliance with the Energy Diversity Act and An Act to Promote a Clean Energy Future (2018). 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 – As a result of the restructuring of the utility industry in New Hampshire and Massachusetts, Unitil Energy’s and Fitchburg’s customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs. 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 (current portion) and Regulatory Assets (long-term portion).

Recently Issued Pronouncements – In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842)”. The new standard requires lessees to record assets and liabilities on the balance sheet for all leases with terms longer than 12 months. The Company adopted the standard as of January 1, 2019. See “Leases” above in Note 1.

Other than the pronouncement discussed above, there are no recently issued pronouncements that the Company has not already adopted or that have a material impact on the Company.

Subsequent Events – The Company has evaluated all events or transactions through the date of this filing. During this period the Company did not have any material subsequent events that would result in adjustment to or disclosure in its unaudited consolidated financial statements.

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SEGMENT INFORMATION (Tables)

9 Months Ended

Sep. 30, 2019

Significant Segment Financial Data

The following table provides significant segment financial data for the three and nine months ended September 30, 2019 and September 30, 2018 and as of December 31, 2018 (millions):

	Gas			Electric		Non- Regulated		Other		Total
Three Months Ended September 30, 2019
Revenues:
Billed and Unbilled Revenue	$	20.5		$	57.3	$	—	$	—	$	77.8
Rate Adjustment Mechanism Revenue		4.4			3.1		—		—		7.5
Other Operating Revenue – Non-Regulated		—			—		—		—		—
Total Operating Revenues	$	24.9		$	60.4	$	—	$	—	$	85.3
Segment Profit		(3.9	)		4.4		—		1.8		2.3
Capital Expenditures		26.9			9.2		—		1.9		38.0
Three Months Ended September 30, 2018
Revenues:
Billed and Unbilled Revenue	$	19.6		$	60.9	$	—	$	—	$	80.5
Rate Adjustment Mechanism Revenue		6.1			0.5		—		—		6.6
Other Operating Revenue – Non-Regulated		—			—		1.1		—		1.1
Total Operating Revenues	$	25.7		$	61.4	$	1.1	$	—	$	88.2
Segment Profit (Loss)		(3.2	)		4.5		0.3		1.2		2.8
Capital Expenditures		30.9			7.2		—		1.0		39.1

Nine Months Ended September 30, 2019
Revenues:
Billed and Unbilled Revenue	$	160.0		$	172.8		$	—	$	—	$	332.8
Rate Adjustment Mechanism Revenue		(16.1	)		4.2			—		—		(11.9	)
Other Operating Revenue – Non-Regulated		—			—			0.9		—		0.9
Total Operating Revenues	$	143.9		$	177.0		$	0.9	$	—	$	321.8
Segment Profit		10.1			9.7			10.2		2.8		32.8
Capital Expenditures		48.3			24.1			—		4.3		76.7
Segment Assets		780.7			507.6			0.3		21.1		1,309.7
Nine Months Ended September 30, 2018
Revenues:
Billed and Unbilled Revenue	$	151.1		$	176.2		$	—	$	—	$	327.3
Rate Adjustment Mechanism Revenue		(3.7	)		(8.6	)		—		—		(12.3	)
Other Operating Revenue – Non-Regulated		—			—			3.5		—		3.5
Total Operating Revenues	$	147.4		$	167.6		$	3.5	$	—	$	318.5
Segment Profit		9.1			10.2			0.9		1.8		22.0
Capital Expenditures		53.1			20.8			—		2.4		76.3
Segment Assets		730.0			485.7			6.6		42.2		1,264.5

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018
Common Stock Authorized	25,000,000	25,000,000	25,000,000
Common Equity Outstanding	14,925,898	14,876,955	14,872,011

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RETIREMENT BENEFIT OBLIGATIONS (Tables)

9 Months Ended

Sep. 30, 2019

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

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

Used to Determine Plan Costs	2019			2018
Discount Rate		4.25	%		3.60	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		7.75	%		7.75	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		7.50	%
Ultimate Health Care Cost Trend Rate		4.50	%		4.50	%
Year that Ultimate Health Care Cost Trend Rate is reached		2024			2024

Components of Retirement Plan Costs

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

	Pension Plan						PBOP Plan						SERP Plan
Three Months Ended September 30,	2019			2018			2019			2018			2019			2018
Service Cost	$	776		$	848		$	576		$	733		$	62		$	122
Interest Cost		1,621			1,469			857			852			142			101
Expected Return on Plan Assets		(2,119	)		(1,946	)		(412	)		(409	)		—			—
Prior Service Cost Amortization		80			81			304			327			14			47
Actuarial Loss Amortization		1,081			1,447			56			346			157			121
Sub-total		1,439			1,899			1,381			1,849			375			391
Amounts Capitalized and Deferred		(650	)		(962	)		(650	)		(930	)		(107	)		(113	)
Net Periodic Benefit Cost Recognized	$	789		$	937		$	731		$	919		$	268		$	278

	Pension Plan						PBOP Plan						SERP Plan
Nine Months Ended September 30,	2019			2018			2019			2018			2019			2018
Service Cost	$	2,328		$	2,544		$	1,728		$	2,199		$	185		$	366
Interest Cost		4,863			4,407			2,569			2,554			426			303
Expected Return on Plan Assets		(6,356	)		(5,838	)		(1,234	)		(1,227	)		—			—
Prior Service Cost Amortization		240			243			910			981			42			141
Actuarial Loss Amortization		3,243			4,341			170			1,038			471			365
Sub-total		4,318			5,697			4,143			5,545			1,124			1,175
Amounts Capitalized and Deferred		(1,659	)		(2,590	)		(1,730	)		(2,557	)		(322	)		(339	)
Net Periodic Benefit Cost Recognized	$	2,659		$	3,107		$	2,413		$	2,988		$	802		$	836

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Company's Liability for Environmental Obligations (Detail) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	$ 2.0	$ 2.1
Additions	1.0	0.6
Less: Payments / Reductions	0.2	0.6
Total Balance at End of Period	2.8	2.1
Less: Current Portion	0.6	0.6
Noncurrent Balance at End of Period	2.2	1.5
Fitchburg Gas and Electric Light Company
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period		0.1
Less: Payments / Reductions		0.1
Northern Utilities Inc
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	2.0	2.0
Additions	1.0	0.6
Less: Payments / Reductions	0.2	0.5
Total Balance at End of Period	2.8	2.1
Less: Current Portion	0.6	0.6
Noncurrent Balance at End of Period	$ 2.2	$ 1.5

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Common Stock And Preferred Stock - Additional Information (Detail) - USD ($)			3 Months Ended		9 Months Ended		12 Months Ended
	Oct. 01, 2019	Jan. 29, 2019	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Class of Stock [Line Items]
Common stock, shares outstanding			14,925,898	14,872,011	14,925,898	14,872,011	14,876,955
Common stock, shares issued			4,727	5,423	15,793	19,700
Proceeds from Issuance of Common Stock					$ 900,000	$ 900,000
Restricted stock weighted average grant date fair value					$ 46.41	$ 41.96
Share based compensation expense					$ 2,200,000	$ 2,100,000
Percentage of fully-vested restricted stock units that directors will receive in common shares when settled					70.00%
Fair value of liabilities associated with fully vested RSUs that will be settled in cash			$ 1,700,000	$ 1,200,000	$ 1,700,000	1,200,000	$ 1,300,000
Percentage of fully-vested restricted stock units that directors will receive in cash when settled					30.00%
Preferred Stock			200,000	200,000	$ 200,000	200,000	$ 200,000
Maximum
Class of Stock [Line Items]
Dividend declared			$ 100,000	$ 100,000	$ 100,000	$ 100,000
Restricted Stock
Class of Stock [Line Items]
Restricted stock vesting period					4 years
Restricted stock non-vested			50,917	49,581	50,917	49,581
Unrecognized share based compensation			$ 800,000		$ 800,000
Share compensation recognition period					2 years 8 months 12 days
Restricted Stock Units Granted		33,150
Aggregate Market Value					$ 1,600,000
Forfeitures under the stock plan					0
Cancellations under the stock plan					0
Restricted Stock | Maximum
Class of Stock [Line Items]
Restricted stock available for awards			677,500		677,500
Restricted stock that may be awarded in any one calendar year to any one participant			20,000		20,000
Restricted Stock | Vesting Annually
Class of Stock [Line Items]
Restricted stock vesting percentage annually					25.00%
Restricted Stock Units (RSUs)
Class of Stock [Line Items]
Restricted Stock Units Granted	9,918				0
Restricted stock units outstanding				53,454		53,454
Weighted-Average Stock Price				$ 36.47		$ 36.47
Series 6 | Unitil Energy Systems Inc
Class of Stock [Line Items]
Preferred stock, outstanding			1,887	1,893	1,887	1,893	1,893
Preferred Stock			$ 200,000	$ 200,000	$ 200,000	$ 200,000	$ 200,000
Dividend rate					6.00%	6.00%	6.00%
Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Proceeds from Issuance of Common Stock					$ 889,000
Dividend and Distribution Reinvestment and Share Purchase Plan | Average
Class of Stock [Line Items]
Common stock price per share			$ 56.29		$ 56.29
Dividend and Distribution Reinvestment and Share Purchase Plan | Common Stock
Class of Stock [Line Items]
Common stock, shares issued					15,793

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Debt and Financing Arrangements - Additional Information (Detail) - USD ($)		1 Months Ended		3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 12, 2019	Nov. 30, 2018	Jul. 25, 2018	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018	Oct. 30, 2015
Line of Credit Facility [Line Items]
Weighted average interest rate on short term borrowings				3.40%	3.30%	3.60%	3.20%	3.30%
Gain on divestiture of business, net						$ 9,800,000
Capital lease obligation, total capitalized cost				$ 620,000	$ 6,500,000	620,000	$ 6,500,000	$ 5,800,000
Capital lease obligation, current				300,000	3,100,000	300,000	3,100,000	3,100,000
Capital lease obligation, noncurrent				300,000	3,400,000	300,000	3,400,000	2,700,000
Accounts Payable				22,900,000	27,400,000	22,900,000	27,400,000	42,600,000
Guarantee outstanding				4,300,000		4,300,000
Total rental expense under operating leases				400,000	400,000	1,100,000	1,400,000
Operating lease obligations						1,100,000
Net Utility Plant				1,083,900,000	1,022,300,000	1,083,900,000	1,022,300,000	1,036,800,000
Other current operating lease obligation				1,200,000		1,200,000
Other noncurrent operating lease obligation				$ 3,000,000.0		$ 3,000,000.0
Long-term debt, maturity date	Sep. 12, 2049
Operating lease, weighted average remaining lease term				4 years		4 years
Operating lease, weighted average discount rate percentage				5.30%		5.30%
Credit Facility [Member] | Amended Credit Facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility			$ 120,000,000
Sublimit for the issuance of standby letters of credit			$ 25,000,000
Revolving credit facility termination date			Jul. 25, 2023
Increase in borrowing limit			$ 50,000,000
Credit Facility [Member] | London Interbank Offered Rate | Amended Credit Facility [Member]
Line of Credit Facility [Line Items]
Credit facility, daily fluctuating rate of interest			1.125%
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility				$ 120,000,000.0	120,000,000.0	$ 120,000,000.0	120,000,000.0	120,000,000.0
Proceeds from lines of credit						187,100,000
Repayments of lines of credit						$ 220,700,000
Revolving Credit Facility [Member] | Credit Facility [Member]
Line of Credit Facility [Line Items]
Percentage of capitalization						The affirmative and negative covenants under the Credit Facility shall apply until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At September 30, 2019, September 30, 2018 and December 31, 2018, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.
Unitil Service Corp [Member]
Line of Credit Facility [Line Items]
Capital lease obligation, total capitalized cost									$ 13,400,000
Northern Utilities Inc
Line of Credit Facility [Line Items]
Accounts Payable				100,000	100,000	$ 100,000	100,000	900,000
Natural gas storage inventory				$ 8,100,000	$ 9,600,000	$ 8,100,000	$ 9,600,000	$ 8,400,000
Northern Utilities Inc | 4.04% Senior Notes, Due September 12, 2049
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount	$ 40,000,000
Long-term debt, stated interest rate	4.04%			4.04%	4.04%	4.04%	4.04%	4.04%
Long-term debt, maturity date						Sep. 12, 2049	Sep. 12, 2049	Sep. 12, 2049
Issuance of long-term debt	$ 200,000
Unitil Energy [Member] | 4.18% First Mortgage Bonds, Due November 30, 2048
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount		$ 30,000,000
Long-term debt, stated interest rate		4.18%
Long-term debt, maturity date		Nov. 30, 2048
Issuance of long-term debt		$ 500,000
Assets under Capital Leases [Member]
Line of Credit Facility [Line Items]
Net Utility Plant				$ 1,300,000	$ 15,000,000.0	$ 1,300,000	$ 15,000,000.0	$ 15,000,000.0
Net Utility Plant, accumulated amortization				$ 600,000	$ 2,100,000	$ 600,000	$ 2,100,000	$ 1,700,000

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DEBT AND FINANCING ARRANGEMENTS (Tables)

9 Months Ended

Sep. 30, 2019

Details on Long Term Debt

Details on long-term debt at September 30, 2019, September 30, 2018 and December 31, 2018 are shown below:

($ millions)	September 30,				December 31,
	2019		2018		2018
Unitil Corporation:
6.33% Senior Notes, Due May 1, 2022	$	20.0	$	20.0	$	20.0
3.70% Senior Notes, Due August 1, 2026		30.0		30.0		30.0
Unitil Energy First Mortgage Bonds:
5.24% Senior Secured Notes, Due March 2, 2020		5.0		10.0		10.0
8.49% Senior Secured Notes, Due October 14, 2024		6.0		7.5		6.0
6.96% Senior Secured Notes, Due September 1, 2028		18.0		20.0		20.0
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
4.18% Senior Secured Notes, Due November 30, 2048		30.0		—		30.0
Fitchburg:
6.75% Senior Notes, Due November 30, 2023		5.7		7.6		5.7
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		12.0		12.0		12.0
5.90% Senior Notes, Due December 15, 2030		15.0		15.0		15.0
7.98% Senior Notes, Due June 1, 2031		14.0		14.0		14.0
4.32% Senior Notes, Due November 1, 2047		15.0		15.0		15.0
Northern Utilities:
6.95% Senior Notes, Due December 3, 2018		—		10.0		—
5.29% Senior Notes, Due March 2, 2020		8.2		16.6		16.6
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
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		—		—
Granite State:
7.15% Senior Notes, Due December 15, 2018		—		3.3		—
3.72% Senior Notes, Due November 1, 2027		15.0		15.0		15.0
Total Long-Term Debt		433.9		396.0		409.3
Less: Unamortized Debt Issuance Costs		3.5		3.1		3.5
Total Long-Term Debt, net of Unamortized Debt Issuance Costs		430.4		392.9		405.8
Less: Current Portion(1)		19.5		31.8		18.4
Total Long-term Debt, Less Current Portion	$	410.9	$	361.1	$	387.4

(1) The Current Portion of Long-Term Debt ​​​​​​​includes sinking ​​​​​​​fund payments.

Fair Value of Long Term Debt

($ millions)	September 30,				December 31,
	2019		2018		2018
Estimated Fair Value of Long-Term Debt	$	495.1	$	418.7	$	422.0

Borrowing Limits Amounts Outstanding and Amounts Available under Credit Facility

The following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of September 30 2019, September 30, 2018 and December 31, 2018:

	Revolving Credit Facility ($ millions)
	September 30,				December 31,
	2019		2018		2018
Limit	$	120.0	$	120.0	$	120.0
Short-Term Borrowings Outstanding		49.2		69.1		82.8
Letter of Credit Outstanding		0.1		—		—
Available	$	70.7	$	50.9	$	37.2

Classification of the Company Lease Obligations

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

	September 30,				December 31,
Lease Obligations ($ millions)	2019		2018		2018
Operating Lease Obligations:
Other Current Liabilities (current portion)	$	1.2	$	—	$	—
Other Noncurrent Liabilities (long-term portion)		3.0		—		—
Total Operating Lease Obligations		4.2		—		—
Capital Lease Obligations:
Other Current Liabilities (current portion)		0.3		3.1		3.1
Other Noncurrent Liabilities (long-term portion)		0.3		3.4		2.7
Total Capital Lease Obligations		0.6		6.5		5.8
Total Lease Obligations	$	4.8	$	6.5	$	5.8

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

The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of September 30, 2019. The payments for capital leases consist of $0.3​​​​​​​​​​​​​​ million of current capital lease obligations, which are included in Other​​​​​​​ Current Liabilities and $0.3 million of noncurrent capital lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of September 30, 2019.

Lease Payments ($000’s) Year Ending December 31,	Operating Leases		Capital Leases
Rest of 2019	$	356	$	80
2020		1,338		262
2021		1,168		161
2022		887		97
2023		587		55
2024-2028		400		—
Total Payments		4,736		655
Less: Interest		507		35
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$	4,229	$	620

The payment amounts in the following table, which are as of December 31, 2018, would not differ substantially from the payment amounts as of September 30, 2018.

Lease Payments ($000’s) Year Ending December 31,	Operating Leases		Capital Leases
2019	$	1,372	$	3,069
2020		1,138		2,535
2021		969		93
2022		689		32
2023		390		14
2024-2028		120		—
Total Payments	$	4,678	$	5,743

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Cover Page - shares	9 Months Ended
	Sep. 30, 2019	Oct. 21, 2019
Document Information [Line Items]
Entity Interactive Data Current	Yes
Document Type	10-Q
Document Quarterly Report	true
Document Transition Report	false
Amendment Flag	false
Document Period End Date	Sep. 30, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q3
Entity Registrant Name	UNITIL CORP
Entity Central Index Key	0000755001
Entity File Number	1-8858
Entity Tax Identification Number	02-0381573
Entity Incorporation, State or Country Code	NH
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Shell Company	false
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Address, Address Line One	6 Liberty Lane West
Entity Address, City or Town	Hampton
Entity Address, Postal Zip Code	03842-1720
Entity Address, State or Province	NH
City Area Code	603
Local Phone Number	772-0775
Trading Symbol	UTL
Security Exchange Name	NYSE
Entity Common Stock, Shares Outstanding		14,926,205
Title of 12(b) Security	Common Stock

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Operating Activities:
Net Income	$ 32.8	$ 22.0
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	39.0	37.4
Deferred Tax Provision	9.3	4.6
Gain on Divestiture, Net (See Note 1)	(13.4)
Changes in Working Capital Items:
Accounts Receivable	27.4	15.1
Accrued Revenue	19.4	17.3
Exchange Gas Receivable	(0.5)	(4.3)
Regulatory Liabilities	2.9	3.0
Accounts Payable	(19.7)	(14.1)
Other Changes in Working Capital Items	(2.4)	3.7
Deferred Regulatory and Other Charges	(4.7)	(5.7)
Other, net	2.1	(9.0)
Cash Provided by Operating Activities	92.2	70.0
Investing Activities:
Property, Plant and Equipment Additions	(76.7)	(76.3)
Proceeds from Divestiture, Net (See Note 1)	13.4
Cash (Used in) Investing Activities	(63.3)	(76.3)
Financing Activities:
(Repayment of) Proceeds from Short-Term Debt, net	(33.6)	30.8
Repayment of Long-Term Debt	(15.2)	(13.5)
Issuance of Long-Term Debt	39.8
Decrease in Capital Lease Obligations	(5.1)	(2.3)
Net Increase in Exchange Gas Financing	0.5	4.1
Dividends Paid	(16.7)	(16.3)
Proceeds from Issuance of Common Stock, net	0.9	0.9
Cash (Used in) Provided by Financing Activities	(29.4)	3.7
Net Decrease in Cash and Cash Equivalents	(0.5)	(2.6)
Cash and Cash Equivalents at Beginning of Period	7.8	8.9
Cash and Cash Equivalents at End of Period	7.3	6.3
Supplemental Cash Flow Information:
Interest Paid	15.6	15.6
Income Taxes Paid	0.9	0.4
Payments on Capital Leases	5.4	2.3
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	0.8	$ 1.2
Right-of-Use Assets Obtained in Exchange for Lease Obligations	$ 4.2

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Summary of Significant Accounting Policies - Additional Information (Detail) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2019 USD ($) mi	Sep. 30, 2019 USD ($) Subsidiary	Jan. 01, 2019 USD ($)	Dec. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)
Significant Accounting Policies [Line Items]
Length Of Pipeline | mi	86
Gain on divestiture of business, pretax		$ 13.4
Gain on divestiture of business, net		9.8
Provision for income taxes		3.6
Cost of removal obligation	$ 98.4	98.4		$ 90.7	$ 91.2
Recognition of lease assets			$ 4.2
Recognition of lease liabilities			$ 4.2
Regulatory assets	123.6	123.6		140.3	138.0
Investments in trading securities	5.9	$ 5.9		4.8	5.3
Utilities
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Subsidiary		3
Unitil Service; Unitil Realty; and Unitil Resources
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Subsidiary		3
Annual Electric Sales Volume
Significant Accounting Policies [Line Items]
Percentage of total sales volumes revenue subject to RDM		27.00%
Annual Natural Gas Sales Volume
Significant Accounting Policies [Line Items]
Percentage of total sales volumes revenue subject to RDM		11.00%
Environmental and Rate Case Costs and Other Expenditures | Recovered over the next seven years
Significant Accounting Policies [Line Items]
Regulatory assets	5.8	$ 5.8
ISO-NE Obligations
Significant Accounting Policies [Line Items]
Cash Deposits	$ 3.5	$ 3.5		3.5	3.2
Maximum
Significant Accounting Policies [Line Items]
Cash equivalents maturity period		3 months
Lease term	12 months	12 months
Deferred Compensation Plan [Member]
Significant Accounting Policies [Line Items]
Investments in trading securities	$ 0.1	$ 0.1		$ 0.0	$ 0.0

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Components of Exchange Gas Receivable (Detail) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018
Receivables [Line Items]
Total Exchange Gas Receivable	$ 8.6	$ 8.1	$ 10.1
Northern Utilities Inc
Receivables [Line Items]
Total Exchange Gas Receivable	8.0	7.5	9.5
Fitchburg
Receivables [Line Items]
Total Exchange Gas Receivable	$ 0.6	$ 0.6	$ 0.6

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DIVIDENDS DECLARED PER SHARE

9 Months Ended

Sep. 30, 2019

DIVIDENDS DECLARED PER SHARE [Abstract]

DIVIDENDS DECLARED PER SHARE

Note 2 – Dividends Declared Per Share

Declaration Date	Date Paid (Payable)	Shareholder of Record Date	Dividend Amount
10/23/19	11/27/19	11/13/19	$ 0.370
07/24/19	08/29/19	08/15/19	$ 0.370
04/24/19	05/29/19	05/15/19	$ 0.370
01/30/19	02/28/19	02/14/19	$ 0.370
10/24/18	11/29/18	11/15/18	$ 0.365
07/25/18	08/29/18	08/15/18	$ 0.365
04/25/18	05/29/18	05/15/18	$ 0.365
01/30/18	02/28/18	02/14/18	$ 0.365

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Details on Long Term Debt (Parenthetical) (Detail)		9 Months Ended		12 Months Ended
	Sep. 12, 2019	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Debt Instrument [Line Items]
Debt instrument due date	Sep. 12, 2049
6.33% Senior Notes, Due May 1, 2022
Debt Instrument [Line Items]
Stated interest rate		6.33%	6.33%	6.33%
Debt instrument due date		May 01, 2022	May 01, 2022	May 01, 2022
3.70% Senior Notes, Due August 1, 2026
Debt Instrument [Line Items]
Stated interest rate		3.70%	3.70%	3.70%
Debt instrument due date		Aug. 01, 2026	Aug. 01, 2026	Aug. 01, 2026
First Mortgage Bonds 5.24% Senior Secured Notes, Due March 2, 2020 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate		5.24%	5.24%	5.24%
Debt instrument due date		Mar. 02, 2020	Mar. 02, 2020	Mar. 02, 2020
First Mortgage Bonds 8.49% Senior Secured Notes, Due October 14, 2024 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate		8.49%	8.49%	8.49%
Debt instrument due date		Oct. 14, 2024	Oct. 14, 2024	Oct. 14, 2024
First Mortgage Bonds 6.96% Senior Secured Notes, Due September 1, 2028 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate		6.96%	6.96%	6.96%
Debt instrument due date		Sep. 01, 2028	Sep. 01, 2028	Sep. 01, 2028
First Mortgage Bonds 8.00% Senior Secured Notes, Due May 1, 2031 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate		8.00%	8.00%	8.00%
Debt instrument due date		May 01, 2031	May 01, 2031	May 01, 2031
First Mortgage Bonds 6.32% Senior Secured Notes, Due September 15, 2036 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate		6.32%	6.32%	6.32%
Debt instrument due date		Sep. 15, 2036	Sep. 15, 2036	Sep. 15, 2036
First Mortgage Bonds 4.18% Senior Secured Notes Due November 30, 2048 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate		4.18%	4.18%	4.18%
Debt instrument due date		Nov. 30, 2048	Nov. 30, 2048	Nov. 30, 2048
6.75% Senior Notes, Due November 30, 2023 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate		6.75%	6.75%	6.75%
Debt instrument due date		Nov. 30, 2023	Nov. 30, 2023	Nov. 30, 2023
6.79% Senior Notes, Due October 15, 2025 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate		6.79%	6.79%	6.79%
Debt instrument due date		Oct. 15, 2025	Oct. 15, 2025	Oct. 15, 2025
3.52% Senior Notes, Due November 1, 2027 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate		3.52%	3.52%	3.52%
Debt instrument due date		Nov. 01, 2027	Nov. 01, 2027	Nov. 01, 2027
3.52% Senior Notes, Due November 1, 2027 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate		3.52%	3.52%	3.52%
Debt instrument due date		Nov. 01, 2027	Nov. 01, 2027	Nov. 01, 2027
7.37% Notes, Due January 15, 2029 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate		7.37%	7.37%	7.37%
Debt instrument due date		Jan. 15, 2029	Jan. 15, 2029	Jan. 15, 2029
5.90% Notes, Due December 15, 2030 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate		5.90%	5.90%	5.90%
Debt instrument due date		Dec. 15, 2030	Dec. 15, 2030	Dec. 15, 2030
7.98% Notes, Due June 1, 2031 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate		7.98%	7.98%	7.98%
Debt instrument due date		Jun. 01, 2031	Jun. 01, 2031	Jun. 01, 2031
4.32% Senior Notes, Due November 1, 2047 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate		4.32%	4.32%	4.32%
Debt instrument due date		Nov. 01, 2047	Nov. 01, 2047	Nov. 01, 2047
4.32% Senior Notes, Due November 1, 2047 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate		4.32%	4.32%	4.32%
Debt instrument due date		Nov. 01, 2047	Nov. 01, 2047	Nov. 01, 2047
6.95% Senior Notes, Due December 3, 2018 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate		6.95%	6.95%	6.95%
Debt instrument due date		Dec. 03, 2018	Dec. 03, 2018	Dec. 03, 2018
5.29% Senior Notes, Due March 2, 2020 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate		5.29%	5.29%	5.29%
Debt instrument due date		Mar. 02, 2020	Mar. 02, 2020	Mar. 02, 2020
7.72% Senior Notes, Due December 3, 2038 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate		7.72%	7.72%	7.72%
Debt instrument due date		Dec. 03, 2038	Dec. 03, 2038	Dec. 03, 2038
4.42% Senior Notes, Due October 15, 2044 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate		4.42%	4.42%	4.42%
Debt instrument due date		Oct. 15, 2044	Oct. 15, 2044	Oct. 15, 2044
4.04% Senior Notes, Due September 12, 2049 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	4.04%	4.04%	4.04%	4.04%
Debt instrument due date		Sep. 12, 2049	Sep. 12, 2049	Sep. 12, 2049
7.15% Senior Notes, Due December 15, 2018 | Granite State Gas Transmission Inc
Debt Instrument [Line Items]
Stated interest rate		7.15%	7.15%	7.15%
Debt instrument due date		Dec. 15, 2018	Dec. 15, 2018	Dec. 15, 2018
3.72% Senior Notes, Due November 1, 2027 | Granite State Gas Transmission Inc
Debt Instrument [Line Items]
Stated interest rate		3.72%	3.72%	3.72%
Debt instrument due date		Nov. 01, 2027	Nov. 01, 2027	Nov. 01, 2027

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Components of Energy Supply Obligations (Detail) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 12.5	$ 13.4	$ 15.0
Power Supply Contract Divestitures, Noncurrent	0.4	0.6	0.7
Total Energy Supply Obligations	12.9	14.0	15.7
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	4.2	5.6	5.2
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	0.3	0.3	0.3
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 8.0	$ 7.5	$ 9.5

XML

Components of Gas Inventory (Detail) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.8	$ 0.8	$ 0.9
Liquefied Natural Gas & Other
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.1	0.1	0.1
Natural Gas
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.4	0.3	0.4
Propane
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.3	$ 0.4	$ 0.4

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REGULATORY MATTERS

9 Months Ended

Sep. 30, 2019

REGULATORY MATTERS

note 6 – REgulatory Matters

Unitil’s Regulatory matters are described in Note 8 to the Financial Statements in Item 8 of Part II of Unitil Corporation’s Form 10-K for December 31, 2018 as filed with the Securities and Exchange Commission on january 31, 2019.

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 percent, 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 opened a rulemaking proceeding on this matter which has been addressed in a rate settlement filing by Granite State. More recently, on November 15, 2018, the FERC issued a Notice of Proposed Rulemaking and a Policy Statement to address the TCJA’s effects on the Accumulated Deferred Income Taxes (ADIT) on transmission rates. Under the proposed rules all public utilities with transmission formula rates, including Fitchburg, would be required to: (1) include mechanisms to deduct any excess ADIT from or add any deficient ADIT to their rate bases; (2) include mechanisms in those rates that would raise or lower their income tax allowances by any amortized excess or deficient ADIT; and (3) incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT. The Company believes that these matters are substantially resolved and will not have a material impact on its financial position, operating results, or cash flows.

Rate Case Activity

Northern Utilities – Base Rates – Maine – On June 28, 2019, Northern Utilities filed a petition with the MPUC seeking an increase to annual base operating revenues of $7.0 million. If approved as filed, the requested increase will result in a 7 percent increase over the Company’s test-year operating revenues. The intended rate effective date is April 1, 2020. In addition, Northern Utilities is requesting approval to implement a multi-year alternative rate mechanism (“Capital Investment Recovery Adjustment” or “CIRA”) that will allow for future changes to the Company’s distribution rates and mitigate the need to file a general rate case. The CIRA is designed to recover the costs of replacing, relocating and abandoning existing facilities and other operational and safety-related system improvements. The first annual adjustment is proposed for November 1, 2020, to recover the Company’s 2019 investment cost of eligible facilities and improvements. This matter remains pending.

Northern Utilities – Targeted Infrastructure Replacement Adjustment (TIRA) – Maine – The settlement in Northern Utilities’ Maine division’s 2013 rate case allowed 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’ last 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. On May 7, 2018, the MPUC approved the Company’s request to increase its annual base rates by 2.4%, or $1.1 million, effective May 1, 2018, to recover the revenue requirements for 2017 eligible facilities. On April 17, 2019, the MPUC approved the Company’s request to increase its annual base rates by 2.1%, or $1.0 million, effective May 1, 2019, to recover the revenue requirements for 2018 eligible facilities.

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 step increase of approximately $1.4 million of annual revenue was approved by the NHPUC, effective May 1, 2019, to recover eligible capital investments in 2018. According to the terms of the settlement agreement, Northern Utilities’ next distribution base rate case shall be based on an historic test year of no earlier than twelve months ending December 31, 2020.

Unitil Energy – Base Rates – On April 20, 2017 the NHPUC issued its final order providing for a permanent increase of $4.1 million, effective May 1, 2017, followed by two annual rate step adjustments to recover the revenue requirements associated with certain capital expenditures. On April 30, 2018, the NHPUC approved Unitil Energy’s first step increase, effective May 1, 2018. On April 22, 2019, the NHPUC approved Unitil Energy’s second and final step adjustment, providing for a revenue increase of approximately $340,000, effective May 1, 2019.

Fitchburg – Base Rates – Electric – Fitchburg’s base rates are decoupled, and subject to an annual revenue decoupling adjustment mechanism, which includes a cap on the amount that rates may be increased in any year. In addition, Fitchburg has an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions. On April 3, 2019, the DPU approved Fitchburg’s cumulative revenue requirement associated with the Company’s 2015 and 2016 capital expenditures, an increase of $0.4 million. The increase was effective January 1, 2018. On November 1, 2018, Fitchburg filed its cumulative revenue requirement of $0.9 million associated with the Company’s 2015, 2016 and 2017 capital expenditures. On December 27, 2018, the filing was approved, effective January 1, 2019, subject to further investigation and reconciliation. Final approval of the 2018 filing remains pending. On September 5, 2019, Fitchburg’s electric division filed with the MDPU a letter of intent to file for a general increase in base rates. Under MDPU precedent, a utility company is required to provide no less than a 30 day advance notice of its intent to file for a base rate increase. At this time, Fitchburg anticipates that the filing will be made during the fourth quarter 2019.

Fitchburg – Base Rates – Gas – Pursuant to the Company’s 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 impacts to the Company’s revenues. The MDPU has consistently found that 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 September 5, 2019, Fitchburg’s gas division filed with the MDPU a letter of intent to file for a general increase in base rates. Under MDPU precedent, a utility company is required to provide no less than a 30 day advance notice of its intent to file for a base rate increase. At this time, Fitchburg anticipates that the filing will be made during the fourth quarter 2019.

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 (the “GSEP Filing”); and a filing, submitted on or before May 1, of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably and prudently incurred (the “GREC Filing”). The Company considers these to be routine regulatory proceedings and there are no material issues outstanding.

In an Order issued on April 30, 2019, the MDPU approved Fitchburg’s 2018 GSEP Filing and increased the annual cap on recovery. Because the amount approved for recovery, $1.6 million, still exceeded the annual cap, the Order resulted in a revenue increase of $1.0 million that went into effect on May 1, 2019, subject to reconciliation. The amount that exceeded the cap, $0.6  million, has been deferred to be recovered in a later proceeding. On May 1, 2019, the Company made its 2019 GREC Filing, seeking a waiver of the annual cap and a revenue increase of $1.0  million. This matter remains pending.

Granite State – Base Rates – On May 2, 2018, Granite State filed an uncontested rate settlement with FERC which provided for no change in rates, and accounted for the effects of a capital step adjustment offset by the effect of the TCJA. The settlement was approved by FERC on June 27, 2018, and complies with the FERC Notice of Proposed Rulemaking concerning the justness and reasonableness of rates in light of the corporate income tax reductions under the TCJA.

Other Matters

Fitchburg – Independent Statewide Examination of the Safety of the Commonwealth’s Gas Distribution System – The MDPU has 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 which focuses on the gas incident on September 13, 2018 in the Merrimack Valley and its potential causes. The evaluator will examine the following areas: (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 a Phase 1 summary report including preliminary recommendations for the MDPU’s consideration on May 13, 2019. The investigation is on-going and the evaluator will produce a final report at the end of the process. The Company believes that this examination will not result in a material impact on its financial position, operating results or cash flows.

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, as 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 as well as the 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 July 11, 2019, the MPUC approved Northern Utilities’ request to extend its contract for firm transmission on its affiliate Granite State pipeline for another year, extending the current contract for the period of November 1, 2019 through October 31, 2020. The next request to the MPUC for approval to extend the transmission contract will be filed in July 2020. In New Hampshire, pursuant to statute, Northern Utilities advises the NHPUC of its annual contract renewal with Granite State, though it is not required to seek approval of the renewal.

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

Fitchburg – Massachusetts RFPs – Pursuant to a comprehensive energy law enacted in 2016, “An Act to Promote Energy Diversity,” 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’s 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 (hydro, solar and land-based wind) long-term contracts via one or more staggered solicitations for a total of 9,450,000 megawatt-hours by December 31, 2022. Unitil’s pro rata share of each of these contracts is approximately one percent. The EDCs issued the RFP for Section 83D Long-Term Contracts for Qualified Clean Energy Projects in March 2017, and after selection of final projects and negotiation, final contracts for 9,554,940 MWh of Qualified Clean Energy and associated Environmental Attributes from hydroelectric generation were filed in July 2018 for approval by the MDPU. On June 25, 2019, the MDPU approved the power purchase agreements, including the EDCs’ proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market costs to customers. The MDPU also determined that the EDCs’ request for remuneration equal to 2.75 percent is reasonable and in the public interest. Also, the MDPU approved the EDCs’ proposal to amend their respective tariffs to include the recovery of costs associated with the contracts. The Company believes that the power purchase obligations under these long-term contracts will have a material impact on the contractual obligations and regulatory assets 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. Final selection of projects was made 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 400MW of offshore wind energy generation with 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 percent is reasonable and in the public interest. Also, the MDPU approved the EDCs’ proposal to amend their respective tariffs to include the recovery of costs associated with the contracts. The Company believes that the power purchase obligations under these long-term contracts will have a material impact on the contractual obligations and regulatory assets of Fitchburg.

The EDCs issued an RFP pursuant to Section 83C for Long-Term Contracts for Offshore Wind Energy Generation on May 23, 2019. This is the second solicitation pursuant to Section 83C and with the Department’s approval of the Vineyard Wind contracts for 800 MW of offshore wind energy generation as a result of the first solicitation, the remaining obligation under 83C is to procure an additional 800 MW of offshore wind energy generation. The EDCs intend to purchase at least 400 MW of the remaining 800 MW obligation under this RFP. Proposals were received on August 23, 2019, and selection is to occur on November 8, 2019, contracts are to be executed by December 13, 2019, and filed with the Department on January 10, 2020.

Northern Utilities Gas Supply Cost Investigation – The MPUC has opened an investigation into the gas supply and procurement activities of Maine local distribution companies. Northern Utilities is the first company to have its procurement practices examined, and the Company is cooperating with a consultant engaged by the MPUC to conduct this ongoing investigation. The Company believes that this investigation will not result in a material impact on its financial position, operating results or cash flows.

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 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 had 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.

Also pending at FERC is a 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. 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. The initial decision has been rescheduled to be issued on November 2, 2020. 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 that these proceedings will have a material adverse impact on the Company’s financial condition or results of operations.

Legal Proceedings

The Company is involved in legal and administrative proceedings and claims of various types, 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 impact on its financial position, operating results or cash flows.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2019

Accounting Policies [Abstract]

Nature of Operations

Nature of Operations – Unitil Corporation (Unitil or the Company) is a public utility holding company. Unitil and its subsidiaries are subject to regulation as a holding company system by the Federal Energy Regulatory Commission (FERC) under the Energy Policy Act of 2005. The following companies are wholly-owned subsidiaries of Unitil: Unitil Energy Systems, Inc. (Unitil Energy), Fitchburg Gas and Electric Light Company (Fitchburg), Northern Utilities, Inc. (Northern Utilities), Granite State Gas Transmission, Inc. (Granite State), Unitil Power Corp. (Unitil Power), Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) and its non-regulated business unit Unitil Resources, Inc. (Unitil Resources). Usource Inc. and Usource L.L.C., which the Company sold in the first quarter of 2019, were wholly-owned subsidiaries of Unitil Resources.

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

Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capital regions of New Hampshire and the greater Fitchburg area of north central Massachusetts, and the local distribution of natural gas in southeastern New Hampshire, portions of southern and central Maine 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 a natural gas transportation pipeline, 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 natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.

A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of Unitil Energy on May 1, 2003 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.

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. Usource, Inc. and Usource L.L.C. (collectively, Usource), which the Company divested of in the first quarter of 2019, were wholly-owned subsidiaries of Unitil Resources. Usource provided brokering and advisory services to large commercial and industrial customers in the northeastern United States. See additional discussion of the divestiture of Usource below.

Basis of Presentation

Basis of Presentation – The accompanying unaudited Consolidated Financial Statements of Unitil have been prepared in accordance with the instructions to Form 10-Q and include all of the information and footnotes required by generally accepted accounting principles. In the opinion of management, all adjustments considered necessary for a fair presentation have been included and are of a normal and recurring nature. The results of operations for the three and nine months ended September 30, 2019 are not necessarily indicative of results to be expected for the year ending December 31, 2019. 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, 2018, as filed with the Securities and Exchange Commission (SEC) on January 31, 2019, for a description of the Company’s Basis of Presentation.

Divestiture of Non-Regulated Business Subsidiary

Divestiture of Non-Regulated Business Subsidiary – On March 1, 2019, the Company divested of its non-regulated energy brokering and advisory business subsidiary, Usource. The Company recognized an after-tax net gain of approximately $9.8 million on this divestiture in the first quarter of 2019. The pre-tax net gain of approximately $13.4 million on this divestiture is included in Other Income (Expense), Net on the Consolidated Statements of Earnings for the nine months ended September 30, 2019, while the income taxes associated with this transaction of $3.6 million are included in the Provision For Income Taxes.

Utility Revenue Recognition

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

Billed and unbilled revenue is recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenues are calculated. These unbilled revenues are calculated each month based on estimated customer usage by class and applicable customer rates 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 ASU 2014-09. Revenue recognized in connection with rate adjustment mechanisms is consistent with the definition of alternative revenue programs in Accounting Standards Codification (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. ASU 2014-09 requires the Company to disclose separately the amount of revenues from contracts with customers and alternative revenue program revenues.

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

	Three Months Ended September 30, 2019
Gas and Electric Operating Revenues ($ millions):	Gas			Electric		Total
Billed and Unbilled Revenue:
Residential	$	6.9		$	31.3	$	38.2
C&I		12.5			24.5		37.0
Other		1.1			1.5		2.6
Total Billed and Unbilled Revenue		20.5			57.3		77.8
Rate Adjustment Mechanism Revenue		4.4			3.1		7.5
Total Gas and Electric Operating Revenues	$	24.9		$	60.4	$	85.3
	Three Months Ended September 30, 2018
Gas and Electric Operating Revenues ($ millions):	Gas			Electric		Total
Billed and Unbilled Revenue:
Residential	$	6.6		$	33.6	$	40.2
C&I		11.9			25.3		37.2
Other		1.1			2.0		3.1
Total Billed and Unbilled Revenue		19.6			60.9		80.5
Rate Adjustment Mechanism Revenue		6.1			0.5		6.6
Total Gas and Electric Operating Revenues	$	25.7		$	61.4	$	87.1
	Nine Months Ended September 30, 2019
Gas and Electric Operating Revenues ($ millions):	Gas			Electric		Total
Billed and Unbilled Revenue:
Residential	$	61.4		$	94.8	$	156.2
C&I		89.5			72.2		161.7
Other		9.1			5.8		14.9
Total Billed and Unbilled Revenue		160.0			172.8		332.8
Rate Adjustment Mechanism Revenue		(16.1	)		4.2		(11.9	)
Total Gas and Electric Operating Revenues	$	143.9		$	177.0	$	320.9

	Nine Months Ended September 30, 2018
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	58.3		$	95.6		$	153.9
C&I		84.7			74.1			158.8
Other		8.1			6.5			14.6
Total Billed and Unbilled Revenue		151.1			176.2			327.3
Rate Adjustment Mechanism Revenue		(3.7	)		(8.6	)		(12.3	)
Total Gas and Electric Operating Revenues	$	147.4		$	167.6		$	315.0

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 natural 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 Massachusetts Department of Public Utilities (MDPU). The Company estimates that revenue decoupling applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.

Other Operating Revenue - Non-regulated

Other Operating Revenue – Non-regulated – Other Operating Revenue – Non-regulated – Other Operating Revenue consists solely of revenue from Usource, Unitil’s non-regulated subsidiary, which, as discussed previously, the Company divested of on March 1, 2019. Usource conducted its business activities as a broker of competitive energy services. Usource did not take title to the electric and gas commodities which were the subject of the brokerage contracts. The Company recorded energy brokering revenues based upon the amount of electricity and gas delivered to customers through the end of the accounting period. Usource partnered with certain entities to facilitate these brokerage services and paid these entities a fee under revenue sharing agreements.

Income Taxes

Income Taxes – The Company is subject to Federal and State income taxes as well as various other business taxes. This process involves estimating the Company’s current tax liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included in the Company’s Consolidated Balance Sheets. The Company accounts for income tax assets, liabilities and expenses in accordance with the Financial Accounting Standards Board (FASB) Codification guidance on Income Taxes. The Company classifies penalty and interest expense related to income tax liabilities as income tax expense and interest expense, respectively, in the Consolidated Statements of Earnings.

Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s current and deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known. 

Cash and Cash Equivalents

Cash and Cash Equivalents – Cash and Cash Equivalents include all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. As of September 30, 2019, September 30, 2018 and December 31, 2018, the Unitil subsidiaries had deposited $3.5 million, $3.2 million and $3.5 million, respectively to satisfy their ISO-NE obligations.

Allowance for Doubtful Accounts

Allowance for Doubtful Accounts – The Company recognizes a provision for doubtful accounts each month based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables is performed which takes into account an assumption about the cash recovery of delinquent receivables. The analysis 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 hardship accounts that are protected from shut-off. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including the level of customers enrolling in payment plans with the Company. It has been the Company’s experience that the assumptions it has used in evaluating the adequacy of the Allowance for Doubtful Accounts have proven to be reasonably accurate.

The Allowance for Doubtful Accounts as of September 30, 2019, September 30, 2018 and December 31, 2018, which is included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, was as follows:

($ millions)
	September 30,				December 31,
	2019		2018		2018
Allowance for Doubtful Accounts	$	1.0	$	1.2	$	1.3

Accrued Revenue

Accrued Revenue – Accrued Revenue includes the current portion of Regulatory Assets and unbilled revenues. The following table shows the components of Accrued Revenue as of September 30, 2019, September 30, 2018 and December 31, 2018. 

	September 30,				December 31,
Accrued Revenue ($ millions)	2019		2018		2018
Regulatory Assets – Current	$	24.9	$	26.4	$	41.3
Unbilled Revenues		10.4		9.6		13.4
Total Accrued Revenue	$	35.3	$	36.0	$	54.7

Exchange Gas Receivable

Exchange Gas Receivable – Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers natural gas back to the Company during the months of November through March. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of September 30, 2019, September 30, 2018 and December 31, 2018.

	September 30,				December 31,
Exchange Gas Receivable ($ millions)	2019		2018		2018
Northern Utilities	$	8.0	$	9.5	$	7.5
Fitchburg		0.6		0.6		0.6
Total Exchange Gas Receivable	$	8.6	$	10.1	$	8.1

Gas Inventory

Gas Inventory – The Company uses the weighted average cost methodology ​​​​​​​to value natural gas inventory. The following table shows the components of Gas Inventory as of September 30, 2019, September 30, 2018 and December 31, 2018.

	September 30,				December 31,
Gas Inventory ($ millions)	2019		2018		2018
Natural Gas	$	0.4	$	0.4	$	0.3
Propane		0.3		0.4		0.4
Liquefied Natural Gas & Other		0.1		0.1		0.1
Total Gas Inventory	$	0.8	$	0.9	$	0.8

Utility Plan

Utility Plant – The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At September 30, 2019, September 30, 2018 and December 31, 2018, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $98.4 million, $91.2 million, and $90.7 million, respectively.

Leases

Leases – On January 1, 2019, the Company adopted ASU No. 2016-02, “Leases (Topic 842)”. The new standard requires lessees to record assets and liabilities on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allows the Company to carryforward the historical lease classification. The Company also elected the practical expedient related to land easements, allowing the Company to carry forward its current accounting treatment for land easements on existing agreements. The Company made an accounting policy election to keep leases with an initial term of 12 months or less off of the balance sheet. The Company recognizes those lease payments in the Consolidated Statements of Earnings on a straight-line basis over the lease term. The adoption of the standard resulted in recognition of approximately $4.2 million of lease assets and lease liabilities as of January 1, 2019 on the Company’s Consolidated Balance Sheets. The Company’s adoption of the standard did not have a material effect on its Consolidated Statements of Earnings and Consolidated Statements of Cash Flows. See additional discussion below in the “Leases” section of Note 4 to the Consolidated Financial Statements.

Regulatory Accounting

Regulatory Accounting – The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the Massachusetts Department of Public Utilities (MDPU), Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC) and Northern Utilities is regulated by the Maine Public Utilities Commission

(MPUC) and NHPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the FASB Codification. The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.

	September 30,				December 31,
Regulatory Assets consist of the following ($ millions)	2019		2018		2018
Retirement Benefits	$	74.0	$	88.0	$	72.0
Energy Supply & Other Rate Adjustment Mechanisms		20.6		24.8		38.4
Deferred Storm Charges		5.0		6.3		6.3
Environmental		8.0		8.9		7.9
Income Taxes		4.3		5.9		5.7
Other		11.7		4.1		10.0
Total Regulatory Assets		123.6		138.0		140.3
Less: Current Portion of Regulatory Assets(1)		24.9		26.4		41.3
Regulatory Assets – noncurrent	$	98.7	$	111.6	$	99.0

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

	September 30,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2019		2018		2018
Income Taxes (Note 8)	$	47.6	$	47.9	$	47.0
Energy Supply & Other Rate Adjustment Mechanisms		13.5		12.2		11.5
Total Regulatory Liabilities		61.1		60.1		58.5
Less: Current Portion of Regulatory Liabilities		14.4		12.2		11.5
Regulatory Liabilities—noncurrent	$	46.7	$	47.9	$	47.0

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. As of September 30, 2019 there are $5.8 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years which regulators have authorized recovery of, but without a return. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

Derivatives

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 none of its energy supply contracts currently qualify as a derivative instrument under the guidance set forth in the FASB Codification.

As discussed below in the “Fitchburg – Massachusetts RFP’s” section of Note 6 (Regulatory Matters), Fitchburg has entered into power purchase agreements for which contingencies exist. 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 impact on the contractual obligations and regulatory assets of Fitchburg, once they qualify for derivative accounting.

Investments in Marketable Securities

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.)

At September 30, 2019, September 30, 2018 and December 31, 2018, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $5.9 million, $5.3 million and $4.8 million, respectively, as shown in the table below. 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 (Income), Net.

	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2019		2018		2018
Equity Funds	$	—	$	3.0	$	—
Fixed Income Funds		—		2.3		—
Money Market Funds		5.9		—		4.8
Total Marketable Securities	$	5.9	$	5.3	$	4.8

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

At September 30, 2019, September 30, 2018 and December 31, 2018, 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 $0.1 million, $0 and $0, respectively, as shown in the table below. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other Expense, Net.​​​​​​​

	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2019		2018		2018
Equity Funds	$	—	$	—	$	—
Money Market Funds		0.1		—		—
Total Marketable Securities	$	0.1	$	—	$	—

Energy Supply Obligations

Energy Supply Obligations – The following ​​​​​​​discussion and table summarize the nature and amounts of the items recorded on the Company’s Consolidated Balance Sheets. The current portion of these obligations is recorded as Energy Supply Obligations and the noncurrent portion is included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets.

	September 30,				December 31,
Energy Supply Obligations ($ millions)	2019		2018		2018
Current:
Exchange Gas Obligation	$	8.0	$	9.5	$	7.5
Renewable Energy Portfolio Standards		4.2		5.2		5.6
Power Supply Contract Divestitures		0.3		0.3		0.3
Total Energy Supply Obligations – Current		12.5		15.0		13.4
Noncurrent:
Power Supply Contract Divestitures		0.4		0.7		0.6
Total Energy Supply Obligations	$	12.9	$	15.7	$	14.0

Exchange Gas Obligation – Northern Utilities enters into gas exchange agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. The gas inventory related to these agreements is recorded in Exchange Gas Receivable on the Company’s Consolidated Balance Sheets while the corresponding obligations are recorded in Energy Supply Obligations.

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 is 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 renewable energy certificates (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 four of these contracts have been constructed and are now operating. Since 2017, the Company has participated in two major statewide procurements which resulted in contracts for imported hydroelectric power and associated transmission and for offshore wind generation. The contracts were approved by the MDPU in the second quarter of 2019.

Additional long-term clean energy contracts are expected in compliance with the Energy Diversity Act and An Act to Promote a Clean Energy Future (2018). 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 – As a result of the restructuring of the utility industry in New Hampshire and Massachusetts, Unitil Energy’s and Fitchburg’s customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs. 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 (current portion) and Regulatory Assets (long-term portion).

Recently Issued Pronouncements

Recently Issued Pronouncements – In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842)”. The new standard requires lessees to record assets and liabilities on the balance sheet for all leases with terms longer than 12 months. The Company adopted the standard as of January 1, 2019. See “Leases” above in Note 1.

Other than the pronouncement discussed above, there are no recently issued pronouncements that the Company has not already adopted or that have a material impact on the Company.

Subsequent Events

Subsequent Events – The Company has evaluated all events or transactions through the date of this filing. During this period the Company did not have any material subsequent events that would result in adjustment to or disclosure in its unaudited consolidated financial statements.

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Components of Retirement Plan Costs (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 776	$ 848	$ 2,328	$ 2,544
Interest Cost	1,621	1,469	4,863	4,407
Expected Return on Plan Assets	(2,119)	(1,946)	(6,356)	(5,838)
Prior Service Cost Amortization	80	81	240	243
Actuarial Loss Amortization	1,081	1,447	3,243	4,341
Sub-total	1,439	1,899	4,318	5,697
Amounts Capitalized and Deferred	(650)	(962)	(1,659)	(2,590)
Net Periodic Benefit Cost Recognized	789	937	2,659	3,107
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	576	733	1,728	2,199
Interest Cost	857	852	2,569	2,554
Expected Return on Plan Assets	(412)	(409)	(1,234)	(1,227)
Prior Service Cost Amortization	304	327	910	981
Actuarial Loss Amortization	56	346	170	1,038
Sub-total	1,381	1,849	4,143	5,545
Amounts Capitalized and Deferred	(650)	(930)	(1,730)	(2,557)
Net Periodic Benefit Cost Recognized	731	919	2,413	2,988
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	62	122	185	366
Interest Cost	142	101	426	303
Prior Service Cost Amortization	14	47	42	141
Actuarial Loss Amortization	157	121	471	365
Sub-total	375	391	1,124	1,175
Amounts Capitalized and Deferred	(107)	(113)	(322)	(339)
Net Periodic Benefit Cost Recognized	$ 268	$ 278	$ 802	$ 836